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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, 1998
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, 1998 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
Items 1 and 2 Business and Properties.................................... 1
General........................................... 1
Gas Utility Operations............................ 1
Electric Utility Operations....................... 4
Item 3 Legal Proceedings.......................................... 10
Item 4 Submission of Matters to a Vote of
Security Holders.................................. 13
PART II SECURITIES AND FINANCIAL INFORMATION
Item 5 Market for Registrant's Common Equity
and Related Stockholder Matters................... 13
Item 6 Selected Financial Data.................................... 14
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations............... 15
Item 7A Quantitative and Qualitative Disclosure About Market Risk.. 25
Item 8 Financial Statements and Supplementary Data................ 25
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure............ 25
PART III UGI UTILITIES, INC. MANAGEMENT AND SECURITY HOLDERS
Item 10 Directors and Executive Officers of the Registrant......... 26
Item 11 Executive Compensation..................................... 31
Item 12 Security Ownership of Certain Beneficial
Owners and Management............................. 38
Item 13 Certain Relationships and Related
Transactions...................................... 39
PART IV ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
Item 14 Exhibits, Financial Statement Schedules
and Reports on Form 8-K........................... 40
Signatures................................................. 44
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"). 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.
GAS UTILITY OPERATIONS
SERVICE AREA; REVENUE ANALYSIS
Gas Utility distributes natural gas to approximately 258,000 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, 1998, 1997 and 1996, revenues of
Gas Utility accounted for approximately 83%, 84%, and 85%, 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 1998 fiscal year was
approximately 74.9 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 42% of system throughput, while gas transported for commercial and
industrial customers (who buy their gas from others) accounted for approximately
58% of system throughput. Based on industry data for 1997, residential customers
account for approximately 38% of total system throughput by local gas
distribution companies in the United States. By contrast, for the 1998 fiscal
year, Gas Utility's residential customers represented 22% 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, ANR Pipeline Company, Columbia Gulf Transmission Company, CNG
Transmission Corporation, National Fuel Gas Supply Corporation, Transcontinental
Gas Pipeline Corporation, Trunkline Gas Company, Texas Gas Transmission
Corporation, Panhandle Eastern Pipe Line Company and Tennessee Gas Pipeline Co.
GAS SUPPLY CONTRACTS
During the 1998 fiscal year, Gas Utility purchased approximately 30.8
bcf of natural gas and sold approximately 31.3 bcf to customers. Approximately
25 bcf or 81% of the volumes purchased were supplied under agreements with six
major suppliers of natural gas. The remaining 5.8 bcf or 19% of gas purchased
was supplied by producers and marketers under other arrangements, including
multi-month agreements at spot prices. Certain gas supply contracts require
minimum gas purchases, however, each of these agreements either terminates in
fiscal year 1999, or includes provisions that entitle Utilities to terminate the
agreement if it is not market responsive.
STORAGE AND PEAK SHAVING
Gas Utility contracts for 9.5 bcf of seasonal storage with several
interstate pipelines. Gas is injected in storage during the summer and delivered
during the winter at combined peak day capacities of approximately 0.16 bcf. In
Harrisburg, Reading and Bethlehem, Pennsylvania, Gas Utility operates
peak-shaving facilities capable of producing 0.06 bcf of gas per day from
propane-air and liquefied natural gas facilities. These facilities are used to
meet winter peak service requirements.
SEASONAL VARIATION
Because many of its customers use gas for heating purposes, Gas
Utility's sales are seasonal, with approximately 57% of fiscal year 1998
throughput and approximately 76% of earnings before interest expense, income
taxes, depreciation and amortization occurring during the winter season from
November through March.
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COMPETITION
Natural gas is a fuel that competes with electricity and oil, and to a
lesser extent, with propane and coal. Competition among these fuels is primarily
a function of their comparative price and the relative cost and efficiency of
fuel utilization equipment. Electric utilities in Gas Utility's service area are
aggressively 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 13 years, Gas Utility provides transportation services for
those sales. Pennsylvania is considering legislation which would require a
customer choice option for retail purchasers of natural gas. See "Utility
Regulation and Rates."
Customers representing approximately 41% 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
under flexible, interruptible 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 33% 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 the ten Utilities' customers
with the highest volume of system throughput. Three of the top five customers
have entered into long-term agreements with Utilities. 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 1999. Supply mix is diversified, market priced,
and delivered pursuant to a number of long- and short-term firm transportation
and storage arrangements.
During the 1998 fiscal year, Gas Utility supplied transportation
service to three major cogeneration installations. 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 6,955
additional residential heating customers during the 1998 fiscal year, a modest
increase from the previous year. Of those new customers, new home construction
accounted for a record 4,905 heating customers, an increase of approximately 14%
from the prior year. Customers converting from other energy sources,
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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
1,246, up from 1,068 in fiscal year 1997.
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
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.
ELECTRIC UTILITY OPERATIONS
ELECTRICITY GENERATION CUSTOMER CHOICE AND COMPETITION ACT
On January 1, 1997, Pennsylvania's Electricity Generation Customer
Choice and Competition Act (Customer Choice Act) became effective. The Customer
Choice Act permits all Pennsylvania retail electric customers to choose their
electric generation supplier over a three-year phase-in period commencing
January 1, 1999. The Customer Choice Act required all electric utilities 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 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 from January 1, 1999 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
Customer Choice Act. The Restructuring Order approved a settlement agreement
among all parties to Utilities' proceeding except Pennsylvania Power & Light
Company ("PP&L"). Under the terms of the Restructuring Order, commencing January
1, 1999 Electric Utility is authorized 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 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. The Restructuring
Order also provides that Electric Utility may extend the CTC period to recover
additional amounts it may be ordered to pay as a result of a contract dispute
with PP&L. See "Sources of Supply" below. All of Electric Utility's customers
will be permitted to select an alternative electric generation supplier as of
January 1, 1999. Customers choosing another supplier will on average receive a
generation "shopping credit" developed from system-wide generation rates of 3.67
cents per kilowatt hour ("kwh") in calendar years 1999 and 2000, and 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 the sources
and costs of electric power vary from period to period and because Electric
Utility no longer defers the difference between its actual power costs and
amounts included in its rates, Electric Utility's quarterly results may become
more volatile in the future. Results will also be affected by the number of
customers who choose to purchase their power from other suppliers during any
given time period. Utilities has applied to the PUC for approval to transfer its
electric generation assets to a non-regulated subsidiary as provided for in the
settlement agreement approved by the Restructuring Order. Utilities' management
believes that the PUC will approve this request.
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
1998 fiscal year, about 51% of sales volume came from residential customers, 34%
from commercial customers and 13% from industrial customers. The remaining 2%
represents electricity transported for customers who purchased their power from
others during the pilot program phase of the Customer Choice Act. For the 1998,
1997 and 1996 fiscal years, revenues of Electric Utility accounted for
approximately 17%, 16%, and 15%, respectively, of our total consolidated
revenues.
SOURCES OF SUPPLY
Electric Utility distributes both electricity that it generates or
purchases from others and, since November 1, 1997, electricity that customers
purchase from other suppliers. Utilities owns and operates Hunlock generating
station located near Kingston, Pennsylvania ("Hunlock Station"), and 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
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coal-fired stations can generate up to 69 megawatts of electric power for
Electric Utility and provided approximately 46% of its energy requirements
during the 1998 fiscal year.
Utilities has short-term, fixed-price, power supply agreements to
purchase the total output, 32 megawatts of electric power, from the Montgomery
County (Maryland) Resource Recovery Facility (the "Montgomery Facility"). The
Montgomery Facility output is expected to replace higher cost power under the
PP&L contract through calendar year 1999.
Utilities has a long-term power supply agreement with PP&L. Under this
agreement, PP&L supplies all the electric power required by Electric Utility
above that provided from certain other sources, including Hunlock Station and
the Montgomery Facility. The cost of electricity supplied by PP&L is based on
PP&L's actual system costs. As a result of the availability and projected cost
of alternative supplies, Utilities provided PP&L with notice of its intent to
stop purchasing power under their power supply agreement as of March 2001. In
addition, if certain conditions are met, the power supply agreement may
terminate at an earlier date.
There currently is a dispute between Utilities and PP&L over the effect
of customer choice on Utilities' obligations under the agreement. Utilities
filed an action in the Court of Common Pleas of Luzerne County, Pennsylvania
seeking a declaration of the rights and responsibilities of the parties to the
agreement, including a declaration that Utilities is obligated to purchase only
the amount of energy required to serve its customers who do not elect to
purchase energy from alternate suppliers. On August 31, 1998 the Court granted
Utilities' motion for partial judgment on the pleadings, holding that Utilities'
purchase obligation does not include energy for customers who have chosen
alternative suppliers. Utilities expects PP&L to appeal this decision at the
conclusion of the case. In addition, PP&L disputes Utilities' right to displace
PP&L power with power purchased from the Montgomery Facility. The Restructuring
Order provides that Utilities may extend the CTC period to recover any
additional stranded costs it may incur if it is ultimately determined that
Utilities must pay PP&L for power that is no longer needed to serve customers.
In a regulated utility environment, Hunlock Station could be expected
to operate until the end of its useful life in 2004. As a result of electric
deregulation, however, Hunlock Station may cease operations earlier, depending
on a number of factors, including customer load, contract purchase obligations,
the availability and cost of replacement power and the ability to market Hunlock
Station's output. Utilities estimates that the cost of electricity supplied by
Hunlock Station is higher than projected market rates, but lower than the cost
of electricity purchased under the current PP&L contract. Utilities' decisions
regarding the operation of Hunlock Station will be highly dependent on the
maturation of the emerging deregulated energy market in Pennsylvania.
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.
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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 21% of the total sales of Electric Utility during
the 1998 fiscal year. Electricity competes with natural gas, oil, propane and
other heating fuels in this use. Approximately 53% of volume occurred during
November through April, the six coldest months of the 1998 fiscal year,
demonstrating modest seasonality favoring winter due to the use of electricity
for residential heating purposes.
UTILITIES' PROPERTIES
Utilities' Mortgage and Deed of Trust constitutes a first lien on
substantially all real and personal property of Utilities.
UTILITY REGULATION AND RATES
REGULATORY ENVIRONMENT
Since December 1982, Gas Utility has provided transportation service
for commercial and industrial customers who purchase their gas from others. As
previously reported, this unbundled service accounted for approximately 58% of
Gas Utility's system throughput in fiscal year 1998. Certain states, including
Pennsylvania, are considering whether transportation service options should be
extended to residential and small commercial customers. On March 27, 1997,
proposed customer choice legislation was introduced in the Pennsylvania General
Assembly that would, among other things, extend the availability of gas
transportation service to residential and small commercial customers of local
gas distribution companies. It would permit all customers of natural gas
distribution utilities to transport their natural gas supplies through the
distribution systems of Pennsylvania gas utilities by April 1, 1999 and would
also require Pennsylvania gas utilities to stop selling natural gas. Legislative
committees have conducted public hearings on the proposed legislation and
Utilities has provided testimony on such issues as the need for standards to
assure reliability of future gas supplies
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and the recovery of costs associated with existing gas supply assets. At the
request of the Governor of Pennsylvania, in December 1997 a collaborative group
of industry stakeholders was convened to attempt to further develop the proposed
legislation. To date, this group has failed to reach a consensus. We expect the
collaborative process to continue, and we will participate as appropriate.
Independently, Utilities is considering a number of options for addressing the
provision of unbundled transportation services to residential and small
commercial customers.
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.
PENNSYLVANIA PUBLIC UTILITY COMMISSION JURISDICTION
Utilities' gas and electric utility operations are subject to
regulation by the PUC as to rates, terms and conditions of service, accounting
matters, issuance of securities, contracts and other arrangements with
affiliated entities, and various other matters.
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. In accordance with
regulations adopted by the PUC on June 14, 1995, PGC rates may also be adjusted
quarterly 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 may qualify for the PGC(2) rate. In accordance with the schedule
established by law and PUC regulations, Gas Utility will file a new PGC tariff
on June 1, 1999, to be effective December 1, 1999. When filed, the proposed
tariff will reflect estimated PGC over-collections and under-collections through
November 30, 1999.
