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 five-month peak heating season of November through March and is directly affected by the severity of the winter weather. Our rate structure does not contain weather normalization provisions to compensate for warmer-than-normal weather conditions, and we have historically sold less natural gas and electricity when weather conditions are milder and, consequently, earned less income. As a result, warmer-than-normal heating season weather could reduce our net income and harm our financial condition and adversely affect our cash flows.
INCREASES IN NATURAL GAS AND ELECTRICITY MARKET PRICES COULD ADVERSELY AFFECT OUR BUSINESS.
Prices for natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high natural gas costs, our prices generally increase. High prices can lead to customer conservation, resulting in reduced demand for our product.
Similarly, beginning in 2007 when our current mandatory rate caps expire, increases in the market price of electricity could cause us to raise the prices that we charge our customers, which in turn could reduce demand for our electricity. This could lower our revenues, and, therefore, lower our net income and adversely affect our cash flows.
ELECTRICITY SUPPLIER DEFAULTS MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.
Generally, we purchase our power needs from electricity suppliers under fixed-price energy and capacity contracts. Should any of the suppliers under these contracts fail to provide electric power under the terms of these contracts, any increases in the cost of replacement power or capacity could negatively impact our results and adversely affect our cash flows because of our inability to recover these potential cost increases in our current rates.
IF THE PUC DOES NOT INCREASE THE PROVIDER OF LAST RESORT RATES FOR 2007, ELECTRIC UTILITY'S RESULTS MAY BE ADVERSELY AFFECTED.
Electric Utility remains the provider of last resort ("POLR") for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established through December 31, 2006 in a series of PUC-approved settlements. Electric Utility has no agreement currently in place for POLR rates to be effective after December 31, 2006. Although Electric Utility expects it will be able to recover electric power costs incurred in serving POLR customers after December 31, 2006, it is unable to forecast the level of margins, if any, from providing POLR service.
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. We maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent. There can be no assurance, however, that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage 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 are investigating and remediating contamination at a number of present and former operating sites in the United States, including former sites where we operated manufactured gas plants. We have also received claims from third parties that allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant. Costs we incur to remediate sites outside of Pennsylvania cannot be recovered in future utility rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs to clean up these sites may exceed our current estimates due to factors beyond our control, such as:
o the discovery of presently unknown conditions;
o changes in environmental laws and regulations;
o judicial rejection of our legal defenses to the third-party claims; or
o 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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
With the exception of the matters set forth below, no material legal proceedings are pending involving Utilities, or any of its properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of the Company's business.
ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
From the late 1800s through the mid-1900s, 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, Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the business of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility by the early 1950s.
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 Utilities is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by Utilities or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. Utilities is currently litigating three claims against it relating to out-of-state sites.
City of Bangor, Maine v. Citizens Communications Co. In April 2003, Citizens Communications Company ("Citizens") served a complaint naming Utilities as a third-party defendant in a civil action pending in United States District Court for the District of Maine. In that action, the plaintiff, City of Bangor, Maine ("City"), sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens' predecessors at a site on the Penobscot River. Citizens subsequently joined Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizens' third-party claims have been stayed pending a resolution of the City's suit against Citizens, which was tried in September 2005 and has not yet been decided. Utilities believes that it has good defenses to the claim and is defending the suit.
Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit against Utilities in the United States District Court for the Southern District of New York, seeking contribution from Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that Utilities "owned and operated" the MGPs prior to 1904. The complaint also seeks a declaration that Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70 million.
The trial court granted Utilities' motion for summary judgment and dismissed ConEd's complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court's decision dismissing claims that Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court's decision that Utilities was released from liability at three sites where Utilities operated MGPs under lease. On
October 7, 2005 Utilities filed for reconsideration of the panel's order. Utilities believes that any liability it may have for a share of the response costs at the three leased MGP sites will not have a material effect on its financial condition or results of operations.
Atlanta Gas Light Company v. UGI Utilities, Inc. By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. On March 22, 2005, the court granted Utilities' motion for summary judgment. AGL has appealed.
Savannah, Georgia Matter. AGL previously informed Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of Utilities operated the MGP in the early 1900s. AGL has recently informed Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55 million. AGL has not filed suit against Utilities for a share of these costs. Utilities believes that it will have good defenses to any action that may arise out of this site.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million to clean up a MGP site it owns in Sag Harbor, New York. KeySpan believes that Utilities is responsible for approximately 50% of these costs as a result of Utilities' alleged direct ownership and operation of the plant from 1885 to 1902. Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
Connecticut Gas Plants Matter. By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the "Northeast Companies"), demanded contribution from 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 Utilities controlled operations of the plants from 1883 to 1941. According to the letter, investigation and remedial costs at the sites to date total approximately $10 million and complete remediation costs for all sites could total $182 million. The Northeast Companies seek an unspecified fair and equitable allocation of these costs to Utilities. Utilities is in the process of reviewing the information provided by Northeast Companies and is investigating this claim.
PART II:
ITEM 5.
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 $38.5 million in fiscal year 2005, $45.0 million in fiscal year 2004 and $33.9 million in fiscal year 2003.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BUSINESS OVERVIEW
UGI Utilities, a wholly owned subsidiary of UGI Corporation, owns and operates a natural gas distribution utility in parts of eastern and southeastern Pennsylvania, and an electricity distribution utility in northeastern Pennsylvania. UGI Utilities is regulated by the Pennsylvania Public Utility Commission ("PUC"). UGI Utilities' operations are managed with the goal of growing its business in a profitable manner without the need for frequent base rate increases. Gas Utility's rate of customer growth exceeds the national averages for local gas distribution companies ("LDCs"), and its proximity to major population centers and its extensive transportation infrastructure makes its service territory a desired location for homes and businesses. Because many customers use natural gas and electricity for heating purposes, Gas Utility's and to a lesser extent Electric Utility's results are seasonal with the peak-heating season comprising the months of November through March.
In conducting its business operations, UGI Utilities' management focuses its attention on those factors it believes have a significant effect on the successful operation of the business. These factors include, among others, regulation by the PUC, pursuing customer growth in its service territory and controlling operating costs in order to maintain competitive prices. Year-to-year weather variations can have a significant impact on the Company's results. To a lesser extent, customer behavior in response to increases and volatility in natural gas costs can also affect the Company's results. Gas Utility's tariffs contain purchased gas cost rates that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. These tariffs provide for annual increases or decreases in rates that Gas Utility charges for natural gas sold by it to reflect projected costs of purchased gas. These rates may be adjusted quarterly or, under certain
conditions monthly, to reflect the actual cost of gas. Because of this ratemaking process, there is limited commodity price risk associated with Gas Utility operations. Electric Utility is subject to commodity price risk for electricity as its rates for electric generation under Provider of Last Resort ("POLR") settlements contain rate caps which provide limited protection against electricity price increases. Management attempts to reduce natural gas product cost volatility through the use of call options, fixed-price forward contracts and storage services. Management attempts to reduce electric price volatility by entering into price swap agreements and fixed-price forward contracts. Because a number of Gas Utility's customers have the ability to switch to an alternate fuel at any time and are therefore served on an interruptible basis, profitability for these customers is affected by the difference between the delivered cost of gas and the delivered cost of the alternate fuel in addition to the frequency and duration of service interruptions.
