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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, 1997
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, 1997 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........................................................ 14
PART II SECURITIES AND FINANCIAL INFORMATION
Item 5 Market for Registrant's Common Equity
and Related Stockholder Matters......................................... 14
Item 6 Selected Financial Data................................................... 15
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations..................................... 16
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........................ 25
Item 11 Executive Compensation.................................................... 30
Item 12 Security Ownership of Certain Beneficial
Owners and Management................................................... 39
Item 13 Certain Relationships and Related
Transactions............................................................ 40
PART IV ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
Item 14 Exhibits, Financial Statement Schedules
and Reports on Form 8-K................................................. 41
Signatures................................................................ 48
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"). Utilities is a wholly owned subsidiary of
UGI Corporation ("UGI").
Utilities (formerly, UGI Corporation) was incorporated in Pennsylvania
in 1925 as the successor to a business founded in 1882. The Company is subject
to regulation by the Pennsylvania Public Utility Commission ("PUC"). Its
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. References to the "Company" include Utilities and its consolidated
subsidiaries unless the context indicates otherwise.
GAS UTILITY OPERATIONS
Service Area; Revenue Analysis. Gas Utility distributes natural gas to
approximately 252,000 customers in portions of 14 eastern and southeastern
Pennsylvania counties through its distribution system of approximately 4,200
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 steel
fabrication. For the fiscal years ended September 30, 1997, 1996 and 1995,
revenues of Gas Utility accounted for approximately 84%, 85% and 82%,
respectively, of Utilities' total consolidated revenues.
System throughput (the total volume of gas sold to or transported for
customers within Gas Utility's distribution system) for the 1997 fiscal year was
approximately 80.2 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 46% of system throughput, while gas transported for commercial and
industrial customers (who buy their gas from others) accounted for approximately
54% of system throughput. Based on industry data for 1996, residential customers
account for approximately 38% of total system throughput by local gas
distribution companies in the United States. By contrast, for the 1997 fiscal
year, Gas Utility's residential customers represented 23% of its total system
throughput.
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
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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
("Columbia"), 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 and Panhandle Eastern Pipe Line Company.
Gas Supply Contracts. During the 1997 fiscal year, Gas Utility
purchased approximately 37.5 bcf of natural gas and sold approximately 36.8 bcf
to customers. Gas not sold to customers was used by Gas Utility principally for
storage for later sale to customers. Approximately 31 bcf or 83% of the volumes
purchased were supplied under agreements with six major suppliers of natural
gas. The remaining 6.5 bcf or 17% 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. Each of
these agreements, however, either terminates in fiscal year 1998, or includes
provisions which entitle Utilities to terminate in the event the agreement is
not market responsive.
Storage and Peak Shaving. Gas Utility contracts for 10.8 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 .14 bcf. In Harrisburg, Reading and Bethlehem,
Pennsylvania, Gas Utility operates peak-shaving facilities capable of producing
.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. Approximately 58% of Gas Utility's system
throughput for the 1997 fiscal year occurred during the winter season from
November 1, 1996 through March 31, 1997, because many of its customers use gas
for heating purposes.
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 12 years, Gas Utility provides transportation services for
those sales.
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Customers representing approximately 25% of the Company's
non-residential system throughput (11% of non-residential 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 spread between the customers' delivered cost of gas and the
customers' delivered alternate fuel cost. In addition, other customers
representing 30% of non-residential system throughput (8% of non-residential
revenues) have locations which afford them the option of seeking transportation
service directly from interstate pipelines, thereby bypassing Gas Utility,
although none have done so. The majority of these customers 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 executed ten-year agreements
with Utilities. No single customer represents, or is anticipated to represent,
more than 5% 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 at least through fiscal
year 1998. Supply mix is diversified, market priced, and delivered pursuant to a
number of long and short-term firm transportation and storage arrangements.
During the 1997 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 6,882
additional residential heating customers during the 1997 fiscal year, an
increase of 8% from the previous year. Approximately 63% of the additions
represent gas customers from the new construction market. The remaining 37%
represent customers converting from other energy sources, primarily oil, and
existing non-heating gas customers who have added gas heating systems to replace
other energy sources. The total number of new commercial and industrial
customers was 1,068, down slightly from 1,122 in fiscal year 1996.
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 continues to take the measures it believes necessary, in
negotiations with interstate pipeline and natural gas suppliers and in cases
before regulatory agencies, to assure availability of supply, transportation and
storage alternatives to serve market requirements at the lowest cost consistent
with security of supply considerations. Those measures include negotiating
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the terms of firm transportation capacity from production areas on all pipelines
serving Gas Utility, arranging for appropriate storage and peak-shaving
resources, negotiating with producers for competitively priced secure gas
purchases and aggressively participating 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 requires all electric utilities to file
restructuring plans with the PUC which, among other things, include 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 and certain customers that
increase their own generation of electricity. "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 the generation component of prices as long as stranded costs
are being recovered through the CTC. 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.
Electric Utility has filed its restructuring plan with the PUC
("Restructuring Plan"). The Restructuring Plan includes a claim for the recovery
of $34.4 million for stranded costs during the period January 1, 1999 through
December 31, 2002. The major components of this claim are: (1) plant investments
in excess of competitive market value and electric generation facility
retirement costs; (2) potential costs associated with existing power purchase
agreements; and (3) regulatory assets (principally income taxes) recoverable
from ratepayers under current regulatory practice. It also seeks to establish a
recovery mechanism that would permit the recovery of up to an additional $28
million of costs associated with the buyout or implementation of a December 1993
agreement with Foster Wheeler Penn Resources, Inc. to purchase power from a
wood-fired generator to be constructed by Foster Wheeler. The PUC is expected to
take action on Electric Utility's filing in May 1998.
The Customer Choice Act also authorized the PUC to implement pilot
customer choice programs for up to five percent of the noncoincident peak load
of industrial, commercial and residential customers. In accordance with PUC
directives, Electric Utility implemented such a pilot program effective November
1, 1997. It is anticipated that a full five percent of the
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noncoincident peak load of Electric Utility's industrial, commercial and
residential customers will participate in the pilot.
Given the changing regulatory environment in the electric utility
industry, the Company continues to evaluate its ability to apply the provisions
of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS 71), as it relates to its electric generation operation. SFAS 71 permits
the recording of costs (regulatory assets) that have been, or are expected to
be, allowed in the ratesetting process in a period different from the period in
which such costs would be charged to expense by an unregulated enterprise. The
Company believes its electric generation assets and related regulatory assets
continue to satisfy the criteria of SFAS 71. If such electric generation assets
no longer meet the criteria of SFAS 71, then any related regulatory assets would
be written-off unless some form of transition cost recovery is established by
the PUC which would meet the requirements under generally accepted accounting
principles for continued accounting as regulatory assets during such recovery
period. Any generation-related, long-lived fixed and intangible assets would be
evaluated for impairment under the provisions of SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
Based upon an evaluation of the various factors and conditions
affecting future cost recovery, the Company does not expect the Customer Choice
Act to have a material adverse effect on its financial condition or results of
operations.
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 1997 fiscal year, about 53% of sales volume
came from residential customers, 34% from commercial customers and 13% from
industrial customers and others. For the 1997, 1996 and 1995 fiscal years,
revenues of Electric Utility accounted for approximately 16%, 15% and 18%,
respectively, of Utilities' total consolidated revenues.
Sources of Supply. Electric Utility distributes electricity which it
generates or purchases from others. As the provisions of the Customer Choice Act
are implemented, it will also distribute electric power acquired and transmitted
by others. 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
coal-fired stations can generate up to 69 megawatts of electric power for
Electric Utility and provided approximately 47% of its energy requirements
during the 1997 fiscal year.
Utilities has a long-term power supply agreement with Pennsylvania
Power & Light Company ("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. The cost of electricity supplied by
PP&L is based on PP&L's actual system costs. Utilities estimates that the cost
of electricity supplied by Hunlock is higher than projected market rates, but
lower
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than the cost of electricity purchased under the PP&L contract. As a result of
the availability and projected cost of alternative supplies, Utilities has
provided PP&L with notice of its intent to stop purchasing power under the power
supply agreement as of March 2001. In addition, if certain conditions occur
(i.e., Electric Utilities' demand falls to zero in any particular billing
month), 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 PP&L power supply agreement.
Utilities has 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.
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 may cease operations as early as January 1, 1999,
depending on a number of factors, including customer load, contract purchase
obligations and the availability and cost of replacement power. Until
restructuring proceedings under the Customer Choice Act are completed, Utilities
will be unable to predict how long Hunlock Station will operate.
Environmental Factors. The operation of Hunlock Station complies with
the air quality standards of the Pennsylvania Department of Environmental
Resources ("DER") with respect to stack emissions. Under the Federal Water
Pollution Control Act, Utilities has a permit from the DER to discharge water
from Hunlock Station into the North Branch of the Susquehanna River.
The Federal Clean Air Act Amendments of 1990 (the "Clean Air Act
Amendments") impose emissions limitations for certain compounds, including
sulfur dioxide and nitrous oxides. The Conemaugh Station is in compliance with
these standards, and the Hunlock Station is required to meet these emission
standards by 1999.
In compliance with the Clean Air Act Amendments, the DER issued final
Reasonably Available Control Technology ("RACT") regulations for nitrous oxides
in January 1994. These regulations are applicable to Hunlock and Conemaugh
Stations. Utilities' compliance plans for Hunlock Station and Conemaugh Station
have been approved by the DER. Capital expenditures associated with the RACT
regulations are not expected to be material.
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 (the "EPA"). Future
actions of the Commission may cause the DER to modify its nitrous oxide RACT
plans and thereby affect the compliance plans of Hunlock and Conemaugh Stations.
Seasonality. Sales of electricity for residential heating purposes
accounted for approximately 23% of the total sales of Electric Utility during
the 1997 fiscal year. Electricity competes with natural gas, oil, propane and
other heating fuels in this use. Approximately 54% of
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sales occurred in the six coldest months of the 1997 fiscal year, demonstrating
modest seasonality favoring winter due to the use of electricity for residential
heating purposes.
PROPERTIES
Utilities' Mortgage and Deed of Trust constitutes a first lien on
substantially all real and personal property of Utilities.
UTILITY REGULATION AND RATES
Recent Regulatory Environment. Since December 1982, Utilities has
provided transportation service for commercial and industrial customers who
purchase their gas from others. As previously reported, this unbundled service
accounted for approximately 54% of Utilities' system throughput in fiscal year
1997. 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 and the recovery
of costs associated with existing gas supply assets. Utilities is considering a
number of options for addressing the provision of unbundled transportation
services to residential and small commercial customers, including the
termination of bundled retail sales services. The Company will continue to
monitor the proposed legislation.
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 UGI 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 Utilities' 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.
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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 specific rates (Rates BD, BD-L and
N/CIAC). 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, 1998, to be
effective December 1, 1998. When filed, the proposed tariff will reflect
estimated PGC over-collections and under-collections through November 30, 1998.
Energy Cost Rates. In accordance with provisions of the Customer Choice
Act, the PUC approved Electric Utility's application to roll its energy costs
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. Although Electric Utility may no longer adjust customer charges to
reflect changes in the cost of purchased power, it will continue to account for
such changes in order to reconcile costs as part of its Restructuring Plan.
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, to be effective March 26,
1996. 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.
Deferred Fuel Adjustments. Gas Utility defers and until January 1, 1997
Electric Utility deferred the difference between the amount of revenue
recognized, and the applicable purchased gas costs and purchased power costs
incurred, until subsequently billed or refunded to customers.
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
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calculation are changed. These clauses protect Utilities from the effect of
increases in most of the Pennsylvania taxes to which it is subject.
UTILITY FRANCHISES
Utilities holds certificates of public convenience issued by the PUC
and certain "grandfather rights" predating the adoption of the Pennsylvania
Public Utility Code and its predecessor statutes which it believes are adequate
to authorize it to carry on its business in substantially all the territory to
which it now renders gas and electric service. Under applicable Pennsylvania
law, Utilities also has certain rights of eminent domain as well as the right to
maintain its facilities in streets and highways in its territories.