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ENERGY COST RATES
In accordance with provisions of the 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 customers' monthly 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.
GAS RATE CASE
On January 27, 1995, Gas Utility filed with the PUC for a $41.3 million
increase in base rates. The PUC approved a $19.5 million settlement of this
proceeding, effective August 31, 1995.
ELECTRIC RATE CASE
On January 26, 1996, Electric Utility filed with the PUC for a $6.2
million increase in its base rates. On July 18, 1996, the PUC approved a
settlement of this proceeding authorizing a $3.1 million increase in annual
revenues. This increase in base rates became effective on July 19, 1996.
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.
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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 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, CERCLA 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."
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to Utilities' industry segments for the 1998,
1997 and 1996 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, 1998, Utilities and its subsidiaries had 1,183
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
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for commercial use. Some constituents of coal tars produced from the
manufactured gas process are today considered hazardous substances under the
Superfund Law.
The gas distribution business has been one of Utilities' principal
lines of business since its inception in 1882. One of the ways Utilities
initially expanded its business in its early years was by entering into
agreements with other gas companies to operate their businesses. After 1888, the
principal means by which Utilities expanded its gas business was to acquire all
or a portion of the stock of companies engaged in this business. Utilities also
provided management and administrative services to some of these companies.
Utilities grew rapidly by means of stock acquisitions and became one of the
largest public utility holding companies in the country. Pursuant to the
requirements of the Public Utility Holding Company Act of 1935, Utilities
divested all of its utility operations other than those which now constitute the
Gas Utility and the Electric Utility.
The manufactured gas process was once used by Utilities in connection
with providing gas service to its customers. In addition, virtually all of the
gas companies that Utilities operated or to which it provided services, or in
which Utilities held stock, utilized a manufactured gas process. Utilities has
been notified of several sites outside Pennsylvania on which (i) gas plants were
formerly operated by it or owned or operated by its former subsidiaries and (ii)
either environmental agencies or private parties are investigating the extent of
environmental contamination and the necessity of environmental remediation.
Utilities is currently litigating a claim against it relating to an out-of-state
site. If Utilities were found liable as a "responsible party" as defined in the
Superfund Law (or comparable state statutes) with respect to this site, it would
have joint and several liability with other responsible parties for the full
amount of the cleanup costs. A "responsible party" under that statute includes
(i) the current owner of the affected property and (ii) each owner or operator
of a facility during the time when hazardous substances were released on the
property.
Management believes that Utilities should not have significant
liability in those instances in which a former subsidiary operated a
manufactured gas plant because Utilities generally is not legally liable for the
obligations of its subsidiaries. Under certain circumstances, however, a court
could find a parent company liable for environmental damage caused by a
subsidiary company when the parent company either (i) itself operated the
facility causing the environmental damage or (ii) otherwise so controlled the
subsidiary that the subsidiary's separate corporate form should be disregarded.
There could be, therefore, significant future costs of an uncertain amount
associated with environmental damage caused by manufactured gas plants that
Utilities owned or directly operated, or that were owned or operated by former
subsidiaries of Utilities, if a court were to conclude that the subsidiary's
separate corporate form should be disregarded.
Utilities believes that there are approximately 40 manufactured gas
plant sites in Pennsylvania where either (i) Utilities formerly operated the
plant or (ii) Utilities owns or at one time owned the site. Most of the sites
are no longer owned by Utilities and the gas plants formerly operated at these
40 sites have all been out of operation since at least the early 1950s.
Utilities or other parties are currently conducting investigative or remedial
activities at nine of the 40 sites. Based on the 1995 settlement agreement with
the PUC relating to Gas Utilities' 1995
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<PAGE> 14
base rate increase filing, rate relief will be permitted for certain remediation
expenditures on environmentally contaminated sites located in Pennsylvania.
Because of this, Utilities does not expect its costs for Pennsylvania sites to
be material to its results of operations.
The following is a short description of the status of certain matters
involving Utilities related to manufactured gas plants located in other states.
See also Notes 1 and 8 to the Company's Consolidated Financial Statements.
OUT OF STATE GAS PLANT SITES
1. Halladay Street, Jersey City, New Jersey. By letter dated April 12,
1993, Public Service Electric and Gas Company ("PSE&G") informed Utilities that
PSE&G had been named as a defendant in a civil action pending in the United
States District Court for the District of New Jersey, seeking damages as a
result of contamination relating to the former manufactured gas plant operations
at Halladay Street in Jersey City, New Jersey. The Halladay Street gas plant
operated from approximately 1884 until 1950. PSE&G asserted that Utilities is
liable for that portion of the costs associated with operations of the plant
between 1886 and 1899. PPG Industries, Inc. has also been named as a defendant
in the action for costs associated with chemical contamination at the site
unrelated to gas plant operations. In July 1993, PSE&G served Utilities with a
complaint naming Utilities as a third-party defendant in this civil action.
PSE&G subsequently amended the complaint to allege additional theories of
liability for the period from 1899 to 1940. To date, that action has focused on
the chemical contamination allegedly associated with PPG Industries' activities
and there have been no developments concerning liability for gas plant related
contamination. Investigations of the site conducted to date are insufficient to
establish the extent of environmental remediation necessary, if any. Hence,
Utilities is unable to estimate the total cost of cleanup associated with
manufactured gas plant wastes at this site.
2. Savannah, Georgia. On March 2, 1992, Atlanta Gas Light Company
("AGL") informed Utilities that it was investigating contamination that appears
to be related to manufactured gas plant operations at a site owned by AGL in
Savannah, Georgia. AGL believes that Utilities may be liable for investigative
and remedial costs as a result of having operated the gas plant through a
subsidiary company in the early 1900s. AGL has stated its intention to bring
suit against Utilities. AGL estimates that total costs to remediate the site may
exceed $5 million. Management believes that Utilities has substantial defenses
to any action that may arise out of the activities of its former subsidiary at
this site.
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<PAGE> 15
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 1998 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 during the 1998 fiscal
year totaled $22.6 million. Dividends declared on the Company's Common Stock
during the 1997 and 1996 fiscal years totaled $25.1 million, including a $1
million intercompany receivable, and $32.9 million, respectively.
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<PAGE> 16
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended
September 30,
--------------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
FOR THE PERIOD ENDED:
Income statement data:
Revenues............................. $422,283 $461,208 $460,496 $357,364 $395,061
======== ======== ======== ======== ========
Income from:
Continuing operations.............. $ 35,551 $ 38,711 $ 38,348 $ 28,018 $ 23,555
Discontinued operations(a)......... -- -- -- -- 6,918
-------- -------- -------- -------- --------
Income before accounting change...... 35,551 38,711 38,348 28,018 30,473
Change in accounting for
postemployment benefits............ -- -- -- (1,028) --
-------- -------- -------- -------- --------
Net income........................... 35,551 38,711 38,348 26,990 30,473
Dividends on preferred stock......... 2,160 2,764 2,765 2,778 1,356
-------- -------- -------- -------- --------
Net income after dividends
on preferred stock................. $ 33,391 $ 35,947 $ 35,583 $ 24,212 $ 29,117
======== ======== ======== ======== ========
AT PERIOD END:
Balance sheet data:
Total assets......................... $690,317 $681,378 $649,899 $661,480 $581,426
======== ======== ======== ======== ========
Capitalization:
Debt:
Bank loans....................... $ 68,400 $ 67,000 $ 50,500 $ 42,000 $ 17,000
Long-term debt including
current maturities:............ 187,170 169,294 176,654 208,162 177,444
-------- -------- -------- -------- --------
Total debt....................... 255,570 236,294 227,154 250,162 194,444
-------- -------- -------- -------- --------
Preferred stock subject to
mandatory redemption............. 20,000 35,187 35,187 35,202 35,202
Common equity...................... 211,242 200,494 189,441 186,803 178,071
-------- -------- -------- -------- --------
Total capitalization................. $486,812 $471,975 $451,782 $472,167 $407,717
======== ======== ======== ======== ========
Ratio of capitalization:
Total debt......................... 52.5% 50.0% 50.3% 53.0% 47.7%
UGI Utilities preferred stock...... 4.1% 7.5% 7.8% 7.4% 8.6%
Common equity...................... 43.4% 42.5% 41.9% 39.6% 43.7%
-------- -------- -------- -------- --------
100.0% 100.0% 100.0% 100.0% 100.0%
======== ======== ======== ======== ========
</TABLE>
(a) Includes the Company's oil field activities discontinued in 1986.
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<PAGE> 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
1998 COMPARED WITH 1997
<TABLE>
<CAPTION>
- ------------------------------------------------------- --------------- --------------- ----------------------------
Increase
Year Ended September 30, 1998 1997 (Decrease)
- ------------------------------------------------------- --------------- --------------- ----------------------------
(Millions of dollars)
<S> <C> <C> <C> <C>
GAS UTILITY:
Natural gas system throughput - bcf 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)%
Operating income $ 68.9 $ 74.8 $ (5.9) (7.9)%
ELECTRIC UTILITY:
Sales - gwh 876.4 868.5 7.9 0.9%
Revenues $ 72.1 $ 72.1 $ - - %
Total margin $ 34.0 $ 35.2 $ (1.2) (3.4)%
Operating income $ 10.4 $ 10.7 $ (0.3) (2.8)%
CORPORATE GENERAL EXPENSES $ (4.8) $ (5.6) $ (0.8) (14.3)%
- ------------------------------------------------------- --------------- --------------- -------------- -------------
</TABLE>
bcf - billions of cubic feet. gwh - millions of kilowatt hours. Total margin
represents revenues less cost of sales and revenue-related taxes.
GAS UTILITY. Weather in Gas Utility's service territory was 16.3% warmer than
normal in 1998 compared with weather that was 4.8% warmer than normal in 1997.
Our total system throughput decreased 6.6% in 1998 primarily because the warmer
weather resulted in a 5.1 bcf (14.5%) reduction in sales to our firm-
residential, commercial and industrial (collectively, "core market") customers.
The decrease in Gas Utility's revenues in 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 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 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 operating income decreased $5.9 million in 1998 reflecting lower
total margin partially offset by lower operating expenses and higher other
income. Gas Utility's operating expenses
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<PAGE> 18
during 1998 decreased $5.4 million principally as a result of (1) $1.6 million
of income from an insurance recovery, (2) a $2.1 million decrease in
distribution system maintenance expenses, and (3) lower charges relating to
environmental matters.
ELECTRIC UTILITY. Pennsylvania's Electricity Generation Customer Choice and
Competition Act (Customer Choice Act) and the associated Restructuring Order
issued by the PUC (see "Customer Choice Act" below) did not have a significant
effect on Electric Utility's 1998 results. Total electric sales were higher in
1998 reflecting the warmer summer weather's effect on air conditioning use and
an increase in the number of customers. Electric Utility revenues in 1998 were
equal to 1997 reflecting higher total sales offset by the effects of our
Customer Choice Act pilot program. Our 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 1998 from $33.8 million in 1997.
The increase was due to slightly higher costs to generate electricity and
purchase power under our power supply agreement. In accordance with the June
1998 Restructuring Order, our base 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 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.
CORPORATE GENERAL EXPENSES. Corporate general expenses, which represent an
allocated share of corporate headquarters' expenses incurred by UGI, were $4.8
million in 1998 compared with $5.6 million in 1997. UGI's corporate general
expenses in the previous year included stock based compensation expense.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $17.6 million in 1998
compared with $16.9 million in 1997. The increase reflects higher average levels
of long-term debt outstanding partially offset by lower levels of bank loans
outstanding. The effective income tax rate for 1998 was 37.6% compared with a
rate of 38.8% in 1997.
