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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 1999
Commission file number 1-1398
UGI UTILITIES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Pennsylvania 23-1174060
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER IDENTIFICATION NO.)
OF INCORPORATION OR ORGANIZATION)
100 Kachel Boulevard, Suite 400, Green Hills Corporate Center
Reading, PA 19607
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(610) 796-3400
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED
TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING
THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS
REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING
REQUIREMENTS FOR THE PAST 90 DAYS. YES X . NO .
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
At December 1, 1999 there were 26,781,785 shares of UGI Utilities Common Stock,
par value $2.25 per share, outstanding, all of which were held, beneficially and
of record, by UGI Corporation.
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TABLE OF CONTENTS
PART I BUSINESS PAGE
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Items 1 and 2 Business and Properties................................................... 1
General................................................................. 1
Gas Utility Operations.................................................. 1
Electric Utility Operations............................................. 4
Item 3 Legal Proceedings......................................................... 9
Item 4 Submission of Matters to a Vote of
Security Holders........................................................ 12
PART II SECURITIES AND FINANCIAL INFORMATION
Item 5 Market for Registrant's Common Equity
and Related Stockholder Matters......................................... 12
Item 6 Selected Financial Data................................................... 13
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations....................................... 14
Item 7A Quantitative and Qualitative Disclosures About Market Risk................ 24
Item 8 Financial Statements and Supplementary Data............................... 24
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.................................. 24
PART III UGI UTILITIES, INC. MANAGEMENT AND SECURITY HOLDERS
Item 10 Directors and Executive Officers of the Registrant........................ 25
Item 11 Executive Compensation.................................................... 30
Item 12 Security Ownership of Certain Beneficial
Owners and Management................................................... 39
Item 13 Certain Relationships and Related
Transactions............................................................ 41
PART IV ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
Item 14 Exhibits, Financial Statement Schedules
and Reports on Form 8-K................................................. 41
Signatures................................................................ 45
Index to Financial Statements and
Financial Statement Schedule.............................................. F-2
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PART I: BUSINESS
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. ("Utilities" or the "Company") is a public utility
company that owns and operates (i) a natural gas distribution utility serving 14
counties in eastern and southeastern Pennsylvania ("Gas Utility"), and (ii) an
electric utility serving parts of Luzerne and Wyoming counties in northeastern
Pennsylvania ("Electric Utility"). Effective October 1, 1999, we transferred our
electric generation assets to our non-utility subsidiary, UGI Development
Company ("UGID"). We are a wholly owned subsidiary of UGI Corporation ("UGI").
Utilities was incorporated in Pennsylvania in 1925 as the successor to
a business founded in 1882. We are subject to regulation by the Pennsylvania
Public Utility Commission ("PUC"). Utilities' executive offices are located at
100 Kachel Boulevard, Suite 400, Green Hills Corporate Center, Reading,
Pennsylvania 19607, and its telephone number is (610) 796-3400. In this report,
the terms "Company" and "Utilities," as well as the terms, "our," "we," and
"its," are sometimes used to refer to UGI Utilities, Inc. or, collectively, UGI
Utilities, Inc. and its consolidated subsidiaries.
GAS UTILITY OPERATIONS
SERVICE AREA; REVENUE ANALYSIS
Gas Utility distributes natural gas to approximately 265,000 customers
in portions of 14 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 4,400 miles of gas mains. The service area
consists of approximately 3,000 square miles and includes the cities of
Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon and
Reading, Pennsylvania. Located in Gas Utility's service area are major
production centers for basic industries such as specialty metals, aluminum and
glass. For the fiscal years ended September 30, 1999, 1998 and 1997, revenues of
Gas Utility accounted for approximately 82%, 83% and 84%, respectively, of our
total consolidated revenues.
System throughput (the total volume of gas sold to or transported for
customers within Gas Utility's distribution system) for the 1999 fiscal year was
approximately 76.1 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 40% of system throughput, while gas transported for commercial and
industrial customers (who bought their gas from others) accounted for
approximately 60% of system throughput. Based on industry data for 1998,
residential customers account for approximately 35% of total system throughput
by local gas distribution companies in the United States. By contrast, for the
1999 fiscal year, Gas Utility's residential customers represented 23% of its
total system throughput.
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SOURCES OF SUPPLY AND PIPELINE CAPACITY
Gas Utility meets its service requirements by utilizing a diverse mix
of natural gas purchase contracts with producers and marketers, storage and
transportation services from pipeline companies, and its own propane-air and
liquefied natural gas peak-shaving facilities. Purchases of natural gas in the
spot market are also made to reduce costs and manage storage inventory levels.
These arrangements enable Gas Utility to purchase gas from Gulf Coast,
Mid-Continent, Appalachian and Canadian sources. For the transportation and
storage function, Utilities has agreements with a number of pipeline companies,
including Texas Eastern Transmission Corporation, Columbia Gas Transmission
Corporation and Transcontinental Gas Pipeline Corporation.
GAS SUPPLY CONTRACTS
During the 1999 fiscal year, Gas Utility purchased approximately 32.5
bcf of natural gas and sold approximately 30.6 bcf to customers. Gas not sold to
customers was used by Gas Utility principally for its own needs or was placed in
storage for later sale to customers. Approximately 30.2 bcf or 93% of the
volumes purchased were supplied under agreements with six major suppliers of
natural gas. The remaining 2.3 bcf or 7% of gas purchased was supplied by
producers and marketers under other arrangements, including multi-month
agreements at spot prices. In fiscal year 2000, Gas Utility expects to obtain
necessary gas supplies under contracts no longer than 12 months in duration. See
"Natural Gas Choice and Competition Act."
SEASONAL VARIATION
Because many of its customers use gas for heating purposes, Gas
Utility's sales are seasonal, with approximately 58% of fiscal year 1999
throughput and approximately 74% of earnings before interest expense, income
taxes, depreciation and amortization occurring during the winter season from
November through March.
COMPETITION
Natural gas is a fuel that competes with electricity and oil, and to a
lesser extent, with propane and coal. Competition among these fuels is primarily
a function of their comparative price and the relative cost and efficiency of
fuel utilization equipment. Electric utilities in Gas Utility's service area are
seeking new load, primarily in the new construction market. Competition with
fuel oil dealers is focused on industrial customers. Gas Utility responds to
this competition with marketing efforts designed to retain and grow its customer
base.
In substantially all of its service territory, Gas Utility is the only
regulated gas distribution utility having the right, granted by the PUC or by
law, to provide transportation services. While unregulated gas marketers have
been selling gas to commercial and industrial customers in Gas Utility's service
territory for over 14 years, Gas Utility provides transportation services for
those sales. Pennsylvania has enacted legislation which requires a customer
choice option for retail purchasers of natural gas. See "Natural Gas Choice and
Competition Act."
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Commercial and industrial customers representing approximately 42% of
Gas Utility's transportation system throughput (22% of transportation revenues)
have the ability to switch to an alternate fuel at any time and, therefore, are
served on an interruptible basis under rates which are competitively priced with
respect to their alternate fuel. Gas Utility's margins from these customers,
therefore, are affected by the difference, or "spread," between the customers'
delivered cost of gas and the customers' delivered alternate fuel cost. In
addition, other customers representing 31% of transportation system throughput
(19% of transportation revenues) have locations which afford them the option,
although none has exercised it, of seeking transportation service directly from
interstate pipelines, thereby bypassing Gas Utility. The majority of customers
in the latter group are served under transportation contracts having three- to
ten-year terms. Included in these two groups are Utilities' ten largest
customers in terms of annual volume. All of these customers have contracts with
Utilities, seven of which extend into fiscal year 2002. No single customer
represents, or is anticipated to represent, more than 1% of the total revenues
of Gas Utility.
OUTLOOK FOR GAS SERVICE AND SUPPLY
Gas Utility anticipates having adequate pipeline capacity and sources
of supply available to it to meet the full requirements of all firm customers on
its system through fiscal year 2000. Supply mix is diversified, market priced,
and delivered pursuant to a number of long- and short-term firm transportation
and storage arrangements, including transportation contracts held by some of
Utilities' larger customers. Gas Utility also operates propane air and liquefied
natural gas facilities to meet winter peak service requirements.
During the 1999 fiscal year, Gas Utility supplied transportation
service to three major cogeneration installations and two utility generation
sites. Gas Utility continues to pursue opportunities to supply natural gas to
electric generation projects located in its service territory. Gas Utility also
continues to seek new residential, commercial and industrial customers for both
firm and interruptible service. In the residential market sector, Gas Utility
connected 7,130 additional residential heating customers during the 1999 fiscal
year, a modest increase from the previous year. Of those new customers, new home
construction accounted for a record 5,692 heating customers, an increase of
approximately 16% from the prior year. Customers converting from other energy
sources, primarily oil, and existing non-heating gas customers who have added
gas heating systems to replace other energy sources, accounted for the balance
of the additions. The total number of new commercial and industrial customers
was 1,174.
Utilities continues to monitor and participate extensively in
third-party proceedings before the Federal Energy Regulatory Commission ("FERC")
affecting the rates and the terms and conditions under which Gas Utility
transports and stores natural gas. Among these proceedings are those arising out
of certain FERC orders and/or pipeline filings which relate to (i) the relative
pricing of pipeline services in a competitive energy marketplace; (ii) the
flexibility of the terms and conditions of pipeline service contracts; and (iii)
pipelines' requests to increase their base rates, or change the terms and
conditions of their storage and transportation services.
