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
In 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 business of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by 1953, UGI Utilities had 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 UGI Utilities 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 (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private 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.
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, Inc. 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. Utilities believes that it has good defenses to the claim and is defending the suit.
In November 2003, the court granted Utilities' motion for summary judgment in part, dismissing all claims premised on a disregard of the separate corporate form of Utilities' former subsidiaries and dismissing claims premised on Utilities' operation of three of the MGPs under operating leases with ConEd's predecessors. The court reserved decision on the remaining theory of liability, that UGI Utilities was a direct operator of the remaining MGPs.
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, 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 any response costs Citizens may be required to pay to the City of Bangor. Remedial proposals for the site range between $5 million and $50 million. Utilities is unable to estimate what portion of this potential cost may be associated with MGP wastes. Utilities believes that it has good defenses to the claim.
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. Utilities believes that it has good defenses to the claim and is defending the suit.
RELATED MATTER
UGI Utilities, Inc. v. Insurance Co. of North America, et al. On February 11, 1999, UGI Utilities, Inc. filed suit in the Court of Common Pleas of Montgomery County, Pennsylvania against more than fifty insurance companies, including Insurance Services, Ltd. (AEGIS). The complaint alleges that the defendants breached contracts of insurance by failing to indemnify Utilities for certain environmental costs. Utilities has now settled with all known solvent defendants. The suit has been stayed pending resolution of the remaining claims.
PART II: SECURITIES AND FINANCIAL INFORMATION
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
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 $33.9 million in fiscal year 2003, $37.9 million in fiscal year 2002 and $35.3 million in fiscal year 2001.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the following Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A"), Electric Utility and UGID's electricity generation business prior to its distribution to UGI in June 2003 are collectively referred to 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 2003 Compared with Fiscal 2002
bcf - billions of cubic feet. gwh - millions of kilowatt hours.
(a) Gas Utility's total margin represents total revenues less cost of sales. Electric Operation's total margin represents total revenues less cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $4.8 million and $4.6 million in Fiscal 2003 and Fiscal 2002, respectively. For financial statement purposes, 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 7.0% colder than normal during Fiscal 2003 compared to weather that was 17.4% warmer than normal during Fiscal 2002. The significantly colder weather resulted in higher heating-related sales to firm- residential, commercial and industrial ("retail core-market") customers and, to a lesser extent, greater volumes transported for residential, commercial and industrial delivery service customers. System throughput in Fiscal 2003 also benefited from a year-over-year increase in the number of customers.
Gas Utility revenues increased principally as a result of the previously mentioned greater retail core-market and delivery service volumes and higher average retail core-market purchased gas cost ("PGC") rates resulting from higher natural gas costs. Gas Utility cost of gas was $343.0 million in Fiscal 2003, an increase of $101.3 million from the prior year, reflecting the higher retail core-market volumes sold and the higher retail core-market PGC rates.
The increase in Gas Utility total margin principally reflects a $27.1 million increase in retail core-market total margin due to the higher retail core-market sales and increased margin from greater delivery service volumes.
The increase in Gas Utility operating income principally reflects the increase in total margin partially offset by a $12.7 million increase in operating and administrative expenses and lower other income. Fiscal 2003 operating and administrative expenses include higher costs associated with litigation-related costs and expenses, greater distribution system maintenance expenses, higher uncollectible accounts expenses and increased incentive compensation costs. Other income declined $3.2 million principally reflecting a $2.2 million decrease in pension income and lower interest income on PGC undercollections. The increase in Gas Utility income before income taxes reflects the increase in operating income offset by higher interest expense on PGC overcollections and, beginning July 1, 2003, dividends on preferred shares.
ELECTRIC OPERATIONS. Electric Utility's Fiscal 2003 kilowatt-hour sales increased principally as a result of weather that was 8.4% colder than normal compared to weather that was 14.5% warmer than normal in the prior year.
The higher Electric Operations revenues reflect greater Electric Utility sales and greater sales of electricity produced by UGID's electricity generation assets to third parties prior to its distribution to UGI in June 2003. Prior to September 2002, UGID sold substantially all of the electricity it produced to Electric Utility with the associated revenue and margin eliminated in our consolidated results. Beginning September 2002, Electric Utility began purchasing its power needs exclusively from third-party electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market, and UGID began selling electric power produced from its interests in electricity generating facilities to third parties on the spot market. Notwithstanding the significant increase in Electric Operations' revenues, cost of sales increased only $1.3 million in Fiscal 2003 as the impact on cost of sales resulting from the greater Electric Utility and electric generation third-party sales was partially offset by lower Electric Utility per-unit purchased power costs.
The increase in Electric Operations' total margin principally reflects lower Electric Utility per-unit purchased power costs, the increase in Electric Utility sales, and margin from the greater sales of electricity produced by UGID's electricity generation assets to third parties. The higher Fiscal 2003 operating income reflects the greater total margin and higher other income partially offset by slightly higher operating and administrative expenses. The increase in Electric Operations income before income taxes reflects the increase in operating income and slightly lower interest expense.
Fiscal 2002 Compared with Fiscal 2001
(a) Electric Operation's total margin represents total revenues less cost of sales and Electric Utility gross receipts taxes of $4.6 million and $3.4 million in Fiscal 2002 and Fiscal 2001, respectively.
GAS UTILITY.
Weather in Gas Utility's service territory during Fiscal 2002 based upon heating degree days was 17.4% warmer than normal compared to weather that was 2.0% colder than normal in Fiscal 2001. As a result of the significantly warmer weather and the effects of a weak economy on commercial and industrial natural gas usage, distribution system throughput declined 8.8%.