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<PAGE> 19
1997 COMPARED WITH 1996
<TABLE>
<CAPTION>
- ---------------------------------------------------------- ------------- ------------- ----------------------------
Increase
Year Ended September 30, 1997 1996 (Decrease)
- ---------------------------------------------------------- ------------- ------------- ----------------------------
(Millions of dollars)
<S> <C> <C> <C> <C>
GAS UTILITY:
Natural gas system throughput - bcf 80.2 85.4 (5.2) (6.1)%
Degree days - % colder (warmer)
than normal (4.8)% 4.2% - -
Revenues $ 389.1 $ 391.0 $ (1.9) (.5)%
Total margin $ 168.7 $ 169.7 $ (1.0) (.6)%
Operating income $ 74.8 $ 72.9 $ 1.9 2.6%
ELECTRIC UTILITY:
Sales - gwh 868.5 884.7 (16.2) (1.8)%
Revenues $ 72.1 $ 69.5 $ 2.6 3.7%
Total margin $ 35.2 $ 33.0 $ 2.2 6.7%
Operating income $ 10.7 $ 8.6 $ 2.1 24.4%
CORPORATE GENERAL EXPENSES $ (5.6) $ (3.9) $ 1.7 43.6%
- ---------------------------------------------------------- ------------- ------------- ------------- --------------
</TABLE>
bcf - billions of cubic feet. gwh - millions of kilowatt hours. Total margin
represents revenues less cost of sales and revenue-related taxes.
GAS UTILITY. Weather in Gas Utility's service territory was 4.8% warmer than
normal in 1997 compared with weather that was 4.2% colder than normal in 1996.
Total system throughput decreased 6.1% during 1997 due to (1) the warmer
weather's effect on our core market sales and (2) a decrease in low-margin
interruptible delivery service volumes associated with the shut-down of a
gas-fired cogeneration facility.
Gas Utility's revenues were $1.9 million lower in 1997 as a $27.2 million
increase in core market revenues due mainly to higher average purchased gas cost
("PGC") rates was offset by (1) a $21.2 million decrease in core market revenues
from lower sales and (2) an $8.1 million decrease in revenues from off-system
sales. Our cost of gas sold decreased $1.1 million to $205.2 million in 1997
reflecting the lower off-system and core market sales partially offset by higher
average PGC rates.
The decrease in Gas Utility's total margin principally reflects a $6.3 million
decrease in total margin from core market customers resulting from the warmer
weather. This decrease was partially offset by a $5.5 million increase in total
margin from our interruptible customers.
Although total margin was slightly lower in 1997, Gas Utility operating income
increased $1.9 million because of (1) a $1.5 million decrease in operating
expenses and (2) higher other income. Operating expenses in 1997 declined $1.5
million due to (1) a decrease in distribution system expenses, (2) lower
accruals for uncollectible accounts, and (3) lower general and administrative
-17-
<PAGE> 20
expenses. These decreases were partially offset by higher costs associated with
environmental matters.
ELECTRIC UTILITY. Electric Utility sales decreased during 1997 on weather which
was 5.6% warmer than in 1996. Electric Utility base rate revenues increased $1.7
million in 1997 as a $2.8 million increase resulting from higher base rates was
partially offset by a $1.1 million decrease resulting from the lower sales. In
addition, Electric Utility revenues include a $.9 million increase in energy
cost recoveries. Our cost of sales increased to $33.8 million in 1997 from $33.4
million in 1996 due to higher energy cost recoveries partially offset by the
lower sales.
Electric Utility total margin and operating income increased during 1997
principally as a result of the higher base rates. Total operating and
administrative expenses in 1997 and 1996 were comparable.
CORPORATE GENERAL EXPENSES. Corporate general expenses, which represent an
allocated share of corporate headquarters' expenses incurred by UGI, were $5.6
million in 1997 compared with $3.9 million in 1996. The 1997 expenses were
higher due to UGI stock based compensation expense while the 1996 corporate
general expenses were reduced due to adjustments to incentive compensation
accruals.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $16.9 million in 1997
compared with $16.1 in 1996. The increase in interest expense reflects higher
average bank loans outstanding partially offset by lower average long-term debt
outstanding. The effective income tax rate for 1997 was 38.8% compared with a
rate of 37.9% for 1996.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
UGI Utilities' debt outstanding at September 30, 1998 totaled $255.6 million
compared with $236.3 million at September 30, 1997. During 1998, we issued $35
million of notes under our Medium-Term Note program and repaid $17.1 million of
maturing long-term debt. We also redeemed $15.2 million face value of preferred
stock during 1998.
UGI Utilities' primary cash sources have been (1) cash generated by operations
and (2) borrowings under its revolving credit agreements. UGI Utilities also can
issue up to an additional $52 million of unsecured debt under its shelf
registration.
UGI Utilities may borrow up to $97 million under its revolving credit
agreements. Borrowings under these credit agreements totaled $68.4 million at
September 30, 1998 and $67 million at September 30, 1997. The revolving credit
agreements contain financial covenants with respect to interest coverage ratios
and minimum tangible net worth. These covenants also restrict payments for
investments, redemptions of capital stock, repayments of debt and dividends. At
September 30, 1998, UGI Utilities could borrow up to the maximum amount
available.
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<PAGE> 21
Management believes that UGI Utilities' cash flow from operations and borrowings
under its shelf registration and bank credit facilities will satisfy UGI
Utilities cash needs for the foreseeable future.
CASH FLOWS
OPERATING ACTIVITIES. Our operating cash flows are seasonal and are generally
greatest during the winter and spring when customers pay heating bills incurred
during the heating season. Accordingly, the actual amount of cash generated
during such period is dependent in large part upon the severity of
heating-season weather. Cash flow from operating activities was $50.2 million in
1998 compared with $69.5 million in 1997. Cash flow from operating activities
before changes in operating working capital was $69.0 million in 1998 compared
with $64.1 million in 1997. The increase in 1998 cash flow before changes in
working capital is due principally to higher noncash deferred tax expense in
1998. Changes in operating working capital in 1998 used $18.9 million of
operating cash flow principally from (1) a decrease in accounts payable, (2) a
decrease in deferred fuel overcollections, and (3) higher income tax payments.
These items were partially offset by an increase in accounts receivable and
inventories. In 1997, changes in operating working capital provided $5.4 million
of operating cash flow principally from an increase in accounts payable and
purchased gas cost overcollections partially offset by an increase in accounts
receivable.
INVESTING ACTIVITIES. Expenditures for property, plant and equipment was $37.2
million in 1998 compared with $41.7 million in 1997. The decrease reflects lower
Gas Utility capital expenditures.
FINANCING ACTIVITIES. During 1998, we paid $22.6 million in cash dividends to
UGI and $2.1 million in cash dividends to holders of our preferred stock. During
1997, we paid $24.1 million in dividends to UGI and $2.8 million to holders of
preferred stock. UGI Utilities borrowed a net $1.4 million under its revolving
credit facilities in 1998 compared with net borrowings of $16.5 million in 1997.
During 1998, UGI Utilities issued $35 million of notes under its Medium-Term
Note program, compared with $20 million issued in 1997. In April 1998, UGI
Utilities voluntarily redeemed $12.2 million of its Series Preferred Stock and
an additional $3.0 million was redeemed pursuant to a mandatory sinking fund
requirement.
CAPITAL EXPENDITURES
The following table presents capital expenditures of Gas Utility and Electric
Utility for the years ended September 30, 1998, 1997 and 1996, as well as
expected amounts for fiscal 1999. Utilities expects to finance 1999 capital
expenditures through internally generated cash and borrowings under its credit
facilities.
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<PAGE> 22
<TABLE>
<CAPTION>
- --------------------------------------------------------- ------------- ------------- ------------- --------------
Year Ended September 30, 1999 1998 1997 1996
- --------------------------------------------------------- ------------- ------------- ------------- --------------
(Millions of dollars) (estimate)
<S> <C> <C> <C> <C>
Gas Utility $40.5 $32.0 $36.7 $34.6
Electric Utility 4.5 5.2 5.0 5.0
- --------------------------------------------------------- ------------- ------------- ------------- --------------
$45.0 $37.2 $41.7 $39.6
- --------------------------------------------------------- ------------- ------------- ------------- --------------
</TABLE>
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 having date sensitive 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 are using
internal and external resources to conduct a detailed assessment of critical,
date sensitive computer-based systems and to identify and modify systems which
are not Y2K compliant. The scope of such efforts includes (1) our information
technology ("IT") systems such as computer hardware and software we use in the
operation of our business; (2) non-IT systems that contain embedded computer
technology such as micro-controllers contained in various equipment and
facilities; and (3) the readiness of third parties, including our suppliers and
key vendors, and certain of our customers. We have directed our Y2K compliance
efforts toward ensuring that we will be able 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. In
addition, the PUC has ordered that all Pennsylvania utilities' mission critical
systems must be Y2K compliant by March 31, 1999. We have completed the
assessment phase of our IT and non-IT systems.
We have successfully modified and unit tested all of our critical IT and non-IT
systems including our customer information systems, distribution control
systems, and financial systems. We plan to begin integrated testing of these
systems in February 1999. We currently anticipate that all IT and non-IT systems
critical to the operations of our business will be Y2K compliant and tested by
March 31, 1999.
In addition to internal Y2K remediation activities, we are in the process of
assessing the readiness of our key suppliers and third-party providers. Although
none of our products or services are directly date sensitive, as a utility
company we are dependent upon other companies whose IT and non-IT systems may
not be Y2K compliant. We rely on these companies for the supply and
transportation of natural gas and the generation of electricity beyond that
which we generate ourselves. If key third parties cannot provide products or
services because of their own Y2K problems, it could have a material adverse
impact on our operations. The extent of such impact
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<PAGE> 23
would depend upon the duration of disruption and our costs to find alternative
sources of products and services, among others. We expect to complete our
evaluation of key supplier and third-party readiness by March 31, 1999.
While we have directed our focus on resolving our Y2K issues and expect our
critical IT and non-IT systems to be Y2K compliant by March 31, 1999, we are in
the process of developing contingency plans as required by the PUC. We
anticipate the major elements of these contingency plans will be based upon the
use of manual back-up systems, additional staffing, and alternative supply
sources. These contingency plans attempt to mitigate the impact of third-party
Y2K noncompliance. However, they cannot assure that business disruptions caused
by key suppliers or third party providers will not have a material adverse
impact on our operations. We expect the business contingency plans to be
completed by March 31, 1999. In addition to the business risks noted above,
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 the failure of
utility and telecommunication companies to provide service and the failure of
financial institutions to process transactions.
Incremental costs associated with our Y2K efforts have not had a material effect
on our results of operations. Estimated future costs to modify IT and non-IT
systems are expected to be less than $.5 million and will be financed through
internally generated funds. We expense Y2K costs as incurred.
CUSTOMER CHOICE ACT
On June 19, 1998, the PUC entered its Opinion and Order (the "Restructuring
Order") in Electric Utility's restructuring proceeding. The Restructuring Order
was issued pursuant to the Customer Choice Act which requires all Pennsylvania
electric utilities to "unbundle" rates for generation, transmission and
distribution services and to open electric sales to permit competitors to sell
electricity to our customers. Under the terms of the Restructuring Order,
beginning January 1, 1999 we will begin recovering $32.5 million in stranded
costs (including all related income taxes and gross receipts taxes) over a
four-year period. We will recover these costs through a Competitive Transition
Charge ("CTC") that we will charge all of our distribution customers. We will
also recover interest costs on the unrecovered balances at an annual rate of
7.94%. "Stranded costs" are costs that we would have recovered under prior
ratemaking but may not be recoverable in the new competitive electric generation
marketplace.
Under the terms of the Restructuring Order, our rates for the transmission and
distribution of electricity through our wires are capped through July 1, 2001.
Electric Utility may generally 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. All of our Electric
Utility customers have the opportunity to purchase electricity from other
suppliers beginning January 1, 1999. We will give those customers who choose an
alternate supplier a "shopping credit" averaging about 3.67 cents a
kilowatt-hour in calendar 1999 and 2000, and 4.3 cents a kilowatt-hour in
calendar 2001 and 2002.
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<PAGE> 24
As a result of the Restructuring Order, we discontinued regulatory accounting
for the electric generation portion of our business in June 1998. The
discontinuance did not have a material effect on our financial condition or
results of operations.