Gas Utility's objective in negotiations with interstate pipeline and
natural gas suppliers, and in litigation before regulatory agencies, is to
assure availability of supply, transportation and storage alternatives to serve
market requirements at the lowest cost possible, taking into account the need
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for security of supply. Consistent with that objective, Gas Utility negotiates
the terms of firm transportation capacity on all pipelines serving Gas Utility,
arranges for appropriate storage and peak-shaving resources, negotiates with
producers for competitively priced gas purchases and aggressively participates
in regulatory proceedings related to transportation rights, costs of service and
gas costs.
NATURAL GAS CHOICE AND COMPETITION ACT
Since December 1982, Gas Utility has provided transportation service
for commercial and industrial customers who purchase their gas from others. As
noted earlier, this unbundled service accounted for approximately 60% of Gas
Utility's system throughput in fiscal year 1999.
In June 1999, Governor Ridge signed into law the Natural Gas Choice and
Competition Act ("Gas Competition Act") which requires local natural gas
distribution companies to extend the availability of gas transportation service
to residential and small commercial customers by July 1, 2000 pursuant to a
PUC-approved plan. Gas Utility submitted its plan to the PUC on October 1, 1999.
We expect the PUC to act on the plan in the spring of 2000. Gas Utility designed
its plan to ensure reliability of gas supply deliveries to Gas Utility on behalf
of residential and small commercial customers. The plan also provides for
recovery of costs associated with Gas Utility's existing pipeline capacity and
gas supply contracts. If the plan is approved substantially as filed, we do not
expect that the Gas Competition Act will have a material adverse impact on our
financial condition or results of operations. See Note 2 to the Consolidated
Financial Statements.
ELECTRIC UTILITY OPERATIONS
ELECTRICITY GENERATION CUSTOMER CHOICE AND COMPETITION ACT
On January 1, 1997, Pennsylvania's Electricity Generation Customer
Choice and Competition Act (Electricity Customer Choice Act) became effective.
The Electricity Customer Choice Act permits all Pennsylvania retail electric
customers to choose their electric generation supplier. Pursuant to the Act, all
electric utilities were required to file restructuring plans with the PUC which,
among other things, included unbundled prices for electric generation,
transmission and distribution and a competitive transition charge (CTC) for the
recovery of "stranded costs" which would be paid by all customers receiving
distribution service. Stranded costs generally are electric generation-related
costs that traditionally would be recoverable in a regulated environment but may
not be recoverable in a competitive electric generation market. Under the
Electricity Customer Choice Act, Electric Utility's rates for transmission and
distribution services provided through June 30, 2001 are capped at levels in
effect on January 1, 1997. In addition, Electric Utility generally may not
increase prices for electric generation as long as stranded costs are being
recovered through the CTC. In accordance with the restructuring proceedings
discussed below, Utilities expects to collect a CTC from all distribution
customers until December 31, 2002. Electric Utility will continue to be the only
regulated electric utility having the right, granted by the PUC or by law, to
distribute electric energy in its service territory.
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On June 19, 1998, the PUC entered its Opinion and Order (the
"Restructuring Order") in Electric Utility's restructuring proceeding under the
Electricity Customer Choice Act. The Restructuring Order authorized Electric
Utility to recover from its customers approximately $32.5 million in stranded
costs (on a full revenue requirements basis, which includes all income and gross
receipts taxes) over a four-year period commencing January 1, 1999 through a
CTC, together with carrying charges on unrecovered balances of 7.94%. Electric
Utility's recoverable stranded costs include approximately $8.7 million for the
termination of a 1993 power purchase agreement with Foster Wheeler Penn
Resources, Inc., an independent power producer. Since January 1, 1999, all of
Electric Utility's customers have been permitted to select an alternative
electric generation supplier. Customers choosing another supplier currently
receive an average generation "shopping credit" (developed from system-wide
generation rates) of 3.67 cents per kilowatt hour ("kwh"), which will remain in
effect through December 31, 2000. The shopping credit will increase to 4.3 cents
per kwh in calendar years 2001 and 2002.
As noted above, Electric Utility's power generation rates are capped
until December 31, 2002. Because Electric Utility has discontinued regulatory
accounting, which permitted it to adjust customer charges to reflect changes in
Electric Utility's power costs, quarterly results have been, and future results
are likely to be, more volatile, due in large part to seasonal variations in
such costs. Results will also be affected by the number of customers who choose
to purchase their power from other suppliers during any given time period.
During fiscal 1999, Utilities received PUC approval to transfer its electric
generation assets to a non-utility subsidiary. These electric generation assets,
consisting principally of Utilities' Hunlock generating station and its 1.11%
interest in the Conemaugh generating station, were transferred effective October
1, 1999 to UGID, a wholly-owned subsidiary of Utilities. UGID has been granted
"Exempt Wholesale Generator" status by FERC.
SERVICE AREA; REVENUE ANALYSIS
Electric Utility supplies electric service to approximately 61,000
customers in portions of Luzerne and Wyoming Counties in northeastern
Pennsylvania through a system consisting of approximately 2,100 miles of
transmission and distribution lines and 14 transmission substations. For the
1999 fiscal year, about 52% of sales volume came from residential customers, 35%
from commercial customers and 13% from industrial customers. Electricity
transported for customers who purchased their power from others pursuant to the
Electricity Customer Choice Act represented approximately 5% of this sales
volume. For the 1999, 1998 and 1997 fiscal years, revenues of Electric Utility
accounted for approximately 18%, 17%, and 16%, respectively, of our total
consolidated revenues.
SOURCES OF SUPPLY
Electric Utility distributes both electricity that it purchases from
others (including UGID) and, since November 1, 1997, electricity that customers
purchase from other suppliers. Through UGID, Utilities owns and operates the
Hunlock generating station located near Kingston, Pennsylvania ("Hunlock
Station"); it also has a 1.11% ownership interest in the Conemaugh generating
station located near Johnstown, Pennsylvania ("Conemaugh Station"), which is
operated by another utility. These two coal-fired stations can generate up to 69
megawatts of electric power
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for Electric Utility and provided approximately 50% of its energy requirements
during the 1999 fiscal year.
Effective August 1, 1999, Utilities and PP&L terminated their 1992
power supply agreement and entered into a new agreement. Through December 2000,
PP&L will supply approximately 30% of Electric Utility's energy requirements
and, through February 2001, PP&L will supply all of Electric Utility's capacity
requirements in excess of its capacity from other sources. Electric Utility
expects to enter into short-term contracts to meet the balance of its energy
needs.
UGID is evaluating the potential of the Hunlock Station site, and
currently expects to operate the Hunlock plant through the next few years.
Decisions regarding the operation of Hunlock Station will be highly dependent on
market prices for power.
ENVIRONMENTAL FACTORS
The operation of Hunlock Station complies with the air quality
standards of the Pennsylvania Department of Environmental Resources ("DER") with
respect to stack emissions. Under the Federal Water Pollution Control Act,
Utilities has a permit from the DER to discharge water from Hunlock Station into
the North Branch of the Susquehanna River.
The Federal Clean Air Act Amendments of 1990 (the "Clean Air Act
Amendments") impose emissions limitations for certain compounds, including
sulfur dioxide and nitrous oxides. Both the Conemaugh Station and the Hunlock
Station are in material compliance with these emission standards.
More stringent regulation of nitrous oxide emissions at both Hunlock
and Conemaugh Stations may be required due to the actions of the Northeast Ozone
Transport Commission. The Commission was created by the Clean Air Act Amendments
to provide a plan to reduce ground level ozone in the Northeast to a level
acceptable to the U.S. Environmental Protection Agency. Future actions of the
Commission may cause the DER to modify its regulations for nitrous oxides and
thereby affect the compliance plans of Hunlock and Conemaugh Stations.
SEASONALITY
Sales and distribution of electricity for residential heating purposes
accounted for approximately 20% of the total sales of Electric Utility during
the 1999 fiscal year. Electricity competes with natural gas, oil, propane and
other heating fuels in this use. Approximately 53% of volume occurred during the
six coldest months of the 1999 fiscal year (November through April),
demonstrating modest seasonality favoring winter due to the use of electricity
for residential heating purposes.
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UTILITY REGULATION AND RATES
PENNSYLVANIA PUBLIC UTILITY COMMISSION JURISDICTION
Utilities' gas and electric utility operations, which exclude electric
generation, are subject to regulation by the PUC as to rates, terms and
conditions of service, accounting matters, issuance of securities, contracts and
other arrangements with affiliated entities, and various other matters. As noted
earlier, effective October 1, 1999 Utilities transferred its electric generation
assets to UGID. UGID has FERC authority to sell power at market-based rates.
Generally, UGID is not subject to regulation by the PUC.
FERC ORDERS 888 AND 889
In April 1996, FERC issued Orders No. 888 and 889 which established
rules for the use of electric transmission facilities for wholesale
transactions. FERC has also asserted jurisdiction over the transmission
component of electric retail choice transactions. In compliance with these
orders, the PJM Interconnection, LLC ("PJM"), of which Utilities is a member,
has filed an open access transmission tariff with the FERC establishing
transmission rates and procedures for transmission within the PJM control area.
Under the PJM tariff and associated agreements, Electric Utility is entitled to
receive certain revenues when its transmission facilities are used by third
parties.
