ITEM 3. LEGAL PROCEEDINGS
With the exception of the matters set forth below, no material legal proceedings are pending involving Utilities, any of its subsidiaries or any of their properties, and no such proceedings are known to be contemplated by governmental authorities.
ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
Prior to the general availability of natural gas, in the 1800s through the mid-1900s, manufactured gas was a chief source of gas for lighting and heating nationwide. The process involved heating certain combustibles such as coal, oil and coke in a low-oxygen atmosphere. Methods of production included coal carbonization, carbureted water gas and catalytic cracking. These methods were employed at many different sites throughout the country. The residue from gas manufacturing, including coal tar, was typically stored on site, burned in the gas plant, or sold for commercial use. Some constituents of coal tars produced from the manufactured gas process are today considered hazardous substances under the Superfund Law.
The gas distribution business has been one of Utilities' principal lines of business since its inception in 1882. One of the ways Utilities initially expanded its business in its early years was by entering into agreements with other gas companies to operate their businesses. After 1888, the principal means by which Utilities expanded its gas business was to acquire all or a portion of the stock of companies engaged in this business. Utilities also provided management and administrative services to some of these companies. Utilities grew rapidly by means of stock acquisitions and became one of the largest public utility holding companies in the country. 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 the Gas Utility and the Electric Utility.
The manufactured gas process was once used by Utilities in connection with providing gas service to its customers. In addition, virtually all of the gas companies that Utilities operated or to which it provided services, or in which Utilities held stock, utilized a manufactured gas process. Utilities has been notified of several sites outside Pennsylvania on which (i) gas plants were formerly operated by it or owned or operated by its former subsidiaries and (ii) either environmental agencies or private parties are investigating the extent of environmental
contamination and the necessity of environmental remediation. Utilities is currently litigating a claim against it relating to an out-of-state site. If Utilities were found liable as a "responsible party" as defined in the Superfund Law (or comparable state statutes) with respect to this site, it would have joint and several liability with other responsible parties for the full amount of the cleanup costs. A "responsible party" under that statute includes (i) the current owner of the affected property and (ii) each owner or operator of a facility during the time when hazardous substances were released on the property.
Management believes that Utilities should not have significant liability in those instances in which a former subsidiary operated a manufactured gas plant because Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage caused by a subsidiary company when the parent company either (i) itself operated the facility causing the environmental damage or (ii) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by manufactured gas plants that Utilities owned or directly operated, or that were owned or operated by former subsidiaries of Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded.
Utilities believes that there are approximately 40 manufactured gas plant sites in Pennsylvania where either (i) Utilities formerly operated the plant or (ii) Utilities owns or at one time owned the site. Most of the sites are no longer owned by Utilities and the gas plants formerly operated at these 40 sites have all been out of operation since at least the early 1950s. Utilities or other parties are currently conducting investigative or remedial activities at nine of the 40 sites. Based on the 1995 settlement agreement with the PUC relating to Gas Utilities' 1995 base rate increase filing, rate relief will be permitted for certain remediation expenditures on environmentally contaminated sites located in Pennsylvania. Because of this, Utilities does not expect its costs for Pennsylvania sites to be material to its results of operations.
The following is a short description of the status of certain matters involving Utilities related to manufactured gas plants located in other states. See also Notes 1 and 8 to the Company's Consolidated Financial Statements.
OUT OF STATE GAS PLANT SITES
1. Halladay Street, Jersey City, New Jersey. By letter dated April 12, 1993, Public Service Electric and Gas Company ("PSE&G") informed Utilities that PSE&G had been named as a defendant in a civil action pending in the United States District Court for the District of New Jersey, seeking damages as a result of contamination relating to the former manufactured gas plant operations at Halladay Street in Jersey City, New Jersey. The Halladay Street gas plant operated from approximately 1884 until 1950. PSE&G asserted that Utilities is liable for that portion of the costs associated with operations of the plant between 1886 and 1899. PPG Industries, Inc. has also been named as a defendant in the action for costs associated with chemical contamination at the site unrelated to gas plant operations. In July 1993, PSE&G served Utilities with a complaint naming Utilities as a third-party defendant in this civil action. PSE&G subsequently amended the complaint
to allege additional theories of liability for the period from 1899 to 1940. To date, that action has focused on the chemical contamination allegedly associated with PPG Industries' activities and there have been no developments concerning liability for gas plant related contamination. Investigations of the site conducted to date are insufficient to establish the extent of environmental remediation necessary, if any. Hence, Utilities is unable to estimate the total cost of cleanup associated with manufactured gas plant wastes at this site.
2. Savannah, Georgia. On March 2, 1992, Atlanta Gas Light Company ("AGL") informed Utilities that it was investigating contamination that appears to be related to manufactured gas plant operations at a site owned by AGL in Savannah, Georgia. AGL believes that Utilities may be liable for investigative and remedial costs as a result of having operated the gas plant through a subsidiary company in the early 1900s. AGL has stated its intention to bring suit against Utilities. AGL estimates that total costs to remediate the site may exceed $5 million. Management believes that Utilities has substantial defenses to any action that may arise out of the activities of its former subsidiary at this site.
RELATED MATTER
1. 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. The suit seeks to recover more than $11 million in costs incurred by Utilities at various manufactured gas plant sites. The case is in the preliminary discovery phase.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the last fiscal quarter of the 1999 fiscal year.
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
Dividends declared on the Company's Common Stock totaled $29 million in the 1999 fiscal year, $22.6 million in the 1998 fiscal year and $25.1 million, including a $1 million intercompany receivable, in the 1997 fiscal year.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
- 13 -
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FISCAL 1999 COMPARED WITH FISCAL 1998
(a) bcf - billions of cubic feet. gwh - millions of kilowatt hours. Total margin represents revenues less cost of sales and revenue-related taxes.
(b) EBITDA (earnings before interest expense, income taxes, depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under generally accepted accounting principles.
GAS UTILITY. Weather in Gas Utility's service territory was 12.8% warmer than normal in Fiscal 1999 but 4.2% colder than in Fiscal 1998. Total system throughput increased 1.6% as a result of the slightly colder weather as well as an increase in total customers.
The decrease in Gas Utility revenues in Fiscal 1999 is principally due to several of our core market industrial customers switching from retail to delivery service. Under retail service, we bill our customers for the transportation of gas through our distribution system as well as the cost of the gas itself, for which we get dollar-for-dollar recovery. Under delivery service, we bill customers for the transportation of the gas but not for the gas itself. Our revenues from customers who switch to delivery service are therefore lower, but there is little impact on our total margin. Partially offsetting the decline in revenues from our core market industrial customers was an increase in revenues from sales to our core market residential and commercial customers. Gas Utility cost of gas was $172.0 million in 1999, a decrease of $7.6 million from 1998, reflecting the impact of core market industrial customers switching to delivery service.
The increase in Gas Utility total margin in Fiscal 1999 includes a $3.6 million increase from sales to our core market residential and commercial customers. Total margin from interruptible customers (who have the ability to switch to alternate fuels, principally oil) was slightly lower in Fiscal 1999. The decline in total margin from our interruptible customers reflects lower interruptible rates due to a decline in the spread between oil and natural gas prices during most of Fiscal 1999.
Gas Utility operating income was higher in Fiscal 1999 reflecting the increase in total margin and higher other income partially offset by slightly higher operating and administrative expenses and increased charges for depreciation. Operating expenses in the prior year are net of $1.6 million of income from an insurance recovery. Excluding the impact of the insurance recovery in Fiscal 1998, total Gas Utility operating and administrative expenses in Fiscal 1999 were essentially unchanged.
ELECTRIC UTILITY. The increase in Fiscal 1999 sales of electricity reflects slightly colder heating season weather and warmer weather during the summer air conditioning season. Electric Utility revenues increased $2.9 million in Fiscal 1999 principally as a result of the higher sales. Although Electric Utility's Restructuring Order filed pursuant to Pennsylvania's Electricity Customer Choice Act gives all of our customers the ability to choose their electricity generation supplier effective January 1, 1999, only approximately 5% of our sales during Fiscal 1999 represented electricity we distributed for alternate suppliers. Notwithstanding the increase in Electric Utility sales in Fiscal 1999, cost of sales decreased $1.8 million to $33.2 million. The impact of the higher Fiscal 1999 sales on purchased power costs was more than offset by (1) the benefit of a power supply agreement settlement and (2) lower average purchased power costs.