We continue to evaluate the potential impact of the Customer Choice Act and the
Restructuring Order on Electric Utility's future financial results. Because the
sources and costs of our electric power vary from period to period and because
we no longer defer the difference between actual power costs and amounts
included in rates, Electric Utility's quarterly results may be more volatile in
the future. In addition, financial results will likely depend upon a number of
factors including the number of our customers who choose alternative electricity
suppliers and our success in producing or purchasing electricity at competitive
market prices. If our costs to produce or purchase power exceed the amounts we
are able to charge our customers (including an allocable portion of our CTC
revenues), Electric Utility's results would be adversely affected.
PROPOSED GAS CUSTOMER CHOICE LEGISLATION
On March 27, 1997, proposed gas customer choice legislation was introduced in
the Pennsylvania General Assembly. The proposed legislation would, among other
things, extend the availability of gas transportation service to residential and
small commercial customers of local gas distribution companies. It would permit
all customers of natural gas distribution utilities to purchase gas from
suppliers of their choice by April 1, 1999. It would also require Pennsylvania
gas utilities to stop selling natural gas. Legislative committees have conducted
public hearings on the proposed legislation and we have provided testimony on
issues such as the recovery of costs associated with our existing gas supply
assets and the need for standards to assure reliability of future gas supplies.
At the request of the Governor of Pennsylvania, in December 1997 a collaborative
group of industry stakeholders was convened to attempt to further develop the
proposed legislation. To date, this group has failed to reach a consensus. We
expect the collaborative process to continue, and we will participate and
monitor developments, as appropriate. Gas Utility is considering a number of
options for addressing the provision of unbundled transportation to residential
and small commercial customers.
MANUFACTURED GAS PLANTS
The gas distribution business has been one of UGI Utilities' main businesses
since it began in 1882. Prior to the 1950s construction of major natural gas
pipelines, 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 Comprehensive Environmental Response, Compensation and Liability Act
("Superfund Law") and may be located at those sites.
One of the ways UGI Utilities 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 of expansion was by acquiring all or a portion
of the stock of companies engaged in this business. UGI Utilities also provided
management and administrative services to some of these companies. UGI Utilities
grew rapidly to become one of the largest public utility holding companies in
the
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<PAGE> 25
U.S. Pursuant to the Public Utility Holding Company Act of 1935, UGI Utilities
divested all of its utility operations other than those which now constitute Gas
Utility and Electric Utility.
UGI Utilities has been notified of several sites outside Pennsylvania on which
(1) MGPs were formerly operated by it or owned or operated by its former
subsidiaries and (2) either environmental agencies or private parties are
investigating the extent of environmental contamination and the necessity of
environmental remediation. UGI Utilities is currently litigating a claim against
it relating to an out of state site. If UGI Utilities were found liable as a
"responsible party" as defined in the Superfund Law or in comparable state
statutes, it would have joint and several liability with other responsible
parties for the full amount of the cleanup costs. A "responsible party" under
the Superfund Law includes the current owner of the property and each owner or
operator of the facility during the time hazardous substances were released on
the property. In addition, UGI Utilities has identified environmental
contamination at several of its properties and has voluntarily investigated and,
as appropriate, remediated these sites in cooperation with 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.
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 on 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.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive
Income" ("SFAS 130"), and SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information" ("SFAS 131"). SFAS 130 establishes standards
for reporting and displaying comprehensive income and its components in
financial statements. Comprehensive income includes net income and all other
nonowner changes in equity. SFAS 131 establishes standards for reporting
information about operating segments as well as related disclosures about
products and services, geographic areas, and major customers. We will adopt SFAS
130 and SFAS 131 in fiscal 1999. In addition, 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
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<PAGE> 26
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
adoptions of SFAS 130 and SOP 98-1 will have a material effect on our financial
position or results of operations. In addition, we do not expect the initial
application of SFAS 131 will affect the operating segments we disclose.
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. We will adopt SFAS 133 in
fiscal 2000.
We are currently evaluating the potential impact of SFAS 133 on our future
financial condition and results of operations. The impact of SFAS 133 will
likely depend upon the extent to which we use derivative instruments and their
designation and effectiveness as hedges of market risk.
IMPACT OF INFLATION
Inflation impacts the Company's gas and electric utility operations primarily in
the prices they pay for labor, materials and services. Because Electric
Utility's base rates are capped and 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 the utilities' results. Under
current tariffs, Gas Utility is permitted, after annual 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 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
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<PAGE> 27
conditions resulting in reduced demand; (2) price volatility and availability of
oil, electricity and natural gas and the capacity to transport to market areas;
(3) changes in laws and regulations, including safety, tax and accounting
matters; (4) competitive pressures from the same and alternative energy sources;
(5) liability for environmental claims; (6) improvements in energy efficiency
and technology resulting in reduced demand; (7) labor relations; (8) large
customer defaults; (9) operating hazards and risks incidental to generating and
distributing electricity and distributing natural gas including the risk of
explosions and fires resulting in personal injury and property damage; (10)
regional economic conditions; (11) the success of the company and its suppliers
in achieving Year 2000 compliance; and (12) interest rate fluctuations and other
capital market conditions.
These factors are not necessarily all of the important factors that could cause
actual results to differ materially from those expressed in any of our
forward-looking statements. Other unknown or unpredictable factors could also
have material adverse effects on future results. We undertake no obligation to
update publicly any forward-looking statement whether as a result of new
information or future events.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
At September 30, 1998, Utilities had no material market risk requiring
disclosure in accordance with Item 305 of Regulation S-K.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the financial statement schedule set forth
on pages F-1 to F-27 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
During fiscal year 1997, Utilities engaged a new independent auditor,
Arthur Andersen LLP. The information required by Item 9 is incorporated in this
report by reference to Utilities' Amendment No. 1 on Form 8-K/A to its Current
Report on Form 8-K dated July 11, 1997.
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<PAGE> 28
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 48 1994 Chairman of the Company (since August 1996); Chief
Executive Officer (since August 1995), Director and
President (since 1994) of UGI; formerly, Vice
Chairman of the Company (1994 to 1996) and 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 62 1979 President and Chief Executive Officer of Stratton
Management Company since 1972 (investment advisory
and financial consulting firm); Chairman and Chief
Executive Officer of FinDaTex (financial services
firm). Director: AmeriGas Propane, Inc.; Stratton
Growth Fund; Stratton Monthly Dividend Shares, Inc.;
Stratton Small-Cap Yield Fund; Unisource Worldwide,
Inc.; Teleflex, Inc.
David I. J. Wang 66 1988 Retired; formerly, Executive Vice President-Timber
and Specialty Products and a Director of
International Paper Company (1987 to 1991).
Director: AmeriGas Propane, Inc.
</TABLE>
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<PAGE> 29
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ---------- ------------------------------------------------------
<S> <C> <C> <C>
Richard C. Gozon 60 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 58 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.
Richard L. Bunn 62 1992 President and Chief Executive Officer of the Company
(since May 1992). Mr. Bunn joined the Company in
1958 as an engineer in the Electric Division.
Director: Paoli Travel Services, Inc.
</TABLE>
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<PAGE> 30
<TABLE>
<CAPTION>
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ---------- ------------------------------------------------------
<S> <C> <C> <C>
Marvin O. Schlanger 50 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). Director: Wellman, Inc.
Thomas F. Donovan 65 1998 Retired; formerly Vice Chairman of Mellon Bank (1988
to 1986). 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) With the exception of Mr. Bunn, all of the directors serve as directors
of UGI. Messrs. Greenberg, Donovan, Gozon, Stratton and Wang also serve
as directors of AmeriGas Propane, Inc., the General Partner of AmeriGas
Partners, L.P.
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<PAGE> 31
EXECUTIVE OFFICERS
<TABLE>
<CAPTION>
Name Age Position
- ---- --- --------
<S> <C> <C>
Lon R. Greenberg 48 Chairman of the Board of Directors
Richard L. Bunn 62 President and Chief Executive Officer
Brendan P. Bovaird 50 Vice President and General Counsel
Robert J. Chaney 56 Executive Vice President
Mark R. Dingman 49 Vice President and General Manager-
Electric Utility Division
John C. Barney 50 Vice President-Finance and Accounting
</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).
Richard L. Bunn
Mr. Bunn is President and Chief Executive Officer of the Company (since
May 1992). Mr. Bunn began his career with the Company as an engineer in the
Electric Utility Division in 1958, and successively held various operating and
staff positions.
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<PAGE> 32
Robert J. Chaney
Mr. Chaney is Executive Vice President - Utilities (since September
1998). He previously served as Vice President and General Manager-Gas Utility
Division of the Company (1991 to 1998) and as Vice President-Rates and Energy
Utilization of the Company's Gas Utility Division (1981 to 1991).
Mark R. Dingman
Mr. Dingman is Vice President and General Manager-Electric Utility
Division of the Company (since 1990). Previously, he was Manager-Power
Production of the Electric Division (1986 to April 1990).
John C. Barney
Mr. Barney is Vice President-Finance and Accounting of Utilities (since
April 1992). Previously, Mr. Barney served as Vice President-Finance of the
Company's Gas Utility Division (1987 to April 1992).
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) and Senior Vice President,
General Counsel and Secretary of Orion Pictures Corporation (1990 to 1991).
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<PAGE> 33
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
Securities
Other Underlying Payouts All
Annual Options/ Long-Term Other
Name and Bonus Compensation SARs Granted Incentive Compensation
Principal Position Year Salary (1) (2) (#) Payouts (3)
------------------ ---- ------ --- --- --- ------- ---
<S> <C> <C> <C> <C> <C> <C> <C>
Lon R. Greenberg (4)(5) 1998 $559,616 $225,000 $ 8,209 0 $0 $ 22,154
Chairman 1997 $509,827 $425,000 $ 7,671 200,000 (6) $0 $ 14,233
1996 $465,000 $122,760 $ 7,359 0 $0 $ 10,462
Richard L. Bunn (5) 1998 $330,801 $83,623 $ 9,410 0 $0 $ 10,572
President and Chief 1997 $318,089 $139,073 $ 7,696 75,000 (6) $0 $ 10,254
Executive Officer 1996 $305,900 $137,655 $ 5,855 0 $0 $ 10,579
Robert J. Chaney 1998 $171,801 $33,777 $ 4,528 8,333 $0 $ 5,023
Executive Vice 1997 $164,396 $51,457 $ 4,272 35,000 (6) $0 $ 4,921
President 1996 $156,601 $54,321 $ 4,019 0 $0 $ 5,074
Mark R. Dingman 1998 $132,796 $47,282 $ 7,524 0 $0 $ 3,580
Vice President & 1997 $125,298 $26,322 $ 6,410 35,000 (6) $0 $ 3,649
General Manager, 1996 $120,000 $33,600 $ 5,730 0 $0 $ 3,375
Electric Utility
Division
Brendan P. Bovaird (4)(5) 1998 $176,677 $42,188 $ 4,075 0 $0 $ 5,425
Vice President and 1997 $164,653 $64,449 $ 3,769 30,000 (6) $0 $ 4,196
General Counsel 1996 $149,999 $21,853 $ 1,299 0 $0 $ 1,363
</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 1998
ranged from 0% to 148% of base salary for Mr. Greenberg, 0% to 52% for Mr.
Bunn, from 0% up to 38% for Mr. Chaney, from 0% to 30% for Mr. Dingman,
and from 0% to 65% for Mr. Bovaird.
(2) Amounts represent tax payment reimbursements for certain benefits.
(3) 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 1998,
1997 and 1996, the following contributions were made to the Named
Executives: (i) under the Employee Savings Plan: For Messrs. Greenberg,
Bunn and Chaney, $3,600, $3,375 and $3,375; Mr. Dingman, $3,580, $3,375
and $3,375; Mr. Bovaird, $3,600, $3,375, and $1,363; and (ii) under the
Supplemental Executive
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<PAGE> 34
Retirement Plan: Mr. Greenberg, $18,554, $10,858, and $7,087; Mr. Bunn,
$6,972, $6,879, and $7,204; Mr. Bovaird, $1,825, $821, and $0; Mr. Chaney,
$1,423, $1,546, and $1,699; Mr. Dingman, $0, $274, and $0.