PURCHASED GAS COST RATES
Gas Utility's gas service tariff contains Purchased Gas Cost ("PGC")
rates which provide for annual increases or decreases in the rate per thousand
cubic feet ("mcf") which Gas Utility charges for natural gas sold by it, to
reflect Utilities' projected cost of purchased gas. PGC rates may also be
adjusted quarterly, or monthly, to reflect purchased gas costs. Each proposed
PGC rate is required to be filed with the PUC six months prior to its effective
date. During this period the PUC holds hearings to determine whether the
proposed rate reflects a least-cost fuel procurement policy consistent with the
obligation to provide safe, adequate and reliable service. After completion of
these hearings, the PUC issues an order permitting the collection of gas costs
at levels which meet that standard. The PGC mechanism also provides for an
annual reconciliation. Utilities has two PGC rates. PGC (1) is applicable to
small, firm, core market customers consisting of the residential and small
commercial and industrial classes; PGC (2) is applicable to firm, contractual,
high-load factor customers served on three separate rates. In addition,
residential customers maintaining a high load factor may qualify for the PGC (2)
rate.
ENERGY COST RATES
In accordance with provisions of the Electricity Customer Choice Act,
the PUC approved Electric Utility's application to roll its energy cost rate
("ECR") into its base rates effective as of May 2, 1997, at a combined level not
to exceed the rate cap established as of January 1, 1997. Before January 1,
1997, the ECR permitted Electric Utility to adjust customer charges to reflect
annual changes in the cost of purchased power, fuel, interchange power and the
cost of transmitting power purchased from external sources. Electric Utility may
no longer adjust customer charges to reflect changes in such costs.
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BASE RATES
Gas Utility's current base rates have been in effect since August 31,
1995. Rates for total non-gas charges to retail customers are currently capped
through December 31, 2000 pursuant to the Gas Competition Act. Electric
Utility's current base rates have been in effect since July 19, 1996 and are
capped through June 2001 pursuant to the Electricity Customer Choice Act. See
Note 2 to the Consolidated Financial Statements.
STATE TAX SURCHARGE CLAUSES
Utilities' gas and electric service tariffs contain state tax surcharge
clauses. The surcharges are recomputed whenever any of the tax rates included in
their calculation are changed. These clauses protect Utilities from the effect
of increases in most of the Pennsylvania taxes to which it is subject, however,
any increase in Electric Utility's state tax surcharge is generally subject to
the rate caps discussed above.
UTILITY FRANCHISES
Utilities holds certificates of public convenience issued by the PUC
and certain "grandfather rights" predating the adoption of the Pennsylvania
Public Utility Code and its predecessor statutes which it believes are adequate
to authorize it to carry on its business in substantially all the territory to
which it now renders gas and electric service. Under applicable Pennsylvania
law, Utilities also has certain rights of eminent domain as well as the right to
maintain its facilities in streets and highways in its territories.
OTHER GOVERNMENT REGULATION
In addition to regulation by the PUC, the gas and electric utility
operations of Utilities are subject to various federal, state and local laws
governing environmental matters, occupational health and safety, pipeline safety
and other matters. Certain of Utilities' activities involving the interstate
movement of natural gas, the transmission of electricity, transactions with
non-utility generators of electricity, like UGID, and other matters, are also
subject to the jurisdiction of FERC.
Utilities is subject to the requirements of the federal Resource
Conservation and Recovery Act, Comprehensive Environmental Response,
Compensation and Liability Act ("Superfund Law") and comparable state statutes
with respect to the release of hazardous substances on property owned or
operated by Utilities. See ITEM 3. "LEGAL PROCEEDINGS - Environmental Matters -
Manufactured Gas Plants." The electric generation activities of Utilities are
also subject to the Clean Air Act Amendments, the Federal Water Pollution
Control Act and comparable state statutes and regulations. See "UTILITY
OPERATIONS - Generation and Distribution of Electricity Environmental-Factors."
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BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to Utilities' operating segments for the 1999,
1998 and 1997 fiscal years appears in Note 10 "Segment Information" of Notes to
Consolidated Financial Statements included in this Report and is incorporated
herein by reference.
EMPLOYEES
At September 30, 1999, Utilities and its subsidiaries had 1,138
employees.
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
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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
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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.
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<PAGE> 14
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. 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.
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<PAGE> 15
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended
September 30,
-----------------------------------------------------------------------------
1999 1998 1997 1996 1995
--------- --------- --------- --------- ---------
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
FOR THE PERIOD:
INCOME STATEMENT DATA:
Revenues $ 420,647 $ 422,283 $ 461,208 $ 460,496 $ 357,364
========= ========= ========= ========= =========
Income before accounting change $ 38,868 $ 35,551 $ 38,711 $ 38,348 $ 28,018
Change in accounting for
postemployment benefits -- -- -- -- (1,028)
--------- --------- --------- --------- ---------
Net income 38,868 35,551 38,711 38,348 26,990
Dividends on preferred stock 1,550 2,160 2,764 2,765 2,778
--------- --------- --------- --------- ---------
Net income after dividends
on preferred stock $ 37,318 $ 33,391 $ 35,947 $ 35,583 $ 24,212
========= ========= ========= ========= =========
AT PERIOD END:
BALANCE SHEET DATA:
Total assets $ 712,533 $ 690,317 $ 681,378 $ 649,899 $ 661,480
========= ========= ========= ========= =========
Capitalization:
Debt:
Bank loans $ 87,400 $ 68,400 $ 67,000 $ 50,500 $ 42,000
Long-term debt including
current maturities: 180,047 187,170 169,294 176,654 208,162
--------- --------- --------- --------- ---------
Total debt 267,447 255,570 236,294 227,154 250,162
Preferred stock subject to
mandatory redemption 20,000 20,000 35,187 35,187 35,202
Common equity 219,560 211,242 200,494 189,441 186,803
--------- --------- --------- --------- ---------
Total capitalization $ 507,007 $ 486,812 $ 471,975 $ 451,782 $ 472,167
========= ========= ========= ========= =========
RATIO OF CAPITALIZATION:
Total debt 52.8% 52.5% 50.0% 50.3% 53.0%
UGI Utilities preferred stock 3.9% 4.1% 7.5% 7.8% 7.4%
Common equity 43.3% 43.4% 42.5% 41.9% 39.6%
--------- --------- --------- --------- ---------
100.0% 100.0% 100.0% 100.0% 100.0%
========= ========= ========= ========= =========
</TABLE>
- 13 -
<PAGE> 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FISCAL 1999 COMPARED WITH FISCAL 1998
<TABLE>
<CAPTION>
Increase
Year Ended September 30, 1999 1998 (Decrease)
- ------------------------ ---- ---- ----------
<S> <C> <C> <C> <C>
(Millions of dollars)
GAS UTILITY:
Natural gas system throughput - bcf (a) 76.1 74.9 1.2 1.6 %
Degree days - % warmer than normal 12.8% 16.3% - -
Revenues $345.6 $350.2 $(4.6) (1.3)%
Total margin $160.6 $157.2 $ 3.4 2.2 %
EBITDA $ 87.0 $ 82.9 $ 4.1 4.9 %
Operating income $ 68.0 $ 64.8 $ 3.2 4.9 %
ELECTRIC UTILITY:
Sales - gwh (a) 900.4 876.4 24.0 2.7 %
Revenues $ 75.0 $ 72.1 $ 2.9 4.0 %
Total margin $ 38.6 $ 34.0 $ 4.6 13.5 %
EBITDA (b) $ 16.8 $ 13.6 $ 3.2 23.5 %
Operating income $ 12.8 $ 9.7 $ 3.1 32.0 %
</TABLE>
(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.
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<PAGE> 17
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.
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<PAGE> 18
Fiscal 1998 Compared with Fiscal 1997
<TABLE>
<CAPTION>
Increase
Year Ended September 30, 1998 1997 (Decrease)
- ------------------------ ---- ---- ----------
<S> <C> <C> <C> <C>
(Millions of dollars)
GAS UTILITY:
Natural gas system throughput - bcf (a) 74.9 80.2 (5.3) (6.6)%
Degree days - % warmer than normal 16.3% 4.8% - -
Revenues $350.2 $389.1 $(38.9) (10.0)%
Total margin $157.2 $168.7 $(11.5) (6.8)%
EBITDA $ 82.9 $ 87.3 $ (4.4) (5.0)%
Operating income $ 64.8 $ 70.1 $ (5.3) (7.6)%
ELECTRIC UTILITY:
Sales - gwh (a) 876.4 868.5 7.9 0.9 %
Revenues $ 72.1 $ 72.1 $ - -%
Total margin $ 34.0 $ 35.2 $ (1.2) (3.4)%
EBITDA (b) $ 13.6 $ 14.0 $ (0.4) (2.9)%
Operating income $ 9.7 $ 9.8 $ (0.1) (0.1)%
</TABLE>
(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
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<PAGE> 19
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
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<PAGE> 20
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.
<TABLE>
<CAPTION>
Year Ended September 30, 2000 1999 1998 1997
- ------------------------ ---- ---- ---- ----
(Millions of dollars) (estimate)
<S> <C> <C> <C> <C>
Gas Utility $36.6 $31.9 $32.0 $36.7
Electric Utility 6.1 4.5 5.2 5.0
----- ----- ----- -----
$42.7 $36.4 $37.2 $41.7
----- ----- ----- -----
</TABLE>
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<PAGE> 21
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
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<PAGE> 22
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,
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<PAGE> 23
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.
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<PAGE> 24
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.
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<PAGE> 25
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.