Electric Utility's total margin increased $4.6 million as a result of (1) the power supply agreement settlement, (2) lower average purchased power costs, and (3) the higher sales. EBITDA and operating income were also higher as the greater total margin was partially offset by higher maintenance costs for our generation assets, higher customer service and information expenses, and lower other income.
Fiscal 1998 Compared with Fiscal 1997
(a) bcf - billions of cubic feet. gwh - millions of kilowatt hours. Total margin represents revenues less cost of sales and revenue-related taxes.
(b) EBITDA (earnings before interest expense, income taxes, depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under generally accepted accounting principles.
GAS UTILITY. Weather in Gas Utility's service territory was 16.3% warmer than normal in Fiscal 1998 compared with weather that was 4.8% warmer than normal in Fiscal 1997. Our total system throughput decreased 6.6% in Fiscal 1998 primarily because the warmer weather resulted in a 5.1 bcf reduction (14.5%) in sales to our core market customers.
The decrease in Gas Utility's revenues in Fiscal 1998 was primarily due to the lower volumes sold to our core market customers. Our cost of gas sold decreased $25.5 million to $179.6 million in Fiscal 1998 also reflecting the lower sales to core market customers.
The decrease in Gas Utility's total margin includes (1) a $9.9 million decrease in margin from our core market customers and (2) a $2.7 million decrease in margin from our interruptible customers. Interruptible margin in Fiscal 1998 was impacted by lower interruptible transportation rates. Gas Utility reduced its rates to alternate-fuel interruptible customers in order to remain competitive with declining oil prices.
Gas Utility EBITDA decreased $4.4 million in Fiscal 1998 reflecting the lower total margin partially offset by lower operating expenses and higher other income. Gas Utility's operating expenses during Fiscal 1998 decreased $5.9 million principally as a result of (1) $1.6 million of
income from an insurance recovery, (2) a $2.1 million decrease in distribution system maintenance expenses, (3) lower charges relating to environmental matters, and (4) lower allocated UGI corporate expenses. Operating income was lower in Fiscal 1998 reflecting the previously mentioned lower EBITDA and a $1.0 million increase in depreciation charges.
ELECTRIC UTILITY. Pennsylvania's Electricity Customer Choice Act and the associated Restructuring Order issued by the PUC in June 1998 (see "Customer Choice Legislation" below) did not have a significant effect on Electric Utility's Fiscal 1998 results. Total electric sales were higher in Fiscal 1998 reflecting the warmer summer weather's effect on air conditioning use and an increase in the number of customers. Electric Utility revenues in Fiscal 1998 were equal to Fiscal 1997 reflecting higher total sales offset by the effects of our Electricity Customer Choice Act pilot program. Our Electricity Customer Choice Act pilot program allowed a limited number of our customers to choose another supplier of electricity beginning November 1, 1997. Because pilot program participants buy their electricity from others, we record revenues for distributing the electricity over our wires but we do not record revenues related to the electricity itself.
Our cost of sales increased to $35.0 million in Fiscal 1998 from $33.8 million in Fiscal 1997. The increase was due to slightly higher costs to generate electricity and higher purchased power costs. In accordance with the June 1998 Restructuring Order, our rates reflect a fixed amount for electric generation costs, and we no longer recover a separate Energy Cost Rate ("ECR"). As a result, we no longer defer the difference between our actual costs of electricity and the amount of such costs included in our rates.
Electric Utility's total margin decreased $1.2 million in Fiscal 1998 due to higher generation and purchased power costs. The decrease in operating income reflects the net effects of (1) lower total margin, (2) legal expenses associated with Restructuring Order activities, and (3) higher other income.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
UGI Utilities' debt outstanding at September 30, 1999 totaled $267.4 million compared with $255.6 million at September 30, 1998. The increase reflects higher borrowings under our revolving credit facilities. We did not issue any additional long-term debt during 1999 but had long-term debt repayments of $7.1 million.
UGI Utilities' primary cash sources have been (1) cash generated by operations, (2) borrowings under its revolving credit agreements, and (3) debt issued under its Medium-Term Note program. Under its Medium-Term Note program, UGI Utilities can issue up to an additional $52 million of unsecured debt through June 17, 2000.
UGI Utilities may borrow up to $117 million under its revolving credit agreements. Borrowings under these agreements totaled $87.4 million at September 30, 1999 and $68.4 million at September 30, 1998. The revolving credit agreements contain financial covenants including
interest coverage ratios and minimum tangible net worth. At September 30, 1999, UGI Utilities could borrow up to the maximum amount available under its revolving credit agreements.
Management believes that UGI Utilities' cash flow from operations and borrowings under its Medium-Term Note programs and bank credit facilities will satisfy UGI Utilities' cash needs in fiscal 2000. For a more detailed discussion of UGI Utilities debt and credit facilities, see Note 3 to Consolidated Financial Statements.
CASH FLOWS
OPERATING ACTIVITIES. Cash flow from operating activities was $62.2 million in Fiscal 1999 compared with $50.2 million in Fiscal 1998. Cash flow from operating activities before changes in operating working capital was $70.5 million in Fiscal 1999 compared with $69.0 million in Fiscal 1998. Changes in operating working capital in Fiscal 1999 used $8.4 million of operating cash flow principally from (1) an increase in accounts receivable and (2) changes in deferred fuel costs. Changes in operating working capital in Fiscal 1998 used $18.9 million of operating cash flows principally from (1) a decrease in accounts payable, (2) changes in deferred fuel costs, and (3) higher income tax payments.
INVESTING ACTIVITIES. Expenditures for property, plant and equipment were $36.4 million in Fiscal 1999 compared with $37.2 million in Fiscal 1998. The decrease is primarily a result of lower Electric Utility capital expenditures.
FINANCING ACTIVITIES. During Fiscal 1999 we paid $29 million in cash dividends to UGI and $1.6 million in dividends to holders of our preferred stock. During Fiscal 1998, we paid $22.6 million in cash dividends to UGI and $2.1 million in dividends on our preferred stock. In Fiscal 1999 we borrowed a net $19 million under our revolving credit agreements compared with borrowings of $1.4 million in Fiscal 1998. In Fiscal 1998 we (1) borrowed $35 million under our Medium-Term Note program, (2) repaid $17.1 million of long-term debt and (3) redeemed $15 million of our preferred stock. In Fiscal 1999, we repaid $7.1 million of long-term debt.
CAPITAL EXPENDITURES
The following table presents capital expenditures of Gas Utility and Electric Utility for the fiscal years ended September 30, 1999, 1998 and 1997, as well as expected amounts for fiscal 2000. Utilities expects to finance fiscal 2000 capital expenditures through internally generated cash and borrowings under its credit facilities.
YEAR 2000 MATTERS
The Year 2000 ("Y2K") issue is a result of computer programs being written using two digits (rather than four) to identify and process a year in a date field. Computer programs, computer-controlled systems and equipment with embedded software may recognize date fields using "00" as the year 1900 rather than the year 2000. If uncorrected, miscalculations and possible computer-based system failures could result which might disrupt business operations. We are designating the following information as our "Year 2000 Readiness Disclosure."
Recognizing the potential business consequences of the Y2K issue, we conducted a detailed assessment of our critical, date-sensitive, computer-based systems to identify those systems that were not Y2K compliant and developed programs to modify those systems that were not otherwise scheduled for replacement prior to the year 2000. Our Y2K compliance efforts focused on our ability to continue to perform three critical operating functions: (1) obtain products to sell; (2) provide service to our customers; and (3) bill customers and pay our vendors and employees.
Those systems that we assessed included (1) our information technology ("IT") systems such as computer hardware and software we use in the operation of our business and (2) our non-IT systems that contain embedded systems with potentially date-sensitive components such as micro-controllers contained in various equipment and facilities. Among these systems are our customer information systems, financial systems and distribution control systems. In order to identify and modify those systems that we determined were not Y2K compliant, we used internal resources as well as outside consultants and vendor representatives. In addition to assessing, identifying and modifying our own systems, we developed and implemented a program to attempt to determine the Y2K compliance status of third parties, including our key suppliers and vendors, and certain of our customers.
We have successfully completed the modification and testing of all our critical IT and non-IT systems that were not Y2K compliant, including Electric Utility's System Control and Data Acquisition system.