(4) Mr. Greenberg was elected Chairman, UGI Utilities, Inc. effective August
1, 1996. 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.
(5) Compensation reported for Messrs. Greenberg, Bovaird and Bunn is also
reported in the Proxy Statement for UGI's 1999 Annual Meeting of
Shareholders and is not additive.
(6) Non-qualified stock options granted on December 10, 1996 under the UGI
1997 Stock Option and Dividend Equivalent Plan (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.
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<PAGE> 35
OPTION GRANTS IN LAST FISCAL YEAR
The following table shows information on grants of stock options during
fiscal year 1998 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 (1) Fiscal Year (2) or Base Price Expiration Date Value (3)
---- ----------- --------------- ------------- --------------- ---------
<S> <C> <C> <C> <C> <C>
Lon R. Greenberg 0
Richard L. Bunn 0
Robert J. Chaney 8,333 69% $22.375 9/28/08 $17,340
Mark R. Dingman 0
Brendan P. Bovaird 0
</TABLE>
(1) Non-qualified stock options granted on September 28, 1998 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.
(2) A total of 12,083 options were granted to employees and executive officers
of the Company during fiscal year 1998 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.
(3) Based on the Black-Scholes options pricing model. The assumptions used in
calculating the grant date present value are as follows:
- Three years of closing monthly stock price observations were used
to calculate the stock volatility and dividend yield assumptions
- Stock volatility - .1614
- Stock's dividend yield - 6.0%
- Length of option term - 10 years
- Annualized risk-free interest rate - 5.03%
- Discount of risk of forfeiture - 0%
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.
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<PAGE> 36
OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
The following table shows information for the 1998 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
Unexercised
Number Of Securities In-The-Money
Underlying Unexercised 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 (2) -0- $281,877 (4) $0
Lon R. Greenberg (1) 50,000 $ 393,750 200,000 (3) -0- $100,000 (5) $0
Richard L. Bunn (1) 87,500 $ 673,682 75,000 (3) -0- $ 37,500 (5) $0
43,639 (2) -0- $130,917 (4) $0
Robert J. Chaney 1,361 $ 10,718 35,000 (3) -0- $ 17,500 (5) $0
8,333 (3) -0- $ 6,250 (6) $0
Mark R. Dingman 2,950 $ 23,231 35,000 (3) -0- $17,500 (5) $0
Brendan P. Bovaird(1) 5,007 (2) -0- $ 15,021 (4) $0
4,993 $ 37,448 30,000 (3) -0- $ 15,000 (5) $0
</TABLE>
(1) Information reported for Messrs. Greenberg, Bunn 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 1992 Stock Option and Dividend Equivalent Plan.
(3) Options granted under the 1997 Stock Option and Dividend Equivalent Plan.
(4) Value based on comparison of price per share at September 30, 1998 (fair
market value $23.125) to the option price ($20.125).
(5) Value based on comparison of price per share at September 30, 1998 (fair
market value $23.125) to the option price ($22.625).
(6) Value based on comparison of price per share at September 30, 1998 (fair
market value $23.125) to the option price ($22.375).
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<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 1998 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, Chaney, Dingman and
Bovaird had, respectively, 18 years, 40 years, 34 years, 25 years and 3
years of estimated credited service at September 30, 1998.
(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.
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<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, Bunn, Chaney 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
The Named Executives 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 2002, 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
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<PAGE> 39
(x) the then outstanding shares of common stock of UGI or (y) the combined
voting power of UGI's then outstanding voting securities, in either case unless
the members of the Executive Committee of the Board of Directors in office
immediately prior to such acquisition (the "Executive Committee") determine that
the circumstances do not warrant the implementation of the provisions of the
Agreement; (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, in any such case, unless the
Executive Committee determines at the time of such transaction that the
circumstances do not warrant the implementation of the provisions of the
Agreement; or (iv) UGI is liquidated or dissolved.
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.
COMPENSATION OF DIRECTORS
Messrs. Bunn 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.
-37-
<PAGE> 40
COMPENSATION COMMITTEE
The members of the UGI Utilities, Inc. Compensation and Management
Development Committee are Richard C. Gozon (Chairman), Thomas F. Donovan and
David I. J. Wang.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
At December 9, 1998, 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, 1998, 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 1.2%
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
Ownership
Excluding Options Number of Stock
Name of Beneficial Owner (1) (2) Options Total
------------------------ ------- ------- -----
<S> <C> <C> <C>
Stephen D. Ban 9,989 (3) 3,400 13,389
Brendan P. Bovaird 13,498 (4)(5) 35,007 48,505
Richard L. Bunn 62,216(6) 75,000 137,216
Robert J. Chaney 9,720 (7) 88,333 98,053
Mark R. Dingman 7,408 35,000 42,408
Thomas F. Donovan 1,647 0 1,647
Richard C. Gozon 14,184 5,000 19,184
Lon R. Greenberg 90,360(8) 293,959 384,319
Marvin O. Schlanger 1,283 0 1,283
James W. Stratton 9,880 5,000 14,880
David I. J. Wang 21,952 5,000 26,952
All directors and executive
officers as a group (12) 254,624 555,699 810,323 (9)
</TABLE>
-38-
<PAGE> 41
(1) The director or officer has sole voting and investment power
unless otherwise specified.
(2) Included in the number of shares shown above are Deferred Units
("Units") acquired through the 1997 Directors' Equity
Compensation Plan. Units are neither actual shares nor other
securities, but each Unit will be converted to one share of
Common Stock and paid out to directors upon their retirement or
termination of service. The number of Units included for each
director is as follows: Messrs. Donovan (630), Stratton (8,335),
Schlanger (866), Wang (7,407), Gozon (7,639) and Ban (4,219).
(3) Dr. Ban's shares are held jointly with his spouse.
(4) Mr. Bovaird's beneficial ownership includes 12,993 shares that
he holds jointly with his spouse.
(5) Included in beneficial ownership are shares represented by units
held in the UGI Stock Fund of the 401(k) Employee Savings Plan,
based on September 30, 1998 Savings Plan statements.
(6) Mr. Bunn's beneficial ownership includes 40,716 shares that he
holds jointly with his spouse and 21,500 shares held directly by
his spouse.
(7) Mr. Chaney's beneficial ownership includes 2,561 shares that he
holds jointly with his spouse.
(8) Mr. Greenberg's beneficial ownership includes 88,220 shares that
he holds jointly with his spouse.
(9) The total number of shares beneficially owned by the directors
and officers as group represents 2.5% of UGI's outstanding
shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In fiscal year 1998 UGI allocated $4.8 million, representing 45% of its
general corporate expenses, to Utilities.
-39-
<PAGE> 42
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:
Reports of Independent Accountants
Consolidated Balance Sheets, September 30, 1998 and 1997
Consolidated Statements of Income for the fiscal years ended
September 30, 1998, 1997 and 1996
Consolidated Statements of Cash Flows for the fiscal years
ended September 30, 1998, 1997 and 1996
Consolidated Statements of Stockholders' Equity for the fiscal
years ended September 30, 1998, 1997 and 1996
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.
-40-
<PAGE> 43
(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>
-41-
<PAGE> 44
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 P. 61,060 (1993), order
on rehearing, 64 FERC P. 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
P. 61,060 (1993), order on rehearing, 64 FERC P. 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 P. 61,060 (1993), order on rehearing, 64 FERC
P. 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>
-42-
<PAGE> 45
INCORPORATION BY REFERENCE
<TABLE>
<CAPTION>
Exhibit No. Exhibit Registrant Filing Exhibit
----------- ------- ---------- ------ -------
<S> <C> <C> <C> <C>
10.12** Change of Control Agreement between UGI Corporation UGI Form 10-K 10.13
and Lon R. Greenberg (9/30/97)
10.13** Form of Change of Control Agreement between UGI UGI Form 10-K 10.14
Corporation and Mr. Bunn (9/30/97)
10.14** Form of Change of Control Agreement between UGI UGI Form 10-K 10.15
Corporation and each of Messrs. Chaney, Dingman and (9/30/97)
Bovaird
10.15** UGI Corporation 1992 Non-Qualified Stock Option Plan AmeriGas Form 10-K 10.19
Partners, (9/30/95)
L.P.
10.16** Amendment No. 1 to UGI Corporation 1992 Non-Qualified UGI Utilities Form 10-Q 10
Stock Option Plan (6/30/97)
10.17** UGI Corporation 1997 Stock Option and Dividend UGI Form 10-Q 10.2
Equivalent Plan (3/31/97)
10.18** UGI Corporation Supplemental Executive Retirement Plan UGI Form 10-Q 10
Amended and Restated effective October 1, 1996 (6/30/98)
*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
*13 Amendment No. 1 on Form 8-K/A to Form 8-K dated July
11, 1997
*23.1 Consent of Arthur Andersen LLP
*23.2 Consent of PricewaterhouseCoopers 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 1998 fiscal year, the Company filed no
Current Reports on Form 8-K.
-43-
<PAGE> 46
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 15, 1998 By: John C. Barney
-----------------------------------
John C. Barney
Vice President -
Finance and Accounting
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below on December 15, 1998 by the following persons
on behalf of the Registrant in the capacities indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<S> <C>
Richard L. Bunn President and Chief
- ----------------------------- Executive Officer
Richard L. Bunn (Principal Executive
Officer) and Director
Lon R. Greenberg Chairman and Director
- -----------------------------
Lon R. Greenberg
John C. Barney Vice President -
- ----------------------------- Finance and Accounting
John C. Barney (Principal Financial
Officer and Principal
Accounting Officer)
Stephen D. Ban Director
- -----------------------------
Stephen D. Ban
Thomas F. Donovan Director
- -----------------------------
Thomas F. Donovan
</TABLE>
-44-
<PAGE> 47
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<S> <C>
Richard C. Gozon Director
- -----------------------------
Richard C. Gozon
Marvin O. Schlanger Director
- -----------------------------
Marvin O. Schlanger
James W. Stratton Director
- -----------------------------
James W. Stratton
David I. J. Wang Director
- -----------------------------
David I. J. Wang
</TABLE>
-45-
<PAGE> 48
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 1998
F-1
<PAGE> 49
UGI UTILITIES, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
Pages
-----
Financial Statements:
Reports of Independent Public Accountants F-3 and F-4
Consolidated Balance Sheets as of September 30,
1998 and 1997 F-5 and F-6
Consolidated Statements of Income for the years
ended September 30, 1998, 1997, and 1996 F-7
Consolidated Statements of Cash Flows for the years
ended September 30, 1998, 1997, and 1996 F-8
Consolidated Statements of Stockholder's Equity
for the years ended September 30, 1998, 1997, and 1996 F-9
Notes to Consolidated Financial Statements F-10 to F-27
Financial Statement Schedule:
For the years ended September 30, 1998, 1997, and 1996:
II - Valuation and Qualifying Accounts S-1
We have omitted all other financial statement schedules because the required
information is either (1) not present; (2) not present in amounts sufficient to
require submission of the schedule; or (3) the information required is included
elsewhere in the financial statements or related notes.
F-2
<PAGE> 50
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholder
UGI Utilities, Inc.
We have audited the accompanying consolidated balance sheets of UGI Utilities,
Inc. and subsidiaries as of September 30, 1998 and 1997 and the related
consolidated statements of income, stockholder's equity and cash flows for the
years then ended. 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, 1998 and 1997 and the
results of their operations and their cash flows for the years then ended 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 information for the years ended
September 30, 1998 and 1997 included on 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 13, 1998
F-3
<PAGE> 51
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder
UGI Utilities, Inc.
We have audited the accompanying consolidated statements of income,
stockholder's equity, and cash flows of UGI Utilities, Inc. and subsidiaries for
the year ended September 30, 1996. We have also audited the related financial
statement schedule for the year ended September 30, 1996 listed in the index on
page F-2 of this Form 10-K. These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated results of operations and cash flows of
UGI Utilities, Inc. and subsidiaries for the year ended September 30, 1996 in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedule referred to above, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
Coopers & Lybrand L.L.P.