The $96.3 million decrease in Fiscal 2002 Gas Utility revenues reflects the impact of lower PGC rates, resulting from the pass through of lower natural gas costs to retail core-market customers, and the lower distribution system throughput. Gas Utility cost of gas was $241.7 million in Fiscal 2002 compared to $322.9 million in Fiscal 2001 reflecting lower natural gas costs and the decline in retail core-market throughput in Fiscal 2002.
The decline in Gas Utility margin principally reflects a $6.0 million decline in retail core-market margin due to the lower sales; a $6.6 million decline in interruptible margin due principally to the flowback of certain interruptible customer margin to retail core-market customers beginning December 1, 2001 pursuant to the Gas Restructuring Order; and lower firm delivery service total margin due to lower delivery service volumes. Interruptible customers are those who have the ability to switch to alternate fuels.
Gas Utility operating income declined $10.7 million in Fiscal 2002 reflecting the previously mentioned decline in total margin and a decrease in pension income partially offset by lower
operating expenses. Operating expenses declined $4.1 million primarily as a result of lower charges for uncollectible accounts and lower distribution system expenses. Depreciation expense declined $1.2 million due to a change effective April 1, 2002 in the estimated useful lives of Gas Utility's natural gas distribution assets resulting from an asset life study required by the PUC. The decline in Gas Utility income before income taxes reflects the decrease in operating income offset by lower interest expense resulting from lower levels of bank loans outstanding and lower short-term interest rates.
ELECTRIC OPERATIONS. The decline in kilowatt-hour sales in Fiscal 2002 reflects the effects on heating-related sales of significantly warmer winter weather partially offset by the beneficial effect on air conditioning sales of warmer summer weather. Notwithstanding the decrease in total kilowatt-hour sales, revenues increased $2.1 million principally due to an increase in state tax surcharge revenue and greater third-party sales of electricity produced by UGID's electric generation facilities. Electric Operations cost of sales was $48.6 million in Fiscal 2002 compared to $51.9 million in Fiscal 2001 principally reflecting the impact of the lower sales and lower purchased power unit costs partially offset by the full-period increase in cost of sales resulting from the December 2000 transfer of our Hunlock Creek electricity generation assets to our electricity generation joint venture, Energy Ventures. Subsequent to the formation of Energy Ventures, our electricity generating business purchases its share of the power produced by Energy Ventures rather than producing this electricity itself. As a result, the purchased cost of this power is reflected in cost of sales whereas prior to the formation of Energy Ventures electricity generation costs were reflected in operating and administrative expenses.
Electric Operations total margin increased $4.2 million in Fiscal 2002 as a result of lower purchased power unit costs partially offset by the weather-driven decline in sales. Operating income increased $2.5 million reflecting the greater total margin and lower operating and administrative costs subsequent to the formation of Energy Ventures partially offset by a decline in other income. The increase in Electric Operations income before income taxes reflects the increase in operating income and lower interest expense.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Utilities total debt outstanding was $258.0 million at September 30, 2003. Included in this amount is $40.7 million under revolving credit agreements.
Utilities has revolving credit commitments under which it may borrow up to a total of $107 million. These agreements are currently scheduled to expire in June 2005 and 2006. The revolving credit agreements have restrictions on such items as total debt, debt service and payments for investments. At September 30, 2003, Utilities was in compliance with these covenants. Utilities has a shelf registration statement with the U.S. Securities and Exchange Commission under which it may issue up to an additional $40 million of Medium-Term Notes or other debt securities.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations and
borrowings available under revolving credit agreements, management believes that Utilities will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2004. For a more detailed discussion of Utilities' long-term debt and credit facilities, see Note 3 to Consolidated Financial Statements.
CASH FLOWS
OPERATING ACTIVITIES. Due to the seasonal nature of 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 generally at their lowest levels during the first and fourth quarters when the Company's investment in working capital, principally accounts receivable and inventories, is generally greatest. Utilities uses its revolving credit agreements to satisfy its seasonal operating cash flow needs. Cash flow from operating activities was $97.8 million in Fiscal 2003, $55.1 million in Fiscal 2002, and $76.1 million in Fiscal 2001. Cash flow from operating activities before changes in operating working capital was $91.8 million in Fiscal 2003, $78.4 million in Fiscal 2002, and $72.3 million in Fiscal 2001. Changes in operating working capital provided $6.0 million of operating cash flow in Fiscal 2003, used $23.3 million of operating cash flow in Fiscal 2002, and provided $3.8 million of operating cash flow in Fiscal 2001. The increase in Fiscal 2003 cash flow from operating activities principally reflects the increased operating results and greater cash flow from changes in Gas Utility deferred fuel overcollections and accrued income taxes partially offset by higher inventories resulting from greater natural gas prices.
INVESTING ACTIVITIES. Cash flow used in investing activities was $43.1 million in Fiscal 2003, $36.6 million in Fiscal 2002, and $44.2 million in Fiscal 2001. Expenditures for property, plant and equipment were $41.3 million in Fiscal 2003, $35.9 million in Fiscal 2002, and $36.8 million in Fiscal 2001. The higher Fiscal 2003 level of capital expenditures reflects greater Gas Utility distribution system capital expenditures. Net costs of property, plant and equipment disposals were also higher in Fiscal 2003 principally reflecting greater gas main replacement activity.
FINANCING ACTIVITIES. Cash flow used by financing activities was $60.5 million in Fiscal 2003, $20.1 million in Fiscal 2002, and $39.8 million in Fiscal 2001. Financing activity cash flow changes are primarily due to issuances and repayments of long-term debt, net borrowings under revolving credit facilities, dividends on preferred shares subject to mandatory redemption and dividends to, and capital contributions from, UGI.