-23-
<PAGE> 26
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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the financial statement schedule set forth on
pages F-1 to F-24 and page S-1 of this report are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
-24-
<PAGE> 27
PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ---------- ---------------------------------------------
<S> <C> <C> <C>
Lon R. Greenberg 49 1994 Chairman (since August 1996) and Vice Chairman (1994
to 1996) of the Company; Chairman (since August
1996), Chief Executive Officer (since August 1995),
Director and President (since 1994) of UGI;
formerly, Senior Vice President-Legal and Corporate
Development of UGI (1989 to July 1994). Mr.
Greenberg is also a director on the Mellon PSFS
Advisory Board.
James W. Stratton 63 1979 President and Chief Executive Officer of Stratton
Management Company since 1972 (investment advisory
and financial consulting firm); Chairman and Chief
Executive Officer of EFI (financial services firm).
Director: AmeriGas Propane, Inc.; Stratton Growth
Fund; Stratton Monthly Dividend Shares, Inc.;
Stratton Small-Cap Yield Fund; Teleflex, Inc.
David I. J. Wang 67 1988 Retired; formerly, Executive Vice President-Timber
and Specialty Products and a Director of
International Paper Company (1987 to 1991).
Director: AmeriGas Propane, Inc.; BE&K Inc.;
Emsource Inc.; Forest Resources LLC.
</TABLE>
-25-
<PAGE> 28
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ---------- ---------------------------------------------
<S> <C> <C> <C>
Richard C. Gozon 61 1989 Executive Vice President of Weyerhaeuser Company
(integrated forest products company) (since 1994).
Formerly Director (1984 to 1993), President and
Chief Operating Officer of Alco Standard Corporation
(provider of paper and office products) (1988 to
1993); Executive Vice President and Chief Operating
Officer (1987); Vice President (1982 to 1988);
President (1979 to 1987) of Paper Corporation of
America. Director: AmeriGas Propane, Inc.;
AmeriSource Health Corporation; Triumph Group, Inc.
Stephen D. Ban 59 1991 President and Chief Executive Officer of Gas
Research Institute (gas industry research and
development) (since 1987); formerly Executive Vice
President of Gas Research Institute (1986); formerly
Vice President Research and Development, Bituminous
Materials, Inc. (1981). Director: Energen
Corporation.
Robert J. Chaney 57 1999 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).
</TABLE>
-26-
<PAGE> 29
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ---------- ---------------------------------------------
<S> <C> <C> <C>
Marvin O. Schlanger 51 1998 Principal in the firm of Cherry Hill Chemical
Investments, L.L.C. (management services and capital
for chemical and allied industries) (October 1998 to
present). He was President and Chief Executive
Officer (May 1998 to October 1998), Executive Vice
President and Chief Operating Officer (1994 to 1998)
and a director (1994 to 1998) of ARCO Chemical
Company. Mr. Schlanger also held the position of
Senior Vice President of ARCO Chemical Company and
President of ARCO Chemical Americas Company (1992 to
1994). Mr. Schlanger also serves as interim
President of OneChem, Ltd. Director: OneChem, Ltd.;
Wellman, Inc.
Thomas F. Donovan 66 1998 Retired; formerly Vice Chairman of Mellon Bank (1988
to 1997). Mr. Donovan continues to serve as an
advisory board member to Mellon Bank Corp. Director:
AmeriGas Propane, Inc.; Nuclear Electric Insurance
Co.; Merrill Lynch International Bank, Ltd.
</TABLE>
(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.
-27-
<PAGE> 30
EXECUTIVE OFFICERS
<TABLE>
<CAPTION>
Name Age Position
- ---- --- --------
<S> <C> <C>
Lon R. Greenberg 49 Chairman of the Board of Directors
Brendan P. Bovaird 51 Vice President and General Counsel
Robert J. Chaney 57 President and Chief Executive Officer
Mark R. Dingman 50 Vice President and General Manager-
Electric Utility Division
John C. Barney 51 Senior Vice President-Finance
</TABLE>
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).
-28-
<PAGE> 31
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).
-29-
<PAGE> 32
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
--------------------------
<TABLE>
<CAPTION>
LONG TERM COMPENSATION
---------------------------------------------
ANNUAL COMPENSATION AWARDS PAYOUTS
-------------------------------- ------------------------ ---------
SECURITIES
OTHER UNDER- ALL
ANNUAL RESTRICTED LYING OTHER
NAME AND PRINCIPAL FISCAL COMPEN- STOCK OPTIONS/ LTIP COMPEN-
POSITION YEAR SALARY BONUS (1) SATION(2) AWARDS(3) SARS PAYOUTS SATION(4)
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Lon R. Greenberg (5)(6) 1999 $587,139 $266,776 $11,359 $611,260 225,000 (7a) $0 $18,273
Chairman 1998 $559,616 $225,000 $ 8,209 $ 0 0 $0 $22,154
1997 $509,827 $425,000 $ 7,671 $ 0 200,000 (7b) $0 $14,233
Richard L. Bunn (8) 1999 $146,038 $ 50,000 $13,422 $ 0 0 $0 $93,304
President and Chief 1998 $330,801 $ 83,623 $ 9,410 $ 0 0 $0 $10,572
Executive Officer 1997 $318,089 $139,073 $ 7,696 $ 0 75,000 (6) $0 $10,254
(Retired)
Robert J. Chaney 1999 $221,445 $ 72,109 $ 7,817 $142,625 5,556 (7b) $0 $ 5,742
President and Chief 1998 $171,801 $ 33,777 $ 4,528 $ 0 8,333 (7b) $0 $ 5,023
Executive Officer 1997 $164,396 $ 51,457 $ 4,272 $ 0 35,000 (7b) $0 $ 4,921
John C. Barney 1999 $150,279 $ 33,055 $ 0 $101,875 0 $0 $ 4,156
Senior Vice President - 1998 $139,870 $ 34,412 $ 0 $ 0 0 $0 $ 3,813
Finance 1997 $135,018 $ 29,590 $ 0 $ 0 10,000 (9) $0 $ 3,649
Mark R. Dingman 1999 $139,783 $ 45,303 $ 7,723 $101,875 0 $0 $ 4,209
Vice President & 1998 $132,796 $ 47,282 $ 7,524 $ 0 0 $0 $ 3,580
General Manager, 1997 $125,298 $ 26,322 $ 6,410 $ 0 35,000 (7b) $0 $ 3,649
Electric Utility
Division
Brendan P. Bovaird (5)(6) 1999 $189,600 $ 53,048 $14,399 $142,625 0 $0 $ 5,215
Vice President and 1998 $176,677 $ 42,188 $ 4,075 $ 0 0 $0 $ 5,425
General Counsel 1997 $164,653 $ 64,449 $ 3,769 $ 0 30,000 (7b) $0 $ 4,196
</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.
-30-
<PAGE> 33
(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.
-31-
<PAGE> 34
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
<TABLE>
<CAPTION>
Grant Date
Individual Grants Value
- ----------------------------------------------------------------------------------------------- -------------------
Number of
Securities % of Total
Underlying Options Granted Grant Date
Options to Employees in Exercise Present
Name Granted Fiscal Year (1) or Base Price Expiration Date Value
- ----------------------- ------------- ---------------- ------------- ---------------- ----------------
<S> <C> <C> <C> <C> <C>
Lon R. Greenberg 225,000 (2) 97% $20.375 6/3/09 $641,857 (3a)
Richard L. Bunn 0
John C. Barney 0
Robert J. Chaney 5,556 (4) 2% $21.250 2/22/09 $ 12,704 (3b)
Mark R. Dingman 0
Brendan P. Bovaird 0
</TABLE>
(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%
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<PAGE> 35
(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.
-33-
<PAGE> 36
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
<TABLE>
<CAPTION>
Value Of
Number Of Securities Unexercised
Underlying Unexercised In-The-Money
Options/SARs Options/SARs
At Fiscal Year-End (#) At Fiscal Year-End
Shares ---------------------------- ------------------------------
Acquired on Value
Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable
- -------------------------- ------------ ----------- ------------ -------------- -------------- --------------
<S> <C> <C> <C> <C> <C> <C>
93,959 (4) 225,000 (2) $293,622 (5) $646,875 (3)
Lon R. Greenberg (1) 0 $ 0 200,000 (2) 0 $125,000 (6)
Richard L. Bunn 0 $ 0 75,000 (2) 0 $ 46,875 (6) $ 0
John C. Barney 0 $ 0 10,000 (8) 0 $ 6,250 (6) $ 0
5,556 (2) 0 $ 11,112 (9) $ 0
Robert J. Chaney (1) 0 $ 0 43,639 (4) 0 $136,372 (5)
35,000 (2) 0 $ 21,875 (6)
8,333 (2) 0 $ 7,291 (7)
Mark R. Dingman 0 $ 0 35,000 (2) 0 $ 21,875 (6) $ 0
Brendan P. Bovaird (1) 0 $ 0 5,007 (4) 0 $ 15,647 (5) $ 0
30,000 (2) 0 $ 18,750 (6)
</TABLE>
(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).