As previously mentioned, in addition to assuring our IT and non-IT systems are Y2K compliant, we developed and implemented a program to assess the readiness of our key suppliers and third-party providers, including suppliers of interstate transportation capacity, natural gas producers and electricity interchange providers. Although none of our products or services are of themselves date sensitive, as a utility company we are dependent upon other companies whose IT and non-IT systems may not be Y2K compliant. We have completed our program to contact and inquire of the readiness of these key suppliers and vendors. We have evaluated the responses received from our critical vendors and suppliers, and to the extent we were not satisfied with the responses, or have determined that the responses indicate a lack of Y2K readiness, we have developed contingency plans. The major elements of these contingency plans are based upon the use of manual back-up systems, additional staffing, and alternative supply sources. These contingency plans attempt to mitigate the potential impact of Y2K noncompliance by our key suppliers and vendors. However, these plans cannot assure that business disruptions that may be
caused by key suppliers or third-party providers will not have a material adverse impact on our operations. Gas Utility and Electric Utility have completed their contingency plans.
In addition, there are other Y2K risks which are beyond our control any of which could have a material adverse impact on our operations. Such risks include, but are not limited to, the failure of utility and telecommunications companies to provide service and the failure of financial institutions to process transactions.
Expenses associated with our Y2K efforts during the last three fiscal years totaled approximately $1.0 million.
CUSTOMER CHOICE LEGISLATION
GAS UTILITY. On June 22, 1999, Pennsylvania's Gas Competition Act was signed into law. The Gas Competition Act expands choice of gas suppliers to residential and small commercial customers. Under the Gas Competition Act, all Pennsylvania natural gas consumers will have the right to choose their natural gas commodity supplier no later than July 1, 2000. Gas distribution services provided by local gas distribution companies ("LDCs") will remain subject to rate regulation. The Gas Competition Act requires energy marketers seeking to serve customers of LDCs to accept assignment of a portion of the LDC's interstate pipeline capacity and storage contracts at contract rates, thus avoiding the creation of stranded costs.
On October 1, 1999, Gas Utility filed its restructuring plan with the PUC pursuant to the Gas Competition Act. If such plan is approved substantially as filed, the Company does not believe the Gas Competition Act will have a material adverse impact on its financial condition or results of operations. For a more detailed description of the Gas Competition Act, see Note 2 to Consolidated Financial Statements.
ELECTRIC UTILITY. On June 19, 1998, the PUC entered its Opinion and Order ("Restructuring Order") in Electric Utility's restructuring proceeding pursuant to Pennsylvania's Electricity Customer Choice Act. The Act required all Pennsylvania electric utilities to "unbundle" rates for generation, transmission and distribution services and allow competitors to sell electricity to our customers. Under the terms of the Restructuring Order, Electric Utility's unbundled rates for transmission and distribution services are capped through July 1, 2001. Electric Utility is authorized to recover through the CTC (competitive transition charge) $32.5 million of "stranded costs" over the four-year period commencing January 1, 1999. In addition, Electric Utility generally may not increase the generation component of prices as long as stranded costs are being recovered. Since January 1, 1999, all of Electric Utility's customers have been permitted to select an alternative generation supplier. The Restructuring Order also gives Electric Utility the right, subject to prior PUC approval, to transfer its electric generation assets to a non-utility affiliate. Electric Utility exercised such right in October 1999 by transferring such assets to its wholly owned subsidiary, UGI Development Company. These generation assets supply power exclusively to Electric Utility.
Because Electric Utility's rates for electric generation are capped during the period stranded costs are being recovered, and transmission and distribution rates are capped through July 1, 2001,
Electric Utility's profitability during these periods is highly dependent upon its costs to purchase and generate power and its ability to control operating and administrative expenses. In addition, because we discontinued regulatory accounting treatment for our electric power costs, Electric Utility's quarterly results have been, and future results are likely to be, more volatile due in large part to seasonal variations in power costs. For a more detailed description of the Restructuring Order, see Note 2 to Consolidated Financial Statements.
MANUFACTURED GAS PLANTS
The gas distribution business has been one of UGI Utilities' main businesses since it began in 1882. Prior to the construction of major natural gas pipelines in the 1950s, gas used for lighting and heating was produced at manufactured gas plants ("MGPs") from processes involving coal, coke or oil. Some constituents of coal tars produced from this process are today considered hazardous substances under the Superfund Law and may be located at those sites. At sites where a former subsidiary of UGI Utilities operated an MGP, we believe that UGI Utilities should not have significant liability because UGI Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage at sites owned by a subsidiary company when the parent company either (1) itself operated the facility causing the environmental damage or (2) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by MGPs that UGI Utilities owned or directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded.
UGI Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify UGI Utilities for certain environmental costs. The suit seeks to recover more than $11 million in costs incurred by UGI Utilities at various manufactured gas plant sites. The parties to suit are in the early stages of exchanging information.
We believe, after consultation with counsel, that future costs of investigation and remediation, if any, will not have a material adverse effect on our financial position but could be material to our operating results and cash flows depending upon the nature and timing of future developments and the amounts of future operating results and cash flows. For a further discussion of environmental matters, see Notes 1 and 8 to Consolidated Financial Statements.
MARKET RISK DISCLOSURES
Although Gas Utility is subject to changes in the price of natural gas, the current regulatory framework allows Gas Utility to recover prudently incurred gas costs from its customers. In addition, the Gas Competition Act permits LDCs to recover prudently incurred costs of gas sold to customers. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations.
Electric Utility purchases electricity it does not otherwise produce, representing approximately 50% of its electric power needs, under power supply arrangements of varying length terms with other producers and, to a lesser extent, on the spot market. Spot market prices for electricity and, to a lesser extent, monthly market-based contracts can be volatile, especially during periods of high demand. Because Electric Utility's generation rates are capped during the period that it is recovering stranded costs under its Restructuring Order, any increases in costs to purchase power will negatively impact Electric Utility's results.
We have interest rate exposure associated with borrowings under our revolving credit agreements. These agreements provide for interest rates on borrowings which are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements during Fiscal 1999 and Fiscal 1998, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $0.6 million and $0.5 million, respectively.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In March 1998, the American Institute of Certified Public Accountants issued Statement of Position No. 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" ("SOP 98-1"). SOP 98-1 requires companies to capitalize the cost of computer software developed or obtained for internal use once certain criteria have been met. We will adopt SOP 98-1 in fiscal 2000. We do not expect the adoption of SOP 98-1 will have a material effect on our financial position or results of operations.
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires that an entity recognize all derivative instruments as either assets or liabilities and measure them 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. To the extent derivative instruments qualify and are designated as hedges of forecasted transactions, changes in fair value will generally be reported as a component of other comprehensive income and be reclassified into net income when the forecasted transaction affects earnings. To the extent such derivative instrument qualifies as a hedge of a firm commitment, any gain or loss would generally be recognized in earnings when the firm commitment affects earnings. In June 1999, the FASB deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. Accordingly, we will adopt SFAS 133 in fiscal 2001. The impact of SFAS 133 will depend upon the extent to which we use derivative instruments and their designation and effectiveness as hedges of market risk.
IMPACT OF INFLATION
Inflation impacts Gas Utility and Electric Utility primarily in the prices they pay for labor, materials and services. Because Electric Utility's base rates are currently capped and because Gas Utility's base rates can be adjusted only through general rate filings with the PUC, increased costs, absent timely rate relief, can have a significant impact on their results. Under current tariffs, Gas Utility is permitted, after PUC review, to recover certain costs of purchased gas, fuel and power which comprise a substantial portion of Gas Utility's costs and expenses.
The Company attempts to limit the effects of inflation on its results of operations through cost control efforts, productivity improvements and, as permitted by the PUC, timely rate relief.
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 with respect to expected financial results and future events is forward-looking, based on our estimates and assumptions and subject to risk and uncertainties. For those statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.
The following important factors 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 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) improvements in energy efficiency and technology resulting in reduced demand, (7) labor relations, (8) large customer defaults, (9) operating hazards and risks incidental to generating and distributing electricity and distributing natural gas including the risk of explosions and fires resulting in personal injury and property damage, (10) regional economic conditions, (11) the success of the company and its suppliers in achieving Year 2000 compliance, and (12) 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.
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
None.
PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
(1) All of the directors also serve as directors of UGI. In addition, Messrs. Greenberg, Donovan, Gozon, Stratton and Wang serve as directors of AmeriGas Propane, Inc., the General Partner of AmeriGas Partners, L.P.
EXECUTIVE OFFICERS
Directors are elected annually. All officers are elected for a one-year term at the organizational meeting of the Board of Directors held each year.
There are no family relationships between any of the directors or any of the officers or between any of the officers and any of the directors.
The following is a summary of the business experience of the executive officers listed above during at least the last five years:
Lon R. Greenberg
Mr. Greenberg is Chairman of the Board of the Company (since August 1996), having served as a Director since 1994; he is also Chairman (since 1996), Chief Executive Officer (since August 1995) and President (since 1994) of UGI. In addition, he is Chairman (since August 1996), President and Chief Executive Officer of AmeriGas Propane, Inc. (since July 1996). Mr. Greenberg previously served as Senior Vice President-Legal and Corporate Development of UGI (1989 to 1994).
Robert J. Chaney
Mr. Chaney is President and Chief Executive Officer of the Company (since March 1999). He previously served as Executive Vice President - Utilities (1998 to 1999) and Vice President and General Manager-Gas Utility Division of the Company (1991 to 1998).
Mark R. Dingman
Mr. Dingman is Vice President and General Manager-Electric Utility Division of the Company (since 1990).
John C. Barney
Mr. Barney is Senior Vice President-Finance of Utilities (since March 1999). Previously, Mr. Barney served as Vice President-Finance and Accounting (1992 to 1999).
Brendan P. Bovaird
Mr. Bovaird is Vice President and General Counsel of the Company (since April 1995). He is also Vice President and General Counsel of UGI Corporation and AmeriGas Propane, Inc. (since April 1995). Mr. Bovaird previously served as Division Counsel and Member of the Executive and Operations Committees of Wyeth-Ayerst International Inc. (1992 to 1995).
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following table shows cash and other compensation paid or accrued to the Company's Chief Executive Officer and each of the four other most highly compensated executive officers (collectively, the "Named Executives") for the last three fiscal years.
SUMMARY COMPENSATION TABLE --------------------------
(1) Bonuses earned under the UGI Corporation and UGI Utilities, Inc. Annual Bonus Plans are for the year reported, regardless of the year paid. The Annual Bonus Plans are based on the achievement of pre-determined business and/or financial performance objectives which support business plans and goals. Bonus opportunities vary by position and for fiscal year 1999 ranged from 0% to 148% of base salary for Mr. Greenberg, 0% to 60% for Mr. Bunn, from 0% up to 53% for Mr. Chaney, from 0% to 38% for Messrs. Barney and Dingman, and from 0% to 91% for Mr. Bovaird.
(2) Amounts represent tax payment reimbursements for certain benefits.
(3) (a) On June 4, 1999, the Board of Directors of UGI Corporation approved restricted stock awards to certain executives of UGI and UGI Utilities, Inc. The dollar values shown above represent the aggregate value of each award on the date of grant, determined by multiplying the number of shares awarded by the closing stock price of UGI Common Stock on the New York Stock Exchange on June 4, 1999. Holders of restricted shares have the right to vote and to receive dividends during the restriction period.
(b) Based on the closing stock price of UGI Common Stock on the New York Stock Exchange on September 30, 1999, Mr. Greenberg's 30,000 share grant had a market value of $697,000; Mr. Chaney's and Mr. Bovaird's 7,000 share grant each had a market value of $162,750 and Mr. Barney's and Mr. Dingman's 5,000 share award each had a value of $116,250.
(4) Amounts represent matching contributions by the Company or UGI in accordance with the provisions of the UGI Utilities, Inc. Employee Savings Plan and/or allocations under the Executive Retirement Plan. During 1999, 1998 and 1997, the following contributions were made to the Named Executives: (i) under the Employee Savings Plan: for Mr. Greenberg, $3,600, $3,600 and $3,375; Mr. Bunn, $3,235, $3,600 and $3,375; Mr. Chaney, $3,600, $3,600 and $3,375; Mr. Barney, $3,403, $3,600 and $3,375; Mr. Dingman, $3,202, $3,580 and $3,375; Mr. Bovaird, $3,509, $3,600 and $3,375; and (ii) under the Supplemental Executive Retirement Plan: Mr. Greenberg, $14,673, $18,554, and $10,858; Mr. Bunn, $3,069, $6,972 and $6,879; Mr. Bovaird, $1,706, $1,825 and $821; Mr. Chaney, $2,142, $1,423 and $1,546; Mr. Barney, $752, $213 and $274; Mr. Dingman, $1,007, $0 and $274. Mr. Bunn also received $87,000 during 1999 under a Consulting Services Agreement with the Company for services rendered after his retirement.
(5) Compensation for Mr. Greenberg is attributable to his employment as Chairman, President and Chief Executive Officer of UGI Corporation. Compensation for Mr. Bovaird is attributable to his employment as Vice President and General Counsel of UGI Corporation. Mr. Greenberg and Mr. Bovaird receive no compensation from UGI Utilities, Inc.
(6) Compensation reported for Messrs. Greenberg, Bovaird and Chaney is also reported in the Proxy Statement for UGI's 1999 Annual Meeting of Shareholders and is not additive.
(7) (a) Non-qualified stock options granted on June 4, 1999 under the UGI 1997 Stock Option and Dividend Equivalent Plan (the "1997 Plan") without the opportunity to earn dividend equivalents described below.
(b) Non-qualified stock options granted under the 1997 Plan. The 1997 Plan consists of non-qualified stock option grants and the opportunity for participants to earn an amount equivalent to the dividends paid on shares covered by options, subject to a comparison of the total return realizable on a share of UGI's Common Stock with the total return achieved by each member of a group of comparable peer companies over a three-year period beginning January 1, 1997 and ending December 31, 1999. Total return encompasses both changes in the per share market price and dividends paid on a share of common stock.
(8) Mr. Bunn retired on March 1, 1999.
(9) Non-qualified stock options granted under the UGI 1992 Non-Qualified Stock Option Plan.
OPTION GRANTS IN LAST FISCAL YEAR
The following table shows information on grants of stock options during fiscal year 1999 to each of the Named Executives.
OPTION GRANTS IN LAST FISCAL YEAR
(1) A total of 231,806 options were granted to employees and executive officers of the Company during fiscal year 1999 under the 1997 SODEP and the 1992 Non-Qualified Stock Option Plan. Under the 1992 Non-Qualified Stock Option Plan, the option exercise price is not less than 100% of the fair market value of UGI's Common Stock on the date of grant. Options granted on and after December 10, 1996 are fully vested on the date of grant. Options under the 1992 Plan are nontransferable and generally exercisable only while the optionee is employed by the Company or an affiliate. Options are subject to adjustment in the event of recapitalizations, stock splits, mergers, and other similar corporate transactions affecting UGI's Common Stock.
(2) Non-qualified stock options granted on June 4, 1999 under the 1997 SODEP. This grant does not include the opportunity to earn an amount equivalent to the dividends paid during the performance period on shares covered by options. The option exercise price is not less than 100% of the fair market value of UGI's Common Stock determined on the date of the grant. These options will vest at the rate of 25% per year on the anniversary of the grant date. Options granted under the Plan are nontransferable and are generally exercisable only while the optionee is employed by the Company or an affiliate. Options are subject to adjustment in the event of recapitalizations, stock splits, mergers, and other similar corporate transactions affecting UGI's Common Stock.
(3) Based on the Black-Scholes options pricing model. The assumptions used in calculating the grant date present value are as follows:
(a) - Three years of closing monthly stock price observations were used to calculate the stock observations were used to calculate the stock volatility and dividend yield assumptions.
- Stock volatility 22.39%
- Stock's dividend yield 6.18%
- Length of option term 10 years
- Annualized risk-free interest rate 6.14%
- Discount of risk of forfeiture 3% per year
(b) - Three years of closing monthly stock price observations were used to calculate the stock observations were used to calculate the stock volatility and dividend yield assumptions.