In October 2002, Utilities repaid $26 million of maturing long-term debt. In August 2003, Utilities issued $25 million face amount of ten-year notes at an interest rate of 5.37% and $20 million face amount of 30-year notes at an interest rate of 6.50% under its Medium-Term Note program. The net proceeds from these issuances along with existing cash balances were used to repay $50 million of 6.50% Senior Notes maturing in August 2003.
During Fiscal 2003 we paid cash dividends to UGI of $33.9 million and dividends on our preferred shares subject to mandatory redemption of $1.6 million of which $0.4 million has been classified as
interest expense in accordance with Statement of Financial Accounting Standards ("SFAS") No. 150 (see "Recently Issued Accounting Pronouncements" below).
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) has been eliminated from the consolidated balance sheet. The results of operations of UGID and its subsidiaries through the date of distribution did not have a material effect on the Company's net income in Fiscal 2003, 2002 or 2001.
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. During Fiscal 2002 and 2001, the market value of plan assets was negatively affected by declines in the equity markets. Equity market performance improved in Fiscal 2003 and, as a result, the fair value of Pension Plan assets increased to $183.8 million at September 30, 2003 compared to $166.1 million at September 30, 2002. At September 30, 2003 and 2002, the Pension Plan's assets exceeded its accumulated benefit obligations by $7.3 million and $7.2 million, respectively. The Company is in full compliance with regulations governing defined benefit pension plans, including ERISA rules and regulations, and does not anticipate it will be required to make a contribution to the Pension Plan in Fiscal 2004. Pre-tax pension income reflected in Fiscal 2003, 2002 and 2001 results was $1.2 million, $3.9 million and $5.7 million, respectively. The decrease in pension income during this period reflects the significant declines in the market value of Plan assets and decreases in the discount rate assumptions. Pension expense in Fiscal 2004 is expected to be approximately $1.1 million, compared to pension income of $1.2 million in Fiscal 2003 due to decreases in the discount rate and expected return on Pension Plan assets assumptions.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business segment for Fiscal 2003, Fiscal 2002 and Fiscal 2001. We also provide amounts we expect to spend in Fiscal 2004. We expect to finance a substantial portion of Fiscal 2004 capital expenditures from cash generated by operations and the remainder from borrowings under our credit facilities.
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
Utilities has certain contractual cash obligations that extend beyond Fiscal 2003 including scheduled repayments of long-term debt and redeemable preferred stock, operating lease obligations and unconditional purchase obligations for pipeline capacity, 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, 2003 (in millions).
RELATED PARTY TRANSACTIONS
UGI provides administrative and general support to UGI Utilities. UGI bills UGI Utilities monthly for an allocated share of its general corporate expenses. This allocation is based upon a three-factor formula which includes revenues, costs and expenses, and net assets. These billed expenses totaled $9.4 million in Fiscal 2003, $6.7 million in Fiscal 2002 and $5.3 million in Fiscal 2001 and are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income.
In accordance with the terms of an Affiliated Interest Agreement ("Affiliated Agreement") approved by the PUC, Gas Utility enters into wholesale natural gas transactions with Energy Services, Inc. ("Energy Services"), a wholly owned second-tier subsidiary of UGI, for winter storage service and, from time to time, purchases of natural gas. In addition, from time to time, the Company sells natural gas to Energy Services pursuant to the terms of the Affiliated Agreement. These transactions did not have a material effect on the Company's net income during Fiscal 2003, 2002 and 2001. For additional information on these transactions, see Note 13 to Consolidated Financial Statements included elsewhere in this Form 10-K.
OFF-BALANCE SHEET ARRANGEMENTS
We lease various buildings and other facilities, transportation, computer and office equipment. We account for these arrangements as operating leases. These off-balance sheet arrangements enable us to lease facilities and equipment from third parties rather than, among other options, purchasing the equipment and facilities using on-balance sheet financing. For a summary of
scheduled future payments under these lease arrangements, see "Contractual Cash Obligations and Commitments."
REGULATORY MATTERS
As a result of Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act") signed into law on June 22, 1999, all natural gas consumers in Pennsylvania have the ability to purchase their gas supplies from the supplier of their choice. Under the Gas Competition Act, local gas distribution companies ("LDCs") like Gas Utility may continue to sell gas to customers, and such sales of gas, as well as distribution services provided by LDCs, continue to be subject to rate regulation by the PUC. LDCs serve as the supplier of last resort for all residential and small commercial and industrial customers. As of September 30, 2003, less than five percent of Gas Utility's retail customers purchase their gas from alternative suppliers.
On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving Gas Utility's restructuring plan filed by Gas Utility pursuant to the Gas Competition Act. Among other things, the implementation of the Gas Restructuring Order resulted in an increase in Gas Utility's retail core-market base rates effective October 1, 2000. This base rate increase was designed to generate approximately $16.7 million in additional net annual revenues. In accordance with the Gas Restructuring Order, Gas Utility reduced its retail core-market PGC rates by an annualized amount of $16.7 million in the first 14 months following the October 1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its retail core-market PGC rates by amounts equal to the margin it receives from interruptible customers using pipeline capacity contracted by Gas Utility for retail core-market customers. As a result, Gas Utility operating results are more sensitive to the effects of heating-season weather and less sensitive to the market prices of alternative fuels.