-34-
<PAGE> 37
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
<TABLE>
<CAPTION>
FINAL 5-YEAR
AVERAGE ANNUAL ANNUAL BENEFIT FOR YEARS OF CREDITED SERVICE SHOWN (1)
EARNINGS (2) ---------------------------------------------------------------------------------------
15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS 40 YEARS
--------- -------- -------- -------- -------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
$ 100,000 $28,500 $38,000 $47,500 $57,000 $66,500 $68,400 (3)
$ 200,000 $57,000 $76,000 $95,000 $114,000 $133,000 $136,800 (3)
$ 300,000 $85,500 $114,000 $142,500 $171,000 $199,500 $205,200 (3)
$ 400,000 $114,000 $152,000 $190,000 $228,000 $266,000 $273,600 (3)
$ 500,000 $142,500 $190,000 $237,500 $285,000 $332,500 $342,000 (3)
$ 600,000 $171,000 $228,000 $285,000 $342,000 $399,000 $410,400 (3)
$ 700,000 $199,500 $266,000 $332,500 $399,000 $465,500 $478,800 (3)
$ 800,000 $228,000 $304,000 $380,000 $456,000 $532,000 $547,200 (3)
$ 900,000 $256,500 $342,000 $427,500 $513,000 $598,500 $615,600 (3)
$1,000,000 $285,000 $380,000 $475,000 $570,000 $665,000 $684,000 (3)
$1,200,000 $342,000 $456,000 $570,000 $684,000 $798,000 $820,800 (3)
$1,400,000 $399,000 $532,000 $665,000 $798,000 $931,000 $957,600 (3)
</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.
-35-
<PAGE> 38
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
-36-
<PAGE> 39
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.
-37-
<PAGE> 40
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.
-38-
<PAGE> 41
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
<TABLE>
<CAPTION>
Number of Shares and
Nature of Beneficial Number of
Ownership Excluding Exercisable Stock
Name of Beneficial Owner Options (1) (2) Options Total
- ------------------------ --------------------- ------- -----
<S> <C> <C> <C>
Stephen D. Ban 11,879 (3) 2,900 14,779
John C. Barney 7,902 (9) 10,000 17,902
Brendan P. Bovaird 23,054 (4) 35,007 58,061
Richard L. Bunn 62,216 (5) 75,000 137,216
Robert J. Chaney 16,720 (6) 92,528 109,248
Mark R. Dingman 12,408 35,000 47,408
Thomas F. Donovan 2,963 0 2,963
Richard C. Gozon 17,663 5,000 22,663
Lon R. Greenberg 125,438 (7) 293,959 419,397
Marvin O. Schlanger 4,045 0 4,045
James W. Stratton 11,171 5,000 16,171
David I. J. Wang 23,187 5,000 28,187
All directors and executive
officers as a group (12) 318,646 559,394 878,040 (8)
</TABLE>
(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
-39-
<PAGE> 42
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.
-40-
<PAGE> 43
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. 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.
-41-
<PAGE> 44
(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
<TABLE>
<CAPTION>
Exhibit No. Exhibit Registrant Filing Exhibit
----------- ------- ---------- ------ -------
<S> <C> <C> <C> <C>
3.1 Utilities' Articles of Incorporation Utilities Form 8-K 4(a)
(9/22/94)
3.2 Bylaws of UGI Utilities as in effect since September Utilities Form 10-K 3.2
26, 1995 (9/30/95)
4 Instruments defining the rights of security holders,
including indentures. (The Company agrees to furnish
to the Commission upon request a copy of any
instrument defining the rights of holders of its
long-term debt not required to be filed pursuant to
the description of Exhibit 4 contained in Item 601 of
Regulation S-K)
4.1 Utilities' Articles of Incorporation and Bylaws
referred to in Exhibit Nos. 3.1 and 3.2
4.2 Indenture between Utilities and First Union National UGI Form 10-K (4)e
Bank (formerly, First Fidelity Bank, N.A. (9/30/93)
Pennsylvania,) Trustee, dated as of August 1, 1993 and
related 6.5% Note due 2003
4.3 Form of Fixed Rate Medium-Term Note Utilities Form 8-K (4)i
(8/26/94)
4.4 Form of Fixed Rate Series B Medium-Term Note Utilities Form 8-K 4(i)
(8/1/96)
4.5 Form of Floating Rate Series B Medium-Term Note Utilities Form 8-K 4(ii)
(8/1/96)
4.6 (Intentionally left blank)
4.7 Officer's Certificate establishing Medium-Term Notes Utilities Form 8-K 4(iv)
series (8/26/94)
4.8 Calculation Agent Agreement dated August 1, 1996 Utilities Form 8-K 4(iii)
between UGI Utilities, Inc. and First Union National (8/1/96)
Bank
4.9 Form of Officer's Certificate establishing Series B Utilities Form 8-K 4(iv)
Medium-Term Notes under the Indenture (8/1/96)
</TABLE>
-42-
<PAGE> 45
INCORPORATION BY REFERENCE
<TABLE>
<CAPTION>
Exhibit No. Exhibit Registrant Filing Exhibit
----------- ------- ---------- ------ -------
<S> <C> <C> <C> <C>
10.1 Service Agreement (Rate FSS) dated as of November 1, UGI Form 10-K 10.5
1989 between Utilities and Columbia, as modified (9/30/95)
pursuant to the orders of the Federal Energy Regulatory
Commission at Docket No. RS92-5-000 reported at Columbia Gas
Transmission Corp., 64 FERC Section 61,060 (1993), order on
rehearing, 64 FERC Section 61,365 (1993)
10.2 Service Agreement (Rate FTS) dated June 1, 1987 Utilities Form 10-K (10)o.
between Utilities and Columbia, as modified by (12/31/90)
Supplement No. 1 dated October 1, 1988; Supplement No.
2 dated November 1, 1989; Supplement No. 3 dated
November 1, 1990; Supplement No. 4 dated November 1,
1990; and Supplement No. 5 dated January 1, 1991, as
further modified pursuant to the orders of the Federal
Energy Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
Section 61,060 (1993), order on rehearing, 64 FERC
Section 61,365 (1993)
10.3 Transportation Service Agreement (Rate FTS-1) dated Utilities Form 10-K (10)p.
November 1, 1989 between Utilities and Columbia Gulf (12/31/90)
Transmission Company, as modified pursuant to the orders of the
Federal Energy Regulatory Commission in Docket No. RP93-6-000
reported at Columbia Gulf Transmission Co., 64 FERC
Section 61,060 (1993), order on rehearing, 64 FERC
Section 61,365 (1993)
10.4** UGI Corporation 1992 Directors' Stock Plan UGI Form 10-Q (10)ff
(6/30/92)
10.5** UGI Corporation Directors Deferred Compensation Plan UGI Form 10-K 10.39
dated August 26, 1993 (9/30/94)
10.6** UGI Corporation Directors' Equity Compensation Plan UGI Form 10-Q 10.1
(3/31/97)
10.7** UGI Corporation 1992 Stock Option and Dividend UGI Form 10-Q (10)ee
Equivalent Plan, as amended May 19, 1992 (6/30/92)
10.8** UGI Corporation Annual Bonus Plan dated March 8, 1996 UGI Form 10-Q 10.4
(6/30/96)
10.9** UGI Utilities, Inc. Annual Bonus Plan dated March 8, Utilities Form 10-Q 10.4
1996` (6/30/96)
10.10** 1997 Stock Purchase Loan Plan UGI Form 10-K 10.16
(9/30/97)
10.11** UGI Corporation Senior Executive Employee Severance UGI Form 10-K 10.12
Pay Plan effective January 1, 1997 (9/30/97)
</TABLE>
-43-
<PAGE> 46
INCORPORATION BY REFERENCE
<TABLE>
<CAPTION>
Exhibit No. Exhibit Registrant Filing Exhibit
----------- ------- ---------- ------ -------
<S> <C> <C> <C> <C>
10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan AmeriGas Form 10-K 10.19
Partners, (9/30/95)
L.P.
10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-K 10.13
(9/30/97)
10.14** UGI Corporation 2000 Stock Incentive Plan UGI Form 10-K 10.14
(9/30/99)
10.15** Amendment No. 1 to UGI Corporation 1992 Non-Qualified UGI Utilities Form 10-Q 10
Stock Option Plan (6/30/97)
10.16** UGI Corporation 1997 Stock Option and Dividend UGI Form 10-Q 10.2
Equivalent Plan (3/31/97)
10.17** UGI Corporation Supplemental Executive Retirement Plan UGI Form 10-Q 10
Amended and Restated effective October 1, 1996 (6/30/98)
10.18 ** Summary of Terms of UGI Corporation 1999 Restricted UGI Form 10-Q 10
Stock Awards (6/30/99)
*10.19** Consulting Services Agreement dated as of March 1,
1999 between UGI Utilities, Inc. and Richard L. Bunn
10.20** Description of Change of Control arrangements for UGI Form 10-K 10.33
Messrs. Greenberg and Bovaird Corporation (9/30/99)
10.21** Description of Change of Control arrangements for UGI Form 10-K 10.34
Messrs. Chaney, Dingman and Barney Corporation (9/30/99)
*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
</TABLE>
* 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.
-44-
<PAGE> 47
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
-45-
<PAGE> 48
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
-46-
<PAGE> 49
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 1999
F-1
<PAGE> 50
UGI UTILITIES, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
<TABLE>
<CAPTION>
Pages
-----
<S> <C>
Financial Statements:
Report of Independent Public Accountants F-3
Consolidated Balance Sheets as of September 30,
1999 and 1998 F-4 to F-5
Consolidated Statements of Income for the years
ended September 30, 1999, 1998, and 1997 F-6
Consolidated Statements of Cash Flows for the years
ended September 30, 1999, 1998, and 1997 F-7
Consolidated Statements of Stockholder's Equity
for the years ended September 30, 1999, 1998, and 1997 F-8
Notes to Consolidated Financial Statements F-9 to F-24
Financial Statement Schedule:
For the years ended September 30, 1999, 1998, and 1997:
II - Valuation and Qualifying Accounts S-1
</TABLE>
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.