The following Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") compares the results of the Company's operations covering the three-year period ended September 30, 2005. Electric Utility and the electric generation business of UGI Development Company ("UGID") prior to its distribution to UGI in June 2003 are collectively referred to herein as "Electric Operations." The MD&A should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the business segment information in Note 10.
FISCAL 2005 COMPARED WITH FISCAL 2004
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 $5.2 million in Fiscal 2005 and $4.8 million in Fiscal 2004. For financial statement purposes, Gas Utility's and Electric Utility's cost of sales are included in "gas, fuel and purchased power" and revenue-related taxes are included in "taxes other than income taxes" on the Consolidated Statements of Income.
GAS UTILITY. Weather in Gas Utility's service territory based upon heating degree days was 1.4% warmer than normal in Fiscal 2005 compared with weather that was 2.9% warmer than normal in Fiscal 2004. Total distribution system throughput increased in Fiscal 2005 due primarily to greater interruptible delivery service volumes. Notwithstanding the volume effects of the slightly colder weather and an increase in the number of firm- residential, commercial and industrial ("retail core-market") customers, Fiscal 2005 retail core-market throughput was substantially equal to Fiscal 2004 primarily due to a reduction in customer usage per degree day. We believe that the lower usage per degree day was primarily the result of conservation in response to higher natural gas prices. These higher natural gas prices are passed through to retail core-market customers through higher purchased gas cost ("PGC") rates.
The increase in Gas Utility revenues during Fiscal 2005 is principally the result of a $53.4 million increase in retail core-market revenues reflecting higher average PGC rates and, to a lesser extent, the increase in throughput and higher revenues from interruptible customers. These increases were partially offset by a $37.2 million decrease in revenues from low-margin off-system sales. Increases or decreases in retail core-market customer revenues and cost of sales results principally from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under this 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 amount 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 the 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 $390.1 million in Fiscal 2005 compared to $368.9 million in Fiscal 2004 reflecting the effects of the higher PGC rates partially offset by lower cost of sales associated with lower off-system sales.
The $3.5 million increase in Gas Utility total margin in Fiscal 2005 principally reflects greater margin generated from higher interruptible delivery service volumes and higher average interruptible delivery service unit margins. The increase in average interruptible delivery service unit margins reflects an increase in the spread between delivered prices for natural gas and alternative fuels, principally oil. Gross margin from retail core-market customers was relatively stable as lower usage per degree day was offset by an increase in the number of customers.
Gas Utility operating income increased $1.5 million in Fiscal 2005 as the $3.5 million increase in total margin and a $1.9 million increase in other income were partially offset by higher operating and administrative expenses and a $1.2 million increase in depreciation and amortization. The increase in other income is due in large part to the absence of costs recorded in Fiscal 2004 related to a regulatory claim resulting from the discontinuance of natural gas service to certain customers. Fiscal 2005 operating and administrative expenses were slightly higher than in Fiscal 2004 as a $1.9 million increase in uncollectible accounts and customer assistance expenses, the absence of environmental insurance settlements received in the prior year and higher professional services expenses were partially offset by lower injuries and damages and distribution system expenses. The increase in depreciation expense reflects the normal effects of yearly capital expenditures. The increase in Gas Utility income before income taxes in Fiscal 2005 reflects the increase in operating income partially offset by higher interest expense resulting from higher average short-term debt outstanding and higher short-term interest rates.
ELECTRIC UTILITY. Electric Utility's Fiscal 2005 kilowatt-hour sales increased principally reflecting slightly colder Fiscal 2005 heating-season weather and warmer Fiscal 2005 cooling-season weather which increased sales for air conditioning. The increase in Electric Utility revenues principally reflects the effects of a 4.5% increase in its Provider of Last Resort ("POLR") electric generation rates effective January 1, 2005 and the higher kilowatt-hour sales. Electric Utility's cost of sales increased $4.5 million as a result of higher per-unit purchased power costs and the higher sales.
Electric Utility total margin in Fiscal 2005 increased $1.6 million principally as a result of the previously mentioned increase in POLR rates and the higher kilowatt-hour sales partially offset by the increase in per-unit purchased power costs. Operating income and income before income taxes in Fiscal 2005 were higher than the prior year as the increase in total margin was partially offset by higher operating and administrative costs, principally higher incentive compensation and distribution system maintenance expenses.
FISCAL 2004 COMPARED WITH FISCAL 2003
(a) Fiscal 2003 includes the results of UGID prior to its distribution to UGI in June 2003.
(b) Electric Operations' total margin represents total revenues less cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $4.8 million in both Fiscal 2004 and Fiscal 2003.
GAS UTILITY. Weather in Gas Utility's service territory based upon heating degree days was 2.9% warmer than normal in Fiscal 2004 compared with weather that was 7.0% colder than normal in
Fiscal 2003. Total distribution system throughput decreased 1.6 bcf or 1.9% as the adverse effects of the warmer weather on heating-related sales to retail core-market customers were partially offset by greater volumes transported for delivery service customers and the volume effects of year-over-year retail core-market customer growth.
The increase in Gas Utility revenues during Fiscal 2004 includes a $20.1 million increase in revenues from off-system sales partially offset by lower retail core-market and delivery service revenues. The decline in retail core-market revenues reflects the effects of the reduced retail core-market volumes partially offset by higher average rates reflecting the pass through of higher natural gas costs. Gas Utility's cost of gas was $368.9 million in Fiscal 2004 compared to $343.0 million in Fiscal 2003 reflecting greater cost of gas associated with the higher off-system sales and the higher average retail core-market PGC rates partially offset by the effects of the lower retail core-market volumes sold.
Gas Utility total margin declined $5.4 million principally reflecting a $4.0 million decline in retail core-market margin and the effects of lower margins from delivery-service customers.
Gas Utility operating income declined $16.0 million in Fiscal 2004 principally reflecting the previously mentioned decline in total margin, lower other income and higher operating and administrative expenses. Other income declined $5.4 million due in large part to a decline in non-tariff service income, costs related to settling a regulatory claim and the absence of pension income in Fiscal 2004. Operating and administrative expenses increased $3.8 million due primarily to higher compensation and benefits expense, including the effects of a lump-sum payment made to a participant of UGI Utilities' unfunded executive retirement plan, partially offset by the absence of costs related to settling an environmental claim recorded in the prior year and lower Fiscal 2004 distribution system maintenance expenses. The decrease in Gas Utility income before income taxes reflects the decline in operating income and slightly higher interest expense in Fiscal 2004 resulting from classifying dividends paid on preferred shares subject to mandatory redemption as interest expense, beginning on July 1, 2003, in accordance with Statement of Financial Accounting Standards ("SFAS") No. 150 ("SFAS 150").
ELECTRIC OPERATIONS. Electric Utility's Fiscal 2004 kilowatt-hour sales were slightly higher than in Fiscal 2003 due in part to greater air conditioning sales partially offset by the adverse effects of warmer weather on heating-related sales.
The decline in Electric Operations revenues in Fiscal 2004 principally reflects the absence of $8.0 million of revenues from UGID's electricity generation business reflected in the prior year. Electric Operations' cost of sales declined $6.6 million in Fiscal 2004 reflecting the absence of $6.2 million of costs related to UGID's operations and approximately $0.4 million of lower Electric Utility purchased power costs.
Electric Operations total margin in Fiscal 2004 declined $0.7 million principally reflecting the absence of $1.8 million of total margin related to UGID's operations partially offset by a $1.1 million increase in Electric Utility total margin. Operating income and income before income taxes were lower in Fiscal 2004 principally reflecting the decline in total margin.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
UGI Utilities' total debt outstanding was $318.2 million at September 30, 2005. Included in this amount is $81.2 million of bank loans outstanding.
