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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, 2003
Commission file number 1-1398
UGI UTILITIES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Pennsylvania 23-1174060
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
100 Kachel Boulevard, Suite 400, Green Hills Corporate Center
Reading, PA 19607
(ADDRESS OF PRINCIPAL 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 November 30, 2003, 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
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]
THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I(1)(a) AND
(b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE REDUCED
DISCLOSURE FORMAT PERMITTED BY THAT GENERAL INSTRUCTION.
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TABLE OF CONTENTS
PAGE
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PART I: BUSINESS............................................................................................... 1
Items 1 and 2. Business and Properties........................................................ 1
General........................................................................ 1
Gas Utility Operations......................................................... 1
Electric Utility Operations.................................................... 5
Item 3. Legal Proceedings.............................................................. 8
PART II: SECURITIES AND FINANCIAL INFORMATION................................................................... 11
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.......... 11
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations..................................................................... 12
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..................... 26
Item 8. Financial Statements and Supplementary Data.................................... 26
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure..................................................................... 26
Item 9A. Controls and Procedures........................................................ 26
PART III: INTENTIONALLY OMITTED.................................................................................. 28
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS............................................................. 29
Item 15. Exhibits, Financial Statement Schedule, and Reports on Form 8-K................ 29
Signatures..................................................................... 35
Index to Financial Statements and Financial Statement Schedule................. F-2
(i)
PART I: BUSINESS
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. ("Utilities", "UGI Utilities" or the "Company") is
a public utility company that owns and operates (i) a natural gas distribution
utility serving 15 counties in eastern and southeastern Pennsylvania ("Gas
Utility"), and (ii) an electric utility serving parts of Luzerne and Wyoming
counties in northeastern Pennsylvania ("Electric Utility"). We are a wholly
owned subsidiary of UGI Corporation ("UGI"). In response to state deregulation
legislation, effective October 1, 1999 we transferred our electric generation
assets to our non-utility subsidiary, UGI Development Company ("UGID"). UGID
contributed certain of its generation assets to a joint venture with a
subsidiary of Allegheny Energy, Inc. in December 2000. In June 2003, we
dividended the stock of UGID to UGI. UGID's results of operations did not have a
material effect on our results of operations for fiscal years 2003, 2002 or
2001.
Utilities was incorporated in Pennsylvania in 1925. We are subject to
regulation by the Pennsylvania Public Utility Commission ("PUC"). Our executive
offices are located at 100 Kachel Boulevard, Suite 400, Green Hills Corporate
Center, Reading, Pennsylvania 19607, and our telephone number is (610) 796-3400.
In this report, the terms "Company" and "Utilities," as well as the terms,
"our," "we," and "its," are sometimes used to refer to UGI Utilities, Inc. or,
collectively (for periods prior to July 2003), UGI Utilities, Inc. and its
consolidated subsidiaries.
GAS UTILITY OPERATIONS
NATURAL GAS CHOICE AND COMPETITION ACT
On June 22, 1999, Pennsylvania's Natural Gas Choice and Competition Act
("Gas Competition Act") was signed into law. The purpose of the Gas Competition
Act was to provide all natural gas consumers in Pennsylvania with the ability to
purchase their gas supplies from the supplier of their choice. Under the Gas
Competition Act, local distribution companies ("LDCs") like Gas Utility may
continue to sell gas to customers, and such sales of gas, as well as
distribution services provided by LDCs, continue to be subject to price
regulation by the PUC.
Generally, Pennsylvania LDCs will serve as the supplier of last resort
for all residential and small commercial and industrial customers unless the PUC
approves another supplier of last resort. The Gas Competition Act requires
energy marketers seeking to serve customers of LDCs to accept assignment of a
portion of the LDC's interstate pipeline capacity and storage contracts at
contract rates, thus avoiding the creation of stranded costs.
On October 1, 1999, Gas Utility filed its restructuring plan with the
PUC pursuant to the Gas Competition Act. On June 29, 2000, the PUC entered its
order ("Gas Restructuring Order") approving Gas Utility's restructuring plan
substantially as filed. Gas Utility designed its
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restructuring plan to ensure reliability of gas supply deliveries to Gas Utility
on behalf of residential and small commercial and industrial customers. In
addition, the plan changed Gas Utility's base rates for firm customers. It also
changed the calculation of purchased gas cost rates. See "Utility Regulation and
Rates."