F-2
<PAGE> 51
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
F-3
<PAGE> 52
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
<TABLE>
<CAPTION>
September 30,
1999 1998
--------- ---------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents (note 1) $ 11,063 $ 4,720
Accounts receivable (less allowances for doubtful
accounts of $1,716 and $1,373, respectively) 21,887 20,258
Accrued utility revenues (note 1) 6,867 6,745
Inventories (notes 1 and 6) 28,103 28,460
Deferred income taxes (notes 1 and 4) 2,972 4,070
Prepaid expenses and other current assets 6,283 6,556
--------- ---------
Total current assets 77,175 70,809
Property, plant and equipment (note 1):
Gas utility 689,558 665,313
Electric utility 124,558 121,395
General 12,680 10,813
--------- ---------
826,796 797,521
Less accumulated depreciation and amortization (270,003) (253,608)
--------- ---------
Net property, plant and equipment 556,793 543,913
Regulatory assets (notes 1, 2 and 4) 61,082 59,318
Other assets 17,483 16,277
--------- ---------
Total assets $ 712,533 $ 690,317
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 53
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
<TABLE>
<CAPTION>
September 30,
1999 1998
-------- --------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt (note 3) $ 7,143 $ 7,143
Bank loans (note 3) 87,400 68,400
Accounts payable 37,881 38,847
Employee compensation and benefits accrued 8,278 7,807
Dividends and interest accrued 4,693 4,613
Income taxes accrued 179 197
Other current liabilities 17,898 17,103
-------- --------
Total current liabilities 163,472 144,110
Long-term debt (note 3) 172,904 180,027
Deferred income taxes (notes 1 and 4) 112,284 105,734
Deferred investment tax credits (notes 1 and 4) 9,580 9,978
Other noncurrent liabilities 14,733 19,226
Commitments and contingencies (note 8)
Preferred stock subject to mandatory redemption,
without par value (note 7) 20,000 20,000
Common stockholder's equity:
Common Stock, $2.25 par value (authorized - 40,000,000 shares;
issued and outstanding - 26,781,785 shares) 60,259 60,259
Additional paid-in capital 68,559 68,559
Retained earnings 90,742 82,424
-------- --------
Total common stockholder's equity 219,560 211,242
-------- --------
Total liabilities and stockholders' equity $712,533 $690,317
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 54
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
<TABLE>
<CAPTION>
Year Ended
September 30,
---------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Revenues (note 1) $ 420,647 $ 422,283 $ 461,208
----------- ----------- -----------
Costs and expenses:
Gas, fuel and purchased power (note 1) 205,221 214,631 238,978
Operating and administrative expenses 111,972 111,175 117,874
Operating and administrative expenses
- related parties (note 12) 4,946 4,837 5,555
Depreciation and amortization (note 1) 23,005 22,043 21,431
Other income, net (5,168) (4,993) (2,777)
----------- ----------- -----------
339,976 347,693 381,061
----------- ----------- -----------
Operating income 80,671 74,590 80,147
Interest expense 17,532 17,583 16,872
----------- ----------- -----------
Income before income taxes 63,139 57,007 63,275
Income taxes (notes 1 and 4) 24,271 21,456 24,564
----------- ----------- -----------
Net income 38,868 35,551 38,711
Dividends on preferred stock 1,550 2,160 2,764
----------- ----------- -----------
Net income after dividends on preferred stock $ 37,318 $ 33,391 $ 35,947
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 55
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
<TABLE>
<CAPTION>
Year Ended
September 30,
------------------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 38,868 $ 35,551 $ 38,711
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 23,005 22,043 21,431
Deferred income taxes, net 5,792 5,468 549
Provision for uncollectible accounts 4,269 4,099 4,272
Other (1,391) 1,887 (850)
---------- ---------- ----------
70,543 69,048 64,113
Net change in:
Accounts receivable and accrued utility revenues (6,020) 1,895 (2,401)
Inventories 357 2,185 (610)
Deferred fuel costs (5,120) (5,741) 2,870
Accounts payable (966) (6,520) 5,850
Other current assets and liabilities 3,367 (10,709) (338)
---------- ---------- ----------
Net cash provided by operating activities 62,161 50,158 69,484
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (36,384) (37,219) (41,684)
Net proceeds (costs) of property, plant and equipment
disposals (741) 311 (884)
Other, net -- -- 500
---------- ---------- ----------
Net cash used by investing activities (37,125) (36,908) (42,068)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (30,550) (25,093) (26,823)
Issuance of long-term debt -- 35,000 20,000
Repayment of long-term debt (7,143) (17,143) (27,380)
Bank loans increase 19,000 1,400 16,500
Redemption of Series Preferred Stock -- (15,507) --
---------- ---------- ----------
Net cash used by financing activities (18,693) (21,343) (17,703)
---------- ---------- ----------
Cash and cash equivalents increase (decrease) $ 6,343 $ (8,093) $ 9,713
========== ========== ==========
CASH AND CASH EQUIVALENTS:
End of period $ 11,063 $ 4,720 $ 12,813
Beginning of period 4,720 12,813 3,100
---------- ---------- ----------
Increase (decrease) $ 6,343 $ (8,093) $ 9,713
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-7
<PAGE> 56
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of dollars)
<TABLE>
<CAPTION>
Additional
Common Paid-in Retained
Stock Capital Earnings
-------- -------- --------
<S> <C> <C> <C>
Balance September 30, 1996 $ 60,259 $ 68,052 $ 61,130
Net income 38,711
Cash dividends - common stock (24,060)
Cash dividends - preferred stock (2,764)
Dividend of subsidiary assets (1,031)
Other 197
-------- -------- --------
Balance September 30, 1997 60,259 68,249 71,986
Net income 35,551
Cash dividends - common stock (22,633)
Cash dividends - preferred stock (2,160)
Redemption of Series Preferred Stock (320)
Other 310
-------- -------- --------
Balance September 30, 1998 60,259 68,559 82,424
Net income 38,868
Cash dividends - common stock (29,000)
Cash dividends - preferred stock (1,550)
-------- -------- --------
Balance September 30, 1999 $ 60,259 $ 68,559 $ 90,742
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-8
<PAGE> 57
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
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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.
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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
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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
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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
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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.
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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:
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Regulatory assets:
Income taxes recoverable $46,875 $46,483
Power agreement buy-out 6,756 8,692
Other postretirement benefits 3,104 3,340
Deferred fuel costs 3,444 --
Deferred environmental costs 903 803
------- -------
Total regulatory assets $61,082 $59,318
------- -------
Regulatory liabilities:
Refundable state taxes $ 975 $ 2,039
Deferred fuel costs -- 1,676
Other postretirement benefits 2,816 1,397
------- -------
Total regulatory liabilities $ 3,791 $ 5,112
------- -------
</TABLE>
3. DEBT
Long-term debt comprises the following at September 30:
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Medium-Term Notes:
7.25% Notes, due November 2017 $ 20,000 $ 20,000
7.17% Notes, due June 2007 20,000 20,000
6.17% Notes, due March 2001 15,000 15,000
7.37% Notes, due October 2015 22,000 22,000
6.73% Notes, due October 2002 26,000 26,000
6.62% Notes, due May 2005 20,000 20,000
6.50% Senior Notes, due August 2003 (less unamortized discount of $96 and $115,
respectively) 49,904 49,885
9.71% Notes, due through September 2000 in annual
installments of $7,143 7,143 14,285
--------- ---------
Total long-term debt 180,047 187,170
Less current maturities (7,143) (7,143)
--------- ---------
Long-term debt due after one year $ 172,904 $ 180,027
--------- ---------
</TABLE>
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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:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Current:
Federal $ 13,989 $ 12,184 $ 18,168
State 4,490 3,804 5,847
-------- -------- ---------
18,479 15,988 24,015
-------- -------- ---------
Deferred 6,190 5,866 947
Investment credit amortization (398) (398) (398)
-------- -------- ---------
Total income tax expense $ 24,271 $ 21,456 $ 24,564
-------- -------- ---------
</TABLE>
A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal
benefit 6.3 6.4 6.5
Deferred investment credit
amortization (0.7) (0.7) (0.6)
Other, net (2.2) (3.1) (2.1)
-------- -------- ---------
Effective tax rate 38.4% 37.6% 38.8%
-------- -------- ---------
</TABLE>
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(CONTINUED)
Deferred tax liabilities (assets) comprise the following at September 30:
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Excess book basis over tax basis of property, plant and equipment $ 92,996 $ 89,724
Regulatory assets 25,345 24,613
Other 6,158 6,305
--------- ---------
Gross deferred tax liabilities 124,499 120,642
--------- ---------
Deferred investment tax credits (3,975) (4,140)
Employee-related expenses (4,960) (5,421)
Regulatory liability - state income taxes (405) (846)
Power purchase agreement liability (3,215) (3,607)
Other (2,632) (4,964)
--------- ---------
Gross deferred tax assets (15,187) (18,978)
--------- ---------
Net deferred tax liabilities $ 109,312 $ 101,664
--------- ---------
</TABLE>
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.