- Stock volatility 17.13%
- Stock's dividend yield 5.97%
- Length of option term 10 years
- Annualized risk-free interest rate 5.39%
- Discount of risk of forfeiture 0%
(4) Non-qualified stock options granted on February 23, 1999 under the 1997 SODEP. This grant also includes the opportunity to earn an amount equivalent to the dividends paid during the performance period on shares covered by options. The option exercise price is not less than 100% of the fair market value of UGI's Common Stock determined on the date of the grant. These options were fully vested on the date of grant. Options granted under the Plan are nontransferable and are generally exercisable only while the optionee is employed by the Company or an affiliate. Options are subject to adjustment in the event of recapitalizations, stock splits, mergers, and other similar corporate transactions affecting UGI's Common Stock.
All options were granted at fair market value. The actual value, if any, the executive may realize will depend on the excess of the stock price on the date the option is exercised over the exercise price. There is no assurance that the value realized by the executive will be at or near the value estimated by the Black-Scholes model.
OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
The following table shows information for the 1999 fiscal year concerning exercised and unexercised stock options for shares of UGI Common Stock for each of the Named Executives.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUE
(1) Information reported for Messrs. Greenberg, Chaney and Bovaird is also reported in the Proxy Statement for UGI's 1999 Annual Meeting of Shareholders and is not additive.
(2) Options granted under the 1997 Stock Option and Dividend Equivalent Plan.
(3) Value based on comparison of price per share at September 30, 1999 (fair market value $23.25) to the option exercise price ($20.375).
(4) Options granted under the 1992 Stock Option and Dividend Equivalent Plan.
(5) Value based on comparison of price per share at September 30, 1999 (fair market value $23.25) to the option price ($20.125).
(6) Value based on comparison of price per share at September 30, 1999 (fair market value $23.25) to the option price ($22.625).
(7) Value based on comparison of price per share at September 30, 1999 (fair market value $23.25) to the option price ($22.375).
(8) Options granted under the 1992 Non-Qualified Stock Option Plan.
(9) Value based on comparison of price per share at September 30, 1999 (fair market value $23.25) to the option price ($21.25).
RETIREMENT BENEFITS
The following table shows the annual benefits payable upon retirement to the Named Executive Officers under the Retirement Income Plan for Employees of UGI Utilities, Inc. and participating employers (the "Retirement Plan") and the UGI Supplemental Executive Retirement Plan. The amounts shown assume the executive retires in 1999 at age 65, and that the aggregate benefits are not subject to statutory maximums.
PENSION PLAN BENEFITS TABLE
(1) Annual benefits are computed on the basis of straight life annuity amounts. These amounts include pension benefits, if any, to which a participant may be entitled as a result of participation in a pension plan of a subsidiary during previous periods of employment. The amounts shown do not take into account exclusion of up to 35% of the estimated primary Social Security benefit. The Retirement Plan provides a minimum benefit equal to 25% of a participant's final 12 months' earnings, reduced proportionately for less than 15 years of credited service at retirement. The minimum Retirement Plan Benefit is not subject to Social Security offset. Messrs. Greenberg, Bunn, Barney, Chaney, Dingman and Bovaird had, respectively, 19 years, 40 years, 28 years, 35 years, 26 years and 4 years of estimated credited service at September 30, 1999.
(2) Consists of (i) base salary, commissions and cash payments under the UGI and Utilities Annual Bonus Plans, and (ii) deferrals thereof permitted under the Internal Revenue Code.
(3) The maximum benefit under the Retirement Plan and the Supplemental Executive Retirement Plan is equal to 60% of a participant's highest consecutive 12 months' earnings during the last 120 months.
SEVERANCE PAY PLAN FOR SENIOR EXECUTIVE EMPLOYEES
The UGI Corporation Senior Executive Employee Severance Pay Plan (the "UGI Severance Plan") assists certain senior level employees of Utilities, including Messrs. Greenberg, Bovaird, Chaney, Barney and Dingman in the event their employment is terminated without fault on their part. Specified benefits are payable to a senior executive covered by the UGI Severance Plan if the senior executive's employment is involuntarily terminated for any reason other than for cause or as a result of the senior executive's death or disability.
The UGI Severance Plan provides for cash payments equal to a participant's compensation for a period of time ranging from 3 months to 15 months (30 months in the case of Mr. Greenberg), depending on length of service. In addition, a participant receives the cash equivalent of his or her target bonus under the Annual Bonus Plan, pro-rated for the number of months served in the fiscal year. However, if the termination occurs in the last two months of the fiscal year, the Chief Executive Officer has the discretion to determine whether the participant will receive a pro-rated target bonus, or the actual annual bonus which would have been paid after the end of the fiscal year, assuming that the participant's entire bonus was contingent on meeting the applicable financial performance goal. The Plan also provides for separation pay equal to one day's pay per month of service, not to exceed 12 months' compensation. Certain employee benefits are continued under the Plan for a period of up to 15 months (30 months in the case of Mr. Greenberg). Utilities has the option to pay a participant the cash equivalent of those employee benefits.
In order to receive benefits under the UGI Severance Plan, a senior executive is required to execute a release which discharges Utilities and its affiliates from liability for any claims the senior executive may have against any of them, other than claims for amounts or benefits due to the executive under any plan, program or contract provided by or entered into with Utilities or its affiliates. The senior executive is also required to cooperate in attending to matters pending at the time of his or her termination of employment.
CHANGE OF CONTROL ARRANGEMENTS
Named Executives Employed by UGI Corporation. Messrs. Greenberg and Bovaird each have an agreement with UGI Corporation (the "Agreement") which provides certain benefits in the event of a change of control of UGI. The Agreements operate independently of the UGI Severance Plan, continue through July 2004, and are automatically extended in one-year increments thereafter unless, prior to a change of control, UGI terminates an Agreement. In the absence of a change of control, each Agreement will terminate when, for any reason, the executive terminates his employment with UGI or its subsidiaries.
A change of control is generally deemed to occur if: (i) any person (other than the executive, his affiliates and associates, UGI or any of its subsidiaries, any employee benefit plan of UGI or any of its subsidiaries, or any person or entity organized, appointed, or established by UGI or its subsidiaries for or pursuant to the terms of any such employee benefit plan), together with all affiliates and associates of such person, acquires securities representing 20% or more of either (x) the then outstanding shares of common stock of UGI or (y) the combined voting power
of UGI's then outstanding voting securities; (ii) individuals who at the beginning of any 24-month period constitute the Board of Directors (the "Incumbent Board") and any new director whose election by the Board, or nomination for election by UGI's shareholders, was approved by a vote of at least a majority of the Incumbent Board, cease for any reason to constitute a majority thereof; (iii) UGI is reorganized, merged or consolidated with or into, or sells all or substantially all of its assets to, another corporation in a transaction in which former shareholders of UGI do not own more than 50% of the outstanding common stock and the combined voting power, respectively, of the then outstanding voting securities of the surviving or acquiring corporation after the transaction; or (iv) UGI is liquidated or dissolved.
Upon a change of control, the Agreement provides for an immediate cash payment equal to the market value of any pending target award under UGI's long-term compensation plan.
Severance benefits are payable under the Agreements if there is a termination of the executive's employment without cause at any time within three years after a change of control. In addition, following a change of control, the executive may elect to terminate his or her employment without loss of severance benefits in certain specified contingencies, including termination of officer status; a significant adverse change in authority, duties, responsibilities or compensation; the failure of UGI to comply with and satisfy any of the terms of the Agreement; or a substantial relocation or excessive travel requirements.
An executive who is terminated with rights to severance compensation under an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 (2.5 in the case of Mr. Greenberg) times his average total cash remuneration for the preceding five calendar years. If the severance compensation payable under the Agreement, either alone or together with other payments to an executive, would constitute "excess parachute payments," as defined in Section 280G of the Internal Revenue Code of 1986, as amended (the "Code"), the executive will also receive an amount to satisfy the executive's additional tax burden.
Named Executives Employed by UGI Utilities, Inc.. Messrs. Chaney, Barney and Dingman each have an agreement with UGI Utilities (the "Agreement") which provides certain benefits in the event of a change of control of Utilities or of UGI. The Agreements operate independently of the UGI Severance Plan, continue through July 2004, and are automatically extended in one-year increments thereafter unless, prior to a change of control, the Company terminates an Agreement. In the absence of a change of control, each Agreement will terminate when, for any reason, the executive terminates his employment with Utilities or its subsidiaries.