UGI Utilities has revolving credit commitments under which it may borrow up to a total of $110 million. These agreements are currently scheduled to expire in June 2007 through June 2008. UGI Utilities from time to time enters into short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs during the peak heating season. At September 30, 2005, UGI Utilities had two separate $35 million borrowings outstanding under these uncommitted arrangements and $11.2 million under the revolving credit facilities. Borrowings under the uncommitted arrangements mature in February and March 2006. Amounts outstanding under the revolving credit agreements and the uncommitted arrangements are classified as bank loans on the Consolidated Balance Sheets. The revolving credit agreements have restrictions on such items as total debt, debt service and payments for investments.
In November 2004, UGI Utilities borrowed $20 million from a major bank which was repaid on March 1, 2005. During Fiscal 2005 and Fiscal 2004, peak bank loan borrowings totaled $91.4 million and $90.9 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January. Average daily bank loan borrowings were $52.9 million in Fiscal 2005 and $44.5 million in Fiscal 2004. The higher amounts outstanding in Fiscal 2005 reflect, in large part, higher natural gas prices and the associated increase in working capital. Average and peak bank loan borrowings are expected to increase in Fiscal 2006 due in large part to higher natural gas costs.
On October 1, 2004, UGI Utilities redeemed all 200,000 shares of its $7.75 Series Preferred Stock at a price of $100 per share together with full cumulative dividends. The redemption was funded with proceeds from the issuance of $20 million of 6.13% Medium-Term Notes due October 2034. Utilities has a shelf registration statement with the U.S. Securities and Exchange Commission under which it may issue up to $125 million of Medium-Term Notes or other debt securities. Medium-Term Notes of $50 million maturing in December 2005 are expected to be refinanced through the issuance of debt under this shelf registration.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations, short-term borrowings under revolving credit agreements and uncommitted arrangements, and the Company's ability to issue debt under its Medium-Term Note program, management believes that Utilities will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2006. For additional discussion of Utilities' long-term debt and revolving credit facilities, see Note 3 to Consolidated Financial Statements.
CASH FLOWS
OPERATING ACTIVITIES. Due to the seasonal nature of UGI Utilities' businesses, cash flows from 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 usually 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 its revolving credit agreements and uncommitted arrangements with major banks to satisfy its seasonal operating cash flow needs. Cash flow from operating activities was $68.3 million in Fiscal 2005, $67.0 million in Fiscal 2004, and $97.8 million in Fiscal 2003. Cash flow from operating activities before changes in operating working capital was $86.3 million in Fiscal 2005, $92.9 million in Fiscal 2004 and $91.8 million in Fiscal 2003. Changes in operating working capital used $18.0 million of operating cash flow in Fiscal 2005, used $26.0 million of operating cash flow in Fiscal 2004 and provided $6.0 million of operating cash flow in Fiscal 2003. Fiscal 2005 changes in operating working capital includes $11.0 million of cash flow from electric supplier collateral deposits and greater cash from purchased gas cost overcollections partially offset by a decrease in accounts payable.
INVESTING ACTIVITIES. Cash flow used in investing activities was $47.5 million in Fiscal 2005, $42.4 million in Fiscal 2004 and $43.1 million in Fiscal 2003. Expenditures for property, plant and equipment were $46.3 million in Fiscal 2005, $40.7 million in Fiscal 2004 and $41.3 million in Fiscal 2003. The higher 2005 capital expenditures principally reflect higher Electric Utility distribution and transmission system capital expenditures and greater information system expenditures. Net costs of property, plant and equipment disposals which principally represent net costs associated with retirements of distribution system assets were $1.2 million in Fiscal 2005, $1.7 million in Fiscal 2004 and $1.8 million in Fiscal 2003.
FINANCING ACTIVITIES. Cash flow used by financing activities was $18.2 million in Fiscal 2005, $24.8 million in Fiscal 2004 and $60.5 million in Fiscal 2003. Financing activity cash flow changes are primarily due to issuances and repayments of long-term debt and preferred stock, net short-term borrowings including borrowings under revolving credit facilities, dividends on common stock, capital contributions from UGI and, prior to the adoption of SFAS 150 effective July 1, 2003, dividends on preferred shares subject to mandatory redemption.
As previously mentioned, in September 2005, UGI Utilities entered into two $35 million borrowings which are scheduled to mature in February and March 2006. In May 2005, UGI Utilities refinanced $20 million of its maturing 6.62% Medium-Term Notes through the issuance of 5.16% Medium-Term Notes due in May 2015. Also during Fiscal 2005, UGI Utilities borrowed and repaid $20 million associated with a short-term loan that matured on March 1, 2005. On October 1, 2004, UGI Utilities redeemed all 200,000 shares of $7.75 Series Preferred Stock at a price of $100 per share together with full cumulative dividends. The redemption of the $7.75 Series Preferred Stock was funded with proceeds from the October 2004 issuance of $20 million of 6.13% Medium-Term Notes due 2034.
During Fiscal 2005, 2004 and 2003, we paid cash dividends to UGI of $38.5 million, $45.0 million and $33.9 million, respectively. Although we paid dividends on our preferred shares subject to mandatory redemption of $1.6 million in Fiscal 2004 and 2003, only dividends paid on the preferred shares subject to mandatory redemption before July 1, 2003 are reflected in cash flow from investing activities (see "Preferred Shares Subject to Mandatory Redemption" below).
PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION
Beginning July 1, 2003 through the date of their redemption on October 1, 2004, the Company accounted for its preferred shares subject to mandatory redemption in accordance with SFAS 150. SFAS 150 establishes guidelines on how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The adoption of SFAS 150 on July 1, 2003, resulted in the Company presenting its preferred shares subject to mandatory redemption in the liabilities section of the balance sheet and reflecting dividends paid on these shares as a component of interest expense for periods presented after June 30, 2003. Prior to July 1, 2003, dividends on these preferred shares were reflected as a deduction from net income. The amount of such dividends reflected in interest expense was $1.6 million in Fiscal 2004 and $0.4 million in Fiscal 2003.
DIVIDEND OF UGID
In June 2003, the Company dividended all of the common stock of UGID and UGID's subsidiaries to UGI. The net book value of the assets and liabilities of UGID and its subsidiaries on the date of distribution totaling $15.4 million (including $2.6 million of cash) was eliminated from the consolidated balance sheet and reflected as a dividend from retained earnings.
UTILITIES PENSION PLAN
UGI Utilities sponsors a defined benefit pension plan ("Pension Plan") for employees of UGI Utilities, UGI, and certain of UGI's other subsidiaries. The fair value of Pension Plan assets was $211.7 million and $196.4 million at September 30, 2005 and 2004, respectively. At September 30, 2005 and 2004, the Pension Plan's assets exceeded its accumulated benefit obligations by $7.4 million and $9.2 million, respectively. The Company is in full compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 ("ERISA") rules and regulations, and does not anticipate it will be required to make a contribution to the Pension Plan in Fiscal 2006. Pre-tax pension expense (income) reflected in Fiscal 2005, 2004 and 2003 results was $2.5 million, $1.0 million and $(1.2) million, respectively. The increase in pension expense over this period reflects the changes in the market value of Pension Plan assets and decreases in the discount rate assumption. In addition, Fiscal 2005 pension expense reflects the expiration of the Pension Plan's transition asset amortization. Pension expense in Fiscal 2006 is expected to be approximately $2.3 million.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business segment for Fiscal 2005, Fiscal 2004 and Fiscal 2003. We also provide amounts we expect to spend in Fiscal 2006. We expect to finance a substantial portion of Fiscal 2006 capital expenditures from cash generated by operations and the remainder from borrowings under our credit facilities.