OTHER GOVERNMENT REGULATION
In addition to regulation by the PUC, the gas and electric utility
operations of Utilities are subject to various federal, state and local laws
governing environmental matters, occupational health and safety, pipeline safety
and other matters. Certain of Utilities' activities involving the interstate
movement of natural gas, the transmission of electricity, transactions with
non-utility generators of electricity 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." The electric
generation activities of Utilities are also subject to the Clean Air Act
Amendments, the Federal Water Pollution Control Act and comparable state
statutes and regulations. See "UTILITY OPERATIONS - Generation and Distribution
of Electricity-Environmental Factors."
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BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to Utilities' industry segments for the 1997,
1996 and 1995 fiscal years appears in Note 11 "Segment Information" of Notes to
Consolidated Financial Statements included in this Report and is incorporated
herein by reference.
EMPLOYEES
At September 30, 1997, Utilities and its subsidiaries had 1,226
employees.
ITEM 3. LEGAL PROCEEDINGS
With the exception of the matters set forth below, no material legal
proceedings are pending involving Utilities, any of its subsidiaries or any of
their properties, and no such proceedings are known to be contemplated by
governmental authorities.
ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
Prior to the general availability of natural gas, in the 1800s through
the mid-1900s, manufactured gas was a chief source of gas for lighting and
heating nationwide. The process involved heating certain combustibles such as
coal, oil and coke in a low-oxygen atmosphere. Methods of production included
coal carbonization, carbureted water gas and catalytic cracking. These methods
were employed at many different sites throughout the country. The residue from
gas manufacturing, including coal tar, was typically stored on site, burned in
the gas plant, or sold for commercial use. Some constituents of coal tars
produced from the manufactured gas process are today considered hazardous
substances under the Superfund Law.
The gas distribution business has been one of Utilities' principal
lines of business since its inception in 1882. One of the ways Utilities
initially expanded its business in its early years was by entering into
agreements with other gas companies to operate their businesses. After 1888, the
principal means by which Utilities expanded its gas business was to acquire all
or a portion of the stock of companies engaged in this business. Utilities also
provided management and administrative services to some of these companies.
Utilities grew rapidly by means of stock acquisitions and became one of the
largest public utility holding companies in the country. Pursuant to the
requirements of the Public Utility Holding Company Act of 1935, Utilities
divested all of its utility operations other than those which now constitute the
Gas Utility and the Electric Utility.
The manufactured gas process was once used by Utilities in connection
with providing gas service to its customers. In addition, virtually all of the
gas companies that Utilities operated or to
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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, courts
have found parent companies liable for environmental damage caused by subsidiary
companies when the parent company exercised such substantial control over the
subsidiary that the court concluded that 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 level
of control exercised by Utilities over the subsidiary satisfies the standard
described above.
Utilities believes that there are approximately 40 manufactured gas
plant sites in Pennsylvania where either (i) Utilities formerly operated the
plant or (ii) Utilities owns or at one time owned the site. Most of the sites
are no longer owned by Utilities and the gas plants formerly operated at these
40 sites have all been out of operation since at least the early 1950s.
Utilities or other parties are currently conducting investigative or remedial
activities at nine of the 40 sites. Based on the 1995 settlement agreement with
the PUC relating to Gas Utilities' 1995 base rate increase filing, rate relief
will be permitted for certain remediation expenditures on environmentally
contaminated sites located in Pennsylvania. Because of this, Utilities does not
expect its costs for Pennsylvania sites to be material to its results of
operations.
The following is a short description of the status of certain matters
involving Utilities related to manufactured gas plants located in other states.
See also Note 8 to the Company's Consolidated Financial Statements.
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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 of 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. Management is currently investigating Utilities' involvement in
operations of the site and evaluating its defenses. 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. Burlington, Vermont. By letter dated November 24, 1992, the EPA
notified Utilities of potential liability with respect to contamination at the
Pine Street Canal Superfund Site, Burlington, Vermont. The EPA has also
identified eighteen other "potentially responsible parties." Utilities has
responded to the EPA letter and denied liability for any contamination caused by
the former operator of the gas plant. Management believes that Utilities has
substantial defenses to any claim that may be made for investigative or remedial
costs because, among other things, the plant was operated by a subsidiary of a
predecessor company.
The site is the location of a former manufactured gas plant owned and
operated by Burlington Gas Light Company ("BGLC") and Burlington Light and Power
Company ("BLPC"). The EPA contends that Utilities is potentially liable because
it assumed the liabilities of American Gas Company of New Jersey, a one-time
parent of BGLC and BLPC. In 1985, the EPA removed approximately 15,000 tons of
coal tar contaminated material from a portion of the site. From 1986 through
1992, the EPA conducted investigations and developed potential remedial actions
at the site. The results of EPA's investigations show that coal gasification
wastes, particularly polynuclear aromatic hydrocarbons and coal tar, are present
in surface and subsurface soils as well as groundwater. The contamination also
extends to wetlands adjacent to the site.
In November 1992, the EPA proposed a cleanup of the site that, among
other actions, would consist of on-site containment, dredging and excavation,
dewatering and consolidation of contaminated soils, treatment of groundwater and
restoration of wetlands. The estimated cost of the proposed plan would have been
approximately $50 million. In May 1993, after reviewing extensive public comment
concerning the proposed plan of remediation, the EPA withdrew the
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proposed plan and announced that it would work with a coordinating council
consisting of community groups, potentially responsible parties ("PRPs") and
others to develop an alternative plan.
In September 1997, the coordinating council proposed a remedial plan
calling for capping of the site at an estimated cost of $6 million to $10
million. In addition, the coordinating council and EPA may have spent an
additional $10 million in studying the site. In December 1997, Green Mountain
Power Company, the lead PRP, agreed in principle to indemnify and release
Utilities from any further liability at the site on terms and conditions which
are not material to the results of operations of Utilities.
3. 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.
4. Concord, New Hampshire. By letter dated October 18, 1993,
EnergyNorth Natural Gas, Inc. ("EnergyNorth") informed Utilities that the New
Hampshire Department of Environmental Services ("NHDES") has alleged that there
is environmental contamination on property in Concord, N.H., where a
manufactured gas plant was once located. EnergyNorth requested that Utilities,
as a former operator of the plant, participate in investigation of the site.
Because this gas plant appears to have been operated almost exclusively by
former subsidiary companies of Utilities, Utilities declined to participate. On
September 17, 1995 EnergyNorth filed suit against Utilities alone in federal
District Court in New Hampshire, seeking Utilities' allocable share of response
costs associated with remediating gas plant related contamination at that site.
The complaint alleges that EnergyNorth has spent $3.5 million to remove
contaminants from a gas holder at the site and will be required to spend an
unknown amount in the future. As a result of investigations of gas plant related
contamination in a nearby pond completed in 1996, EnergyNorth recommended to
NHDES a remedial plan that would cost approximately $4 million. In November
1997, Utilities settled this litigation on terms which are not material to the
results of operations of Utilities.
OTHER MATTERS
Foster Wheeler Penn Resources, Inc. v. UGI Utilities, Inc. Civil Action
No. 97CV4592. On July 14, 1997, Foster Wheeler Penn Resources, Inc. filed suit
against UGI Utilities, Inc. in United States District Court for the Eastern
District of Pennsylvania alleging, among other things, that UGI Utilities
breached an Agreement for the Sale and Purchase of Net Electrical Energy under
which UGI Utilities had agreed to purchase electricity from a generating
facility yet to be
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built by Foster Wheeler. In its suit Foster Wheeler seeks, among other things, a
declaration that the Sale and Purchase Agreement remains in effect or in the
alternative that Foster Wheeler be awarded damages in excess of $20 million.
Management believes that it has defenses to Foster Wheeler's claims.
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 1997 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 1997 fiscal
year totaled $25.1 million, including a $1 million intercompany receivable.
Dividends declared on the Company's Common Stock during the 1996 and 1995 fiscal
years totaled $32.9 million and $15.5 million (including $1.0 million in net
assets of its former GASMARK operation), respectively.
The information concerning restrictions on dividends required by Item 5
is included in Note 3 to the Company's Consolidated Financial Statements
included in this Report and is incorporated herein by reference.
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ITEM 6. SELECTED FINANCIAL DATA
Nine
Months
Year Ended Ended
September 30, September 30,
------------------------------------------------- ----------------------
1997 1996 1995 1994 1993 1992
--------- --------- --------- --------- --------- ---------
(unaudited)
(Thousands of dollars)
FOR THE PERIOD ENDED:
Income statement data:
Revenues $ 461,208 $ 460,496 $ 357,364 $ 395,061 $ 251,210 $ 246,677
========= ========= ========= ========= ========= =========
Income from:
Continuing operations $ 38,711 $ 38,348 $ 28,018 $ 23,555 $ 16,031 $ 15,782
Discontinued operations (a) -- -- -- 6,918 -- 13,471
--------- --------- --------- --------- --------- ---------
Income before accounting change 38,711 38,348 28,018 30,473 16,031 29,253
Change in accounting for
postemployment benefits -- -- (1,028) -- -- --
--------- --------- --------- --------- --------- ---------
Net income 38,711 38,348 26,990 30,473 16,031 29,253
Dividends on preferred stock 2,764 2,765 2,778 1,356 2,124 1,905
--------- --------- --------- --------- --------- ---------
Net income after dividends
on preferred stock $ 35,947 $ 35,583 $ 24,212 $ 29,117 $ 13,907 $ 27,348
========= ========= ========= ========= ========= =========
AT PERIOD END:
Balance sheet data:
Total assets $ 681,378 $ 649,899 $ 661,480 $ 581,426 $ 561,306 $ 560,672
========= ========= ========= ========= ========= =========
Capitalization:
Debt:
Bank loans $ 67,000 $ 50,500 $ 42,000 $ 17,000 $ -- $ --
Long-term debt including
current maturities: 169,294 176,654 208,162 177,444 200,421 198,273
--------- --------- --------- --------- --------- ---------
Total debt 236,294 227,154 250,162 194,444 200,421 198,273
--------- --------- --------- --------- --------- ---------
Preferred stock subject to
mandatory redemption 35,187 35,187 35,202 35,202 33,222 35,223
Common equity 200,494 189,441 186,803 178,071 169,077 161,971
--------- --------- --------- --------- --------- ---------
Total capitalization $ 471,975 $ 451,782 $ 472,167 $ 407,717 $ 402,720 $ 395,467
========= ========= ========= ========= ========= =========
Ratio of capitalization:
Total debt 50.0% 50.3% 53.0% 47.7% 49.8% 50.1%
UGI Utilities preferred stock 7.5% 7.8% 7.4% 8.6% 8.2% 8.9%
Common equity 42.5% 41.9% 39.6% 43.7% 42.0% 41.0%
--------- --------- --------- --------- --------- ---------
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
========= ========= ========= ========= ========= =========
(a) Includes results of AmeriGas and Ashtola prior to April 10, 1992. Also
includes the Company's oil field activities discontinued in 1986.
15
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
1997 COMPARED WITH 1996
- -----------------------------------------------------------------------------------
Increase
Year Ended September 30, 1997 1996 (Decrease)
- -----------------------------------------------------------------------------------
(Millions of dollars)
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:
Electric 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 AND OTHER:
Corporate general expenses $ (5.6) $ (3.9) $ 1.7 43.6 %
Other operating income $ .2 $ .1 $ .1 100.0 %
- -----------------------------------------------------------------------------------
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 to 4.2% colder than normal in 1996. The decrease in
total system throughput principally reflects the warmer weather's effect on core
market sales as well as a decrease in low-margin interruptible delivery service
volumes associated with the shut-down of a gas-fired cogeneration facility.
Gas Utility revenues were $1.9 million lower in 1997 as a $27.2 million increase
in core market revenues principally due to higher average PGC rates was offset
by a $21.2 million decrease in core market revenues from lower sales and an $8.1
million decrease in revenues from off-system sales. Cost of gas sold by Gas
Utility decreased $1.1 million to $205.2 million reflecting the lower off-system
and core market sales offset by higher average PGC rates.
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The decrease in Gas Utility total margin principally reflects a $6.3 million
decrease in total margin from core market customers resulting from the warmer
weather partially offset by a $5.5 million increase in total margin from
interruptible customers.