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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:
<TABLE>
<CAPTION>
Pension Other Postretirement
Benefits Benefits
--------------------------- ---------------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $ 164,817 $ 149,063 $ 13,277 $ 21,972
Service cost 3,800 3,381 84 83
Interest cost 11,187 10,902 1,014 907
Actuarial (gain) loss (21,442) 9,859 666 (8,709)
Benefits paid (8,859) (8,388) (1,052) (976)
--------- --------- --------- ---------
Benefit obligations - end of year $ 149,503 $ 164,817 $ 13,989 $ 13,277
--------- --------- --------- ---------
CHANGE IN PLAN ASSETS:
Fair value of plan assets - beginning of
year $ 183,281 $ 189,539 $ 4,905 $ 3,478
Actual return on plan assets 27,727 2,130 232 232
Employer contributions -- -- 1,041 1,593
Benefits paid (8,859) (8,388) (1,223) (398)
--------- --------- --------- ---------
Fair value of plan assets - end of year $ 202,149 $ 183,281 $ 4,955 $ 4,905
--------- --------- --------- ---------
Funded status of the plans $ 52,646 $ 18,464 $ (9,033) $ (8,372)
Unrecognized net actuarial gain (36,807) (3,918) (3,231) (4,258)
Unrecognized prior service cost 4,667 5,333 -- --
Unrecognized net transition (asset) obligation (7,894) (9,524) 9,112 9,797
--------- --------- --------- ---------
Prepaid (accrued) benefit cost - end of year $ 12,612 $ 10,355 $ (3,152) $ (2,833)
--------- --------- --------- ---------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 7.8% 6.9% 7.8% 6.9%
Expected return on plan assets 9.5 9.5 6.0 6.0
Rate of increase in salary levels 4.5 4.5 4.5 4.5
</TABLE>
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.
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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:
<TABLE>
<CAPTION>
Pension Benefits Other Postretirement Benefits
---------------------------------------- ------------------------------------------
1999 1998 1997 1999 1998 1997
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 3,459 $ 3,038 $ 2,564 $ 78 $ 77 $ 64
Interest cost 10,548 10,233 10,037 991 890 1,588
Expected return on assets (15,375) (14,332) (12,844) (256) (177) (64)
Amortization of:
Transition (asset)
obligation (1,539) (1,533) (1,545) 679 680 1,058
Prior service cost 629 626 631 -- -- --
Actuarial gain -- -- -- (48) (237) (60)
-------- -------- -------- -------- -------- --------
Net benefit cost (income) (2,278) (1,968) (1,157) 1,444 1,233 2,586
Change in regulatory
assets & liabilities -- -- -- 1,655 1,866 513
-------- -------- -------- -------- -------- --------
Net expense (income) $ (2,278) $ (1,968) $ (1,157) $ 3,099 $ 3,099 $ 3,099
-------- -------- -------- -------- -------- --------
</TABLE>
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'
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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:
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Utility fuel and gases $24,440 $24,487
Appliances for sale 991 1,191
Materials, supplies and other 2,672 2,782
------- -------
Total inventories $28,103 $28,460
------- -------
</TABLE>
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
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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.
F-21
<PAGE> 70
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.
F-22
<PAGE> 71
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:
<TABLE>
<CAPTION>
Elim- Gas Electric
Total inations Utility Utility Other
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
1999
Revenues $420,647 $ -- $345,637 $ 75,010 $ --
EBITDA(1) $103,677 $ -- $ 86,963 $ 16,780 $ (67)
Depreciation and amortization 23,005 -- 18,995 4,010 --
-------- -------- -------- -------- --------
Operating income (loss) 80,671 -- 67,968 12,770 (67)
Interest expense 17,532 -- 15,184 2,348 --
-------- -------- -------- -------- --------
Income (loss) before income taxes $ 63,139 $ -- $ 52,784 $ 10,422 $ (67)
Total assets $712,533 $ (52) $615,645 $ 94,989 $ 1,951
Capital expenditures $ 36,384 $ -- $ 31,929 $ 4,455 $ --
-------- -------- -------- -------- --------
1998
Revenues $422,283 $ -- $350,154 $ 72,129 $ --
EBITDA(1) $ 96,633 $ -- $ 82,937 $ 13,560 $ 136
Depreciation and amortization 22,043 -- 18,165 3,878 --
-------- -------- -------- -------- --------
Operating income 74,590 -- 64,772 9,682 136
Interest expense 17,583 -- 15,269 2,314 --
-------- -------- -------- -------- --------
Income before income taxes $ 57,007 $ -- $ 49,503 $ 7,368 $ 136
Total assets $690,317 $ (101) $594,447 $ 95,587 $ 384
Capital expenditures $ 37,219 $ -- $ 32,033 $ 5,186 $ --
-------- -------- -------- -------- --------
1997
Revenues $461,208 $ -- $389,064 $ 72,144 $ --
EBITDA(1) $101,578 $ -- $ 87,317 $ 14,038 $ 223
Depreciation and amortization 21,431 -- 17,194 4,237 --
-------- -------- -------- -------- --------
Operating income 80,147 -- 70,123 9,801 223
Interest expense 16,872 -- 14,016 2,746 110
-------- -------- -------- -------- --------
Income before income taxes $ 63,275 $ -- $ 56,107 $ 7,055 $ 113
Total assets $681,378 $ 318 $594,331 $ 86,247 $ 482
Capital expenditures $ 41,684 $ -- $ 36,691 $ 4,993 $ --
-------- -------- -------- -------- --------
</TABLE>
(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.
F-23
<PAGE> 72
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.
<TABLE>
<CAPTION>
December 31, March 31, June 30, September 30,
1998 1997 1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues $112,770 $135,464 $167,692 $152,333 $ 77,338 $ 74,342 $ 62,847 $ 60,144
Operating income
(loss) 25,452 30,329 43,174 36,150 10,799 7,818 1,246 293
Net income (loss) 13,033 16,208 24,167 19,999 4,076 1,892 (2,408) (2,548)
</TABLE>
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.
F-24
<PAGE> 73
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
<TABLE>
<CAPTION>
Balance at Charged to Balance at
beginning costs and end of
of year expenses Other year
---------- ----------- -------------- -----------
<S> <C> <C> <C> <C>
YEAR ENDED SEPTEMBER 30, 1999
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 1,373 $ 4,269 $(3,926) (1) $ 1,716
======= =======
Other reserves (3) $ 3,724 $ 1,079 $(3,730) (2) $ 1,345
======= =======
272 (4)
YEAR ENDED SEPTEMBER 30, 1998
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 3,333 $ 4,099 $(6,059) (1) $ 1,373
======= =======
Other reserves (3) $ 5,945 $ 159 $(2,380) (2) $ 3,724
======= =======
YEAR ENDED SEPTEMBER 30, 1997
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 3,976 $ 4,272 $(4,915) (1) $ 3,333
======= =======
Other reserves (3) $ 3,160 $ 3,021 $ (236) (2) $ 5,945
======= =======
</TABLE>
(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
<PAGE> 74
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
<PAGE> 1
EXHIBIT 10.19
CONSULTING SERVICES AGREEMENT
THIS CONSULTING SERVICES AGREEMENT (the "Agreement"), is entered into
as of March 1, 1999 (the "Effective Date"), by and between UGI Utilities, Inc.,
a Pennsylvania corporation, ("UGI") and Richard L. Bunn, an individual,
("Consultant").
WHEREAS, UGI wishes to obtain the consulting services of Consultant,
and Consultant wishes to provide consulting services according to the terms and
conditions of this Agreement.
NOW, THEREFORE, in consideration of the mutual promises hereinafter set
forth, and intending to be legally bound, UGI and Consultant agree as follows:
1. Services to be Provided. During the term of this Agreement,
Consultant shall perform for UGI such consulting services as UGI may from time
to time request in connection with the transition of UGI's natural gas utility
to a deregulated retail market ("Services").
2. Term. The initial term of this Agreement shall begin on the March 1,
1999 and shall continue until December 31, 1999. Thereafter, this Agreement
shall automatically renew for additional, successive terms of six (6) months
each ("Additional Term") unless UGI terminates this Agreement by giving
Consultant written notice of its intention to do so at least fifteen days prior
to the commencement of any Additional Term.
3. Time Commitment and Compensation.
(a) As compensation for Consultant's performance of the
Services to be performed under this Agreement, UGI shall pay Consultant as
follows:
(1) For the period from March 1, 1999 to June 30,
1999, Consultant shall provide five (5) days of Services per month and shall
receive a fee of $15,000 per month, payable at the end of each month. In
addition, if requested by the Chairman of UGI to perform more than five (5) days
of Services in any month during this period, Consultant shall be paid $1,000 per
day for each such additional day;
(2) For the period from July 1, 1999 to December 31,
1999, Consultant shall provide three (3) days of Services per month and receive
a fee of $9,000 per month, payable at the end of each month. In addition, if
requested by the Chairman of UGI to perform more than three (3) days of Services
in any month during this period, Consultant shall be paid $1,500 per day for
each such additional day;
(3) For any Additional Term during calendar year
2000, Consultant shall provide one day of Services per month and receive a fee
of $5,000 per month, payable at the end of each month. In addition, if requested
by the Chairman of UGI to perform more than one day of Services in any month,
Consultant shall be paid $1,500 per day for each such additional day;
(4) For any Additional Term after January 1, 2001,
Consultant shall receive $2,000 per day for Services requested by the Chairman
of UGI.
<PAGE> 2
(b) Consultant will be reimbursed for actual, reasonable
out-of-pocket expenses incurred in carrying out the Services outlined above.
Consultant will submit an expense report to UGI for reimbursement in a form
acceptable to UGI.
(c) During the term of this Agreement, UGI shall provide
appropriate office space and administrative support to Consultant in carrying
out the Services.