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
Utilities has contractual cash obligations that extend beyond Fiscal 2005 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, 2005 (in millions of dollars).
RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct corporate expenses and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. These billed expenses totaled $12.9 million in Fiscal 2005, $11.2 million in Fiscal 2004 and $9.4 million in Fiscal 2003 and are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. UGI Utilities provides limited administrative services to UGI and certain of UGI's subsidiaries, principally payroll related services. Amounts billed to these entities by UGI Utilities were not material.
Effective December 1, 2004, following a competitive bidding process, UGI Utilities entered into a Storage Contract Administration Agreement ("Storage Agreement") with UGI Energy Services, Inc. ("Energy Services"), a wholly owned, indirect subsidiary of UGI. The Storage Agreement was initially scheduled to expire on October 31, 2005, but effective November 1, 2005, UGI Utilities and Energy Services agreed to extend the Storage Agreement through October 31, 2008. Under the Storage Agreement, UGI Utilities released certain gas transportation and storage contracts through October 31, 2008 and transferred associated gas storage inventories to Energy Services. UGI Utilities may recall such released transportation and storage contracts without penalty if recalled to meet operational requirements, and if not recalled, the releases will terminate at the end of the term of the Storage Agreement. In the event that
released contracts are recalled or at the expiration of the Storage Agreement, Energy Services is required to transfer associated gas storage inventories to UGI Utilities. In exchange for the ability to utilize these assets, Energy Services pays a monthly fee to UGI Utilities and provides a firm natural gas delivery service to UGI Utilities. In accordance with the bidding process, UGI has provided UGI Utilities with performance security in the amount of $20 million. UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (for any amounts of 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, 2005, comprising 8.7 billion cubic feet of natural gas, was $63.0 million. During Fiscal 2005, UGI Utilities purchased natural gas storage inventories from Energy Services under the Storage Agreement totaling $64.4 million, and incurred associated pipeline transportation and storage capacity charges of $16.3 million.
Gas Utility enters into wholesale natural gas transactions with Energy Services for winter peaking service and, from time to time, purchases of natural gas or pipeline capacity. During Fiscal 2005, 2004 and 2003, the aggregate amount of these transactions (exclusive of Storage Agreement transactions) totaled $8.5 million, $6.3 million, and $4.7 million, respectively. In addition, from time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2005, 2004 and 2003, revenues associated with these sales to Energy Services totaled $4.2 million, $1.7 million and $4.2 million, respectively. These transactions did not have a material effect on the Company's net income during Fiscal 2005, 2004 and 2003.
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.
REGULATORY MATTERS
Since the 1980s, larger commercial and industrial customers have been able to purchase gas supplies from entities other than Gas Utility. As a result of Pennsylvania's Natural Gas Choice and Competition Act (the "Gas Competition Act"), since July 1, 1999, all natural gas consumers in Pennsylvania, including residential and smaller commercial and industrial customers ("core-market customers"), have been afforded this opportunity. Gas Utility's gross margin is not negatively affected by customers who use its transportation service and purchase natural gas from another supplier because its tariff is designed so that no profit is earned on the commodity portion of sales to firm customers. Under the Gas Competition Act, natural gas distribution companies ("NGDCs"), like Gas Utility, continue to serve as the supplier of last resort for all core-market customers, and such sales of gas, as well as the distribution service provided by NGDCs, continue to be subject to rate regulation by the PUC. As of September 30, 2005, less than two percent of Gas Utility's core-market customers purchase their gas from alternate suppliers.
As a result of the Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility's customers have the ability to acquire their electricity from entities other than Electric Utility. Electric Utility remains the provider of last resort ("POLR") for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established in a series of PUC approved settlements, the last of which became effective on June 7, 2004 (collectively, the "POLR Settlement").
Electric Utility's POLR service rules provide for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier. Customers who do not select an alternate supplier will be obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service must remain on POLR service until the date of the second open shopping period after returning. Commercial and industrial customers who return to POLR service must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. As of September 30, 2005, fewer than 1% of Electric Utility's customers have chosen an alternative electric generation supplier. In October 2005, Electric Utility was notified by the only alternative electric generation provider supplying electricity in its service territory that it would cease providing electric generation service during the first quarter of Fiscal 2006.
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through December 31, 2006. Consistent with the terms of the POLR Settlement, Electric Utility's POLR rates increased 4.5% on January 1, 2005, and Electric Utility is permitted to further increase its POLR rates beginning January 2006 to no more than 7.5% above the total rates in effect on December 31, 2004. Electric Utility expects to increase POLR rates by 3% beginning January 1, 2006. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers. The PUC is currently developing post-rate-cap POLR regulations that are expected to further define POLR service obligations and pricing.
Electric Utility has no agreement currently in place for POLR rates to be effective after December 31, 2006. The terms of the POLR Settlement require the POLR Settlement parties to begin discussions on post-2006 POLR rates by April 1, 2006. Although Electric Utility expects it will be able to recover electric power costs incurred in serving POLR customers after December 31, 2006, it is unable to forecast the level of margins, if any, from providing POLR service.
We account for the operations of Gas Utility and Electric Utility in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71"). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable.
MANUFACTURED GAS PLANTS
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, UGI Utilities divested all of its utility operations other than those which now constitute Gas Utility 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 Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. 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. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
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 owned or 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.
In April 2003, Citizens Communications Company ("Citizens") served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in United States District Court for the District of Maine. In that action, the plaintiff, City of Bangor, Maine ("City"), sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens' predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizens' third-party claims have been stayed pending a resolution of the City's suit against Citizens, which was tried in September 2005 and has not yet been decided. UGI Utilities believes that it has good defenses to the claim and is defending the suit.
By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. In March 2005, the court granted UGI Utilities' motion for summary judgment and dismissed AGL's complaint. AGL has appealed.
AGL has informed UGI Utilities that it has begun remediation of MGP wastes at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL believes that the total cost of remediation could be as high as $55 million. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities "owned and operated" the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible FOR an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70 million.
The trial court granted UGI Utilities' motion for summary judgment and dismissed ConEd's complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court's decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court's decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. UGI Utilities filed for reconsideration of the panel's order. UGI Utilities believes that any liability it may have for a share of the response costs at the three leased MGP sites will not have a material effect on its financial condition or results of operations.
By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11.0 million 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. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together, the "Northeast Companies"), demanded 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. According to the letter, investigation and remedial costs at the sites to date total approximately $10 million and complete remediation costs for all sites could total $182.0 million. The Northeast Companies seek an unspecified fair and equitable allocation of these costs to UGI Utilities. UGI Utilities is in the process of reviewing the information provided by Northeast Companies and is investigating this claim.
MARKET RISK DISCLOSURES
Gas Utility's tariffs contain clauses that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses exchange-traded natural gas call option contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these call option contracts, net of any associated gains, is included in Gas Utility's PGC recovery mechanism.