Since October 1, 2000, all of Gas Utility's customers have had the
option to purchase their gas supplies from an alternative gas supplier. Large
commercial and industrial customers of Gas Utility have been able to purchase
their gas from other suppliers since 1982. During fiscal year 2003, two
third-party suppliers qualified to serve residential or small commercial and
industrial customers in Gas Utility's service territory. Together, they are
serving approximately 4,500 customers. Management believes none of the Gas
Competition Act, the Gas Restructuring Order, or commodity sales to residential
and small commercial and industrial customers by third-party suppliers will have
a material adverse impact on the Company's financial condition or results of
operations.
SERVICE AREA; REVENUE ANALYSIS
Gas Utility distributes natural gas to approximately 292,000 customers
in portions of 15 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 4,800 miles of gas mains. The service area
consists of approximately 3,000 square miles and includes the cities of
Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon and
Reading, Pennsylvania. Located in Gas Utility's service area are major
production centers for basic industries such as specialty metals, aluminum and
glass.
System throughput (the total volume of gas sold to or transported for
customers within Gas Utility's distribution system) for the 2003 fiscal year was
approximately 83.8 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 43% of system throughput, while gas transported for residential,
commercial and industrial customers (who bought their gas from others) accounted
for approximately 57% of system throughput. Based on industry data for 2001,
residential customers account for approximately 34% of total system throughput
by LDCs in the United States. By contrast, for the 2003 fiscal year, Gas
Utility's residential customers represented 26% 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, and storage and
transportation service contracts. These arrangements enable Gas Utility to
purchase gas from Gulf Coast, Mid-Continent, Appalachian and Canadian sources.
For the transportation and storage function, Utilities has agreements with a
number of pipeline companies, including Texas Eastern Transmission Corporation,
Columbia Gas Transmission Corporation and Transcontinental Gas Pipeline
Corporation.
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GAS SUPPLY CONTRACTS
During fiscal year 2003, Gas Utility purchased approximately 37 bcf of
natural gas for sale to customers. Approximately 88% of the volumes purchased
were supplied under agreements with ten major suppliers. The remaining 12% of
gas purchased was supplied by approximately 25 producers and marketers. Gas
supply contracts are generally no longer than one year.
In fiscal years 2002 and 2003, as a result of changing market
conditions following the bankruptcy of Enron Corp., a number of suppliers with
which Utilities formerly did business exited the wholesale trading market. This
development did not significantly impact Utilities' ability to secure gas
supplies.
SEASONAL VARIATION
Because many of its customers use gas for heating purposes, Gas
Utility's sales are seasonal. Approximately 60% of fiscal year 2003 throughput
occurred during the months of November through March.
COMPETITION
Natural gas is a fuel that competes with electricity and oil, and to a
lesser extent, with propane and coal. Competition among these fuels is primarily
a function of their comparative price and the relative cost and efficiency of
fuel utilization equipment. Electric utilities in Gas Utility's service area are
seeking new load, primarily in the new construction market. Fuel oil dealers
compete for customers in all categories, including 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 gas distribution services. Under the Gas Competition Act, retail
customers may purchase their natural gas from a supplier other than Gas Utility.
Commercial and industrial customers in Gas Utility's service territory have been
able to do this since 1982. As of October 2003, two marketers have qualified to
serve residential and small commercial and industrial customers. Together they
serve approximately 4,500 customers. Gas Utility provides transportation
services for residential and small commercial and industrial customers who
purchase natural gas from others.