The PUC approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002, and a separate settlement that modified these rules on June 13, 2002 (collectively, the "POLR Settlement"). Under the terms of the POLR Settlement, Electric Utility terminated stranded cost recovery through its CTC from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and is no longer subject to the statutory generation rate caps as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Stranded costs are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Charges for generation service (1) were initially set at a level equal to the rates paid by Electric Utility customers for POLR service under the statutory rate caps; (2) may be raised by up to 5% of the total rate for distribution, transmission and generation through December 2004; and (3) may be set at market rates thereafter. Electric Utility may also offer multiple-year POLR contracts to its customers. The POLR Settlement provides 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 at a time other than during the annual shopping period must remain on POLR service until the date of the second open shopping period after returning. C&I customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. Consistent with the terms of the POLR Settlement, Electric Utility's POLR rates for commercial and industrial customers will increase beginning January 2004, and for residential customers beginning June 2004. Also, Electric Utility has offered and entered into multiple-year POLR contracts with certain of its customers. Additionally, pursuant to the requirements of the Electricity Choice Act, the PUC is currently developing post-rate cap POLR regulations that are expected to further define post-rate cap POLR service obligations and pricing. As of September 30, 2003, less than 1% of Electric Utility's customers have chosen an alternative electricity generation supplier.
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 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.
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, 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, Utilities divested all of its utility operations other than those which now constitute Gas Utility and Electric Utility.
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. Utilities has been notified of several sites outside Pennsylvania on which (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private 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.
Management believes that under applicable law 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 Utilities directly owned or operated, or that were owned or operated by former subsidiaries of Utilities, if a court were to conclude that (1) the subsidiary's separate corporate form should be disregarded or (2) Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary's MGP.
With respect to a manufactured gas plant site in Manchester, New Hampshire, EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit against UGI Utilities seeking contribution from UGI Utilities for response and remediation costs associated with the contamination on the site of a former MGP allegedly operated by former subsidiaries of UGI Utilities. UGI Utilities and EnergyNorth agreed to a settlement of this matter in June 2003. UGI Utilities recorded its estimated liability for contingent payments to EnergyNorth under the terms of the settlement agreement which did not have a material effect on Fiscal 2003 net income.
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. The City believes that it could cost as much as $50 million to clean up the river. UGI Utilities believes that it has good defenses to the claim.
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 $8.0 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. UGI Utilities believes that it has good defenses to the claim and is defending the suit.
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. UGI Utilities believes that it has good defenses to the claim and is defending the suit. In November 2003, the court granted UGI Utilities' motion for summary judgment in part, dismissing all claims premised on a disregard of the separate corporate form of UGI Utilities' former subsidiaries and dismissing claims premised on UGI Utilities' operation of three of the MGPs under operating leases with
ConEd's predecessors. The court reserved decision on the remaining theory of liability, that UGI Utilities was a direct operator of the remaining MGPs.
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 a periodic adjustment 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 associated gains, is included in Gas Utility's PGC recovery mechanism.
Prior to September 2002, Electric Utility purchased all of its electric power needs, in excess of the electric power it obtained from its interests in electric generating facilities, under third-party power supply arrangements of various lengths and on the spot market. Beginning September 2002, Electric Utility began purchasing its power needs exclusively from third-party electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market and UGID, through the date of its transfer to UGI in June 2003, began selling electric power produced from its interests in electricity generating facilities to third parties on the spot market. Prices for electricity can be volatile especially during periods of high demand or tight supply. Although the generation component of Electric Utility's rates is subject to various rate cap provisions as a result of the POLR Settlement, Electric Utility's fixed-price contracts with electricity suppliers mitigate most risks associated with offering customers a fixed price during the contract periods. However, should any of the suppliers under these contracts fail to provide electric power under the terms of the power and capacity contracts, increases, if any, in the cost of replacement power or capacity would 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.
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 borrowings under our revolving credit agreements. These agreements provide for interest rates on borrowings that are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements in Fiscal 2003 and Fiscal 2002, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.3 million and $0.5 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 $14.0 million and $11.0 million at September 30, 2003 and 2002, respectively. A 100 basis point
decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $15.7 million and $12.0 million at September 30, 2003 and 2002, 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 agreement, which has been designated and qualifies as a cash flow hedge, was $0.4 million at September 30, 2003. An adverse change in interest rates on ten-year U.S. treasury notes of 50 basis points would result in a $0.4 million decrease in the fair value of this interest rate protection agreement.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance with generally accepted accounting principles 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 its 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.
REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility's distribution businesses are subject to regulation by the Pennsylvania Public Utility Commission. 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. As of September 30, 2003, our regulatory assets totaled $60.3 million.
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 and a commingled bond fund. Changes in plan assumptions as well as fluctuations in actual equity or bond market returns could have a material impact on future pension costs.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS 149 (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (2) clarifies when a derivative contains a financing component, (3) amends the definition of an underlying- rate, price or index to conform it to language used in FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and (4) amends certain other existing pronouncements. SFAS 149 did not change the methods the Company uses to account for and report its derivatives and hedging activities.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" ("SFAS 150"). SFAS 150 is effective at the beginning of the first interim period beginning after June 15, 2003. SFAS 150 establishes guidelines on how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 further defines and requires that certain instruments within its scope be classified as liabilities on the financial statements. The adoption of SFAS 150 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. Because SFAS 150 specifically prohibits the restatement of financial statements prior to its adoption, prior period amounts have not been reclassified.
In January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"), which clarifies Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 is effective immediately for variable interest
entities created or obtained after January 31, 2003. For variable interests created or acquired before February 1, 2003, FIN 46 is effective for the first fiscal or interim period beginning after December 15, 2003. If certain conditions are met, FIN 46 requires the primary beneficiary to consolidate certain variable interest entities in which the other equity investors lack the essential characteristics of a controlling financial interest or their investment at risk is not sufficient to permit the variable interest entity to finance its activities without additional subordinated financial support from other parties. The adoption of FIN 46 is not expected to impact the Company's financial position or results of operations.