A change of control is generally deemed to occur if a change of control of UGI, as defined above, occurs or if: (i) UGI and its subsidiaries fail to own more than fifty percent of the combined voting power of the Company's then outstanding voting securities, (ii) the Company is reorganized, merged or consolidated with or into, or sells all or substantially all of its assets to, another corporation in a transaction in which former shareholders of the Company do not own more than 50% of the outstanding common stock and the combined voting power, respectively, of the then outstanding voting securities of the surviving or acquiring corporation after the transaction, or (iii) the Company is liquidated or dissolved.
Upon a change of control, the Agreement provides for an immediate cash payment equal to the market value of any pending target award under Utilities' long-term compensation plan.
Severance benefits are payable under the Agreements if there is a termination of the executive's employment without cause at any time within three years after a change of control. In addition, following a change of control, the executive may elect to terminate his or her employment without loss of severance benefits in certain specified contingencies, including termination of officer status; a significant adverse change in authority, duties, responsibilities or compensation; the failure of the Company to comply with and satisfy any of the terms of the Agreement; or a substantial relocation or excessive travel requirements.
An executive who is terminated with rights to severance compensation under an Agreement will be entitled to receive an amount equal to 1.0 or 1.5 times his average total cash remuneration for the preceding five calendar years. If the severance compensation payable under the Agreement, either alone or together with other payments to an executive, would constitute "excess parachute payments," as defined in Section 280G of the Internal Revenue Code of 1986, as amended (the "Code"), the executive will also receive an amount to satisfy the executive's additional tax burden.
COMPENSATION OF DIRECTORS
Messrs. Chaney and Greenberg are not compensated for service on the Board of Directors or on any Committee of the Board. The other members of the Company's Board of Directors also serve on the UGI Board and receive no additional compensation for service on the Company's Board. The Company reimburses UGI for 50% of the attendance fees and expenses incurred by the non-employee directors of UGI.
COMPENSATION COMMITTEE
The members of the UGI Utilities, Inc. Compensation and Management Development Committee are Richard C. Gozon (Chairman), Thomas F. Donovan and David I. J. Wang.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
At December 1, 1999, UGI Corporation held 100% of the Company's Common Stock. UGI is located at 460 North Gulph Road, King of Prussia, PA 19406.
The following table sets forth, as of October 31, 1999, the number of shares of Common Stock of UGI beneficially owned by each director of the Company and each of the Named Executives, as well as all directors and executive officers as a group. Mr. Greenberg is the beneficial owner of approximately 1.5% of UGI's Common Stock. All other directors, Named Executives and executive officers own less than 1% of UGI's outstanding shares. The total number of shares beneficially owned by all directors and executive officers includes shares subject to options exercisable within 60 days.
SECURITY OWNERSHIP OF MANAGEMENT
(1) The director or officer has sole voting and investment power unless otherwise specified.
(2) The number of Shares shown includes Deferred Units ("Units") acquired through the 1997 Directors' Equity Compensation Plan. Units are neither actual shares nor other securities, but each Unit will be converted to one share of Common Stock and paid out
to directors upon their retirement or termination of service. The number of Units included for each director is as follows: Messrs. Donovan (1,298), Stratton (9,478), Schlanger (2,480), Wang (8,494), Gozon (10,970) and Ban (5,109).
(3) Dr. Ban holds 6,670 Shares jointly with his spouse.
(4) Mr. Bovaird holds 12,993 Shares jointly with his spouse and 3,061 Shares represented by units held in the UGI Stock Fund of the 401(k) Employee Savings Plan, based on September 30, 1999 Savings Plan statements.
(5) Mr. Bunn holds 40,716 Shares jointly with his spouse. 21,500 Shares of the Shares shown are held directly by Mrs. Bunn.
(6) Mr. Chaney holds 2,561 Shares jointly with his spouse.
(7) Mr. Greenberg holds 88,220 Shares jointly with his spouse and 5,178 Shares represented by units held in the UGI Stock Fund of the 401(k) Employee Savings Plan, based on September 30, 1999 Savings Plan statements.
(8) The total number of Shares beneficially owned by the directors and officers as a group represents 3.2% of UGI's outstanding shares.
(9) Mr. Barney disclaims beneficial ownership of 400 Shares owned by his adult children.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In fiscal year 1999 UGI allocated 47%, or $4.9 million, of its general corporate expenses to Utilities.
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 14.
ITEM 14. 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:
Report of Independent Public Accountants
Consolidated Balance Sheets, September 30, 1999 and 1998
Consolidated Statements of Income for the fiscal years ended September 30, 1999, 1998 and 1997
Consolidated Statements of Cash Flows for the fiscal years ended September 30, 1999, 1998 and 1997
Consolidated Statements of Stockholders' Equity for the fiscal years ended September 30, 1999, 1998 and 1997
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULES
II- Valuation and Qualifying Accounts
All other financial statement schedules are omitted because the required information is not present or not present in amounts sufficient to require submission of the schedule or because the information required is included elsewhere in the respective financial statements or notes thereto contained herein.
(3) LIST OF EXHIBITS:
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
INCORPORATION BY REFERENCE
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.
During the last quarter of the 1999 fiscal year, the Company filed no Current Reports on Form 8-K.
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 14, 1999 By: /s/ 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 14, 1999 by the following persons on behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
/s/Robert J. Chaney President and Chief - ------------------------------- Executive Officer Robert J. Chaney (Principal Executive Officer) and Director
/s/Lon R. Greenberg Chairman and Director - ------------------------------- Lon R. Greenberg
/s/John C. Barney Senior Vice President - - ------------------------------- Finance (Principal Financial Officer and Principal Accounting Officer)
/s/Stephen D. Ban Director - ------------------------------- Stephen D. Ban
/s/Thomas F. Donovan Director - ------------------------------- Thomas F. Donovan
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 14, 1999 by the following persons on behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
/s/Richard C. Gozon Director - ------------------------------- Richard C. Gozon
- ------------------------------- Director Anne Pol
/s/Marvin O. Schlanger Director - ------------------------------- Marvin O. Schlanger
/s/James W. Stratton Director - ------------------------------- James W. Stratton
/s/David I. J. Wang Director - ------------------------------- David I. J. Wang
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 1999
UGI UTILITIES, INC. AND SUBSIDIARIES
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) the information required is included elsewhere in the financial statements or related notes.
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, 1999 and 1998, and the related consolidated statements of income, stockholder's equity and cash flows for each of the three years in the period ended September 30, 1999. 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 generally accepted auditing standards. 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, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1999 in conformity with generally accepted accounting principles.
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
Chicago, Illinois November 12, 1999
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Thousands of dollars)
The accompanying notes are an integral part of these financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars, except per share)
The accompanying notes are an integral part of these financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of dollars)
The accompanying notes are an integral part of these financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of dollars)
The accompanying notes are an integral part of these financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (Thousands of dollars)
The accompanying notes are an integral part of these financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION PRINCIPLES
UGI Utilities, Inc. ("UGI Utilities"), a wholly owned subsidiary of UGI Corporation ("UGI"), owns and operates a natural gas distribution utility ("Gas Utility") in parts of eastern and southeastern Pennsylvania and an electric utility ("Electric Utility") in northeastern Pennsylvania. Our consolidated financial statements include the accounts of UGI Utilities and its subsidiaries. We eliminate all significant intercompany accounts and transactions when we consolidate. Revenues of Gas Utility comprise more than four-fifths of our consolidated revenues.
RECLASSIFICATIONS
We have reclassified certain prior-period balances to conform with the current period presentation.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in conformity with generally accepted accounting principles. 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 OPERATIONS
Gas Utility and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission ("PUC"). We account for their regulated operations in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71"). Generally, SFAS 71 requires that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. Under SFAS 71, regulated enterprises defer costs and credits on the balance sheet as regulatory assets and liabilities when it is probable that those costs and credits will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in income by an unregulated enterprise. These regulatory assets and liabilities are then reflected in the income statement in the period in which the same amounts are included in rates. If a separable portion of UGI Utilities' business no longer meets the provisions of SFAS 71, we may be required to write-off certain regulatory assets unless some form of transition cost recovery is established by the appropriate regulatory body which would meet the requirements under generally accepted accounting principles for continued accounting as regulatory assets during such recovery period. We
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
continually monitor the regulatory and competitive environments to determine that regulatory assets are probable of recovery.