Although total margin was slightly lower in 1997, Gas Utility operating income
increased $1.9 million principally as a result of a $1.5 million decrease in
operating and administrative expenses and higher miscellaneous income. Operating
and administrative expenses during 1997 decreased principally as a result of a
decrease in distribution system expenses, lower accruals for uncollectible
accounts, and lower general and administrative expenses partially offset by
higher costs associated with environmental matters.
ELECTRIC UTILITY. Electric Utility sales decreased in 1997 reflecting weather
which was 5.6% warmer than in the prior-year period. Electric Utility base rate
revenues increased $1.7 million 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. Cost of sales increased to $33.8 million in
1997 from $33.4 million in 1996 as a result of the higher energy cost recoveries
partially offset by the lower sales.
Electric Utility total margin and operating income increased in 1997 principally
as a result of the higher base rates. Electric Utility operating and
administrative expenses in 1997 were essentially unchanged from the prior year.
CORPORATE GENERAL AND OTHER. 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 1996 corporate general
expenses were lower as a result of adjustments to incentive compensation
accruals.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $16.9 million in 1997
compared with $16.1 million 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.
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1996 COMPARED WITH 1995
- -----------------------------------------------------------------------------------
Increase
Year Ended September 30, 1996 1995 (Decrease)
- -----------------------------------------------------------------------------------
(Millions of dollars)
GAS UTILITY:
Natural gas system throughput - bcf 85.4 82.4 3.0 3.6%
Degree days - % colder (warmer)
than normal 4.2 (5.4) -- --
Revenues $391.0 $291.3 $ 99.7 34.2%
Total margin $169.7 $140.9 $ 28.8 20.4%
Operating income $ 72.9 $ 51.9 $ 21.0 40.5%
ELECTRIC UTILITY:
Electric sales - gwh 884.7 860.9 23.8 2.8%
Revenues $ 69.5 $ 66.1 $ 3.4 5.1%
Total margin $ 33.0 $ 32.1 $ .9 2.8%
Operating income $ 8.6 $ 9.1 $ (.5) (5.5)%
CORPORATE GENERAL AND OTHER:
Corporate general expenses $ (3.9) $ (6.6) $ (2.7) (40.9)%
Other operating income $ .1 $ 2.1 $ (2.0) (95.2)%
- -----------------------------------------------------------------------------------
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 in 1996 was colder than
normal and also colder than in 1995. The increase in total system throughput
includes a 5.4 bcf increase in sales to core market customers and a .7 bcf
increase in throughput to interruptible customers. Partially offsetting these
increases was a decrease in firm delivery service volumes as a result of
customer switching to interruptible delivery service.
The increase in Gas Utility total revenues reflects a $68.4 million increase in
revenues from core market customers (reflecting higher sales and the full-year
effect of higher base rates), greater off-system sales, and lower refunds of
producer settlement charges. Cost of gas sold was $206.3 million during 1996, an
increase of $67.7 million from 1995, reflecting principally the greater sales to
core market customers, higher off-system sales, and lower refunds of producer
settlement charges.
The increase in Gas Utility total margin in 1996 reflects a $34.5 million
increase in total margin from core market customers as a result of the colder
weather and higher base rates. However, partially offsetting the increase in
core market margin was a decrease in total margin from interruptible customers,
principally as a result of higher 1996 gas costs, and a decrease in total margin
from firm delivery service customers due in large part to the lower volumes.
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Gas Utility operating income in 1996 benefitted from the increase in total
margin. However, the benefit was partially offset by higher operating and
administrative expenses and higher charges for depreciation.
ELECTRIC UTILITY. Electric Utility sales increased during 1996 principally from
colder heating-season weather. The $3.4 million increase in Electric Utility
revenues reflects a $1.7 million increase in base rate revenues and a $1.7
million increase in energy cost recoveries. Electric Utility cost of sales was
$33.4 million, an increase of $2.3 million from the prior year. The increase in
the cost of sales resulted from higher sales and higher energy cost recoveries.
Electric Utility total margin increased as a result of the increased sales and
higher base rates effective in July. However, operating income declined as the
increase in Electric Utility total margin was more than offset by higher
distribution system maintenance expenses, general and administrative expenses,
and depreciation.
CORPORATE GENERAL AND OTHER. Corporate general expenses were $3.9 million in
1996 compared with $6.6 million in 1995. The allocated UGI corporate expenses in
1996 were lower as a result of adjustments to incentive compensation accruals.
Other operating income in 1995 principally reflects income from the gas
marketing activities of GASMARK, a former division of UGI Utilities' wholly
owned subsidiary, UGI Development Company (UGIDC). Effective August 1, 1995, the
business assets of GASMARK, which totaled $1.0 million, were dividended to UGI.
INTEREST EXPENSE AND INCOME TAXES. Interest expense was $16.1 million in 1996
compared with $16.8 million in 1995. The decrease in interest expense
principally reflects a decrease in interest on bank loans and purchased gas cost
overcollections. The effective income tax rate was 37.9% in 1996 compared with
an effective tax rate of 29.5% in 1995. The lower income tax rate in 1995
reflects the benefit of a $4.3 million adjustment to deferred state income taxes
recorded in September 1995 (see Note 4 to Consolidated Financial Statements).
Income taxes in 1996 reflect a reduction in the Pennsylvania corporate income
tax rate to 9.99% from 11.99%.
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FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Utilities' debt outstanding at September 30, 1997 totaled $236.3 million
compared with $227.2 million at September 30, 1996. The increase principally
reflects an increase in borrowings under its revolving credit facilities.
Utilities has revolving credit agreements providing for borrowings of up to $82
million under committed lines through June 30, 2000. At September 30, 1997,
borrowings under its revolving credit agreements totaled $67 million. Utilities
also has a shelf registration for issuance from time to time of up to $75
million of debt securities.
Dividend payments to UGI totaled $24.1 million in 1997 compared with $32.9
million in 1996. The Company intends to declare and pay dividends to UGI subject
to the availability of earnings and the cash needs of its businesses. In
addition, certain of Utilities' debt agreements contain limitations with respect
to incurring additional debt, require the maintenance of consolidated tangible
net worth, as defined, of at least $125 million, and restrict the amounts of
payments for investments, redemptions of capital stock, prepayment of
subordinated debt and dividends. Under the most restrictive of these provisions,
permitted future payments aggregate $149.4 million at September 30, 1997.
Management believes that cash flow from the Company's operations and funds
available under its credit facilities will be sufficient to meet its liquidity
needs for the foreseeable future.
CAPITAL EXPENDITURES
The following table presents capital expenditures of Gas Utility and Electric
Utility for the years ended September 30, 1997, 1996 and 1995, as well as
expected amounts for fiscal 1998. Utilities expects to finance 1998 capital
expenditures through internally generated cash and borrowings under its credit
facilities.
- --------------------------------------------------------------------------------
Year Ended September 30, 1998 1997 1996 1995
- --------------------------------------------------------------------------------
(Millions of dollars) (estimate)
Gas Utility $ 37.3 $ 36.7 $ 34.6 $ 45.3
Electric Utility 5.9 5.0 5.0 5.9
- --------------------------------------------------------------------------------
$ 43.2 $ 41.7 $ 39.6 $ 51.2
- --------------------------------------------------------------------------------
YEAR 2000 MATTERS
The Company is currently in the process of modifying certain of its computer
software systems so that they will function properly in the year 2000. The
Company does not expect the costs necessary to modify these systems, which costs
are and will be expensed as incurred, to have a material effect on the Company's
results of operations.
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CASH FLOWS
OPERATING ACTIVITIES. Utilities' 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 $69.5 million in
1997 compared with $57.0 million in 1996. Cash flows from operating activities
before changes in operating working capital were $64.1 million in 1997 compared
with $71.7 million in 1996. The decrease reflects in large part the effects of
lower noncash deferred tax expense in 1997. Changes in operating working capital
in 1997 provided $5.4 million of operating cash flow principally from an
increase in accounts payable and purchased gas overcollections partially offset
by an increase in accounts receivable. In 1996, changes in operating working
capital required $14.6 million of operating cash flow principally from increases
in inventories and accounts receivable and net refunds of Gas Utility fuel costs
partially offset by an increase in accounts payable.
INVESTING ACTIVITIES. Expenditures for property, plant and equipment increased
to $41.7 million in 1997 from $39.6 million in 1996. The increase is a result of
higher Gas Utility capital expenditures.
FINANCING ACTIVITIES. During 1997, Utilities paid $24.1 million in dividends to
UGI and $2.8 million to holders of preferred stock. Utilities made debt
repayments of $27.4 million including scheduled repayments of $8.4 million of
its 7.85% Series First Mortgage Bonds, $10.0 million of 8.70% Notes, and $7.1
million of 9.71% Notes. In addition, Utilities issued $20 million of ten year
notes under its Series B Medium-Term Note program. Net borrowings under
Utilities' revolving credit facilities totaled $16.5 million in 1997 compared
with net borrowings of $8.5 million in 1996.
UTILITY BASE RATES
During the three-year period ended September 30, 1997, the following Gas and
Electric utility base rate increases became effective:
- ------------------------------------------------------------------------------------
Increase in Annual Revenues
Division Effective Date Requested Granted
- ------------------------------------------------------------------------------------
(Millions of dollars)
Electric Utility 7/19/96 $ 6.2 $ 3.1
Gas Utility 8/31/95 41.3 19.5
- ------------------------------------------------------------------------------------
CUSTOMER CHOICE ACT
On January 1, 1997, the 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 requires all
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electric utilities to file restructuring plans with the PUC which, among other
things, include 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 transmission and
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 the
generation component of prices as long as stranded costs are being recovered
through the CTC. 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.
On August 7, 1997, Electric Utility filed its Restructuring Plan with the PUC.
The Restructuring Plan includes a claim for the recovery of $34.4 million for
stranded costs during the period January 1, 1999 through December 31, 2002. The
claim is primarily for the recovery of: (1) plant investments in excess of
competitive market value and electric generation facility retirement costs; (2)
potential costs associated with existing power purchase agreements; and (3)
regulatory assets (principally income taxes) recoverable from ratepayers under
current regulatory practice. The claim also seeks to establish a recovery
mechanism that would permit the recovery of up to an additional $28 million of
costs associated with the buyout or implementation of a December 1993 agreement
to purchase power from an independent power producer. The PUC is expected to
take action on Electric Utility's filing in May 1998.
Given the changing regulatory environment in the electric utility industry, the
Company continues to evaluate its ability to apply the provisions of Statement
of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71) as it relates to its electric generation
operations. SFAS 71 permits the recording of costs (regulatory assets) that have
been, or are expected to be, allowed in the ratesetting process in a period
different from the period in which such costs would be charged to expense by an
unregulated enterprise. The Company believes its electric generation assets and
related regulatory assets continue to satisfy the criteria of SFAS 71. If such
electric generation assets no longer meet the criteria of SFAS 71, any related
regulatory assets would be written-off unless some form of transition cost
recovery is established by the PUC which would meet the requirements under
generally accepted accounting principles for continued accounting as regulatory
assets. Any generation-related, long-lived fixed and intangible assets would be
evaluated for impairment under the provisions of SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
Based upon an evaluation of the various factors and conditions affecting future
cost recovery, the Company does not expect the Customer Choice Act to have a
material adverse effect on its financial condition or results of operations.
On March 27, 1997, proposed gas customer choice legislation was introduced in
the Pennsylvania General Assembly that would, among other things, extend the
availability of gas transportation
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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 exit the merchant function of selling natural gas. Legislative
committees have conducted public hearings on the proposed legislation and the
Company has provided testimony on such issues as the recovery of costs
associated with its existing gas supply assets and the need for standards to
assure reliability of future gas supplies. The Company will continue to monitor
developments with regard to the proposed legislation.
MANUFACTURED GAS PLANTS
The gas distribution business has been one of Utilities' principal lines of
business since its inception in 1882. Prior to the construction of major natural
gas pipelines in the 1950s, gas 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 the manufactured gas 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 Utilities initially expanded its business 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 to become one of the largest public utility holding companies in
the U.S. Pursuant to the Public Utility Holding Company Act of 1935, by 1954
Utilities divested all of its utility operations other than those which now
constitute Gas Utility and Electric Utility.