Philadelphia, Pennsylvania
November 22, 1996
F-4
<PAGE> 52
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
<TABLE>
<CAPTION>
September 30,
1998 1997
--------- ---------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents (note 1) $ 4,720 $ 12,813
Accounts receivable (less allowances for doubtful
accounts of $1,373 and $3,333, respectively) 20,258 25,309
Accrued utility revenues (note 1) 6,745 7,688
Inventories (notes 1 and 6) 28,460 30,645
Deferred income taxes (notes 1 and 4) 4,070 7,179
Prepaid expenses and other current assets 6,556 4,653
--------- ---------
Total current assets 70,809 88,287
Property, plant and equipment (note 1):
Gas utility 665,313 637,943
Electric utility 121,395 118,808
General 10,813 8,897
--------- ---------
797,521 765,648
Less accumulated depreciation and amortization (253,608) (237,293)
--------- ---------
Net property, plant and equipment 543,913 528,355
Regulatory assets (notes 1, 2 and 4) 59,318 48,953
Other assets 16,277 15,783
--------- ---------
Total assets $ 690,317 $ 681,378
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 53
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
<TABLE>
<CAPTION>
September 30,
1998 1997
-------- --------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt (note 3) $ 7,143 $ 17,143
Current portion of preferred stock (note 7) -- 3,000
Bank loans (note 3) 68,400 67,000
Accounts payable 38,847 45,367
Employee compensation and benefits accrued 7,807 8,207
Dividends and interest accrued 4,613 3,692
Income taxes accrued 197 5,071
Other current liabilities 17,103 26,621
-------- --------
Total current liabilities 144,110 176,101
Long-term debt (note 3) 180,027 152,151
Deferred income taxes (notes 1 and 4) 105,734 99,868
Deferred investment tax credits (notes 1 and 4) 9,978 10,376
Other noncurrent liabilities 19,226 10,201
Commitments and contingencies (note 8)
Preferred stock subject to mandatory redemption,
without par value (note 7) 20,000 32,187
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 68,249
Retained earnings 82,424 71,986
-------- --------
Total common stockholder's equity 211,242 200,494
-------- --------
Total liabilities and stockholders' equity $690,317 $681,378
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 54
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
<TABLE>
<CAPTION>
Year Ended
September 30,
-----------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Revenues (note 1) $ 422,283 $ 461,208 $ 460,496
--------- --------- ---------
Costs and expenses:
Gas, fuel and purchased power (note 1) 214,631 238,978 239,643
Operating and administrative expenses 111,175 117,874 119,432
Operating and administrative expenses
- related parties (note 13) 4,837 5,555 3,850
Depreciation and amortization (note 1) 22,043 21,431 21,602
Other income, net (4,993) (2,777) (1,842)
--------- --------- ---------
347,693 381,061 382,685
--------- --------- ---------
Operating income 74,590 80,147 77,811
Interest expense 17,583 16,872 16,094
--------- --------- ---------
Income before income taxes 57,007 63,275 61,717
Income taxes (notes 1 and 4) 21,456 24,564 23,369
--------- --------- ---------
Net income 35,551 38,711 38,348
Dividends on preferred stock 2,160 2,764 2,765
--------- --------- ---------
Net income after dividends on preferred stock $ 33,391 $ 35,947 $ 35,583
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-7
<PAGE> 55
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
<TABLE>
<CAPTION>
Year Ended
September 30,
--------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 35,551 $ 38,711 $ 38,348
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 22,043 21,431 21,602
Deferred income taxes, net 5,468 549 7,481
Provision for uncollectible accounts 4,099 4,272 4,933
Other 1,887 (850) (704)
-------- -------- --------
69,048 64,113 71,660
Net change in:
Accounts receivable and accrued utility revenues 1,895 (2,401) (9,444)
Inventories 2,185 (610) (6,608)
Deferred fuel costs (5,741) 2,870 (9,657)
Accounts payable (6,520) 5,850 5,894
Other current assets and liabilities (10,709) (338) 5,184
-------- -------- --------
Net cash provided by operating activities 50,158 69,484 57,029
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (37,219) (41,684) (39,659)
Net proceeds (costs) of property, plant and equipment disposals 311 (884) (1,189)
Other, net -- 500 740
-------- -------- --------
Net cash used by investing activities (36,908) (42,068) (40,108)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (25,093) (26,823) (35,649)
Issuance of long-term debt 35,000 20,000 20,000
Repayment of long-term debt (17,143) (27,380) (54,828)
Bank loans increase 1,400 16,500 8,500
Redemption of Series Preferred Stock (15,507) -- (15)
-------- -------- --------
Net cash used by financing activities (21,343) (17,703) (61,992)
-------- -------- --------
Cash and cash equivalents increase (decrease) $ (8,093) $ 9,713 $(45,071)
======== ======== ========
CASH AND CASH EQUIVALENTS:
End of period $ 4,720 $ 12,813 $ 3,100
Beginning of period 12,813 3,100 48,171
-------- -------- --------
Increase (decrease) $ (8,093) $ 9,713 $(45,071)
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-8
<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, 1995 $ 60,259 $ 68,052 $ 58,492
Net income 38,348
Cash dividends - common stock (32,884)
Cash dividends - preferred stock (2,765)
Other (61)
--------- -------- ---------
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
========= ======== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-9
<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 subsidiary UGI Development Company. 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
Management makes 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 Utilities'
business no longer meets the provisions of SFAS 71, we may be required
to write-off certain regulatory assets
F-10
<PAGE> 58
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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 Generation
Customer Choice and Competition Act (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.
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 $15,816 in 1998, $17,507 in 1997, and $16,100
in 1996. We paid income taxes totaling $21,116 in 1998, $24,246 in
1997, and $15,736 in 1996.
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.
F-11
<PAGE> 59
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 1998, 2.7% in 1997, and 2.9% in 1996.
Depreciation as a percentage of the related average depreciable base
for Electric Utility was 3.2% in 1998, 3.6% in 1997, and 3.6% in 1996.
Depreciation expense was $21,454 in 1998, $20,899 in 1997, and $20,848
in 1996.
ACCOUNTING FOR 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.
F-12
<PAGE> 60
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
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 January 1,
1997. We expect the generation rate cap to extend through December 31,
2002 (see Note 2).
ENVIRONMENTAL LIABILITIES
Our policy is to 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. 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.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" (SFAS 130), and SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information" (SFAS 131). SFAS 130 establishes
standards for reporting and displaying comprehensive income and its
components in financial statements. Comprehensive income includes net
income and all other nonowner changes in equity. SFAS 131 establishes
standards for reporting information about operating segments as well as
related disclosures about products and services, geographic areas, and
major customers. We will adopt SFAS 130 and SFAS 131 in fiscal 1999. In
addition, 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 adoptions of SFAS 130 and SOP 98-1 will have a
material effect on our financial position or results of operations. In
addition, we do not expect the initial application of SFAS 131 will
affect the operating segments we disclose.
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
F-13
<PAGE> 61
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. We
will adopt SFAS 133 in fiscal 2000. We are currently evaluating the
potential impact of SFAS 133 on our future financial condition and
results of operations. The impact of SFAS 133 will likely depend upon
the extent to which we use derivative instruments and their designation
and effectiveness as hedges of market risk.
2. 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 Customer Choice Act. The Restructuring Order
essentially adopts the terms included in a comprehensive settlement
agreement (the "Settlement Agreement") previously entered into by UGI
Utilities and the active parties to the restructuring proceeding,
except Pennsylvania Power and Light Company (PP&L). 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. In June 1998, Electric Utility recorded a liability of $8,692
for the buy-out of the 1993 power purchase agreement and also recorded
a corresponding regulatory asset.
Under the terms of the Restructuring Order and in accordance with the
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. All of Electric Utility's customers will be permitted to select
an alternative generation supplier as of January 1, 1999. Customers
choosing an alternative supplier will on average receive a generation
"shopping credit" developed from system-wide generation rates of 3.67
cents per kilowatt hour (kwh) in calendar 1999 and 2000, and 4.3 cents
per kwh in calendar 2001 and 2002. The Settlement Agreement gives
Electric Utility the right, subject to prior PUC approval, to transfer
its electric generation assets to a non-regulated affiliate.
F-14
<PAGE> 62
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Management believes that, upon filing the necessary documents with the
PUC, Electric Utility will receive such approval.
The Customer Choice Act also authorized the PUC to implement pilot
customer choice programs for up to five percent of the peak load of
each customer class. In accordance with PUC directives, Electric
Utility implemented such a pilot program effective November 1, 1997.
The implementation of the pilot program did not have a material effect
on Electric Utility's 1998 results of operations.
The EITF in 1997 issued EITF 97-4 which concluded that utilities should
discontinue application of SFAS 71 for the generation portion of their
business when a restructuring plan is in place and its terms are known.
Based on such guidance, 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 25% of Electric
Utility's identifiable assets. The discontinuance of SFAS 71 did not
have a material effect on our financial position or results of
operations.
REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our
accompanying balance sheets at September 30:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------
1998 1997
- ------------------------------------------------------------------------------
<S> <C> <C>
Regulatory assets:
Regulatory income tax asset $46,483 $44,438
Power agreement buy-out 8,692 --
Other postretirement benefits 3,340 3,809
Deferred environmental costs 803 706
- ------------------------------------------------------------------------------
Total regulatory assets $59,318 $48,953
- ------------------------------------------------------------------------------
Regulatory liabilities:
Refundable state taxes $ 2,039 $ 3,102
Deferred fuel costs 1,676 7,417
Other postretirement benefits 1,397 --
- ------------------------------------------------------------------------------
Total regulatory liabilities $ 5,112 $10,519
- ------------------------------------------------------------------------------
</TABLE>
F-15
<PAGE> 63
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. DEBT
Long-term debt comprises the following at September 30:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1998 1997
- -------------------------------------------------------------------------------
<S> <C> <C>
Medium-Term Notes:
7.25% Notes, due October 2017 $ 20,000 $ --
7.17% Notes, due June 2007 20,000 20,000
6.17% Notes, due January 2001 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 $115 and $134,
respectively) 49,885 49,866
8.70% Notes, due March 1998 -- 10,000
9.71% Notes, due through September 2000 in annual
installments of $7,143 14,285 21,428
- -------------------------------------------------------------------------------
Total long-term debt 187,170 169,294
Less current maturities (7,143) (17,143)
- -------------------------------------------------------------------------------
Long-term debt due after one year $ 180,027 $ 152,151
- -------------------------------------------------------------------------------
</TABLE>
Scheduled repayments of long-term debt for each of the next five fiscal
years ending September 30 are as follows: 1999 - $7,143; 2000 - $7,143;
2001 - $15,000; 2002 - $ -; 2003 - $76,000.
At September 30, 1998, UGI Utilities had revolving credit agreements
with four banks providing for borrowings of up to $97,000 through June
2001. These agreements may be extended for one-year periods, upon
timely notice, unless the banks elect not to renew. 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 $68,400 at
September 30, 1998 and $67,000 at September 30, 1997, which we classify
as bank loans. The weighted-average interest rates on bank loans were
5.90% at September 30, 1998 and 6.26% at September 30, 1997.
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.