4. No Benefits. Consultant is not an employee of UGI and will not be
entitled to participate in or receive any benefit or right under any of UGI's
employee benefit and welfare plans, including, without limitation, insurance,
pension and savings plans, provided however that the payments due hereunder
shall be in addition to and not in lieu of any payments or benefits to which
Consultant is entitled as a result of Consultant's prior employment with UGI.
5. Independent Contractor. For purposes of this Agreement and all
Services to be provided hereunder, Consultant shall not be considered a partner,
co-venturer, agent, employee, or representative of UGI, but shall remain in all
respects an independent contractor, and neither party shall have any right or
authority to make or undertake any promise, warranty or representation, to
execute any contract, or otherwise to assume any obligation or responsibility in
the name of or on behalf of the other party.
6. Confidentiality.
(a) Company Information. Consultant agrees at all times during
the term of this Agreement and thereafter, to hold in strictest confidence, and
not to use, except in connection with Consultant's performance of the Services,
and not to disclose to any person or entity any Confidential Information of UGI
without the prior written authorization of UGI. As used herein, "Confidential
Information" means any proprietary or confidential information, technical data,
trade secrets or know-how, including, but not limited to, research, sales and/or
marketing plans and products, services, business plans, acquisitions or
strategies (past, present and/or prospective), customer lists and customers,
credit information, markets, software, developments, inventions, processes,
formulas, technology, designs, drawings, engineering, distribution and sales
methods and systems, sales and profit figures, finances and other business
information disclosed to Consultant or otherwise learned, discovered or
developed by Consultant, either directly or indirectly in writing, orally or by
drawings or inspection of documents or other tangible property. However,
Confidential Information does not include any of the foregoing items which has
become publicly known and made generally available through no wrongful act of
Consultant.
(b) Third Party Information. Consultant recognizes that UGI
has received and in the future may continue to receive from third parties their
confidential or proprietary information subject to a duty on UGI's part to
maintain the confidentiality of such information and to use it only for certain
limited purposes. Consultant agrees at all times during the term of this
Agreement and thereafter, to hold in strictest confidence, and not to use,
except in connection with Consultant's performance of the Services, and not to
disclose to any person or entity, or to use it except as necessary in performing
the Services, consistent with UGI's agreement with such
2
<PAGE> 3
third party. UGI shall provide Consultant with a copy of any applicable
confidentiality agreements it may have with such third parties.
(c) Survival. The provisions of this Section shall survive the
expiration or sooner termination of the term of this Agreement for a period of
three (3) years.
7. No Conflicting Agreements.
(a) Consultant represents that Consultant is not a party to
any existing agreement which would prevent Consultant from entering into and
performing this Agreement. Consultant will not enter into any other agreement
that is in conflict with Consultant's obligations under this Agreement without
the prior written approval of UGI.
(b) Consultant agrees that during the term of this Agreement
Consultant will not participate in any rate, regulatory or legal proceeding
involving UGI or its interests without the prior written approval of UGI.
8. Entire Agreement, Amendment and Assignment. This Agreement is the
sole agreement between Consultant and UGI with respect to the Services to be
performed hereunder and it supersedes all prior agreements and understandings
with respect thereto, whether oral or written. No modification to any provision
of this Agreement shall be binding unless in writing and signed by both the
Consultant and UGI. No waiver of any rights under this agreement, will be
effective unless in writing signed by the party to be charged. All of the terms
and provisions of this Agreement shall be binding upon and inure to the benefit
of and be enforceable by the respective heirs, executors, administrators, legal
representatives, successors and assigns of the parties hereto, except that the
duties and responsibilities of Consultant hereunder are of a personal nature and
shall not be assignable or delegable in whole or in part by Consultant.
9. Notices. All notices and other communications required or permitted
hereunder or necessary or convenient in connection herewith shall be in writing
and shall be deemed to have been given when hand delivered, sent by facsimile or
mailed by registered or certified mail, as follows (provided that notice of
change of address shall be deemed given only when received):
If to UGI, to:
UGI Utilities, Inc.
100 Kachel Boulevard
Suite 400
Green Hills Corporate Center
Reading, PA 19607
Attention: General Counsel
Facsimile No.: (610) 796-3606
3
<PAGE> 4
If to Consultant, to:
Richard L. Bunn
or to such other names or addresses as UGI or Consultant, as the case may be,
shall designate by notice to each other person entitled to receive notices in
the manner specified in this paragraph.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound,
have duly executed this Agreement as of the date first above written.
UGI UTILITIES, INC.
/s/ Robert J. Chaney
--------------------
Robert J. Chaney
CEO and President
CONSULTANT
/s/ Richard L. Bunn
--------------------
Richard L. Bunn
4
<PAGE> 1
UGI UTILITIES INC. AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - EXHIBIT 12.1
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
Year Ended September 30,
-----------------------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ------------ ----------- --------------
<S> <C> <C> <C> <C> <C>
EARNINGS:
Earnings before income taxes $ 63,139 $ 57,007 $ 63,275 $ 61,717 $ 39,759
Interest expense 17,317 17,383 16,696 15,921 16,632
Amortization of debt discount and expense 215 200 176 173 206
Interest component of rental expense 1,539 1,624 1,887 1,838 1,604
----------- ----------- ------------ ----------- --------------
$ 82,210 $ 76,214 $ 82,034 $ 79,649 $ 58,201
=========== =========== ============ =========== ==============
FIXED CHARGES:
Interest expense $ 17,317 $ 17,383 $ 16,696 $ 15,921 $ 16,632
Amortization of debt discount and expense 215 200 176 173 206
Allowance for funds used during
construction (capitalized interest) 36 39 114 107 65
Interest component of rental expense 1,539 1,624 1,887 1,838 1,604
----------- ----------- ------------ ----------- --------------
$ 19,107 $ 19,246 $ 18,873 $ 18,039 $ 18,507
=========== =========== ============ =========== ==============
Ratio of earnings to fixed charges 4.30 3.96 4.35 4.42 3.14
=========== =========== ============ =========== ==============
</TABLE>
<PAGE> 1
UGI UTILITIES INC. AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS - EXHIBIT 12.2
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
Year Ended September 30,
-----------------------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ------------ ----------- --------------
<S> <C> <C> <C> <C> <C>
EARNINGS:
Earnings before income taxes $ 63,139 $ 57,007 $ 63,275 $ 61,717 $ 39,759
Interest expense 17,317 17,383 16,696 15,921 16,632
Amortization of debt discount and expense 215 200 176 173 206
Interest component of rental expense 1,539 1,624 1,887 1,838 1,604
----------- ----------- ------------ ----------- --------------
$ 82,210 $ 76,214 $ 82,034 $ 79,649 $ 58,201
=========== =========== ============ =========== ==============
COMBINED FIXED CHARGES AND PREFERRED
STOCK DIVIDENDS:
Interest expense $ 17,317 $ 17,383 $ 16,696 $ 15,921 $ 16,632
Amortization of debt discount and expense 215 200 176 173 206
Allowance for funds used during
construction (capitalized interest) 36 39 114 107 65
Interest component of rental expense 1,539 1,624 1,887 1,838 1,604
Preferred stock dividend requirements 1,550 2,160 2,764 2,765 2,778
Adjustment required to state preferred stock
dividend requirements on a pretax basis 968 1,304 1,754 1,685 1,164
----------- ----------- ------------ ----------- --------------
$ 21,625 $ 22,710 $ 23,391 $ 22,489 $ 22,449
=========== =========== ============ =========== ==============
Ratio of earnings to combined fixed charges
and preferred stock dividends 3.80 3.36 3.51 3.54 2.59
=========== =========== ============ =========== ==============
</TABLE>
<PAGE> 1
Exhibit (23.1)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated November 12, 1999, on the consolidated financial statements and
financial statement schedule of UGI Utilities, Inc. and subsidiaries included in
UGI Utilities, Inc.'s Annual Report on Form 10-K for the fiscal year ended
September 30, 1999, into UGI Utilities, Inc.'s previously filed S-3 Registration
Statement No. 333-4288.
Arthur Andersen LLP
Chicago, Illinois
December 21, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AND INCOME STATEMENT OF UGI UTILITIES, INC. AND
SUBSIDIARIES AS OF AND FOR THE YEAR ENDED SEPTEMBER 30, 1999 AND IS QUALIFIED IN
ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS INCLUDED IN UGI
UTILITIES' ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED SEPTEMBER 30, 1999.
</LEGEND>
<CIK> 0000100548
<NAME> UGI UTILITIES
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-START> OCT-01-1998
<PERIOD-END> SEP-30-1999
<CASH> 11,063
<SECURITIES> 0
<RECEIVABLES> 30,062
<ALLOWANCES> 1,308
<INVENTORY> 28,103
<CURRENT-ASSETS> 77,175
<PP&E> 826,796
<DEPRECIATION> 270,003
<TOTAL-ASSETS> 712,533
<CURRENT-LIABILITIES> 163,472
<BONDS> 172,904
20,000
0
<COMMON> 60,259
<OTHER-SE> 159,301
<TOTAL-LIABILITY-AND-EQUITY> 712,533
<SALES> 420,647
<TOTAL-REVENUES> 420,647
<CGS> 205,221
<TOTAL-COSTS> 205,221
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 4,269
<INTEREST-EXPENSE> 17,532
<INCOME-PRETAX> 63,139
<INCOME-TAX> 24,271
<INCOME-CONTINUING> 38,868
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 38,868
<EPS-BASIC> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1>THERE ARE NO PUBLICLY HELD SHARES OUTSTANDING.
</FN>
</TABLE>