The Company has been notified of several sites outside Pennsylvania where MGPs
were operated by Utilities or owned or operated by its former subsidiaries, and
environmental agencies or private parties are investigating the extent of
environmental contamination and the necessity of environmental remediation. If
Utilities were found liable as a "responsible party" as defined in the Superfund
Law (or comparable state statutes) with respect to any of these sites, 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
the current owner of the affected property and 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 MGP because Utilities
generally is not legally liable for the obligations of its subsidiaries. Under
certain circumstances, however, courts have found parent companies liable for
environmental damage caused by subsidiary companies when the parent company
exercised substantial control over the subsidiary. There could be, therefore,
significant future costs of an uncertain amount associated with environmental
damage caused by MGPs that Utilities owned or directly operated, or that were
owned or operated by former subsidiaries of
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26
Utilities if a court were to conclude that Utilities exercised substantial
control over such subsidiaries.
Management believes, after consultation with counsel, that future costs of
investigation and remediation, if any, will not have a material adverse effect
on the Company's financial position but could be material to 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 more detailed
discussion of environmental matters related to MGP sites, see Note 8 to
Consolidated Financial Statements.
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 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, with
respect to Gas Utility, timely rate relief.
ACCOUNTING PRINCIPLES NOT YET ADOPTED
In October 1996, the American Institute of Certified Public Accountants issued
Statement of Position No. 96-1, "Environmental Remediation Liabilities" (SOP
96-1). SOP 96-1 provides guidance on the recognition, measurement, display and
disclosure of environmental remediation liabilities. SOP 96-1, is effective for
fiscal years beginning after December 15, 1996. The adoption of SOP 96-1 in
fiscal 1998 is not expected to have a material effect on the Company's financial
position or results of operations.
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements that are
subject to risks and uncertainties. The factors that could cause actual results
to differ materially include those discussed herein as well as those listed in
Exhibit 99. Readers are cautioned not to place undue reliance on these
forward-looking statements, which speak only as of the date of this Annual
Report on Form 10-K. The Company undertakes no obligation to publicly release
any revision to these forward-looking statements to reflect events or
circumstances after the date of this Annual Report on Form 10-K.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the financial statement schedule set forth on
pages F-1 to F-28 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.
PART III: UGI UTILITIES MANAGEMENT AND SECURITY HOLDERS
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Lon R. Greenberg 47 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 61 1979 President 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.
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Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Robert C. Forney 70 1988 Retired; formerly Executive Vice
President (1981 to 1989) and Director
(1979 to 1989) of E. I. duPont de
Nemours & Co., Inc. (chemicals and
petroleum products). Director: AmeriGas
Propane, Inc.; Wilmington Trust
Corporation; Wilmington Trust Company;
Wilmington Trust of Pennsylvania.
David I. J. Wang 65 1988 Retired; formerly Executive Vice
President-Timber and Specialty Products
and a Director of International Paper
Company (1987 to 1991). Director:
AmeriGas Propane, Inc.; Weirton Steel
Corp.
Richard C. Gozon 59 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: AmeriSource Health Corporation
and Triumph Group, Inc.
Quentin I. Smith, Jr. 70 1990 Retired; formerly Chairman and Chief
Executive Officer of Towers Perrin
(management consulting services) (1957
to 1987). Director: Omnicom Group Inc.;
The Guardian Life Insurance Company
of America.
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Utilities
Director Principal Occupation
Name Age Since and Other Directorships (1)
- ---- --- ----- ---------------------------
Stephen D. Ban 57 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 61 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.
Anne Pol 49 1993 Vice President of Thermo Electron
Corporation (environmental technology
products and services) (since 1996);
formerly President, Pitney Bowes
Shipping and Weighing Systems Division,
a business unit of Pitney Bowes Inc.
(mailing and related business equipment)
(1993 to 1996); Vice President, New
Product Programs in the Mailing Systems
Division of Pitney Bowes Inc. (1991 to
1993); and Vice President, Manufacturing
Operations in the Mailing Systems
Division of Pitney Bowes Inc. (1990 to
1991).
(1) With the exception of Mr. Bunn, all of the directors serve as directors of
UGI. Messrs. Greenberg, Forney, Stratton and Wang also serve as directors of
AmeriGas Propane, Inc., the General Partner of AmeriGas Partners, L.P.
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EXECUTIVE OFFICERS
Name Age Position
- ---- --- --------
Lon R. Greenberg 47 Chairman of the Board of Directors
Richard L. Bunn 61 President and Chief Executive Officer
Brendan P. Bovaird 49 Vice President and General Counsel
Robert J. Chaney 55 Vice President and General Manager-Gas
Utility Division
Mark R. Dingman 48 Vice President and General
Manager-Electric Utility Division
John C. Barney 49 Vice President-Finance and Accounting
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.
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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.
Robert J. Chaney
Mr. Chaney is Vice President and General Manager-Gas Utility Division of
the Company (since 1991). He previously served as Vice President-Rates and
Energy Utilization of the Company's Gas Utility Division (1981 to August 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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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
- -----------------------------------------------------------------------------------------------------------------------------------
Long-Term Compensation
- -----------------------------------------------------------------------------------------------------------------------------------
Annual Compensation
Awards Payouts
- -----------------------------------------------------------------------------------------------------------------------------------
Securities
Other Underlying Long-Term All Other
Annual Options/SARs Incentive Compensation
Name and Year Salary ($) Bonus Compensation Granted Payouts ($) (3)
Principal Position ($) (1) ($) (2) (#) ($)
===================================================================================================================================
Lon R. Greenberg (4) (5) 1997 $509,827 $425,000 $7,671 200,000 (6) $0 $ 14,233
Chairman 1996 $465,000 $122,760 $7,359 0 $0 $ 10,462
1995 $381,923 $ 0 $7,365 14,167 (7) $0 $ 11,439
- -----------------------------------------------------------------------------------------------------------------------------------
Richard L. Bunn (5) 1997 $318,089 $139,073 $7,696 75,000 (6) $0 $ 10,254
President and Chief 1996 $305,900 $137,655 $5,855 0 $0 $ 10,579
Executive Officer 1995 $305,900 $164,268 $6,684 0 $0 $ 9,732
- -----------------------------------------------------------------------------------------------------------------------------------
Robert J. Chaney
Vice President & 1997 $164,396 $ 51,457 $4,272 35,000 (6) $0 $ 4,921
General Manager, 1996 $156,601 $ 54,321 $4,019 0 $0 $ 5,074
Gas Utility Division 1995 $156,429 $ 68,904 $2,757 0 $0 $ 4,579
- -----------------------------------------------------------------------------------------------------------------------------------
Mark R. Dingman
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 1995 $119,912 $ 23,640 $4,036 0 $0 $ 3,493
- -----------------------------------------------------------------------------------------------------------------------------------
Brendan P. Bovaird (4)(5) 1997 $164,653 $ 64,449 $3,769 30,000 (6) $0 $ 4,196
Vice President and 1996 $149,999 $ 21,853 $1,299 0 $0 $ 1,363
General Counsel 1995 $ 66,346 $ 8,663 $ 0 10,000 (7) $0 $ 0
===================================================================================================================================
(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 1997 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 1997,
1996 and 1995, the following contributions were made to the Named
Executives: (i) under the Employee Savings Plan: For Messrs. Greenberg,
Bunn, Chaney and Dingman, $3,375, $3,375 and $3,375; and Mr. Bovaird,
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$3,375, $1,363 and $0; and (ii) under the Supplemental Executive Retirement
Plan: Mr. Greenberg, $10,858, $7,087 and $8,064; Mr. Bunn, $6,879, $7,204
and $6,357; Mr. Bovaird $821, $0 and $0; Mr. Chaney, $1,546, $1,699 and
$1,204; Mr. Dingman, $274, $0 and $118.
(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 1998 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 ("UGI's Return") with the total return
achieved by each member of a group of comparable peer companies (the "SODEP
Peer Group") 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.
(7) Non-qualified stock options granted under the UGI 1992 Stock Option and
Dividend Equivalent Plan (the "1992 Plan").
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OPTION GRANTS IN LAST FISCAL YEAR
The following table shows information on grants of stock options during
fiscal year 1997 to each of the Named Executives.
- -------------------------------------------------------------------------------------------------------------------------------
OPTION GRANTS IN LAST FISCAL YEAR
- -------------------------------------------------------------------------------------------------------------------------------
INDIVIDUAL GRANTS GRANT DATE
VALUE
- -------------------------------------------------------------------------------------------------------------------------------
NUMBER OF % OF TOTAL
SECURITIES OPTIONS
UNDERLYING GRANTED TO EXERCISE
OPTIONS EMPLOYEES IN OR BASE EXPIRATION GRANT DATE
NAME GRANTED (1) FISCAL YEAR (2) PRICE DATE PRESENT VALUE (3)
- -------------------------------------------------------------------------------------------------------------------------------
Lon R. Greenberg 200,000 45% $22.625 12/09/06 $ 486,000
- -------------------------------------------------------------------------------------------------------------------------------
Richard L. Bunn 75,000 17% $22.625 12/09/06 $ 182,250
- -------------------------------------------------------------------------------------------------------------------------------
Robert J. Chaney 35,000 8% $22.625 12/09/06 $ 85,050
- -------------------------------------------------------------------------------------------------------------------------------
Mark R. Dingman 35,000 8% $22.625 12/09/06 $ 85,050
- -------------------------------------------------------------------------------------------------------------------------------
Brendan P. Bovaird 30,000 7% $22.625 12/09/06 $ 72,900
===============================================================================================================================
(1) Non-qualified stock options granted on December 10, 1996 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 445,000 options were granted to employees and executive officers
of the Company during fiscal year 1997 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.
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(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 - .1676
- - Stock's dividend yield - 6.54%
- - Length of option term - 10 years
- - Annualized risk-free interest rate - 6.36%
- - 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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OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR END OPTION VALUES
The following table shows information for the 1997 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
====================================================================================================================================
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED IN-THE-
OPTIONS/SARS MONEY OPTIONS/
AT FISCAL YEAR END (#) SARs AT FISCAL YEAR END ($)
- ------------------------------------------------------------------------------------------------------------------------------------
SHARES
ACQUIRED VALUE
ON REALIZED
NAME EXERCISE (#) ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
====================================================================================================================================
143,959 (2) -0- $1,079,693(4) $0
Lon R. Greenberg (1) -0- $0 200,000 (3) -0- $1,000,000(5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
87,500 (2) -0- $ 656,250 (4) $0
Richard L. Bunn (1) -0- $0 75,000 (3) -0- $ 375,000 (5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
45,000 (2) -0- $ 337,500 (4) $0
Robert J. Chaney -0- $0 35,000 (3) -0- $ 175,000 (5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
2,950 (2) -0- $ 22,125 (4) $0
Mark R. Dingman 42,050 $291,225 35,000 (3) -0- $ 175,000 (5) $0
- ------------------------------------------------------------------------------------------------------------------------------------
10,000 (2) -0- $ 75,000 (4) $0
Brendan P. Bovaird -0- $0 30,000 (3) -0- $ 150,000 (5) $0
====================================================================================================================================
(1) Information reported for Messrs. Greenberg and Bunn is also reported in the
Proxy Statement for UGI's 1998 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, 1997 (fair
market value $27.625) to the 1992 Plan option price ($20.125).
(5) Value based on comparison of price per share at September 30, 1997 (fair
market value $27.625) to the 1997 Plan option price ($22.625).
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RETIREMENT BENEFITS
The following table shows the annual benefits upon retirement at age 65
in 1997 applicable for various combinations of final average earnings and length
of service which may be payable under the Retirement Income Plan for Employees
of UGI Utilities, Inc. and participating employers (the "Retirement Plan") and
the UGI Supplemental Executive Retirement Plan.
=============================================================================================================================
PENSION PLAN BENEFITS
- -----------------------------------------------------------------------------------------------------------------------------
FINAL 5-
YEAR
AVERAGE ANNUAL BENEFIT FOR YEARS OF CREDITED SERVICE SHOWN (1)
ANNUAL
EARNINGS (2)
----------------------------------------------------------------------------------------------------------
15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS 40 YEARS
=============================================================================================================================
$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)
=============================================================================================================================
(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, 17 years, 39 years, 33
years, 24 years and 2 years of estimated credited service at September 30,
1997.
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(2) Consists of (i) base salary, commissions and cash payments under the UGI
and Utilities Annual Bonus Plans, and (ii) deferrals thereof permitted
under the Internal Revenue Code.