Electric Utility purchases its power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Prices for electricity can be volatile especially during periods of high demand or tight supply. In accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2006. In accordance with these settlements, effective January 1, 2005, POLR generation rates for all metered customers increased 4.5% of its total rates in effect on December 31, 2004 and expects to increase POLR rates by 3% beginning January 1, 2006. Currently, Electric Utility's fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2006. However, should any of the suppliers under these contracts fail to provide electric power under the terms of the power and capacity contracts, any increases in the cost of replacement power or capacity could negatively impact Electric Utility results. In order to reduce this non-performance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. At September 30, 2005, Electric Utility held $13.5 million in collateral deposits which are reflected in other current liabilities on the Balance Sheet.
Electric Utility has and may enter into electric price swap agreements to reduce the volatility in the cost of a portion of its anticipated electricity requirements. Electric Utility has an electric price swap agreement associated with purchases of a portion of electricity anticipated to occur in 2007. At September 30, 2005, the fair value of our electric price swap was a gain of $6.1 million. Fair value reflects the estimated amount that we would expect to receive or pay to terminate the contract based upon quoted market prices of comparable contracts at September 30, 2005. An adverse change in electricity prices of ten percent would result in a $1.4 million decrease in the fair value of the swap.
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact its fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt includes our short-term borrowings. These debt agreements provide for interest rates on borrowings that are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements in Fiscal 2005 and Fiscal 2004, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.5 million and $0.4 million, respectively.
The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $16.4 million and $13.8 million at September 30, 2005 and 2004, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $18.7 million and $15.5 million at September 30, 2005 and 2004, respectively.
In order to reduce interest rate risk associated with near-term issuances of fixed-rate debt, we may enter into interest rate protection agreements. The fair value of our unsettled interest rate protection agreements, which have been designated and qualify as cash flow hedges, was a loss of $2.5 million at September 30, 2005. An adverse change in interest rates of ten percent on ten-year U.S. treasury notes would result in a $2.2 million decrease in the fair value of these interest rate protection agreements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance with accounting principles generally accepted in the United States of America requires the selection and application of appropriate accounting principles 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 that are most important to the portrayal of the Company's financial condition and results of operations. Changes in these policies could have a material effect on the financial statements. The application of these accounting policies 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 with the Audit Committee.
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, Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere at which hazardous substances may be present. In accordance with accounting principles generally accepted in the United States of America, 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 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, 2005, Utilities net property, plant and equipment totaled $655.3 million and we recorded depreciation expense of $23.0 million during Fiscal 2005.
REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility's distribution businesses are subject to regulation by the PUC. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," 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, 2005, our regulatory assets totaled $61.3 million. See Note 2 to the Consolidated Financial Statements.
DEFINED BENEFIT PENSION PLAN. The costs of providing benefits under our Pension Plan are 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 utilized including, the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase. Pension Plan assets 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 bond market returns could have a material impact on future pension costs. We believe the two most critical assumptions are the expected rate of return on plan assets and the discount rate. An unfavorable change in the expected rate of return on plan assets of 50 basis points would result in an increase in pre-tax pension expense of approximately $1.0 million in Fiscal 2006. An unfavorable change in the discount rate of 50 basis points would result in an increase in pre-tax pension expense of approximately $1.5 million in Fiscal 2006.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Below is a listing of recently issued accounting pronouncements by the Financial Accounting Standards Board. None of them had or are expected to have a material effect on our financial position or results of operations. SFAS No. 154 applies only to changes in accounting and corrections of errors. See Note 1 to the Consolidated Financial Statements for additional discussion of such pronouncements.
FORWARD-LOOKING STATEMENTS
Information contained above in this Management's Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this 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) competitive pressures from the same and alternative energy sources; (5) liability for environmental claims; (6) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (7) adverse labor relations; (8) large customer, counterparty or supplier defaults; (9) increased uncollectible accounts expense; (10) 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; (11) political, regulatory and economic conditions in the United States; and (12) reduced access to capital markets and interest rate fluctuations.
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.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
"Quantitative and Qualitative Disclosures About Market Risk" are contained in Management's Discussion and Analysis of Financial Condition and Results of Operations under the caption "Market Risk Disclosures" and are incorporated here by reference.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the financial statement schedule referred to in the Index contained on page of this Report are incorporated herein by reference.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
(a) The Company's management, with the participation of the Company's Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures as of the end of the period covered by this Report were designed and functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure.
(b) Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, using the criteria in Internal Control -- Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway
Commission ("COSO Framework"). The Company's system of internal control over financial reporting is designed 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. Management also believes the system of internal control over financial reporting provides reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management's authorization and are properly recorded to permit the preparation of reliable financial information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2005, based on the COSO Framework. Management's assessment of the effectiveness of the Company's internal control over financial reporting as of September 30, 2005, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report.
For the related report of PricewaterhouseCoopers LLP, our Independent Registered Public Accounting Firm, see Item 8 of this Report (which information is incorporated herein by reference).
(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.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III:
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company's independent registered public accountants, in fiscal years 2005 and 2004 were as follows:
- ----------
(1) Audit Fees were for audit services, including (i) the annual audit of the consolidated financial statements of the Company, (ii) the audit of management's assessment of the effectiveness of internal control over financial statements, (iii) review of the interim financial statements included in the Quarterly Reports on Form 10-Q of the Company, and (iv) services that only the independent public accounting firm can reasonably be expected to provide, such as services associated with SEC registration statements, and documents issued in connection with securities offerings.
Consistent with SEC policies regarding auditor independence, the Audit Committee has responsibility for appointing, setting compensation and overseeing the work of the Company's independent accountants. In recognition of this responsibility, the Audit Committee has a policy of pre-approving all audit and permissible non-audit services provided by the independent accountants.
Prior to engagement of the Company's independent accountants for the next year's audit, management submits a list of services and related fees expected to be rendered during that year within each of the four categories of services noted above to the Audit Committee for approval.
PART IV:
ITEM 15.
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, 2005 and
Consolidated Statements of Income for the fiscal years ended September 30, 2005, 2004 and 2003
Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2005, 2004 and 2003
Consolidated Statements of Stockholder's Equity for the fiscal years ended September 30, 2005, 2004 and 2003
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULE:
For the years ended September 30, 2005, 2004 and 2003
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.
(3) LIST OF EXHIBITS:
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
* Filed herewith. ** As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
UGI UTILITIES, INC.
Date: December 6, 2005 By: John C. Barney ----------------------------------------- John C. Barney Senior Vice President - Finance and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 6, 2005 by the following persons on behalf of the Registrant in the capacities indicated.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 6, 2005 by the following persons on behalf of the Registrant in the capacities indicated.
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 year 2005.
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2005
UGI UTILITIES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of UGI Utilities, Inc.:
We have completed an integrated audit of UGI Utilities, Inc.'s 2005 consolidated financial statements and of its internal control over financial reporting as of September 30, 2005 and audits of its 2004 and 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, management's assessment, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of September 30, 2005 based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2005, based on criteria established in Internal Control -- Integrated Framework issued by the COSO. The Company's management is responsible for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP Philadelphia, Pennsylvania December 13, 2005
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars, except per share)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION PRINCIPLES
UGI Utilities, Inc. ("UGI Utilities"), a wholly owned subsidiary of UGI Corporation ("UGI"), owns and operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an electricity distribution utility ("Electric Utility") in northeastern Pennsylvania. Prior to June 2003, UGI Utilities also owned interests in Pennsylvania-based electricity generation assets through its wholly owned subsidiary, UGI Development Company ("UGID"), and UGID's 50% owned joint-venture affiliate Hunlock Creek Energy Ventures ("Energy Ventures"). In June 2003, the Company dividended all of the common stock of UGID and its subsidiaries to UGI.