In June 1998, the PUC approved Electric Utility's restructuring plan which we submitted pursuant to Pennsylvania's Electricity Customer Choice Act (see Note 2). In accordance with the Financial Accounting Standards Board's ("FASB's") Emerging Issues Task Force ("EITF") Statement 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements 71 and 101" ("EITF 97-4"), we discontinued the application of SFAS 71 as it relates to the electric generation portion of Electric Utility's business in June 1998. The discontinuance of SFAS 71 did not have a material effect on our financial position or results of operations. On October 1, 1999, Gas Utility filed its restructuring plan with the PUC pursuant to the Gas Competition Act (see Note 2). We believe that, based upon the provisions of the Gas Competition Act and our restructuring plan, Gas Utility's regulatory assets continue to satisfy the criteria of SFAS 71.
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 $16,894 in 1999, $15,816 in 1998, and $17,507 in 1997. We paid income taxes totaling $19,642 in 1999, $21,116 in 1998, and $24,246 in 1997.
REVENUE RECOGNITION
Gas Utility and Electric Utility record revenues for services provided to the end of each month. We reflect Gas and Electric utility rate increases or decreases in revenues from effective dates permitted by the PUC.
INVENTORIES
Our inventories are stated at the lower of cost or market. We determine cost principally on an average or first-in, first-out ("FIFO") method except for appliances for which we use the specific identification method.
INCOME TAXES
UGI Utilities records deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also recognizes a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and establishes a corresponding regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
We are amortizing deferred investment tax credits related to UGI Utilities' plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.
We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are allocated tax assets, liabilities, expense, benefits and credits resulting from the effects of our transactions in the consolidated federal income tax provision, including giving effect to all intercompany transactions. The result of this allocation is not materially different from income taxes calculated on a separate return basis.
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION
We record property, plant and equipment at cost. We charge to accumulated depreciation the original cost of UGI Utilities' retired plant, together with the net cost of removal, for financial accounting purposes.
We compute depreciation of Gas Utility's and Electric Utility's plant and equipment using the straight-line method over the estimated average remaining lives of the various classes of depreciable property. Depreciation as a percentage of the related average depreciable base for Gas Utility was 2.7% in 1999, 1998 and 1997. Depreciation as a percentage of the related average depreciable base for Electric Utility was 3.2% in 1999 and 1998, and 3.6% in 1997. Depreciation expense was $22,371 in 1999, $21,454 in 1998, and $20,899 in 1997.
COMPUTER SOFTWARE COSTS
We include in property, plant and equipment external and incremental internal costs associated with computer software we develop for use in our businesses. We begin capitalizing these costs when the preliminary stage of the project is completed. We amortize these costs on a straight-line basis over five 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 gas costs in excess of the level of such costs included in base rates. The clauses provide for a periodic adjustment for the difference between the total amount collected from customers under each clause and the recoverable costs incurred. We defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers.
Prior to January 1, 1997, Electric Utility's rates were subject to an Energy Cost Rate ("ECR") designed to recover or refund the difference between the actual fuel and purchased power costs and the amount included in base rates. In accordance with the provisions of the Electricity Customer Choice Act, the rates Electric Utility can charge its customers, including amounts pertaining to the recovery of fuel and purchased power costs, are subject to rate caps effective
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
January 1, 1997. We expect the generation rate cap to extend through December 31, 2002 (see Note 2).
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. We do not discount to present value the costs of future expenditures for environmental liabilities. 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 will be permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred removal costs.
COMPREHENSIVE INCOME
We adopted SFAS No. 130, "Reporting Comprehensive Income" ("SFAS 130") in 1999. SFAS 130 establishes standards for reporting and displaying comprehensive income, comprising net income and other nonowner changes in equity, in the financial statements. For all periods presented, comprehensive income was the same as net income.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In March 1998, the American Institute of Certified Public Accountants issued Statement of Position No. 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" ("SOP 98-1"). SOP 98-1 requires companies to capitalize the cost of computer software developed or obtained for internal use once certain criteria have been met. We will adopt SOP 98-1 in fiscal 2000. We do not expect the adoption of SOP 98-1 will have a material effect on our financial position or results of operations.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires that an entity recognize all derivative instruments as either assets or liabilities and measure them 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. To the extent derivative instruments qualify and are designated as hedges of forecasted transactions, changes in fair value will generally be reported as a component of other comprehensive income and be reclassified into net income when the forecasted transaction affects earnings. To the extent such derivative instrument qualifies as a hedge of a firm commitment, any gain or loss would generally be recognized in earnings when the firm commitment affects earnings. In June 1999, the FASB deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. Accordingly, we will adopt SFAS 133 in fiscal 2001. The impact
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
of SFAS 133 will depend upon the extent to which we use derivative instruments and their designation and effectiveness as hedges of market risk.
2. UTILITY REGULATORY MATTERS
ELECTRIC UTILITY RESTRUCTURING ORDER
On June 19, 1998, the PUC entered its Opinion and Order (the "Restructuring Order") in Electric Utility's restructuring proceeding pursuant to Pennsylvania's Electricity Generation Customer Choice and Competition Act ("Electricity Customer Choice Act"). Under the terms of the Restructuring Order, commencing January 1, 1999, Electric Utility is authorized to recover $32,500 in stranded costs (on a full revenue requirements basis which includes all income and gross receipts taxes) over a four-year period 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. Electric Utility's recoverable stranded costs include $8,692 for the buy-out of a 1993 power purchase agreement with an independent power producer.
Under the terms of the Restructuring Order and in accordance with the Electricity Customer Choice Act, Electric Utility's rates for transmission and distribution services are capped through July 1, 2001. In addition, Electric Utility generally may not increase the generation component of prices as long as stranded costs are being recovered through the CTC. This generation rate cap is expected to extend through December 31, 2002. Since January 1, 1999, all of Electric Utility's customers have been permitted to select an alternative generation supplier. Customers choosing an alternative supplier receive a "shopping credit." The Restructuring Order gives Electric Utility the right, subject to prior PUC approval, to transfer its electric generation assets to a nonregulated affiliate. On October 1, 1999, Electric Utility transferred its electric generation assets to its wholly owned nonregulated subsidiary, UGI Development Company.
In June 1998, Electric Utility discontinued the application of SFAS 71 as it relates to the electric generation portion of its business, which assets comprise less than 15% of Electric Utility's total assets. The discontinuance of SFAS 71 did not have a material effect on our financial position or results of operations.
NATURAL GAS COMPETITION ACT
On June 22, 1999, Pennsylvania's Natural Gas Choice and Competition Act ("Gas Competition Act") was signed into law. The purpose of the Gas Competition Act is to provide all natural gas consumers in Pennsylvania with the ability to purchase their gas supplies from the supplier of their choice by July 1, 2000. Under the Gas Competition Act, local gas distribution companies ("LDCs") 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. The Gas
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Competition Act, in conjunction with a companion bill, effectively eliminates the gross receipts tax (currently 5%) on sales of gas commencing January 1, 2000.
Generally, LDCs will serve as the supplier of last resort for all residential and small commercial and industrial customers unless the PUC approves another supplier of last resort. Natural gas distribution companies are required to make restructuring filings pursuant to a schedule determined by the PUC. In such restructuring filings, LDCs may request permission to capitalize and amortize most costs resulting from the implementation of the Gas Competition Act over appropriate periods. Certain other costs incurred before June 30, 2002 may be deferred for possible future recovery. Notwithstanding the ultimate treatment of such costs resulting from the implementation of the Gas Competition Act, LDCs are generally precluded from increasing rates for the recovery of costs, other than gas costs, until January 1, 2001. The Gas Competition Act requires energy marketers seeking to serve customers of LDCs to accept assignment of a portion of the LDC's interstate pipeline capacity and storage contracts (as well as contracts for Pennsylvania gas supplies) at contract rates, thus avoiding the creation of stranded costs. After July 1, 2002, a natural gas supplier may petition the PUC to avoid such contract release or assignment. The PUC, however, may only grant the petition if certain findings are made and the LDC fully recovers the cost of contracts.
On October 1, 1999, Gas Utility filed its restructuring plan with the PUC pursuant to the Gas Competition Act. If such plan is approved substantially as filed, the Company does not believe the Gas Competition Act will have a material adverse impact on its financial condition or results of operations.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
3. DEBT
Long-term debt comprises the following at September 30:
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Scheduled repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows: 2000 - $7,143; 2001 - $15,000; 2002 - $0; 2003 - $76,000; 2004 - $0.