(3) The maximum benefit under the Retirement Plan and the Supplemental
Executive Retirement Plan is equal to 60% of a participant's highest
consecutive 12 months' earnings during the last 120 months.
SEVERANCE PAY PLAN FOR SENIOR EXECUTIVE EMPLOYEES
The UGI Corporation Senior Executive Employee Severance Pay Plan (the
"UGI Severance Plan") assists certain senior level employees of Utilities,
including Messrs. Greenberg, Bovaird, Chaney, Dingman and Ladner 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.
Benefits payable include a lump sum cash payment in an amount
approximately equal to the sum of (i) three months of compensation (18 months in
the case of Mr. Greenberg), (ii) a pro rata portion of the senior executive's
annual target bonus under the Annual Bonus Plan for the current year, provided
that the employment termination date occurs during the first ten months of the
fiscal year, or, if the employment termination date occurs during the last two
months of the fiscal year, and the Chief Executive Officer determines not to use
his discretion to pay a pro-rata portion of the executive's annual target bonus,
the full bonus payable after the end of the fiscal year, assuming that (x) the
weighting to be applied to the business/financial performance goals is 100%, and
(y) the employee served the entire fiscal year, and (iii) separation pay
determined in a manner consistent with that payable to employees generally, not
exceeding 12 months of compensation. Certain employee benefits are continued for
a specified period (the "Employee Benefit Period") not exceeding 15 months (30
months in the case of Mr. Greenberg) after termination, or the senior executive
may be paid a lump sum equal to the present value of such 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.
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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 (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
receive
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an additional amount, such that the net amount retained after payment of
applicable taxes is equal to the severance total compensation payable.
BOARD OF DIRECTORS
Messrs. Bunn and Greenberg, who are officers of either the Company or
its parent, UGI, are not compensated for service on the Board of Directors or on
any Committee of the Board. The other members of the Company's Board of
Directors also serve on the UGI Board and receive no additional compensation for
service on the Company's Board. The Company reimburses UGI for 50% of the
attendance fees and expenses incurred by the non-employee directors of UGI.
COMPENSATION COMMITTEE
The members of the UGI Utilities, Inc. Compensation and Management
Development Committee are Robert C. Forney (Chairman), Richard C. Gozon, Quentin
I. Smith, Jr., and David I. J. Wang.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
At December 9, 1997, UGI Corporation held 100% of the Company's Common
Stock. UGI is located at 460 N. Gulph Road, King of Prussia, PA 19406.
The following table sets forth, as of December 9, 1997, 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 the directors and executive officers as a group
(including 630,859 shares subject to options exercisable within 60 days),
represents approximately 2.7% of UGI's outstanding shares.
NUMBER OF
SHARES AND
NATURE OF
BENEFICIAL NUMBER
OWNERSHIP OF
EXCLUDING STOCK
NAME OF BENEFICIAL OWNER OPTIONS (1)(2) OPTIONS TOTAL
- ------------------------ -------------- ------- -----
Stephen D. Ban 8,705 (3) 3,400 12,105
Brendan P. Bovaird 8,147 (4) 40,000 48,147
Richard L. Bunn 62,600 (5) 75,000 137,600
Robert J. Chaney 9,720 (6) 149,500 159,220
Mark R. Dingman 358 35,000 35,358
Robert C. Forney 12,186 4,000 16,186
Richard C. Gozon 11,768 5,000 16,768
Lon R. Greenberg 90,360 (7) 293,959 384,319
Anne Pol 4,276 0 4,276
Quentin I. Smith, Jr. 8,071 5,000 13,071
James W. Stratton 8,779 5,000 13,779
David I. J. Wang 20,894 5,000 25,894
All directors and executive
officers as a group (13) 210,019 630,859 879,363
- --------------------
(1) This column shows shares held in the individual's name,
individually or jointly with others, or in the name of a bank, broker or nominee
for the individual's account. It includes 2,000 shares held directly by Mr.
Bunn's spouse.
-39-
42
(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. Stratton (7,351 Units), Forney (7,358
Units), Wang (6,466 Units), Gozon (5,340 Units), Smith (5,643 Units), Ban
(3,424 Units) and Mrs. Pol (2,923 Units).
(3) Shares are held jointly with Dr. Ban's spouse.
(4) Includes the number of shares represented by units held in the UGI Stock
Fund of the 401(k) Employee Savings Plan.
(5) Includes 45,092 shares held jointly with Mr. Bunn's spouse and 2,000 shares
held directly by his spouse.
(6) Includes 2,561 shares held jointly with Mr. Chaney's spouse.
(7) Includes 72,759 shares held jointly with Mr. Greenberg's spouse.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In fiscal year 1997 UGI allocated $5,554,727, representing 42% of its
general corporate expenses, to Utilities.
-40-
43
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, 1997 and 1996
Consolidated Statements of Income for the fiscal years ended
September 30, 1997, 1996 and 1995
Consolidated Statements of Cash Flows for the fiscal years
ended September 30, 1997, 1996 and 1995
Consolidated Statements of Stockholders' Equity for the fiscal
years ended September 30, 1997, 1996 and 1995
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULES
II-Valuation and Qualifying Accounts
All other financial statement schedules are omitted because the required
information is not present or not present in amounts sufficient to require
submission of the schedule or because the information required is included
elsewhere in the respective financial statements or notes thereto contained
herein.
-41-
44
(3) LIST OF EXHIBITS:
The exhibits filed as part of this Report are as follows (exhibits
incorporated by reference are set forth with the name of the registrant,
the type of report and registration number or last date of the period for
which it was filed, and the exhibit number in such filing):
===============================================================================================================================
INCORPORATION BY REFERENCE
===============================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
===============================================================================================================================
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 Utilities Form 10-K 3.2
September 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)
- -------------------------------------------------------------------------------------------------------------------------------
-42-
45
====================================================================================================================================
INCORPORATION BY REFERENCE
====================================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
====================================================================================================================================
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 UGI Form 10-K (4)e
Union National Bank (formerly, First (9/30/93)
Fidelity Bank, N.A. 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 Utilities Form 8-K 4(i)
Medium-Term Note (8/1/96)
4.5 Form of Floating Rate Series B Utilities Form 8-K 4(ii)
Medium-Term Note (8/1/96)
4.6 (Intentionally left blank)
4.7 Officer's Certificate establishing Utilities Form 8-K 4(iv)
Medium-Term Notes series (8/26/94)
4.8 Calculation Agent Agreement dated Utilities Form 8-K 4(iii)
August 1, 1996 between UGI Utilities, (8/1/96)
Inc. and First Union National Bank
4.9 Form of Officer's Certificate establishing Utilities Form 8-K 4(iv)
Series B Medium-Term Notes under the (8/1/96)
Indenture
- -----------------------------------------------------------------------------------------------------------------------------------
-43-
46
==================================================================================================================================
Incorporation by Reference
==================================================================================================================================
Exhibit No. Exhibit Registrant Filing Exhibit
==================================================================================================================================
10.1 Service Agreement (Rate FSS) dated UGI Form 10-K 10.5
as of November 1, 1989 between (9/30/95)
Utilities and Columbia, as 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 Paragraph 61,060
(1993), order on rehearing, 64 FERC
Paragraph 61,365 (1993)
10.2 Service Agreement (Rate FTS) dated Utilities Form 10-K (10)o.
June 1, 1987 between Utilities and (12/31/90)
Columbia, as modified by
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
Paragraph 61,060 (1993), order on
rehearing, 64 FERC Paragraph 61,365
(1993)
10.3 Transportation Service Agreement Utilities Form 10-K (10)p.
(Rate FTS-1) dated November 1, (12/31/90)
1989 between Utilities and Columbia
Gulf 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 Paragraph
61,060 (1993), order on rehearing,
64 FERC Paragraph 61,365 (1993)
- ----------------------------------------------------------------------------------------------------------------------------------
-44-
47
==============================================================================================================================
INCORPORATION BY REFERENCE
==============================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
==============================================================================================================================
10.4** UGI Corporation 1992 Directors' UGI Form 10-Q (10)ff
Stock Plan (6/30/92)
10.5** UGI Corporation Directors Deferred UGI Form 10-K 10.39
Compensation Plan dated August 26, (9/30/94)
1993
10.6** UGI Corporation Directors' Equity UGI Form 10-Q 10.1
Compensation Plan (3/31/97)
10.7** UGI Corporation 1992 Stock Option UGI Form 10-Q (10)ee
and Dividend Equivalent Plan, as (6/30/92)
amended May 19, 1992
10.8** UGI Corporation Annual Bonus Plan UGI Form 10-Q 10.4
dated March 8, 1996 (6/30/96)
10.9** UGI Utilities, Inc. Annual Bonus Utilities Form 10-Q 10.4
Plan dated March 8, 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 UGI Form 10-K 10.12
Employee Severance Pay Plan (9/30/97)
effective January 1, 1997
10.12** Change of Control Agreement UGI Form 10-K 10.13
between UGI Corporation and Lon (9/30/97)
R. Greenberg
10.13** Form of Change of Control Agreement UGI Form 10-K 10.14
between UGI Corporation and Mr. Bunn (9/30/97)
- --------------------------------------------------------------------------------------------------------------------------------
-45-
48
===================================================================================================================================
INCORPORATION BY REFERENCE
===================================================================================================================================
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
===================================================================================================================================
10.14** Form of Change of Control Agreement UGI Form 10-K 10.15
between UGI Corporation and each of Corporation (9/30/97)
Messrs. Chaney, Dingman and Bovaird
10.15** UGI Corporation 1992 Non-Qualified AmeriGas Form 10-K 10.19
Stock Option Plan Partners, L.P. (9/30/95)
10.16** Amendment No. 1 to UGI Corporation UGI Utilities Form 10-Q 10
1992 Non-Qualified Stock Option Plan (6/30/97)
10.17** UGI Corporation 1997 Stock Option UGI Form 10-Q 10.2
and Dividend Equivalent Plan (3/31/97)
- -----------------------------------------------------------------------------------------------------------------------------------
*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 Coopers & Lybrand L.L.P.
*27 Financial Data Schedule
*99 Cautionary Statements Affecting
Forward-looking Information
===================================================================================================================================
* 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 1997 fiscal year, the Company filed a
Current Report on Form 8-K dated July 11, 1997, consisting of Items 4
and 7; and Amendment No. 1 on
-46-
49
Form 8-K/A to the Current Report on Form 8-K dated July 11, 1997,
consisting of Items 4 and 7.
-47-
50
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UGI UTILITIES, INC.
Date: December 16, 1997 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 16, 1997 by the following persons
on behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
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
Robert C. Forney Director
- -----------------------
Robert C. Forney
-48-
51
SIGNATURE TITLE
--------- -----
Richard C. Gozon Director
- ---------------------
Richard C. Gozon
Director
- ---------------------
Anne Pol
Quentin I. Smith, Jr. Director
- ---------------------
Quentin I. Smith, Jr.
James W. Stratton Director
- ---------------------
James W. Stratton
David I. J. Wang Director
- ---------------------
David I. J. Wang
-49-
52
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
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 Coopers & Lybrand L.L.P.
27 Financial Data Schedule
99 Cautionary Statements Affecting Forward-looking
Information
53
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 1997
F-1
54
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,
1997 and 1996 F-5 and F-6
Consolidated Statements of Income for the years
ended September 30, 1997, 1996 and 1995 F-7
Consolidated Statements of Cash Flows for the years
ended September 30, 1997, 1996 and 1995 F-8
Consolidated Statements of Stockholders' Equity
for the years ended September 30, 1997, 1996 and 1995 F-9
Notes to Consolidated Financial Statements F-10 to F-28
Financial Statement Schedule:
For the years ended September 30, 1997, 1996 and 1995:
II - Valuation and Qualifying Accounts S-1
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.
F-2
55
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholder
UGI Utilities, Inc.
We have audited the accompanying consolidated balance sheet of UGI Utilities,
Inc. and subsidiaries as of September 30, 1997 and the related consolidated
statements of income, stockholder's equity and cash flows for the year 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 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 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, 1997 and the results of
their operations and their cash flows for the year then ended in conformity with
generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole. The information for the year ended September 30,
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 14, 1997
F-3
56
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder
UGI Utilities, Inc.