We refer to Gas Utility, Electric Utility and UGID (prior to its distribution to UGI) collectively as "the Company" or "we," and Electric Utility and UGID (prior to its distribution to UGI) collectively as "Electric Operations." Our 2005 and 2004 consolidated financial statements include the accounts of UGI Utilities, and our 2003 consolidated financial statements include the accounts of UGI Utilities and UGID and its consolidated subsidiaries, prior to their dividend to UGI. We eliminate all significant intercompany accounts when we consolidate. UGID's investment in Energy Ventures was accounted for under the equity method. Gas Utility and Electric Utility (collectively, "Utilities") are subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). UGID was granted "Exempt Wholesale Generator" status by the Federal Energy Regulatory Commission. UGID and its subsidiaries' results of operations did not have a material effect on the Company's results of operations in 2003.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.
REGULATED UTILITY OPERATIONS
We account for the operations of Gas Utility and Electric Utility in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71"). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable. See Note 2.
CONSOLIDATED STATEMENTS OF CASH FLOWS
We define cash equivalents as all highly liquid investments with maturities of three months or less when purchased. We record cash equivalents at cost plus accrued interest, which approximates market value.
We paid interest totaling $17,509 in 2005, $18,143 in 2004 and $16,046 in 2003. We paid income taxes totaling $36,348 in 2005, $19,910 in 2004 and $29,372 in 2003.
REVENUE RECOGNITION
We record regulated revenues for service provided to the end of each month which includes an accrual for certain unbilled amounts based upon estimated usage. 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.
INVENTORIES
Our inventories are stated at the lower of cost or market. We determine cost principally on an average cost method except for appliances for which we use the specific identification method.
INCOME TAXES
We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities' plant additions over the service lives of the related property. UGI 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.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION
We record property, plant and equipment at cost. When Gas Utility and Electric Utility retire 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 record depreciation expense for UGI Utilities' plant and equipment on a straight-line method over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.4% in 2005 and 2.3% in both 2004 and 2003. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.9% in 2005, 2.8% in 2004 and 3.0% in 2003. Depreciation expense was $23,046 in 2005, $21,860 in 2004, and $20,754 in 2003.
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.
COMPUTER SOFTWARE COSTS
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.
DEFERRED FUEL COSTS
Gas Utility's tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost ("PGC") rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with SFAS 71, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers. The balance sheet caption "deferred fuel costs" reflects amounts related to this PGC recovery mechanism.
PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION
Beginning July 1, 2003 through the date of their redemption on October 1, 2004 (see Note 7), the Company accounted for its preferred shares subject to mandatory redemption in accordance with SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" ("SFAS 150"). SFAS 150 establishes guidelines on how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The adoption of SFAS 150, effective July 1, 2003, resulted in the Company presenting its preferred shares subject to mandatory redemption in the liabilities section of the balance sheet, and reflecting dividends paid on these shares as a component of interest expense, for periods presented after June 30, 2003. Prior to July 1, 2003, these dividends were reflected as a deduction from net income. Because SFAS 150 specifically prohibits the restatement of financial statements prior to its adoption, prior period amounts have not been reclassified.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
STOCK-BASED COMPENSATION
Certain members of Utilities' management may be granted stock options and other equity-based awards of UGI Common Stock under UGI's current equity compensation plans. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), we apply the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"), in recording compensation expense for grants of equity instruments to employees.
We use the intrinsic value method prescribed by APB 25 for UGI's equity-based employee compensation plans. We recorded equity-based compensation expense of $1,764 in 2005, $2,652 in 2004 and $1,372 in 2003. If we had determined stock-based compensation expense under the fair value method prescribed by the provisions of SFAS 123, net income after dividends on preferred shares subject to mandatory redemption would have been as follows at September 30:
ENVIRONMENTAL AND OTHER LEGAL MATTERS
We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Amounts accrued generally reflect our best estimate of costs expected to be incurred or the minimum liability associated with a range of expected environmental response 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 any incurred costs through all appropriate means, including regulatory relief. Gas Utility is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. Gas Utility is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred removal costs. At September 30, 2005, the Company's undiscounted amount and accrued liability for environmental investigation and cleanup costs were not material.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Similar to environmental matters, we accrue investigation and other legal costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated (see Note 8).
DERIVATIVE INSTRUMENTS
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It 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. For a detailed description of the derivative instruments we use, our objectives for using them, and related supplemental information required by SFAS 133, see Note 9.
COMPREHENSIVE INCOME
Comprehensive income comprises net income and other comprehensive income. Other comprehensive income of $1,698, $594 and $725 for the years ended September 30, 2005, 2004 and 2003, respectively, is the result of gains or losses on interest rate protection agreements ("IRPAs") and changes in the fair value of an electric price swap agreement qualifying as cash flow hedges, net of reclassifications to net income.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In May 2005, the Financial Accounting Standards Board ("FASB") issued SFAS No. 154, "Accounting Changes and Error Corrections" ("SFAS 154"). SFAS 154 replaces APB No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," and establishes retrospective application as the required method for reporting a change in accounting principle. SFAS 154 provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
In March 2005, the FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" ("FIN 47"). It requires an entity to recognize a liability for a conditional asset retirement obligation when incurred if the liability can be reasonably estimated. FIN 47 clarifies that the term "Conditional Asset Retirement Obligation" refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. We do not expect the adoption of FIN 47 to have any impact on our financial position or results of operations.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), "Share-Based Payment" ("SFAS 123R"). SFAS 123R replaces SFAS 123 and supersedes APB 25. SFAS 123, as originally issued in 1995, established as preferable a fair-value-based method of accounting for share-based payment transactions with employees. However, SFAS 123 permitted entities the option of continuing to
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
apply the guidance in APB 25 as long as the footnotes to financial statements disclosed what net income would have been had the preferable fair-value-based method been used. SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. The cost is required to be measured based on the fair value of the equity or liability instruments issued. SFAS 123R covers a wide range of share-based compensation arrangements including share options, restricted share plans, performance-based awards, share appreciation rights and employee share purchase plans. We adopted SFAS 123R effective October 1, 2005. Under the modified prospective transition method, beginning October 1, 2005, unrecognized compensation expense for awards that are not vested on the adoption date will be recognized in the Company's statements of income through the end of the requisite service period. We do not believe that the adoption of SFAS 123R will have a material impact on our annual results of operations or financial position. For disclosure regarding pro forma net income as if we had determined stock-based compensation under the fair value method prescribed by SFAS 123, see Stock-Based Compensation included elsewhere in this Note 1.
In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets - - An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions" ("SFAS 153"). SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, "Accounting for Nonmonetary Transactions," and replaces it with an exception for exchanges that lack commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 was effective for our interim period beginning July 1, 2005. The adoption of SFAS 153 did not have a material effect on our financial position or results of operations.
RECLASSIFICATIONS
We have reclassified certain prior-year balances to conform to the current year presentation.
2. UTILITY REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company's regulatory liabilities relating to other postretirement benefits are included in "other noncurrent liabilities" on the Consolidated Balance Sheets. The Company does not recover a rate of return on its regulatory assets.