At September 30, 1999, UGI Utilities had revolving credit agreements with four banks providing for borrowings of up to $97,000 through June 2001 and an additional $20,000 through September 2000. UGI Utilities may borrow at various prevailing interest rates, including LIBOR. UGI Utilities pays quarterly commitment fees on these credit lines. UGI Utilities had borrowings under these agreements totaling $87,400 at September 30, 1999 and $68,400 at September 30, 1998, which we classify as bank loans. The weighted-average interest rates on bank loans were 5.9% at September 30, 1999 and 1998.
Certain of UGI Utilities' debt agreements restrict the incurrence of additional debt, require consolidated tangible net worth of at least $125,000, and restrict the amount of payments for investments, redemptions of capital stock, prepayments of subordinated indebtedness and dividends.
4. INCOME TAXES
The provisions for income taxes consist of the following:
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Deferred tax liabilities (assets) comprise the following at September 30:
UGI Utilities had recorded deferred tax liabilities of approximately $31,400 as of September 30, 1999 and $31,336 as of September 30, 1998 pertaining to utility temporary differences, principally a result of accelerated tax depreciation, 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 $3,975 at September 30, 1999 and $4,140 at September 30, 1998, pertaining to utility deferred investment tax credits. UGI Utilities had recorded a regulatory income tax asset related to these net deferred taxes of $46,875 as of September 30, 1999 and $46,483 as of September 30, 1998. This regulatory income tax asset represents 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 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 benefit obligations, plan assets, and funded status of the plans as of September 30:
Included in the end of year pension benefit obligations above are $8,401 at September 30, 1999, and $10,289 at September 30, 1998, relating to employees of UGI and its other subsidiaries. Included in the end of year postretirement obligations above are $580 at September 30, 1999, and $440 at September 30, 1998, relating to employees of UGI.
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:
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employee Benefit Trust ("VEBA") 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 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 money market funds.
The assumed health care cost trend rate at September 30, 1999 and 1998 was 6.0%, decreasing to 5.5% in fiscal 2008. A one percentage point charge in the assumed health care cost trend rate would change the 1999 postretirement benefit cost and obligation as follows:
1% 1% Increase Decrease -------- --------
Effect on total service and interest costs $ 151 $ (132) Effect on postretirement benefit obligation 1,934 (1,690)
We also sponsor unfunded retirement benefit plans for certain key employees. At September 30, 1999 and 1998, the projected benefit obligations of these plans were not material. We recorded expense for these plans of $637 in 1999, $1,101 in 1998, and $244 in 1997.
DEFINED CONTRIBUTION PLANS
We sponsor a 401(k) savings plan for eligible employees ("Utilities Savings Plan"). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. We may, at our discretion, match a portion of participants'
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
contributions. The cost of benefits under the savings plans totaled $885 in 1999, $987 in 1998, and $880 in 1997.
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, 1999 and 1998, 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, data processing and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $5,103 in 1999, $5,278 in 1998, and $5,083 in 1997.
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: 2000 - $4,080; 2001 - $3,627; 2002 - $3,170; 2003 - $2,052; 2004 - $1,281; after 2004 - $1,902.
Gas Utility has gas supply agreements with producers and marketers that expire at various dates through 2000. Gas Utility also has agreements for firm pipeline transportation and storage capacity which Gas Utility may terminate at various dates through 2015. In addition, Gas Utility
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
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.
Prior to August 1, 1999, Pennsylvania Power & Light Company ("PP&L"), pursuant to a 1992 power supply agreement for bundled energy and capacity, supplied all of Electric Utility's electric power requirements above that provided by other sources. As part of a settlement of all disputes concerning the 1992 power supply agreement, Electric Utility and PP&L entered into a new power supply agreement under which, from August 1, 1999 through February 28, 2001, PP&L will supply all of Electric Utility's capacity requirements in excess of its capacity resources acquired from other sources, and from January 1, 2000 through December 31, 2000 will supply 32 megawatts of energy in each hour of the day. The energy purchased from PP&L will replace a fixed price power supply agreement with the Montgomery County (Maryland) Resource Recovery Facility, which contract expires on December 31, 1999. In high usage months, Electric Utility meets its electric power needs, above those provided by these contracts and its own generation facilities through monthly market based contracts and through spot purchases at market prices as delivered.
The gas distribution business has been one of UGI Utilities' main businesses since it began in 1882. Prior to the construction of major natural gas pipelines in the 1950s, gas used for lighting and heating was produced at MGPs from processes involving coal, coke or oil. Some constituents of coal tars produced from this process are today considered hazardous substances under the Superfund Law and may be located at these sites.
Certain private parties have filed, or threatened to file, suit against UGI Utilities to recover costs of investigation or remediation of several manufactured gas plant ("MGP") sites. In addition, we have identified environmental contamination at several of our properties and have voluntarily undertaken investigation and, as appropriate, remediation of these sites in cooperation with appropriate environmental agencies or private parties.
At sites where a former subsidiary of UGI Utilities operated a MGP, we believe that UGI Utilities should not have significant liability because UGI Utilities generally is not legally liable for the obligations of its subsidiaries. Under certain circumstances, however, a court could find a parent company liable for environmental damage at sites owned by a subsidiary company when the parent company either (1) itself operated the facility causing the environmental damage or (2) otherwise so controlled the subsidiary that the subsidiary's separate corporate form should be disregarded. There could be, therefore, significant future costs of an uncertain amount associated with environmental damage caused by MGPs that UGI Utilities owned or directly operated, or that were owned or operated by former subsidiaries of UGI Utilities, if a court were to conclude that the subsidiary's separate corporate form should be disregarded. In many circumstances where UGI Utilities may be liable, we may not be able to reasonably quantify expenditures because of a number of factors. These factors include the various costs associated with potential remedial alternatives, the unknown number of other potentially responsible parties involved and their ability to contribute to the costs of investigation and remediation, and changing environmental laws and regulations.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
UGI Utilities has filed suit against more than fifty insurance companies alleging that the defendants breached contracts of insurance by failing to indemnify UGI Utilities for certain environmental costs. The suit seeks to recover more than $11,000 in costs incurred by UGI Utilities at various manufactured gas plant sites. The parties to the suit are in the early stages of exchanging information.
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. Management believes, 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 but could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows.
9. FINANCIAL INSTRUMENTS
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 $175,000 at September 30, 1999 and $193,000 at September 30, 1998. 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 $21,000 at September 30, 1999 and $24,000 at September 30, 1998. 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, 1999 and 1998, we had no significant concentrations of credit risk.
10. SEGMENT INFORMATION
We adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131") in fiscal 1999. SFAS 131 establishes standards for reporting information about operating segments as well as related disclosures about products and services, geographic areas, and major customers. In determining our reportable segments under the provisions of SFAS 131, we examined the way we organize our businesses for making operating decisions and assessing business performance. Based upon the guidance provided by SFAS 131, we have determined that UGI Utilities has two reportable segments comprising Gas Utility and Electric Utility. The adoption of SFAS 131 did not change the operating segments we disclose. However, Gas Utility and Electric Utility results for all periods presented now include billed UGI corporate overhead costs.
UGI UTILITIES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Although the Electricity Customer Choice Act unbundled prices for electric generation, transmission and distribution services, we currently manage and evaluate our electric generation, transmission and distribution operations on a combined basis. Accordingly, these operations are combined for segment presentation purposes.
The accounting policies of our two reportable segments are the same as those described in Note 1 of Consolidated Financial Statements. We evaluate Gas Utility's and Electric Utility's performance principally based upon their earnings before income taxes.
No single customer represents more than 5% of the total revenues of either Gas Utility or Electric Utility. Financial information by business segment follows:
(1) Earnings before interest expense, income taxes, depreciation and amortization (EBITDA) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under generally accepted accounting principles.
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. RELATED PARTY TRANSACTIONS
UGI bills UGI Utilities for an allocated share of its general corporate expenses. These billed expenses are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income.
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
EXHIBIT NO. DESCRIPTION - ----------- -----------
10.19 Consulting Services Agreement dated as of March 1, 1999 between UGI Utilities, Inc. and Richard L. Bunn
12.1 Computation of Ratio of Earnings to Fixed Charges
12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
23 Consent of Arthur Andersen LLP
27 Financial Data Schedule