We have audited the accompanying consolidated balance sheet of UGI Utilities,
Inc. and subsidiaries as of September 30, 1996 and the related consolidated
statements of income, stockholder's equity, and cash flows for the years ended
September 30, 1996 and 1995. We have also audited the related financial
statement schedule for the years ended September 30, 1996 and 1995 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 audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. 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 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, 1996, and the consolidated results of
their operations and cash flows for the years ended September 30, 1996 and 1995
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.
As discussed in Note 5 to the consolidated financial statements, the Company
changed its method of accounting for postemployment benefits in 1995.
COOPERS & LYBRAND L.L.P.
Philadelphia, Pennsylvania
November 22, 1996
F-4
57
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
September 30,
1997 1996
-------- --------
ASSETS
Current assets:
Cash and cash equivalents (note 1) $ 12,813 $ 3,100
Accounts receivable (less allowances for doubtful
accounts of $3,333 and $3,976, respectively) 25,309 26,288
Accrued utility revenues (note 1) 7,688 8,612
Inventories (notes 1 and 6) 30,645 30,035
Deferred income taxes (notes 1 and 4) 7,179 6,316
Prepaid expenses and other current assets 4,653 1,920
-------- --------
Total current assets 88,287 76,271
Property, plant and equipment (notes 1 and 3):
Gas utility 637,943 605,150
Electric utility 118,808 114,915
General 8,897 9,794
-------- --------
765,648 729,859
Less accumulated depreciation and amortization 237,293 222,559
-------- --------
Net property, plant and equipment 528,355 507,300
Regulatory income tax asset (notes 1 and 4) 44,438 42,908
Other assets 20,298 23,420
-------- --------
Total assets $681,378 $649,899
======== ========
The accompanying notes are an integral part of these financial statements.
F-5
58
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
September 30,
1997 1996
-------- --------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt (note 3) $ 17,143 $ 25,543
Current portion of preferred stock (note 7) 3,000 --
Bank loans (note 3) 67,000 50,500
Accounts payable 45,367 39,517
Employee compensation and benefits accrued 8,207 8,210
Dividends and interest accrued 3,692 4,975
Income taxes accrued 5,071 5,302
Other current liabilities 26,621 22,882
-------- --------
Total current liabilities 176,101 156,929
Long-term debt (note 3) 152,151 151,111
Deferred income taxes (notes 1 and 4) 99,868 95,452
Deferred investment tax credits (notes 1 and 4) 10,376 10,775
Other noncurrent liabilities 10,201 11,004
Commitments and contingencies (note 8)
Preferred stock subject to mandatory redemption,
without par value (note 7) 32,187 35,187
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 68,249 68,052
Retained earnings 71,986 61,130
-------- --------
Total common stockholder's equity 200,494 189,441
-------- --------
Total liabilities and stockholders' equity $681,378 $649,899
======== ========
The accompanying notes are an integral part of these financial statements.
F-6
59
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
Year Ended
September 30,
-----------------------------------
1997 1996 1995
--------- --------- ---------
Revenues (note 1) $ 461,208 $ 460,496 $ 357,364
--------- --------- ---------
Costs and expenses:
Gas, fuel and purchased power (note 1) 238,978 239,643 169,694
Operating and administrative expenses 117,874 119,432 108,514
Operating and administrative expenses
- related parties (note 13) 5,555 3,850 6,585
Depreciation and amortization (note 1) 21,431 21,602 19,754
Miscellaneous income, net (note 10) (2,777) (1,842) (3,780)
--------- --------- ---------
381,061 382,685 300,767
--------- --------- ---------
Operating income 80,147 77,811 56,597
Interest expense 16,872 16,094 16,838
--------- --------- ---------
Income before income taxes 63,275 61,717 39,759
Income taxes (notes 1 and 4) 24,564 23,369 11,741
--------- --------- ---------
Income before accounting change 38,711 38,348 28,018
Change in accounting for postemployment
benefits (note 5) -- -- (1,028)
--------- --------- ---------
Net income 38,711 38,348 26,990
Dividends on preferred stock 2,764 2,765 2,778
--------- --------- ---------
Net income after dividends on preferred stock $ 35,947 $ 35,583 $ 24,212
========= ========= =========
The accompanying notes are an integral part of these financial statements.
F-7
60
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
Year Ended
September 30,
--------------------------------
1997 1996 1995
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 38,711 $ 38,348 $ 26,990
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 21,431 21,602 19,754
Deferred income taxes, net 549 7,481 2,369
Provision for uncollectible accounts 4,272 4,933 3,376
Other (850) (704) 541
-------- -------- --------
64,113 71,660 53,030
Net change in:
Accounts receivable and accrued utility revenues (2,401) (9,444) (9,805)
Inventories (610) (6,608) 2,823
Deferred fuel adjustments 4,639 (10,731) (138)
Pipeline transition and producer settlement
recoveries (costs), net (1,769) 1,074 (7,591)
Accounts payable 5,850 5,894 7,803
Other current assets and liabilities (338) 5,184 (3,454)
-------- -------- --------
Net cash provided by operating activities 69,484 57,029 42,668
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (41,684) (39,659) (51,221)
Net costs of property, plant and equipment disposals (884) (1,189) (973)
Other, net 500 740 1,225
-------- -------- --------
Net cash used by investing activities (42,068) (40,108) (50,969)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (26,823) (35,649) (16,897)
Issuance of long-term debt 20,000 20,000 48,000
Repayment of long-term debt (27,380) (54,828) (17,236)
Bank loans increase 16,500 8,500 25,000
Redemption of Series Preferred Stock -- (15) --
-------- -------- --------
Net cash provided (used) by financing activities (17,703) (61,992) 38,867
-------- -------- --------
Cash and cash equivalents increase (decrease) $ 9,713 $(45,071) $ 30,566
======== ======== ========
CASH AND CASH EQUIVALENTS:
End of period $ 12,813 $ 3,100 $ 48,171
Beginning of period 3,100 48,171 17,605
-------- -------- --------
Increase (decrease) $ 9,713 $(45,071) $ 30,566
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-8
61
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of dollars)
Additional
Common Paid-in Retained
Stock Capital Earnings
-------- -------- --------
Balance September 30, 1994 $ 60,259 $ 68,052 $ 49,760
Net income 26,990
Cash dividends - common stock (14,507)
Cash dividends - preferred stock (2,778)
Dividend of subsidiary net assets (973)
-------- -------- --------
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
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-9
62
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) is a wholly owned subsidiary of UGI
Corporation (UGI) and 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.
The consolidated financial statements include the accounts of UGI
Utilities and its subsidiaries (collectively, the Company). All
significant intercompany accounts and transactions have been eliminated
in consolidation. Revenues of Gas Utility comprise more than four-fifths
of the Company's consolidated revenues.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the
financial statements, and revenues and expenses during the reporting
period. 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). Gas Utility and Electric
Utility 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), as amended
and supplemented by subsequently issued standards. SFAS 71, as amended
and supplemented, requires, among other things, that financial
statements of a regulated enterprise reflect the actions of regulators,
where appropriate. The economic effects of regulation can result in
regulated enterprises recording costs that have been or are expected to
be allowed in the ratesetting process in a period different from the
period in which the costs would be charged to expense by an unregulated
enterprise. When this occurs, costs are deferred as assets in the
balance sheet (regulatory assets) and recorded as expenses as those
amounts are reflected in rates. Additionally, regulators can impose
liabilities upon a regulated enterprise for amounts previously collected
from customers and for recovery of costs that are expected to be
incurred in the future (regulatory liabilities). The Company continually
monitors the regulatory and competitive environments in which it
operates to determine that its regulatory assets are probable of
recovery.
F-10
63
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Given the changing regulatory environment in the electric utility
industry (see Note 2), the Company continues to evaluate its ability to
apply the provisions of SFAS 71 as it relates to its electric generation
operations. The Company believes its electric generation assets and
related regulatory assets continue to satisfy the criteria of SFAS 71.
If such electric generation assets no longer meet the criteria of SFAS
71, any related regulatory assets would be written off unless some form
of transition cost recovery is established by the PUC which would meet
the requirements under generally accepted accounting principles for
continued accounting as regulatory assets during such recovery period.
Any generation-related, long-lived fixed and intangible assets would be
evaluated for impairment under the provisions of SFAS 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of."
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash equivalents include all highly liquid investments with maturities
of three months or less when purchased and are recorded at cost plus
accrued interest, which approximates market value.
Interest paid during 1997, 1996 and 1995, was $17,507, $16,100 and
$15,530, respectively. Income taxes paid during 1997, 1996 and 1995 were
$24,246, $15,736, and $11,535, respectively.
REVENUE RECOGNITION
Gas Utility and Electric Utility revenues are recorded for services
provided to the end of each month but not yet billed. Rate increases or
decreases are reflected in revenues from effective dates permitted by
the PUC.
INVENTORIES
Inventories are stated at the lower of cost or market. Cost is
determined on an average or first-in, first-out (FIFO) method except for
appliances for which the specific identification method is used.
INCOME TAXES
Deferred income tax provisions of UGI Utilities resulting from the use
of accelerated depreciation methods are recorded in the Consolidated
Statements of Income 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 asset
(regulatory income tax asset) for the probable increase in future
revenues that will result when the temporary differences reverse.
F-11
64
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Investment tax credits related to UGI Utilities' plant additions have
been deferred and are being amortized over the service lives of the
related property. UGI Utilities reduces its deferred tax liability for
the future tax benefits that will occur when the deferred investment tax
credits, which are not taxable, are amortized, and also reduces the
regulatory asset for the probable reduction in future revenues that will
result when such deferred investment tax credits amortize.
The Company joins with UGI Corporation and its subsidiaries in filing a
consolidated federal income tax return. The Company is allocated tax
assets, liabilities, expense, benefits and credits resulting from the
effects of its 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
Property, plant and equipment is stated at cost. The original cost of
UGI Utilities' retired plant, together with the net cost of removal, is
charged to accumulated depreciation for financial accounting purposes.
Removal costs of UGI Utilities' plant and equipment are deducted
currently for income tax purposes.
Depreciation of Gas Utility's and Electric Utility's plant and equipment
is computed 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
1997, 1996 and 1995 was 2.7%, 2.9% and 2.8%; and 3.6%, 3.6% and 3.4% for
Gas Utility and Electric Utility, respectively. Depreciation expense
during 1997, 1996 and 1995 was $20,899, $20,848 and $18,983,
respectively.
DEFERRED FUEL ADJUSTMENTS
Gas Utility's tariffs contain, and prior to January 1, 1997, Electric
Utility's tariffs contained, clauses which permit recovery of certain
gas, fuel and purchased power 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 under each clause
and the recoverable costs incurred. Accordingly, the difference between
amounts recognized in revenues and the applicable gas, fuel and
purchased power costs incurred is deferred until subsequently billed or
refunded to customers.
In accordance with the provisions of the Customer Choice Act (see Note
2), the rates Electric Utility can charge its customers, including
amounts pertaining to the recovery of fuel and purchased power costs,
were capped effective January 1, 1997. The difference between amounts
collected and costs actually incurred as of January 1, 1997 is being
considered by the PUC in conjunction with Electric Utility's Customer
Choice Act restructuring plan. Such amount was not material.
F-12
65
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. REGULATORY MATTERS
ELECTRICITY GENERATION CUSTOMER CHOICE AND COMPETITION ACT
On January 1, 1997, the 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 requires all
electric utilities to file restructuring plans with the PUC which, among
other things, include 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 transmission and 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 the generation component of prices as long as
stranded costs are being recovered through the CTC. 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.
On August 7, 1997, Electric Utility filed its restructuring plan with
the PUC. The restructuring plan includes a claim for the recovery of
$34,426 for stranded costs during the period January 1, 1999 through
December 31, 2002. The claim is primarily for the recovery of: (1) plant
investments in excess of estimated competitive market value and electric
generation facility retirement costs; (2) potential costs associated
with existing power purchase agreements; and (3) regulatory assets
(principally income taxes) recoverable from ratepayers under current
regulatory practice. The claim also seeks to establish a recovery
mechanism that would permit the recovery of up to an additional $28,000
of costs associated with the buyout or implementation of a December 1993
agreement to purchase power from an independent power producer. The PUC
is expected to take action on Electric Utility's filing in May 1998.