3. DEBT
Long-term debt comprises the following at September 30:
Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows: 2006 - $50,000; 2007 - $20,000; 2008 - $0; 2009 - $0; 2010 - $0.
At September 30, 2005, UGI Utilities had revolving credit agreements with five banks providing for borrowings of up to $110,000. These agreements are currently scheduled to expire in June 2007 through June 2008. Under these agreements, UGI Utilities may borrow at various prevailing interest rates, including LIBOR and the banks' prime rate. UGI Utilities pays quarterly commitment fees on these credit lines. UGI Utilities had revolving credit agreement borrowings totaling $11,200 at September 30, 2005 and $60,900 at September 30, 2004 which we classify as bank loans. UGI Utilities from time to time enters into short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs during the peak heating season. At September 30, 2005, there were two separate $35,000 borrowings outstanding under these arrangements. These borrowings are scheduled to mature on February 15 and March 14, 2006 and are also classified as bank loans. The weighted-average interest rates on bank loans outstanding were 4.41% at September 30, 2005 and 2.35% at September 30, 2004.
UGI Utilities' credit agreements have restrictions on such items as total debt, debt service, and payments for investments. They also require consolidated tangible net worth of at least $125,000. At September 30, 2005, UGI Utilities was in compliance with these financial covenants.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES
The provisions for income taxes consist of the following:
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Deferred tax liabilities (assets) comprise the following at September 30:
UGI Utilities had recorded deferred tax liabilities of approximately $37,270 as of September 30, 2005 and $39,445 as of September 30, 2004 pertaining to utility temporary differences, principally a result of accelerated tax depreciation for state income tax purposes, the tax benefits of which previously were or will be flowed through to ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $2,985 at September 30, 2005 and $3,149 at September 30, 2004, pertaining to utility deferred investment tax credits. UGI Utilities had recorded regulatory income tax assets related to these net deferred taxes of $58,601 at September 30, 2005 and $62,039 at September 30, 2004. These regulatory income tax assets represent future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred.
5. EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS
We sponsor a defined benefit pension plan ("UGI Utilities Pension Plan") for employees of UGI, UGI Utilities, and certain of UGI's other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain of our retirees and postretirement life insurance benefits to nearly all active and retired employees.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following provides a reconciliation of projected benefit obligations, plan assets, and funded status of the plans as of September 30:
Net pension expense (income) is determined using assumptions as of the beginning of each fiscal year. Funded status is determined using assumptions as of the end of each fiscal year. The expected rate of return on assets assumption is based on the rates of return for certain asset classes and the allocation of plan assets among those asset classes as well as actual historic long-term rates of return on our plan assets.
Included in the end of year pension benefit obligations above are $26,223 at September 30, 2005 and $23,581 at September 30, 2004 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year postretirement obligations above are $751 at September 30, 2005 and $735 at September 30, 2004 relating to employees of UGI and certain of its other subsidiaries.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Net periodic pension expense (income) and other postretirement benefit costs relating to UGI Utilities employees include the following components:
UGI Utilities Pension Plan assets are held in trust. Although the UGI Utilities Pension Plan projected benefit obligations exceeded plan assets at September 30, 2005 and 2004, plan assets exceeded accumulated benefit obligations by $7,404 and $9,160, respectively. The Company did not make any contributions to the UGI Utilities Pension Plan in 2005, 2004 or 2003 and does not believe that it will be required to make any contributions during the year ending September 30, 2006 for ERISA funding purposes.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employees' Beneficiary Association ("VEBA") trust to fund the UGI Utilities' postretirement benefit obligations and to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS No. 106, "Employers Accounting for Postretirement Benefits Other than Pensions" ("SFAS 106"). The difference between such amounts calculated under SFAS 106 and the amounts included in Utilities' rates is deferred for future recovery from, or refund to, ratepayers. Effective July 1, 2005, substantially all retirees and their beneficiaries participating in the UGI Utilities' postretirement benefit program were enrolled in insured Medicare Advantage plans. As a result, the projected benefit obligation of our postretirement benefits program was lower at September 30, 2005 as compared to such obligations at September 30, 2004. Additionally, the Company's required contribution to the VEBA during the year ending September 30, 2006 is expected to be significantly lower than in 2005.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Expected payments for pension benefits and for other postretirement welfare benefits are as follows:
In accordance with our investment strategy to obtain long-term growth, our target asset allocations are to maintain a mix of 60% equities and the remainder in fixed income funds or cash equivalents. The target and actual allocations for the UGI Utilities Pension Plan and VEBA trust assets at September 30 are as follows:
UGI Common Stock comprised approximately 11% and 8% of pension plan trust assets at September 30, 2005 and 2004, respectively.
The assumed health care cost trend rates are 10% for fiscal 2006, decreasing to 5.5% in fiscal 2011. A one percentage point change in the assumed health care cost trend rate would increase (decrease) the 2005 postretirement benefit cost and obligation as follows:
We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2005 and 2004, the projected benefit obligations of this plan were $2,700 and $1,600, respectively. We recorded expense for this plan of $439 in 2005, $460 in 2004 and $353 in 2003. We also recorded a settlement loss of $1,537 in 2004 associated with this plan.
DEFINED CONTRIBUTION PLANS
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. We may, at our discretion, match a portion of participants'
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
contributions. The cost of benefits under the savings plan totaled $931 in 2005, $915 in 2004, and $968 in 2003.
6. INVENTORIES
Inventories comprise the following at September 30:
Included in utility fuel and gases inventories at September 30, 2005 are amounts associated with the Company's Storage Contract Administration Agreement ("Storage Agreement") with Energy Services, Inc. ("Energy Services"), a wholly owned subsidiary of UGI. For a detailed description of the Storage Agreement and the accounting for such inventories, see Note 12.
7. SERIES PREFERRED STOCK
We have 2,000,000 shares of Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, authorized for issuance. We had no shares of Series Preferred Stock outstanding at September 30, 2005. Any holders of shares of Series Preferred Stock would have the right to elect a majority of the Company's Board of Directors (without cumulative voting) if dividend payments on any series were in arrears in an amount equal to four quarterly dividends. This election right would continue until the arrearage was cured. We paid cash dividends at the specified annual rates on all outstanding Series Preferred Stock.
On October 1, 2004, we redeemed of all 200,000 shares of the $7.75 Series Preferred Stock at a price of $100 per share together with full cumulative dividends. The redemption on October 1, 2004 was funded with proceeds from the October 2004 issuance of $20,000 of 6.13% Medium-Term Notes due October 2034.
8. COMMITMENTS AND CONTINGENCIES
We lease various buildings and transportation, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $4,703 in 2005, $4,431 in 2004, and $4,303 in 2003.
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: 2006 - $3,855; 2007 - $3,359; 2008 - $2,403; 2009 - $1,410; 2010 - $966; after 2010-$2,707.
Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
service which Gas Utility may terminate at various dates through 2016. Gas Utility's costs associated with transportation and storage service agreements are included in its annual PGC filing 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 capacity requirements and electric energy needs under contracts with various suppliers and on the spot market. Contracts with producers for capacity and energy needs expire at various dates through fiscal 2008.
Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2005 are as follows: 2006 - $250,855; 2007 - $85,486; 2008 - $63,500; 2009 - $53,669; 2010 - $41,705; after 2010 - $74,881.