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 and improvements in energy efficiency and technology resulting in reduced demand; (7) adverse labor relations; (8) large customer, counterparty or supplier defaults; (9) 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; (10) political, regulatory and economic conditions in the United States; and (11) interest rate fluctuations and other capital market conditions.
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 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 set forth on pages to and page S-1 of this Report are incorporated herein by reference.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
During fiscal year 2002, the Company engaged a new independent auditor, PricewaterhouseCoopers LLP. The information required by Item 9 is incorporated in this Report by reference to the Company's Current Report on Form 8-K dated May 21, 2002.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
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 recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The Company believes that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.
(b) Change in Internal Control over Financial Reporting
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.
PART III: INTENTIONALLY OMITTED
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(A) DOCUMENTS FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS:
Included under Item 8 are the following financial statements and supplementary data:
Reports of Independent Public Accountants
Consolidated Balance Sheets as of September 30, 2003 and 2002
Consolidated Statements of Income for the fiscal years ended September 30, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2003, 2002 and 2001
Consolidated Statements of Stockholders' Equity for the fiscal years ended September 30, 2003, 2002 and 2001
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULE:
For the years ended September 30, 2003, 2002 and 2001
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.
NOTICE REGARDING ARTHUR ANDERSEN LLP
Arthur Andersen LLP audited our consolidated financial statements for the three years in the period ended September 30, 2001 and issued a report thereon dated November 16, 2001. Arthur Andersen LLP has not reissued its report or consented to the incorporation by reference of such report into the Company's prospectuses relating to offering and sale of our debt
securities. On June 15, 2002, Arthur Andersen LLP was convicted of obstruction of justice by a federal jury in Houston, Texas in connection with Arthur Andersen LLP's work for Enron Corp. On September 15, 2002, a federal judge upheld this conviction. Arthur Andersen LLP ceased its audit practice before the SEC on August 31, 2002. Effective May 21, 2002, we terminated the engagement of Arthur Andersen LLP as our independent accountants and engaged PricewaterhouseCoopers LLP to serve as our independent accountants for the fiscal year ending September 30, 2002. Because of the circumstances currently affecting Arthur Andersen LLP, as a practical matter it may not be able to satisfy any claims arising from the provision of auditing services to us, including claims available to security holders under federal and state securities laws.
(4) LIST OF EXHIBITS:
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
INCORPORATION BY REFERENCE
INCORPORATION BY REFERENCE
INCORPORATION BY REFERENCE
INCORPORATION BY REFERENCE
INCORPORATION BY REFERENCE
* Filed herewith.
** As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.
(b) REPORTS ON FORM 8-K:
The Company furnished information in a Current Report on Form 8-K during the fourth quarter of fiscal year 2003 as follows:
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 16, 2003 By: John C. Barney -------------------------------- John C. Barney Senior Vice President - Finance
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 16, 2003 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 16, 2003 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 2003.
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2003
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 AUDITORS
To the Board of Directors and Stockholder of UGI Utilities, Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15a (1) and (2) present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2003 and 2002, and the results of their operations and their cash flows for each of the two years in the period ended September 30, 2003 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 15a (1) and (2) present 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 auditing standards generally accepted in the United States of America, which require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit 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. The consolidated financial statements of UGI Utilities, Inc. and its subsidiaries as of and for the year ended September 30, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated November 16, 2001.
PricewaterhouseCoopers LLP Philadelphia, Pennsylvania November 17, 2003
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ACCOUNTANT'S REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholder of UGI Utilities, Inc.:
We have audited the accompanying consolidated balance sheets of UGI Utilities, Inc. and subsidiaries as of September 30, 2001 and 2000, and the related consolidated statements of income, cash flows and stockholder's equity for each of the three years in the period ended September 30, 2001. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of UGI Utilities, Inc. and subsidiaries as of September 30, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2001 in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the Index to Financial Statements and Financial Statement Schedule is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Philadelphia, Pennsylvania November 16, 2001
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; owns and operates an electricity distribution utility ("Electric Utility") in northeastern Pennsylvania; and prior to the June 2003 distribution to UGI of UGI Development Company ("UGID") and UGID's subsidiaries and 50%-owned joint-venture affiliate Hunlock Creek Energy Ventures ("Energy Ventures"), owned interests in Pennsylvania-based electricity generation assets through UGID. 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 collectively as "Electric Operations." Our consolidated financial statements include the accounts of UGI Utilities and its majority-owned subsidiaries. We eliminate all significant intercompany accounts and transactions when we consolidate. Our 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.
In June 2003, the Company dividended all of the common stock of UGID and its subsidiaries to UGI. The net book value of the assets and liabilities of UGID and its subsidiaries totaling $15,407 (including $2,572 of cash) was eliminated from the consolidated balance sheet and reflected as a dividend from retained earnings. UGID and its subsidiaries' results of operations did not have a material effect on the Company's results of operations in 2003, 2002 and 2001.
RECLASSIFICATIONS
We have reclassified certain prior-year balances to conform to the current-year presentation.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States. 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. Certain expenses and credits subject to utility regulation and normally reflected in income as incurred are deferred on the balance sheet and recognized in income as the related amounts are included in rates and recovered from or refunded to customers. As required
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the provisions of the Gas Restructuring Order and the Gas Competition Act, we believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS 71. For further information on the impact of the Gas Competition Act and Pennsylvania's Electricity Customer Choice Act ("Electricity Choice Act"), 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 $16,046 in 2003, $16,348 in 2002 and $17,543 in 2001. We paid income taxes totaling $29,372 in 2003, $36,282 in 2002 and $29,000 in 2001.