Based upon an evaluation of the various factors and conditions affecting
future cost recovery, the Company does not expect the Customer Choice
Act to have a material adverse effect on its financial condition or
results of operations.
BASE RATE CASES
On January 27, 1995, Gas Utility filed with the PUC for a $41,300
increase in base rates to be effective March 28, 1995. In accordance
with normal PUC practice, the effective date was suspended pending
further investigation. On August 31, 1995, the PUC approved a settlement
of this proceeding (Gas Utility Base Rate Settlement) authorizing a
$19,500 increase in annual revenues. The increase in base rates became
effective on August 31, 1995.
F-13
66
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
On January 26, 1996, Electric Utility filed with the PUC for a $6,200
increase in base rates. On July 18, 1996, the PUC approved a settlement
of this proceeding authorizing a $3,100 increase in annual revenues,
effective July 19, 1996.
REGULATORY ASSETS (LIABILITIES)
The following regulatory assets (liabilities) are included in the
accompanying balance sheets at September 30:
1997 1996
-------- --------
Regulatory income tax asset $ 44,438 $ 42,908
Other postretirement benefits 3,809 4,322
Refundable state taxes (3,102) (4,166)
Deferred fuel costs (recoveries), net (3,565) 1,074
Deferred producer settlement and pipeline
transition recoveries (3,852) (5,876)
Deferred environmental costs 706 697
F-14
67
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. DEBT
Long-term debt comprises the following at September 30:
1997 1996
--------- ---------
First Mortgage Bonds:
7.85% Series due November 1996 $ -- $ 8,400
Other long-term debt:
7.17% Series B Medium-Term Notes, due
June 2007 20,000 --
7.37% Medium-Term Notes, due October 2015 22,000 22,000
6.73% Medium-Term Notes, due October 2002 26,000 26,000
6.62% Medium-Term Notes, due May 2005 20,000 20,000
6.50% Senior Notes, due August 2003 (less
unamortized discount of $134 and $153,
respectively) 49,866 49,847
8.70% Notes, due March 1997 and 1998 in annual
installments of $10,000 10,000 20,000
9.71% Notes, due through September 2000 in
annual installments of $7,143 21,428 28,571
Other -- 1,836
--------- ---------
Total long-term debt 169,294 176,654
Less current maturities (17,143) (25,543)
--------- ---------
Long-term debt due after one year $ 152,151 $ 151,111
--------- ---------
Scheduled repayments of long-term debt for each of the next five fiscal
years ending September 30 are as follows: 1998 - $17,143; 1999 - $7,143;
2000 - $7,142; 2001 - $ -; 2002 - $ -.
The mortgage collateralizing UGI Utilities First Mortgage Bonds
constitutes a first lien on UGI Utilities' plant.
At September 30, 1997, UGI Utilities had revolving credit agreements
with five banks providing for borrowings of up to $102,000 through
December 1997 and $82,000 through June 2000. The commitments expiring in
June 2000 may be extended for one-year periods, upon timely notice,
unless the banks elect not to renew. The agreements provide UGI
Utilities with the option to borrow at various prevailing interest
rates, including the prime rate. A commitment fee at an annual rate of
3/16 of 1% is payable quarterly on the unused available committed credit
lines. At September 30, 1997 and 1996, borrowings under these agreements
totaled $67,000 and $50,500, respectively, and are classified as bank
loans. The weighted-average interest rates on UGI Utilities' bank loans
at September 30, 1997 and 1996 were 6.3% and 5.9%, respectively.
F-15
68
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Certain of UGI Utilities' debt agreements contain limitations with
respect to incurring additional debt, require the maintenance of
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. Under the most
restrictive of these provisions, permitted future restricted payments
aggregate $149,413 at September 30, 1997.
4. INCOME TAXES
The provisions for income taxes consist of the following:
1997 1996 1995
-------- -------- --------
Current:
Federal $ 18,168 $ 12,184 $ 6,742
State 5,847 3,704 2,630
-------- -------- --------
24,015 15,888 9,372
Deferred 947 7,880 2,768
Investment credit amortization (398) (399) (399)
-------- -------- --------
$ 24,564 $ 23,369 $ 11,741
-------- -------- --------
F-16
69
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
A reconciliation from the statutory federal tax rate to the effective
tax rate is as follows:
1997 1996 1995
---- ---- ----
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of
federal benefit 6.5 6.2 7.5
Adjustment to deferred state
income taxes -- -- (10.7)
Deferred investment credit
amortization (.6) (.7) (1.0)
Other, net (2.1) (2.6) (1.3)
---- ---- ----
Effective tax rate 38.8% 37.9% 29.5%
---- ---- ----
Deferred tax liabilities (assets) comprise the following at
September 30:
1997 1996
--------- ---------
Excess book basis over tax basis of property, plant
and equipment $ 85,387 $ 81,060
Regulatory income tax asset 18,439 17,802
Other 6,862 8,977
--------- ---------
Gross deferred tax liabilities 110,688 107,839
--------- ---------
Deferred investment tax credits (4,305) (4,471)
Deferred fuel refunds (1,450) --
Employee-related expenses (4,494) (4,348)
Regulatory liability - state income taxes (1,287) (1,729)
Other (6,463) (8,155)
--------- ---------
Gross deferred tax assets (17,999) (18,703)
--------- ---------
Net deferred tax liabilities $ 92,689 $ 89,136
--------- ---------
During 1995, UGI Utilities recorded a regulatory income tax asset of
$12,587 related to $11,329 of existing deferred state income taxes
expected to be recovered in the future through the ratemaking process.
Pursuant to the Gas Utility Base Rate Settlement, UGI Utilities recorded
a regulatory liability of $5,319 associated with a five-year flowback to
ratepayers of approximately $4,787 in previously recovered deferred
state income taxes. The net effect of these adjustments increased 1995
net income by $4,251.
F-17
70
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
As of September 30, 1997 and 1996, UGI Utilities had recorded
approximately $30,305 and $29,575, respectively, of deferred tax
liabilities 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 $4,305 and
$4,471 at September 30, 1997 and 1996, respectively, pertaining to
utility deferred investment tax credits. As of September 30, 1997 and
1996, UGI Utilities had recorded a regulatory income tax asset related
to these net deferred taxes of $44,438 and $42,908, respectively,
representing future revenues expected to be recovered through the
ratemaking process. This regulatory income tax asset will be recognized
in deferred tax expense as the corresponding temporary differences
reverse and additional income taxes are incurred.
5. PENSION PLAN AND OTHER POSTEMPLOYMENT BENEFITS
The Retirement Income Plan for Employees of UGI Utilities, Inc. (UGI
Utilities Plan) is a noncontributory defined benefit pension plan
covering substantially all employees of UGI Utilities and UGI. UGI
Utilities Plan's benefits are generally based on years of service and
employee compensation during the last years of employment.
The components of net pension income associated with UGI Utilities'
employees participating in the UGI Utilities Plan include the following:
1997 1996 1995
--------- --------- ----------
Service cost - benefits earned
during the period $ 2,564 $ 2,657 $ 2,020
Interest cost on projected
benefit obligation 10,037 9,621 9,500
Actual return on plan assets (38,240) (15,393) (26,745)
Net amortization and deferral 24,482 2,330 14,542
--------- --------- ----------
Net pension income $ (1,157) $ (785) $ (683)
--------- --------- ----------
F-18
71
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table sets forth UGI Utilities Plan's actuarial present
value of benefit obligations and funded status at September 30:
1997 1996
--------- ---------
Projected benefit obligation:
Vested benefits $(118,180) $(106,917)
Nonvested benefits (6,772) (5,912)
--------- ---------
Accumulated benefit obligation (124,952) (112,829)
Effect of projected future salary levels (24,111) (21,337)
--------- ---------
Projected benefit obligation (149,063) (134,166)
Plan assets at fair value 189,539 157,264
--------- ---------
Excess of plan assets over projected benefit
obligation 40,476 23,098
Unrecognized net gain (26,885) (9,609)
Unrecognized prior service cost 5,999 6,664
Unrecognized transition asset (11,155) (12,785)
--------- ---------
Prepaid pension cost $ 8,435 $ 7,368
--------- ---------
Included in the September 30, 1997 and 1996 projected benefit obligation
amounts above are $8,264 and $7,569, respectively, relating to employees
of UGI.
The major actuarial assumptions used in determining UGI Utilities Plan's
funded status as of September 30, 1997, 1996 and 1995, and net pension
income for each of the years then ended, are as follows:
1997 1996 1995
---- ---- ----
Funded status at September 30:
Discount rate 7.4% 8.0% 7.5%
Rate of increase in salary levels 4.5 4.75 4.5
Net pension income for the year:
Discount rate 8.0 7.5 8.7
Rate of increase in salary levels 4.75 4.5 5.0
Expected return on plan assets 9.5 9.5 9.5
---- ---- ----
UGI Utilities Plan's assets at September 30, 1997 consist principally of
equity and fixed income mutual funds and investment-grade corporate and
U. S. Government obligations. The Company also has unfunded nonqualified
retirement benefit plans for certain key employees and directors. At
September 30, 1997 and 1996, the projected benefit obligations of these
nonqualified plans were not material. During 1997, 1996 and 1995, the
Company recorded expense for these plans of $244, $257 and $336,
respectively.
F-19
72
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company sponsors a 401(k) savings plan (Savings Plan) for eligible
employees. Participants in the Savings Plan may contribute a portion of
their compensation on a before-tax and after-tax basis. The Company may,
at its discretion, match a portion of participants' contributions to the
Savings Plan. The cost of such Company matching contributions for 1997,
1996 and 1995 were $880, $865 and $770, respectively.
The Company provides 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 and also provides limited
postretirement life insurance benefits to substantially all active and
retired employees.
The components of net periodic postretirement benefit cost are as
follows:
1997 1996 1995
------- ------- -------
Service cost - benefits earned
during the period $ 61 $ 67 $ 51
Interest cost on accumulated
postretirement benefit
obligation 1,576 1,908 1,763
Actual return on plan assets (142) -- --
Net amortization and deferral 1,071 1,369 1,055
------- ------- -------
Net periodic postretirement
benefit cost 2,566 3,344 2,869
Decrease (increase) in
regulatory asset 513 (149) (983)
------- ------- -------
Net expense $ 3,079 $ 3,195 $ 1,886
------- ------- -------
The following table sets forth the actuarial present value and funded
status of the Company's postretirement health care and life insurance
benefit plans at September 30:
F-20
73
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1997 1996
-------- --------
Accumulated postretirement benefit obligation:
Retirees $(18,618) $(20,355)
Fully eligible active participants (1,834) (4,000)
Other active participants (1,520) (1,306)
-------- --------
(21,972) (25,661)
Plan assets at fair value 3,479 1,853
Unrecognized net gain (1,881) (2,835)
Unrecognized prior service cost -- 2,149
Unrecognized transition obligation 16,320 19,921
-------- --------
Accrued postretirement benefit cost $ (4,054) $ (4,573)
-------- --------
Included in the September 30, 1997 and 1996 accumulated postretirement
benefit obligation amounts above are $406 and $365, respectively,
relating to employees of UGI.
The major actuarial assumptions used in determining the funded status of
the Company's postretirement health care and life insurance benefit
plans at September 30, 1997, 1996 and 1995, and net periodic
postretirement benefit cost for the years then ended, are as follows:
1997 1996 1995
------- ------- -------
Funded status at September 30:
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
Net periodic postretirement
benefit cost for the year:
Discount rate 8.0 7.5 8.7
Health care cost trend rate 6.5-5.5 7.0-5.5 10.0-5.5
------- ------- --------
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 September 30, 1997 and 1996 accumulated
postretirement benefit obligations by $1,534 and $2,150, respectively,
and increases the net periodic postretirement benefit costs for 1997,
1996 and 1995, by $115, $160 and $130, respectively.
UGI Utilities has established an Employee Benefit Trust (VEBA) to pay
retiree health care and life insurance benefits and to fund the UGI
Utilities' postretirement benefit liability. At September 30, 1997, the
VEBA balance totaled $3,479 and was primarily invested in money market
funds.