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, UGI Utilities divested all of its utility operations other than those which now constitute Gas Utility 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 Gas Utility is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites. 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. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
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.
In April 2003, Citizens Communications Company ("Citizens") served a complaint naming Utilities as a third-party defendant in a civil action pending in United States District Court for the District of Maine. In that action, the plaintiff, City of Bangor, Maine ("City"), sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
operated by Citizens' predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18,000 to clean up the river. Citizens' third-party claims have been stayed pending a resolution of the City's suit against Citizens, which was tried in September 2005 and has not yet been decided. UGI Utilities believes that it has good defenses to the claim and is defending the suit.
By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8,000 incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. In March 2005, the court granted UGI Utilities' motion for summary judgment dismissing AGL's complaint. AGL has appealed.
AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55,000. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities "owned and operated" the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70,000.
The trial court granted UGI Utilities' motion for summary judgment and dismissed ConEd's complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court's decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court's decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. UGI Utilities has filed for reconsideration of the panel's order. UGI Utilities believes that any liability it may have for a share of the response costs at the three leased MGP sites will not have a material effect on its financial condition or results of operations.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together, the "Northeast Companies"), demanded 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. According to the letter, investigation and remediation costs at the sites to date total approximately $10,000 and complete remediation costs for all sites could total $182,000. The Northeast Companies seek an unspecified fair and equitable allocation of these costs to UGI Utilities. UGI Utilities is in the process of reviewing the information provided by Northeast Companies and is investigating this claim.
In addition to these environmental matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. 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.
9. FINANCIAL INSTRUMENTS
In accordance with its commodity hedging policy, the Company may enter into (1) natural gas call option contracts to reduce volatility in the cost of gas it purchases for its firm- residential, commercial and industrial ("retail core-market") customers and (2) electric price swap agreements to reduce the volatility in the cost of anticipated electricity requirements. We designate these contracts as cash flow or fair value hedges under SFAS 133. Because the cost of the natural gas call option contracts and any associated gains are included in our PGC recovery mechanism, as these contracts are recorded at fair value in accordance with SFAS 133, any gains are deferred for future recovery from or refund to Gas Utility's ratepayers.
We are a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts are not subject to the accounting requirements of SFAS 133, as amended, because they provide for the delivery of products or services in quantities that
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
are expected to be used in the normal course of operating our business or the value of the contract is directly associated with the price or value of a service. We enter into IRPAs in order to manage interest rate risk associated with planned issuances of fixed-rate long-term debt. We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are included in other comprehensive income and are reclassified to interest expense as the interest expense on the associated debt issue affects earnings.
During 2005, 2004 and 2003, there were no gains or losses recognized in earnings as a result of hedge ineffectiveness or as a result of excluding a portion of a derivative instrument's gain or loss from the assessment of hedge effectiveness, and there were no gains or losses recognized in earnings as a result of a hedged firm commitment no longer qualifying as a fair value hedge. At September 30, 2005, our unsettled derivative contracts included in accumulated other comprehensive income included an electric price swap agreement and two IRPAs.
Gains and losses included in accumulated other comprehensive income at September 30, 2005 relating to cash flow hedges will be reclassified into (1) interest expense when interest on hedged issuances of fixed-rate long-term debt is reflected in net income and (2) cost of sales when the forecasted purchases of electricity subject to the hedge impact net income. Included in accumulated other comprehensive income at September 30, 2005 are net after-tax losses of approximately $3,310 associated with settled IRPAs and two unsettled IRPAs associated with forecasted issuances of long-term debt anticipated to occur during the next two years. The amount of net loss on IRPAs expected to be reclassified into net income during the next twelve months is not material. Also included in accumulated other comprehensive income at September 30, 2005 is an after-tax gain of $3,553 associated with our electric price swap agreement for purchases of electricity anticipated to occur during 2007. The actual amount of gains or losses on unsettled derivative instruments that ultimately is reclassified into net income will depend upon the value of such derivative contracts when settled. The fair value of derivative instruments is included in other current assets, other assets, other current liabilities and other noncurrent liabilities in the Consolidated Balance Sheets.
The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivatives and current maturities of long-term debt) approximate their fair values because of their short-term nature.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The carrying amounts and estimated fair values of our remaining financial instruments (including unsettled derivative instruments) at September 30 are as follows:
We estimate the fair value of long-term debt by using current market prices and by discounting future cash flows using rates available for similar type debt. We estimated the fair value of our preferred shares subject to mandatory redemption based on the fair value of redeemable preferred stock with similar credit ratings and redemption features.
We have financial instruments such as trade accounts receivable which could expose us to concentrations of credit risk. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different markets. At September 30, 2005 and 2004, we had no significant concentrations of credit risk.
10. SEGMENT INFORMATION
We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Operations. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern and southeastern Pennsylvania. Electric Operations derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties.
The accounting policies of our reportable segments are the same as those described in Note 1. We evaluate the performance of our Gas Utility and Electric Operations 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.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Financial information by business segment follows:
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. OTHER INCOME, NET
Other income, net, comprises the following:
12. RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. 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, pricipally payroll related services. Amounts billed to these entities by UGI Utilities for all periods presented was not material.
Effective December 1, 2004, following a competitive bidding process, UGI Utilities entered into the Storage Agreement with Energy Services. The Storage Agreement was initially scheduled to expire on October 31, 2005, but effective November 1, 2005, UGI Utilities and Energy Services agreed to extend the Storage Agreement through October 31, 2008. Under the Storage Agreement, UGI Utilities released certain gas transportation and storage contracts through October 31, 2008 and transferred associated gas storage inventories to Energy Services. UGI Utilities may recall such released transportation and storage contracts without penalty if recalled to meet operational requirements, and if not recalled, the releases will terminate at the end of the term of the Storage Agreement. In the event that released contracts are recalled or at the expiration of the Storage Agreement Energy Services is required to transfer associated gas storage inventories to UGI Utilities. In exchange for the ability to utilize these assets, Energy Services pays a monthly fee to UGI Utilities, and Energy Services provides a firm natural gas delivery service to UGI Utilities. In accordance with the bidding process, UGI has provided UGI Utilities with performance security in the amount of $20,000. During 2005, UGI Utilities purchased natural gas storage inventories from Energy Services under the Storage Agreement totaling $64,421, and incurred associated pipeline transportation and storage capacity charges of $16,324.
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, 2005, comprising approximately 8.7 billion cubic feet of natural gas, was $63,004.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Gas Utility enters into wholesale natural gas transactions with Energy Services for purchases of winter peaking service and, from time to time, purchases of natural gas or pipeline capacity. During 2005, 2004 and 2003, the aggregate amount of these transactions (exclusive of Storage Agreement transactions) totaled $8,491, $6,257 and $4,709, respectively. In addition, from time to time the Company sells natural gas or pipeline capacity to Energy Services. During fiscal 2005, 2004 and 2003, revenues associated with these sales to Energy Services totaled $4,249, $1,698 and $4,234, respectively. These transactions did not have a material effect on the Company's net income during 2005, 2004 and 2003.
13. 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 UGI Utilities' businesses.
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Thousands of dollars)
- ---------- (1) Uncollectible accounts written off, net of recoveries.
(2) Payments, net
(3) Includes reserves for self-insured property and casualty liability, insured property and casualty liability, environmental, litigation and other.
(4) Other adjustments
S-1
EXHIBIT INDEX