REVENUE RECOGNITION
Gas Utility and Electric Utility 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
Gas Utility and Electric Utility 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. They also record a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities' plant additions over the service lives of the related property. Utilities 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
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
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 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 2.3% in 2003, 2.5% in 2002 and 2.6% in 2001. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 3.0% in each of 2003 and 2002 and 3.3% in 2001. The declines in the Gas Utility and Electric Utility percentages for 2003 and 2002 are the result of changes, effective April 1, 2002, in the estimated remaining useful lives of Gas Utility's and Electric Utility's distribution assets. Depreciation expense was $20,754 in 2003, $21,649 in 2002 and $22,701 in 2001.
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 ten 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.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION
Beginning July 1, 2003, the Company accounts 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 results 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. Because SFAS 150 specifically prohibits the restatement of financial statements prior to its adoption, prior period amounts have not been reclassified.
ENVIRONMENTAL LIABILITIES
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. 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, 2003, the Company's liability for environmental investigation and cleanup costs was not material.
DERIVATIVE INSTRUMENTS
Effective October 1, 2000, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). 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.
During 2003 and 2002, in order to manage interest rate risk associated with forecasted issuances of fixed-rate long-term debt, we entered into interest rate protection agreements ("IRPAs") which have been designated and qualify as cash flow hedges in accordance with SFAS 133. Included in accumulated other comprehensive loss at September 30, 2003 and 2002 are net after-tax losses of $2,049 and $2,774, respectively, associated with settled and unsettled IRPAs. The amount of the net loss at September 30, 2003 expected to be reclassified into net income during the next twelve months is not material. The fair values of our unsettled IRPAs were a gain of $369 at September 30, 2003 and a loss of $1,205 at September 30, 2002. These amounts are included in other assets and other current liabilities, respectively, on the Consolidated Balance Sheets. The unsettled IRPA at September 30, 2003 hedges interest rate risk associated with forecasted issuances of debt to occur during Fiscal 2005.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
During 2003 and 2002, Gas Utility entered into 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. Because net gains or losses associated with these contracts will be included in our PGC recovery mechanism, as these contracts are recorded at fair value in accordance with SFAS 133, any gains or losses are deferred for future recovery from or refund to Gas Utility's ratepayers.
During 2001, we used a managed program of natural gas and oil futures contracts to preserve gross margin associated with certain of our natural gas customers. These contracts were designated as cash flow hedges. During 2001, the amount of cash flow hedge gains associated with these contracts that were reclassified to earnings because it became probable that the original forecasted transactions would not occur was $1,034 which amount is included in other income.
During 2003, 2002 and 2001, there were no gains or losses recognized in earnings as a result of hedge ineffectiveness or from 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.
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 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.
COMPREHENSIVE INCOME
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) of $725 and $(2,774) for the years ended September 30, 2003 and 2002, respectively, is the result of gains or losses on IRPAs qualifying as cash flow hedges, net of reclassifications to net income. The Company's comprehensive income was the same as net income for the year ended September 30, 2001.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. SFAS 149 (i) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (ii) clarifies when a derivative contains a financing component, (iii) amends the definition of an underlying- rate, price or index to conform it to language used in FASB Interpretation No. 45,
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and (iv) amends certain other existing pronouncements. SFAS 149 did not change the methods the Company uses to account for and report its derivatives and hedging activities.
In January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"), which clarifies Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 is effective immediately for variable interest entities created or obtained after January 31, 2003. For variable interests created or acquired before February 1, 2003, FIN 46 is effective for the first fiscal or interim period beginning after December 15, 2003. If certain conditions are met, FIN 46 requires the primary beneficiary to consolidate certain variable interest entities in which the other equity investors lack the essential characteristics of a controlling financial interest or their investment at risk is not sufficient to permit the variable interest entity to finance its activities without additional subordinated financial support from other parties. The adoption of FIN 46 is not expected to impact the Company's financial position or results of operations.
2. UTILITY REGULATORY MATTERS
Gas Utility
Gas Restructuring Order. On June 29, 2000, the PUC issued the Gas Restructuring Order approving Gas Utility's restructuring plan filed by Gas Utility pursuant to the Gas Competition Act. The purpose of the Gas Competition Act, which was signed into law on June 22, 1999, is to provide all natural gas consumers in Pennsylvania with the ability to purchase their gas supplies from the supplier of their choice. Under the Gas Competition Act, local gas distribution companies ("LDCs") like Gas Utility may continue to sell gas to customers, and such sales of gas, as well as distribution services provided by LDCs, continue to be subject to price regulation by the PUC. LDCs serve as the supplier of last resort for all residential and small commercial and industrial customers.
Among other things, the implementation of the Gas Restructuring Order resulted in an increase in Gas Utility's retail core-market base rates effective October 1, 2000. This base rate increase was designed to generate approximately $16,700 in additional net annual revenues. In accordance with the Gas Restructuring Order, Gas Utility reduced its retail core-market PGC rates by an annualized amount of $16,700 in the first 14 months following the October 1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its retail core-market PGC rates by amounts equal to the margin it receives from interruptible customers using pipeline capacity contracted by Gas Utility for retail core-market customers. As a result, Gas Utility operating results are more sensitive to the effects of heating-season weather and less sensitive to the market prices of alternative fuels.