F-21
74
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Effective August 31, 1995, Gas Utility is permitted to recover in its
rates approximately $2,400 in ongoing annual costs incurred under the
provisions of SFAS No. 106, "Employers Accounting for Postretirement
Benefits Other Than Pensions" (SFAS 106). Gas Utility is required to
defer the difference between the amount of SFAS 106 costs included in
rates and the actuarially determined annual SFAS 106 costs for recovery
or refund to ratepayers in future rate proceedings. Also effective
August 31, 1995, Gas Utility was permitted the recovery over 17.25 years
of approximately $4,000 in deferred excess SFAS 106 costs. These
deferred costs represent the difference between costs incurred under
SFAS 106, comprising principally deferred transition obligation
amortization, and costs incurred on a pay-as-you-go basis for periods
prior to August 31, 1995. Gas Utility's 1995 Base Rate Settlement,
however, reserved the right of any party to challenge the prospective
recovery of these deferred excess SFAS 106 costs in future rate
proceedings. The Company continues to monitor administrative and
judicial proceedings involving deferred excess SFAS 106 costs and
recognizes that, based on applicable law, it is possible that in future
rate proceedings Utilities could prospectively be denied recovery of
some or all of its deferred excess SFAS 106 costs.
Effective October 1, 1994, the Company adopted SFAS No. 112, "Employers'
Accounting for Postemployment Benefits" (SFAS 112). SFAS 112 requires,
among other things, the accrual of benefits provided to former or
inactive employees (who are not retirees) and to their beneficiaries and
covered dependents. Prior to the adoption of SFAS 112, the Company
accounted for these postemployment benefits on a pay-as-you-go basis.
The cumulative effect of SFAS 112 on the Company's results of operations
for periods prior to October 1, 1994 of $1,798 pre-tax ($1,028
after-tax) has been reflected in the 1995 Consolidated Statement of
Income as "Change in accounting for postemployment benefits."
6. INVENTORIES
Inventories comprise the following at September 30:
1997 1996
------- -------
Utility fuel and gases $25,963 $26,012
Appliances for sale 1,877 1,374
Materials, supplies and other 2,805 2,649
------- -------
$30,645 $30,035
------- -------
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
75
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
arrearage has been cured. Cash dividends have been paid at the specified
annual rates on all outstanding Series Preferred Stock.
Series Preferred Stock subject to mandatory redemption comprises the
following at September 30:
1997 1996
-------- --------
$1.80 Series, stated at involuntary liquidation
value of $23.50 per share, cumulative (issued
and outstanding - 7,963 shares) $ 187 $ 187
$8.00 Series, stated at involuntary liquidation
value of $100 per share, cumulative (issued
and outstanding - 150,000 shares) 15,000 15,000
$7.75 Series, stated at involuntary liquidation
value of $100 per share, cumulative (issued
and outstanding - 200,000 shares) 20,000 20,000
-------- --------
Total Series Preferred Stock subject to mandatory
redemption 35,187 35,187
Less current portion (3,000) --
-------- --------
Total Series Preferred Stock due after one year $ 32,187 $ 35,187
-------- --------
UGI Utilities is required to purchase shares of its $1.80 Series
Preferred Stock tendered at a purchase price of $23.50 per share. After
January 1, 1998, UGI Utilities may call any untendered $1.80 Series
shares at a redemption price of $23.50 per share.
UGI Utilities is required to establish a sinking fund to redeem on April
1 in each year, commencing April 1, 1998, 30,000 shares of its $8.00
Series Preferred Stock at a price of $100 per share. The $8.00 Series is
redeemable, in whole or in part, at the option of UGI Utilities at a
price of $103.56 per share commencing April 2, 1997, decreasing by equal
amounts on April 2 of each subsequent year through 2001.
UGI Utilities is required to establish a sinking fund to redeem on
October 1 in each year, commencing October 1, 2004, 10,000 shares of its
$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 the option
of UGI Utilities 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.
Mandatory sinking fund requirements on UGI Utilities' Series Preferred
Stock during each of the fiscal years 1998 to 2002 is $3,000.
F-23
76
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. COMMITMENTS AND CONTINGENCIES
The Company leases various buildings and transportation, data processing
and office equipment under operating leases. Certain of the leases
contain renewal and purchase options and also contain escalation
clauses. The aggregate rental expense for such leases for 1997, 1996 and
1995 was $5,083, $4,891 and $4,861, respectively.
Minimum future payments under operating leases having initial or
remaining noncancelable terms in excess of one year for the fiscal years
ending September 30 are as follows: 1998 - $4,210; 1999 - $3,526; 2000 -
$2,883; 2001 - $2,400; 2002 - $2,104; after 2002 - $1,578.
Gas Utility has gas supply agreements with producers and marketers that
expire at various dates through 2000 and has agreements for pipeline
transportation and storage capacity that expire at various dates through
2017 and 2014, respectively. In addition, Gas Utility has short-term gas
supply agreements which permit it to purchase certain of its gas supply
needs at spot prices.
Electric Utility has a power supply agreement with Pennsylvania Power
and Light, Inc. (PP&L) pursuant to 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. During 1997, 1996 and 1995, approximately
53%, 52% and 50%, respectively, of Electric Utility's total electric
system output was supplied by PP&L. Electric Utility has provided notice
to PP&L of its intention to terminate this agreement as of March 2001.
UGI Utilities, along with other companies, has been named as a
potentially responsible party (PRP) in several administrative
proceedings for the cleanup of various waste sites, including some
Superfund sites. Also, certain private parties have filed, or threatened
to file, suit against the Company to recover costs of investigation and,
as appropriate, remediation of several waste sites. In addition, UGI
Utilities has identified environmental contamination at several of its
properties and has voluntarily undertaken investigation and, as
appropriate, remediation of these sites in cooperation with appropriate
environmental agencies or private parties.
With respect to a manufactured gas plant site in Concord, New Hampshire,
EnergyNorth Natural Gas, Inc. (EnergyNorth) filed suit against UGI
Utilities alone seeking UGI Utilities' allocable share of response costs
associated with remediating gas plant related contaminants at that site.
In September 1997, UGI Utilities reached a settlement pursuant to which
it agreed to pay EnergyNorth a portion of its remediation costs. The
settlement did not materially affect the Company's results of
operations.
At a manufactured gas plant site in Burlington, Vermont, the United
States Environmental Protection Agency has named 19 parties, including
UGI Utilities, as PRPs for gas plant contamination that resulted from
the operations of a former subsidiary of UGI Utilities. In
F-24
77
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
September 1997, after several years of study, a coordinating council of
community groups and PRPs recommended a remedial plan consisting of
capping and monitoring the site. In December 1997, Green Mountain Power
Company, the lead PRP at the site, agreed in principle to relieve UGI
Utilities of any liability at the site on terms that would not
materially affect the Company's results of operations.
At sites in which a former subsidiary of UGI Utilities operated a
manufactured gas plant, 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,
courts have found parent companies liable for environmental damage
caused by subsidiary companies when the parent company exercised such
substantial control over the subsidiary that the court concluded that
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 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 level of control exercised by UGI Utilities over the
subsidiary satisfies the standard described above. In many circumstances
where UGI Utilities may be liable, expenditures may not be reasonably
quantifiable because of a number of factors, including 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.
The Company's 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. The Company intends to
pursue recovery of any incurred costs through all appropriate means,
including regulatory relief, although such recovery cannot be assured.
Under the terms of the Gas Utility Base Rate Settlement, 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.
In addition to these environmental matters, there are various other
pending claims and legal actions arising in the normal course of the
Company's businesses. The final results of environmental and other
matters cannot be predicted with certainty. However, it is reasonably
possible that some of them could be resolved unfavorably to the Company.
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 the Company's
financial position but could be material to 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.
F-25
78
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. FINANCIAL INSTRUMENTS
The carrying amounts reported in the consolidated balance sheets for
cash and cash equivalents, accounts receivable, accounts payable and
bank loans approximate fair value because of the immediate or short-term
maturity of these financial instruments. Based upon current market
prices and discounted present value methods calculated using borrowing
rates available for debt with similar credit ratings, terms and
maturities, the fair values of the Company's long-term debt at September
30, 1997 and 1996 are estimated to be approximately $173,000 and
$176,000, respectively. The fair values of the Company's Series
Preferred Stock are based upon the fair values of redeemable preferred
stock with similar credit ratings and redemption features and are
estimated to be approximately $36,000 and $37,000 at September 30, 1997
and 1996, respectively.
Financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of trade accounts
receivable. This risk is limited due to the Company's large customer
base and its dispersion across many different markets. At September 30,
1997 and 1996, the Company had no significant concentrations of credit
risk.
10. MISCELLANEOUS INCOME
Miscellaneous income comprises the following:
1997 1996 1995
------ ------ ------
Interest income $ 153 $ 403 $1,286
Gas brokerage income -- -- 1,409
Other 2,624 1,439 1,085
------ ------ ------
$2,777 $1,842 $3,780
------ ------ ------
Effective August 1, 1995, the Company dividended the net assets of
GASMARK, the Company's gas brokerage business, to UGI. Such net assets
totaled $973.
F-26
79
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. SEGMENT INFORMATION
Information on revenues, operating income, identifiable assets,
depreciation and amortization and capital expenditures by business
segment for 1997, 1996 and 1995 follows:
1997 1996 1995
--------- --------- ---------
REVENUES
Gas utility $ 389,064 $ 390,994 $ 291,258
Electric utility 72,144 69,502 66,106
--------- --------- ---------
Total $ 461,208 $ 460,496 $ 357,364
--------- --------- ---------
OPERATING INCOME (LOSS)
Gas utility $ 74,790 $ 72,937 $ 51,947
Electric utility 10,689 8,622 9,109
Other 223 102 2,126
Corporate general (5,555) (3,850) (6,585)
--------- --------- ---------
Total $ 80,147 $ 77,811 $ 56,597
--------- --------- ---------
IDENTIFIABLE ASSETS
(at period end)
Gas utility $ 594,331 $ 561,793 $554,277
Electric utility 86,247 83,872 86,637
Corporate general and other 800 4,234 20,566
--------- --------- ---------
Total $ 681,378 $ 649,899 $661,480
--------- --------- ---------
DEPRECIATION AND AMORTIZATION
Gas utility $ 17,194 $ 17,576 $ 16,068
Electric utility 4,237 4,024 3,682
Corporate general - 2 4
--------- --------- ---------
Total $ 21,431 $ 21,602 $ 19,754
--------- --------- ---------
CAPITAL EXPENDITURES
Gas utility $ 36,691 $ 34,624 $ 45,273
Electric utility 4,993 5,035 5,922
Corporate general and other - - 26
--------- --------- ---------
Total $ 41,684 $ 39,659 $ 51,221
========= ========= =========
F-27
80
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. QUARTERLY DATA (UNAUDITED)
The following quarterly information includes all adjustments (consisting
only of normal recurring adjustments) which the Company considers
necessary for a fair presentation of such information. Quarterly results
fluctuate because of the seasonal nature of UGI Utilities' businesses.
December 31, March 31, June 30, September 30,
1996 1995 1997 1996 1997 1996 1997 1996
-------- -------- -------- -------- -------- -------- -------- --------
Revenues $134,154 $122,241 $173,304 $181,412 $ 88,208 $ 88,860 $ 65,542 $ 67,983
Operating income (loss) 30,343 27,712 41,022 40,495 8,977 9,389 (195) 215
Net income (loss) 16,185 14,660 22,763 22,425 2,970 3,702 (3,207) (2,439)
-------- -------- -------- -------- -------- -------- -------- --------
13. 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 for 1997, 1996 and 1995.
F-28
81
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
Balance at Charged to Balance at
beginning costs and end of
of year expenses Other year
---------- ---------- ------- ----------
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
======== ======== ======= ========
YEAR ENDED SEPTEMBER 30, 1995
- -----------------------------
Reserves deducted from assets in the consolidated
balance sheet:
Allowance for doubtful accounts $2,796 $3,376 $(3,512)(1) $2,660
======== ======== ======= ========
Other reserves(3) $2,294 $1,411 $ (450)(2) $3,255
======== ======== ======= ========
(1) Uncollectible accounts written off, net of recoveries.
(2) Represents property and casualty liability payments.
(3) Includes reserves for self-insured property and casualty liability, insured
property and casualty liability, environmental, litigation and other.
S-1