F-16
<PAGE> 64
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES
The provisions for income taxes consist of the following:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------------
<S> <C> <C> <C>
Current:
Federal $ 12,184 $ 18,168 $ 12,184
State 3,804 5,847 3,704
- --------------------------------------------------------------------
15,988 24,015 15,888
Deferred 5,866 947 7,880
Investment credit amortization (398) (398) (399)
- --------------------------------------------------------------------
Total income tax expense $ 21,456 $ 24,564 $ 23,369
- --------------------------------------------------------------------
</TABLE>
A reconciliation from the statutory federal tax rate to our effective
tax rate is as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------------
<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 6.4 6.5 6.2
Deferred investment credit
amortization (.7) (.6) (.7)
Other, net (3.1) (2.1) (2.6)
- --------------------------------------------------------------------
Effective tax rate 37.6% 38.8% 37.9%
- --------------------------------------------------------------------
</TABLE>
F-17
<PAGE> 65
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Deferred tax liabilities (assets) comprise the following at September
30:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
1998 1997
- ----------------------------------------------------------------------------------------------
<S> <C> <C>
Excess book basis over tax basis of property, plant
and equipment $ 89,724 $ 85,387
Regulatory assets 24,613 20,312
Other 6,305 4,989
- ----------------------------------------------------------------------------------------------
Gross deferred tax liabilities 120,642 110,688
- ----------------------------------------------------------------------------------------------
Deferred investment tax credits (4,140) (4,305)
Deferred fuel costs (695) (3,077)
Employee-related expenses (5,421) (4,494)
Regulatory liability - state income taxes (846) (1,287)
Power purchase agreement liability (3,607) --
Other (4,269) (4,836)
- ----------------------------------------------------------------------------------------------
Gross deferred tax assets (18,978) (17,999)
- ----------------------------------------------------------------------------------------------
Net deferred tax liabilities $ 101,664 $ 92,689
- ----------------------------------------------------------------------------------------------
</TABLE>
UGI Utilities had recorded deferred tax liabilities of approximately
$31,336 as of September 30, 1998 and $30,305 as of September 30, 1997
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 $4,140 at September 30,
1998 and $4,305 at September 30, 1997, pertaining to utility deferred
investment tax credits. UGI Utilities had recorded a regulatory income
tax asset related to these net deferred taxes of $46,483 as of
September 30, 1998 and $44,438 as of September 30, 1997. 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
The Retirement Income Plan for Employees of UGI Utilities, Inc. (UGI
Utilities Plan) is a defined benefit pension plan covering employees of
UGI, UGI Utilities, and certain of UGI's other wholly owned
subsidiaries. Benefits under the UGI Utilities Plan are generally based
on years of service and employee compensation during the last years of
employment.
F-18
<PAGE> 66
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The components of net pension income for the UGI Utilities Plan include
the following:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------
1998 1997 1996
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits earned during
the period $ 3,038 $ 2,564 $ 2,657
Interest cost on projected benefit
obligation 10,233 10,037 9,621
Actual return on plan assets (2,017) (38,240) (15,393)
Net amortization and deferral (13,222) 24,482 2,330
- ---------------------------------------------------------------------------
Net pension income $ (1,968) $ (1,157) $ (785)
- ---------------------------------------------------------------------------
</TABLE>
The following table sets forth the funded status of the UGI Utilities
Plan and amounts recognized in our consolidated balance sheet at
September 30:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
1998 1997
- ----------------------------------------------------------------------------------------
<S> <C> <C>
Projected benefit obligation:
Vested benefits $(128,864) $(118,180)
Nonvested benefits (8,109) (6,772)
- ----------------------------------------------------------------------------------------
Accumulated benefit obligation (136,973) (124,952)
Effect of projected future salary levels (27,844) (24,111)
- ----------------------------------------------------------------------------------------
Projected benefit obligation (164,817) (149,063)
Plan assets at fair value 183,281 189,539
- ----------------------------------------------------------------------------------------
Excess of plan assets over projected benefit
obligation 18,464 40,476
Unrecognized net gain (3,918) (26,885)
Unrecognized prior service cost 5,333 5,999
Unrecognized transition asset (9,524) (11,155)
- ----------------------------------------------------------------------------------------
Prepaid pension cost $ 10,355 $ 8,435
- ----------------------------------------------------------------------------------------
</TABLE>
Included in the projected benefit obligation amounts above are $10,289
at September 30, 1998 and $8,264 at September 30, 1997, relating to
employees of UGI and its other subsidiaries.
The major actuarial assumptions used in determining the funded status
of the UGI Utilities Plan as of September 30, 1998, 1997, and 1996, and
net pension income for each of the years then ended, are as follows:
F-19
<PAGE> 67
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Funded status at September 30:
Discount rate 6.9 % 7.4 % 8.0 %
Rate of increase in
salary levels 4.5 4.5 4.75
Net pension income for the year:
Discount rate 7.4 8.0 7.5
Rate of increase in
salary levels 4.5 4.75 4.5
Expected return on plan
assets 9.5 9.5 9.5
- --------------------------------------------------------------------------------
</TABLE>
UGI Utilities Plan's assets at September 30, 1998 consist principally
of equity and fixed income mutual funds and investment-grade corporate
and U. S. Government obligations.
We have unfunded nonqualified retirement benefit plans for certain key
employees. At September 30, 1998 and 1997, the projected benefit
obligations of these plans were not material. We recorded expense for
these plans of $1,101 in 1998, $244 in 1997, and $257 in 1996. Amounts in
1998 include a settlement loss of $730 relating to the settlement of
certain nonqualified pension obligations.
We also sponsor a 401(k) savings plan (Savings Plan) for eligible
employees. Generally, participants in the Savings Plan may contribute a
portion of their compensation on a before-tax and after-tax basis. We may,
at our discretion, match a portion of participants' contributions. The
costs of such matching contributions were $987 in 1998, $880 in 1997, and
$865 in 1996.
We provide postretirement health care benefits to certain retirees and a
limited number of active employees meeting certain age and service
requirements as of January 1, 1989. We also provide limited postretirement
life insurance benefits to nearly all active and retired employees.
F-20
<PAGE> 68
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The components of net periodic postretirement benefit cost are as follows:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------
1998 1997 1996
-------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits
earned during the period $ 77 $ 64 $ 67
Interest cost on accumulated
postretirement benefit
obligation 890 1,588 1,908
Actual return on plan assets (200) (144) -
Net amortization and deferral 466 1,078 1,369
-------------------------------------------------------------------------
Net periodic postretirement
benefit cost 1,233 2,586 3,344
Change in regulatory assets
and liabilities 1,866 513 (149)
-------------------------------------------------------------------------
Net expense $ 3,099 $ 3,099 $ 3,195
-------------------------------------------------------------------------
</TABLE>
The following table sets forth the actuarial present value and funded
status of our postretirement health care and life insurance benefit plans
at September 30:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------
1998 1997
-------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit
obligation:
Retirees $(10,293) $(18,618)
Fully eligible active participants (1,234) (1,834)
Other active participants (1,750) (1,520)
-------------------------------------------------------------------------
(13,277) (21,972)
Plan assets at fair value 4,906 3,479
Unrecognized net gain (4,258) (1,881)
Unrecognized transition obligation 9,796 16,320
-------------------------------------------------------------------------
Accrued postretirement benefit cost $ (2,833) $ (4,054)
-------------------------------------------------------------------------
</TABLE>
Included in the accumulated postretirement benefit obligation amounts
above are $440 at September 30, 1998 and $406 at September 30, 1997,
relating to employees of UGI.
The decrease in the accumulated postretirement benefit obligation at
September 30, 1998 is due to (1) a change in health care provider
provisions and (2) a change in expected health care utilization rates.
F-21
<PAGE> 69
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The major actuarial assumptions used in determining the funded status of
our postretirement health care and life insurance benefit plans at
September 30, 1998, 1997, and 1996, and net periodic postretirement
benefit costs for the years then ended, are as follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------
1998 1997 1996
-----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Funded status at September 30:
Discount rate 6.9 % 7.4 % 8.0 %
Health care cost trend rate 6.0-5.5 6.0-5.5 6.5-5.5
Net periodic postretirement benefit cost for the year:
Discount rate 7.4 8.0 7.5
Health care cost trend rate 6.0-5.5 6.5-5.5 7.0-5.5
Expected return on trust assets 6.0 6.0 -
------------------------------------------------------------------------------------------------
</TABLE>
The ultimate health care cost trend rate of 5.5% in the table above is
assumed for all years after 2007. Increasing the health care cost trend
rate one percent increases the accumulated postretirement benefit
obligations by $614 at September 30, 1998 and $1,534 at September 30,
1997, and increases the net periodic postretirement benefit costs by $42
in 1998, $115 in 1997, and $160 in 1996.
We have established an Employee Benefit Trust (VEBA) to pay retiree health
care and life insurance benefits and to fund the UGI Utilities'
postretirement benefit liability. VEBA investments, comprising money
market funds, totaled $4,906 at September 30, 1998 and $3,479 at September
30, 1997.
6. INVENTORIES
Inventories comprise the following at September 30:
<TABLE>
<CAPTION>
----------------------------------------------------------------------
1998 1997
----------------------------------------------------------------------
<S> <C> <C>
Utility fuel and gases $24,487 $25,963
Appliances for sale 1,191 1,877
Materials, supplies and other 2,782 2,805
----------------------------------------------------------------------
Total inventories $28,460 $30,645
----------------------------------------------------------------------
</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
F-22
<PAGE> 70
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
arrearage has been cured. We have paid cash dividends at the specified
annual rates on all outstanding Series Preferred Stock.
Series Preferred Stock subject to mandatory redemption comprises the
following at September 30:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------
1998 1997
-------------------------------------------------------------------------
<S> <C> <C>
$7.75 Series, stated at involuntary
liquidation value of $100 per share,
cumulative (200,000 shares outstanding) $20,000 $20,000
$1.80 Series, stated at involuntary
liquidation value of $23.50 per share,
cumulative (7,963 shares redeemed April
1998) - 187
$8.00 Series, stated at involuntary
liquidation value of $100 per share,
cumulative (150,000 shares redeemed
April 1998) - 15,000
-------------------------------------------------------------------------
Total Series Preferred Stock subject to
mandatory redemption 20,000 35,187
Less current portion - (3,000)
-------------------------------------------------------------------------
Total Series Preferred Stock due after
one year $20,000 $32,187
-------------------------------------------------------------------------
</TABLE>
In April 1998, we (1) voluntarily redeemed 120,000 shares of our $8.00
Series Preferred Stock at a redemption price of $102.667 per share and (2)
redeemed 30,000 shares of our $8.00 Series Preferred Stock through a
mandatory sinking fund at a price of $100 per share. Also in April 1998,
we voluntarily redeemed all 7,963 outstanding shares of our $1.80 Series
Preferred Stock at a redemption price of $23.50 per share.
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
Preferred Stock at a price of $100 per share. The $7.75 Series Preferred
Stock 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 Preferred Stock 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 $5,278 in 1998, $5,083 in 1997, and
$4,891 in 1996.
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: 1999 - $4,148; 2000 - $3,513; 2001 -
$3,038; 2002 - $2,838; 2003 - $2,431; after 2003 - $3,016.
F-23
<PAGE> 71
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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 has
short-term gas supply agreements which permit it to purchase certain of
its gas supply needs on a firm or interruptible basis at spot market
prices.
Electric Utility has a power supply agreement with PP&L under which PP&L
supplies all the electric power required by Electric Utility, above that
provided from other sources. The cost of such electricity supplied by PP&L
is based on PP&L's actual system costs. The percentage of Electric
Utility's total electric system output supplied by PP&L was approximately
54% in 1998, 53% in 1997, and 52% in 1996. Electric Utility has provided
notice to PP&L of its intention to terminate this agreement as of March
2001. Electric Utility also has short-term, fixed price power supply
agreements to purchase all of the output of the 32 megawatt Montgomery
County Resource Recovery Facility through December 31, 1999.
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.
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. 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-24
<PAGE> 72
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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 $193,000 at
September 30, 1998 and $173,000 at September 30, 1997. 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
$24,000 at September 30, 1998 and $36,000 at September 30, 1997. 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, 1998 and
1997, we had no significant concentrations of credit risk.