Transfer of Assets. On May 24, 2001, the PUC approved Gas Utility's application for approval to transfer its liquefied natural gas ("LNG") and propane air ("LP") facilities, along with related assets, to an unregulated affiliate, Energy Services, Inc. ("Energy Services"), a second-tier wholly
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
owned subsidiary of UGI. Gas Utility transferred the LNG and LP assets, which had a net book value of $4,277, on September 30, 2001. The transfer is reflected as a dividend of net assets in the 2001 Consolidated Statement of Stockholder's Equity. The associated reduction in Gas Utility's base rates, adjusted for the impact of the transfer on net operating expenses, did not have a material effect on our results of operations.
Electric Utility
Electric Utility Restructuring Order. On June 19, 1998, the PUC entered its Opinion and Order ("Electricity Restructuring Order") in Electric Utility's restructuring proceeding pursuant to the Electricity Choice Act. Under the terms of the Electricity Restructuring Order, Electric Utility was authorized to recover $32,500 in stranded costs over a four-year period beginning January 1, 1999 through a Competitive Transition Charge ("CTC") together with carrying charges on unrecovered balances of 7.94% and to charge unbundled rates for generation, transmission and distribution services. Stranded costs are electric generation-related costs that traditionally would be recoverable in a regulated environment but may not be recoverable in a competitive electric generation market. Under the terms of the Electricity Restructuring Order and in accordance with the Electricity Choice Act, Electric Utility generally could not increase the generation component of prices during the period that stranded costs were being recovered through the CTC. Since January 1, 1999, all of Electric Utility's customers have been permitted to choose an alternative generation supplier.
The PUC approved a settlement establishing rules for Electric Utility Provider of Last Resort ("POLR") service on March 28, 2002, and a separate settlement that modified these rules on June 13, 2002 (collectively, the "POLR Settlement") under which Electric Utility terminated stranded cost recovery through its CTC from commercial and industrial ("C&I") customers on July 31, 2002, and from residential customers on October 31, 2002, and is no longer subject to the statutory generation rate caps as of August 1, 2002 for C&I customers and as of November 1, 2002 for residential customers. Charges for generation service (1) were initially set at a level equal to the rates paid by Electric Utility customers for POLR service under the statutory rate caps; (2) may be raised at certain designated times by up to 5% of the total rate for distribution, transmission and generation through December 2004; and (3) may be set at market rates thereafter. Electric Utility may also offer multiple-year POLR contracts to its customers. The POLR Settlement provides 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 at a time other than during the annual shopping period must remain on POLR service until the date of the second open shopping period after returning. C&I customers who return to POLR service at a time other than during the annual shopping period must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. Consistent with the terms of the POLR Settlement, Electric Utility's POLR rates for commercial and industrial customers will increase beginning January 2004, and for residential customers beginning June 2004. Also, Electric Utility has offered and entered into multiple-year POLR contracts with certain of its customers. Additionally, pursuant to the requirements of the Electricity Choice Act, the PUC is currently developing post-rate cap POLR regulations that are expected to further define post-rate cap POLR service obligations and pricing. As of September 30, 2003, less than
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1% of Electric Utility's customers have chosen an alternative electricity generation supplier.
Formation of Hunlock Creek Energy Ventures. On December 8, 2000, UGID contributed its coal-fired Hunlock Creek generating station ("Hunlock") and certain related assets having a net book value of $4,214, and $6,000 in cash, to Energy Ventures, a general partnership jointly owned by a subsidiary of UGID and a subsidiary of Allegheny Energy, Inc. ("Allegheny"). The contribution was recorded at its carrying value and no gain was recognized by the Company. Also on December 8, 2000, Allegheny contributed a newly constructed, gas-fired combustion turbine generator to Energy Ventures to be operated at the Hunlock site. Under the terms of our arrangement with Allegheny, each partner is entitled to purchase 50% of the output of the joint venture at cost. Total purchases from Energy Ventures in 2003 (prior to its June 2003 distribution to UGI), 2002 and 2001 were $6,360, $9,751 and $7,966, respectively.
Regulatory Assets and Liabilities
The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
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.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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: 2004 - $0; 2005 - $20,000; 2006 - - $50,000; 2007 - $20,000; 2008 - $0.
At September 30, 2003, UGI Utilities had revolving credit agreements with five banks providing for borrowings of up to $107,000. These agreements are currently scheduled to expire in June 2005 and 2006. 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 $40,700 at September 30, 2003 and $37,200 at September 30, 2002 which we classify as bank loans. The weighted-average interest rates on bank loans were 1.63% at September 30, 2003 and 2.35% at September 30, 2002.
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, 2003, 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:
Deferred tax liabilities (assets) comprise the following at September 30:
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
UGI Utilities had recorded deferred tax liabilities of approximately $37,029 as of September 30, 2003 and $35,498 as of September 30, 2002 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 $3,314 at September 30, 2003 and $3,479 at September 30, 2002, pertaining to utility deferred investment tax credits. UGI Utilities had recorded regulatory income tax assets related to these net deferred taxes of $57,625 at September 30, 2003 and $54,727 as of September 30, 2002. 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 a limited number of active employees meeting certain age and service requirements, 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 income is determined using assumptions as of the beginning of each year. Funded status is determined using assumptions as of the end of each year.
Included in the end of year pension benefit obligations above are $15,528 at September 30, 2003 and $13,955 at September 30, 2002 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year postretirement obligations above are $658 at September 30, 2003 and $649 at September 30, 2002 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 and other postretirement benefit costs relating to UGI Utilities employees include the following components:
UGI Utilities Pension Plan assets are held in trust and consist principally of equity and fixed income mutual funds and a commingled bond fund. UGI Common Stock comprised approximately 7% of trust assets at September 30, 2003. Although the UGI Utilities Pension Plan projected benefit obligations exceeded plan assets at September 30, 2003 and 2002, plan assets exceeded accumulated benefit obligations by $7,346 and $7,154, respectively.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employees' Beneficiary Association ("VEBA") trust to pay retiree health care and life insurance benefits and to fund the UGI Utilities' postretirement benefit liability. UGI Utilities is required to fund its postretirement benefit obligations 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." The difference between such amounts and amounts included in UGI Utilities' rates is deferred for future recovery from, or refund to, ratepayers. VEBA investments consist principally of equity and fixed income mutual funds.
The assumed health care cost trend rates are 11.0% for fiscal 2004, decreasing to 5.5% in fiscal 2010. A one percentage point change in the assumed health care cost trend rate would change the 2003 postretirement benefit cost and obligation as follows:
We also sponsor unfunded retirement benefit plans for certain key employees. At September 30, 2003 and 2002, the projected benefit obligations of these plans were $3,469 and $2,816, respectively. We recorded expense for these plans of $353 in 2003, $269 in 2002 and $235 in 2001.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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' contributions. The cost of benefits under the savings plans totaled $968 in 2003, $932 in 2002 and $936 in 2001.
6. INVENTORIES
Inventories comprise the following at September 30:
7. SERIES PREFERRED STOCK
The Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, has 2,000,000 shares authorized for issuance. The holders of shares of Series Preferred Stock have the right to elect a majority of the Board of Directors (without cumulative voting) if dividend payments on any series are in arrears in an amount equal to four quarterly dividends. This election right continues until the arrearage has been cured. We have paid cash dividends at the specified annual rates on all outstanding Series Preferred Stock.
At September 30, 2003 and 2002, we had outstanding 200,000 shares of $7.75 Series cumulative preferred stock. We are required to establish a sinking fund to redeem on October 1 in each year, commencing October 1, 2004, 10,000 shares of our $7.75 Series at a price of $100 per share. The $7.75 Series is redeemable, in whole or in part, at our option on or after October 1, 2004, at a price of $100 per share. All outstanding shares of $7.75 Series are subject to mandatory redemption on October 1, 2009, at a price of $100 per share.
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 $4,303 in 2003, $4,690 in 2002 and $4,624 in 2001.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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: 2004 - $2,890; 2005 - $2,420; 2006 - $2,115; 2007 - $1,754; 2008 - $1,024; after 2008 - $3,203.
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 storage capacity which Gas Utility may terminate at various dates through 2016. Gas Utility's costs associated with transportation and storage capacity 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 2008.
Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2003 are as follows: 2004 - $157,050; 2005 - $87,850; 2006 - $48,156; 2007 - $25,074; 2008 - $14,714; after 2008 - $73,997.
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 (1) MGPs were formerly operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or private parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that (1) the subsidiary's separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary's MGP.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
With respect to a manufactured gas plant site in Manchester, New Hampshire, EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit against UGI Utilities seeking contribution from UGI Utilities for response and remediation costs associated with the contamination on the site of a former MGP allegedly operated by former subsidiaries of UGI Utilities. UGI Utilities and EnergyNorth agreed to a settlement of this matter in June 2003. UGI Utilities recorded its estimated liability for contingent payments to EnergyNorth under the terms of the settlement agreement.
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. The City believes that it could cost as much as $50,000 to clean up the river. UGI Utilities believes that it has good defenses to the claim.
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. UGI Utilities believes that it has good defenses to the claim and is defending the suit.
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. UGI Utilities believes that it has good defenses to the claim and is defending the suit. In November 2003, the court granted UGI Utilities' motion for summary judgment in part, dismissing all claims premised on a disregard of the separate corporate form of UGI Utilities' former subsidiaries and dismissing claims premised on UGI Utilities' operation of three of the MGPs under operating leases with ConEd's predecessors. The court reserved decision on the remaining theory of liability, that UGI Utilities was a direct operator of the remaining MGPs.
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. 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
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
developments with respect to these matters and the amounts of future operating results and cash flows.
9. FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments included in current assets and current liabilities (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. The estimated fair value of our long-term debt is approximately $233,000 at September 30, 2003 and $263,000 at September 30, 2002. 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. The estimated fair value of our Series Preferred Stock is approximately $20,900 at September 30, 2003 and $20,400 at September 30, 2002. We estimated the fair value of our Series Preferred Stock 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, 2003 and 2002, we had no significant concentrations of credit risk.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. Financial information by business segment follows:
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UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. 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.
12. OTHER INCOME, NET
Other income, net, comprises the following:
13. RELATED PARTY TRANSACTIONS
UGI provides administrative and general support to UGI Utilities. UGI bills UGI Utilities monthly for an allocated share of its general corporate expenses. This allocation is based upon a three-factor formula which includes revenues, costs and expenses, and net assets. These billed expenses are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income.
In accordance with the terms of an Affiliated Interest Agreement ("Affiliated Agreement") approved by the PUC, Gas Utility enters into wholesale natural gas transactions with Energy Services, Inc. ("Energy Services"), a wholly owned second-tier subsidiary of UGI, for winter storage service and, from time to time, purchases of natural gas. During 2003 and 2002, the aggregate amount of these transactions totaled $4,709 and $2,614, respectively. Such amounts were not material in 2001. In addition, from time to time, the Company sells natural gas to Energy Services pursuant to the terms of the Affiliated Agreement. During 2003, 2002 and 2001, revenues associated with these sales to Energy Services totaled $4,234, $17,379 and $10,976, respectively. These transactions did not have a material effect on the Company's net income during 2003, 2002 and 2001.
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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