F-25
<PAGE> 73
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
10. SEGMENT INFORMATION
Information on revenues, operating income, identifiable assets,
depreciation and amortization and capital expenditures by business segment
for 1998, 1997, and 1996 follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------
1998 1997 1996
----------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES
Gas utility $350,154 $389,064 $390,994
Electric utility 72,129 72,144 69,502
----------------------------------------------------------------------
Total $422,283 $461,208 $460,496
----------------------------------------------------------------------
OPERATING INCOME (LOSS)
Gas utility $68,852 $74,790 $72,937
Electric utility 10,439 10,689 8,622
Other 136 223 102
Corporate general (4,837) (5,555) (3,850)
----------------------------------------------------------------------
Total $74,590 $80,147 $77,811
----------------------------------------------------------------------
IDENTIFIABLE ASSETS
(at period end)
Gas utility $594,447 $594,331 $561,793
Electric utility 95,587 86,247 83,872
Corporate general and other 283 800 4,234
----------------------------------------------------------------------
Total $690,317 $681,378 $649,899
----------------------------------------------------------------------
DEPRECIATION AND AMORTIZATION
Gas utility $18,165 $17,194 $17,576
Electric utility 3,878 4,237 4,024
Corporate general - - 2
----------------------------------------------------------------------
Total $22,043 $21,431 $21,602
----------------------------------------------------------------------
CAPITAL EXPENDITURES
Gas utility $32,033 $36,691 $34,624
Electric utility 5,186 4,993 5,035
----------------------------------------------------------------------
Total $37,219 $41,684 $39,659
======================================================================
</TABLE>
F-26
<PAGE> 74
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,
1997 1996 1998 1997 1998 1997 1998 1997
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues $135,464 $134,154 $152,333 $173,304 $74,342 $88,208 $60,144 $65,542
Operating
income (loss) 30,329 30,343 36,150 41,022 7,818 8,977 293 (195)
Net income
(loss) 16,208 16,185 19,999 22,763 1,892 2,970 (2,548) (3,207)
----------------------------------------------------------------------------------------------------
</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-27
<PAGE> 75
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, 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
======= ======= ======== =======
YEAR ENDED SEPTEMBER 30, 1996
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 2,660 $ 4,933 $ (3,617)(1) $ 3,976
======= ======= ======== =======
Other reserves (3) $ 3,255 $ 237 $ (332)(2) $ 3,160
======= ======= ======== =======
</TABLE>
(1) Uncollectible accounts written off, net of recoveries.
(2) Payments
(3) Includes reserves for self-insured property and casualty liability, insured
property and casualty liability, environmental, litigation and other.
S-1
<PAGE> 76
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<S> <C>
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
13 Amendment No. 1 on Form 8-K/A to Form 8-K dated July 11, 1997
23.1 Consent of Arthur Andersen LLP
23.2 Consent of PricewaterhouseCoopers LLP
27 Financial Data Schedule
</TABLE>
<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,
-----------------------------------------------
1998 1997 1996 1995 1994
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
EARNINGS:
Earnings before income taxes $57,007 $63,275 $61,717 $39,759 $41,244
Interest expense 17,383 16,696 15,921 16,632 16,482
Amortization of debt discount and expense 200 176 173 206 187
Interest component of rental expense 1,624 1,887 1,838 1,604 1,344
------- ------- ------- ------- -------
$76,214 $82,034 $79,649 $58,201 $59,257
======= ======= ======= ======= =======
FIXED CHARGES:
Interest expense $17,383 $16,696 $15,921 $16,632 $16,482
Amortization of debt discount and expense 200 176 173 206 187
Allowance for funds used during
construction (capitalized interest) 39 114 107 65 136
Interest component of rental expense 1,624 1,887 1,838 1,604 1,344
------- ------- ------- ------- -------
$19,246 $18,873 $18,039 $18,507 $18,149
======= ======= ======= ======= =======
Ratio of earnings to fixed charges 3.96 4.35 4.42 3.14 3.27
======= ======= ======= ======= =======
</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,
----------------------------------------------
1998 1997 1996 1995 1994
------- ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
EARNINGS:
Earnings before income taxes $57,007 $63,275 $61,717 $39,759 $41,244
Interest expense 17,383 16,696 15,921 16,632 16,482
Amortization of debt discount and expense 200 176 173 206 187
Interest component of rental expense 1,624 1,887 1,838 1,604 1,344
------- ------ ------ ------ ------
$76,214 $82,034 $79,649 $58,201 $59,257
======= ======= ======= ======= =======
COMBINED FIXED CHARGES AND PREFERRED
STOCK DIVIDENDS:
Interest expense $17,383 $16,696 $15,921 $16,632 $16,482
Amortization of debt discount and expense 200 176 173 206 187
Allowance for funds used during
construction (capitalized interest) 39 114 107 65 136
Interest component of rental expense 1,624 1,887 1,838 1,604 1,344
Preferred stock dividend requirements 2,160 2,764 2,765 2,778 1,356
Adjustment required to state preferred stock
dividend requirements on a pretax basis 1,304 1,754 1,685 1,164 1,018
------- ------- ------- ------- -------
$22,710 $23,391 $22,489 $22,449 $20,523
======= ======= ======= ======= =======
Ratio of earnings to combined fixed charges
and preferred stock dividends 3.36 3.51 3.54 2.59 2.89
======= ======= ======= ======= =======
</TABLE>
<PAGE> 1
Exhibit 13
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K/A
AMENDMENT NO. 1 TO
CURRENT REPORT DATED JULY 11, 1997
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
JULY 11, 1997
(DATE OF REPORT)
UGI UTILITIES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
PENNSYLVANIA 1-1398 23-1174060
(STATE OR OTHER JURISDICTION (COMMISSION FILE (I.R.S. EMPLOYER
OF INCORPORATION) NUMBER) IDENTIFICATION NO.)
100 KACHEL BOULEVARD
GREEN HILLS CORPORATE CENTER, SUITE 400
READING, PENNSYLVANIA 19607
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(610) 796-3400
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
<PAGE> 2
UGI Utilities, Inc. Form 8-K/A
Page 2 July 11, 1997
ITEM 4. CHANGES IN REGISTRANT'S CERTIFYING ACCOUNTANT
In May 1996, Coopers & Lybrand L.L.P. ("C&L") was appointed by
the Audit Committee of the Board of Directors as the Company's independent
public accountants for the year ending September 30, 1997. That appointment was
approved by the Board of Directors.
In May 1997, the staff of the Securities and Exchange Commission
(the "Commission"), notified UGI Corporation ("UGI"), the parent of the Company,
that for the year ending September 30, 1997, UGI's principal auditor must audit
and assume the responsibility for reporting on at least 50% of the assets and
revenues of UGI on a consolidated basis. As stated in their reports on the
consolidated financial statements of UGI Corporation and subsidiaries for each
of the two most recent fiscal years, C&L did not audit the consolidated
financial statements of AmeriGas Propane, Inc. and subsidiaries ("AmeriGas
Propane") as of September 30, 1996 and 1995 and for the year ended September 30,
1996 and the period from April 19, 1995 to September 30, 1995, which statements
reflected total assets and revenues constituting 65 and 68 percent, and 65 and
31 percent, respectively, of the related consolidated totals of UGI. Those
AmeriGas Propane financial statements were audited by Arthur Andersen LLP
("AA"). AA furnished its reports on those financial statements to C&L. C&L's
reports on UGI's consolidated financial statements for the two most recent
fiscal years, in so far as they relate to amounts included for AmeriGas Propane,
are based solely on the reports of AA. The reports contained no adverse opinion
and were not qualified or modified as to uncertainty, audit scope, or accounting
principles. Relying on the reports of AA, C&L was satisfied that it was
qualified to act as UGI's principal auditor.
On July 11, 1997, UGI changed its certifying accountant from C&L to AA. In
conjunction with UGI's decision, on July 11, 1997 management (i) engaged AA as
the Company's independent public accountant (principal auditor), effective
August 15, 1997, to examine and report on the consolidated financial statements
of the Company for fiscal year 1997, and (ii) notified C&L that the prior
engagement of C&L as the Company's independent auditor would terminate on
August 15, 1997, following a review of the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1997. The decision to change accountants
was not recommended or approved by the Audit Committee of the Board of
Directors, however, it was ratified by the Board of Directors at the
July 29, 1997 Board meeting.
The reports of C&L on the Company's consolidated financial
statements for each of the two fiscal years ended September 30, 1996 and 1995,
contained no adverse opinion or disclaimer of opinion, and were not qualified or
modified as to uncertainty, audit scope, or accounting principles.
The Company is not aware of any disagreements with C&L during
the Company's two most recent fiscal years and through the date of this report
on any matters of accounting principles or practices, financial statement
disclosures, or auditing scope and procedures which, if not resolved to the
satisfaction of C&L, would have caused C&L to make reference to the matters in
their reports.
During the Company's two most recent fiscal years and through the
date of this report, the Company has had no reportable events as defined in Item
304 (a) (1)(v) of Regulation S-K.
<PAGE> 3
UGI Utilities, Inc. Form 8-K/A
Page 3 July 11, 1997
The Company has requested that C&L furnish it with a letter
addressed to the Securities and Exchange Commission stating whether C&L agrees
with the above statements. A copy of that letter dated August 1, 1997 is filed
as Exhibit 16 to this Amendment No. 1 on Form 8-K/A.
During the Company's two most recent fiscal years ended September
30, 1996 and September 30, 1995 and through the date of engagement of AA, the
Company has not consulted with AA regarding any of the matters specified in Item
304 (a) (2) of Regulation S-K.
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
(c) Exhibits
(16) Letter to the Securities and Exchange Commission from
Coopers & Lybrand, dated August 1, 1997.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned hereunto duly authorized.
UGI UTILITIES, INC.
(REGISTRANT)
By: /s/ John C. Barney
-------------------------------------
John C. Barney
Vice President-Finance and Accounting
Date: August 4, 1997
<PAGE> 4
EXHIBIT INDEX
Exhibit No. Description
- ----------- -----------
(16) Letter to the Securities and
Exchange Commission from
Coopers & Lybrand dated
August 1, 1997
A-1
<PAGE> 5
EXHIBIT 16
Coopers & Lybrand L.L.P. 101 East Kennedy Boulevard telephone (813)229-0221
Suite 1500
Tampa, Florida 33602-5194 facsimile (813)229-3646
a professional services firm
August 1, 1997
Securities and Exchange Commission
450 5th Street, N.W.
Washington, DC 20549
Gentlemen:
We have read the statements made by UGI Utilities, Inc. (copy attached), which
we understand will be filed with the Commission, pursuant to Item 4 of Form
8-K, as part of the Company's Report on Form 8-K/A dated July 11, 1997. We
agree with the statements concerning our Firm in such Form 8-K/A.
Very truly yours,
/s/ Coopers & Lybrand L.L.P.
<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 13, 1998, on the consolidated financial statements and
financial statement schedule of UGI Utilities, Inc. and subsidiaries for the
years ended September 30, 1998 and 1997, included in UGI Utilities, Inc.'s
Annual Report on Form 10-K for the fiscal year ended September 30, 1998, into
UGI Utilities, Inc.'s previously filed S-3 Registration Statement No. 333-4288.
Arthur Andersen LLP
Chicago, Illinois
December 22, 1998
<PAGE> 1
Exhibit (23.2)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statement of
UGI Utilities, Inc. on Form S-3 (File No. 333-4288) of our report dated
November 22, 1996, on our audit of the consolidated financial statements and
financial statement schedule of UGI Utilities, Inc. and subsidiaries for the
year ended September 30, 1996, which report is included in UGI Utilities, Inc.'s
Annual Report on Form 10-K for the year ended September 30, 1998.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
December 22, 1998
<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, 1998 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, 1998.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-START> OCT-01-1997
<PERIOD-END> SEP-30-1998
<CASH> 4,720
<SECURITIES> 0
<RECEIVABLES> 28,376
<ALLOWANCES> 1,373
<INVENTORY> 28,460
<CURRENT-ASSETS> 70,809
<PP&E> 797,521
<DEPRECIATION> 253,608
<TOTAL-ASSETS> 690,317
<CURRENT-LIABILITIES> 144,110
<BONDS> 180,027
20,000
0
<COMMON> 60,259
<OTHER-SE> 150,983
<TOTAL-LIABILITY-AND-EQUITY> 690,317
<SALES> 422,283
<TOTAL-REVENUES> 422,283
<CGS> 214,631
<TOTAL-COSTS> 214,631
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 4,099
<INTEREST-EXPENSE> 17,583
<INCOME-PRETAX> 57,007
<INCOME-TAX> 21,456
<INCOME-CONTINUING> 35,551
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 35,551
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1>THERE ARE NO PUBLICLY HELD SHARES OUTSTANDING.
</FN>
</TABLE>