A number of Gas Utility's commercial and industrial customers have the
ability to switch to an alternate fuel at any time and, therefore, are served on
an interruptible basis under rates which are competitively priced with respect
to their alternate fuel. Gas Utility's profitability from these customers,
therefore, is affected by the difference, or "spread," between the customers'
delivered cost of gas and the customers' delivered alternate fuel cost. See
"Utility Regulation and Rates - Gas Utility Rates." Commercial and industrial
customers representing 18% of total system throughput have locations which
afford them the opportunity, although none has
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exercised it, of seeking transportation service directly from interstate
pipelines, thereby bypassing Gas Utility. The majority of customers in this
group are served under transportation contracts having three- to twenty-year
terms. Included in these two groups are Utilities' ten largest customers in
terms of annual volume. All of these customers have contracts with Utilities,
nine of which extend beyond fiscal year 2004. 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 meet the full requirements of all firm customers on its
system through fiscal year 2004. Supply mix is diversified, market priced, and
delivered pursuant to a number of long- and short-term firm transportation and
storage arrangements, including transportation contracts held by some of
Utilities' larger customers.
During fiscal year 2003, Gas Utility supplied transportation service to
two major cogeneration installations and three electric generation facilities.
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
approximately 9,600 residential heating customers during fiscal year 2003, which
represented a record annual increase. Of those new customers, new home
construction accounted for over 7,300 heating customers. Customers converting
from other energy sources, primarily oil and electricity, and existing
non-heating gas customers who have added gas heating systems to replace other
energy sources, accounted for the balance of the additions. The number of new
commercial and industrial customers was over 1,100.
Utilities continues to monitor and participate extensively in
rulemaking and individual rate and tariff 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 pricing of pipeline services in a competitive energy
marketplace; (ii) the flexibility of the terms and conditions of pipeline
service tariffs and contracts; and (iii) pipelines' requests to increase their
base rates, or change the terms and conditions of their storage and
transportation services.
Gas Utility's objective in negotiations with interstate pipeline and
natural gas suppliers, and in proceedings before regulatory agencies, is to
assure availability of supply, transportation and storage alternatives to serve
market requirements at the lowest cost possible, taking into account the need
for security of supply. Consistent with that objective, Gas Utility negotiates
the terms of firm transportation capacity on all pipelines serving Gas Utility,
arranges for appropriate storage and peak-shaving resources, negotiates with
producers for competitively priced gas purchases and aggressively participates
in regulatory proceedings related to transportation rights and costs of service.
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ELECTRIC UTILITY OPERATIONS
ELECTRICITY GENERATION CUSTOMER CHOICE AND COMPETITION ACT
On January 1, 1997, Pennsylvania's Electricity Generation Customer
Choice and Competition Act ("ECC Act") became effective. The ECC Act permits all
Pennsylvania retail electric customers to choose their electric generation
supplier. Pursuant to the Act, all electric utilities were required to file
restructuring plans with the PUC which, among other things, included unbundled
prices for electric generation, transmission and distribution and a competitive
transition charge ("CTC") for the recovery of "stranded costs" which would be
paid by all customers receiving distribution service. Stranded costs generally
are electric generation-related costs that traditionally would be recoverable in
a regulated environment but may not be recoverable in a competitive electric
generation market. Under the ECC Act, Electric Utility is obligated to provide
energy to customers who do not choose alternate suppliers. 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 June 19, 1998, the PUC entered its Opinion and Order (the
"Restructuring Order") in Electric Utility's restructuring proceeding under the
ECC Act. The Electric Restructuring Order authorized Electric Utility to recover
from its customers approximately $32.5 million in stranded costs (on a full
revenue requirements basis, which includes all income and gross receipts taxes)
over an estimated four-year period which commenced January 1, 1999 through a
CTC, together with carrying charges on unrecovered balances of 7.94%. Under the
terms of the Restructuring Order, Electric Utility generally could not increase
the generation component of prices during the period that stranded costs were
being recovered through the CTC. Electric Utility's recovery of stranded costs
through the CTC was completed during fiscal year 2003.
SERVICE AREA; SALES ANALYSIS
Electric Utility supplies electric service to approximately 61,600
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 fiscal
year 2003, about 53% of sales volume came from residential customers, 36% from
commercial customers and 11% from industrial customers. Electricity transported
for customers who purchased their power from others pursuant to the ECC Act
represented approximately 1% of fiscal year 2003 sales volume.
SOURCES OF SUPPLY
Electric Utility has third-party generation supply contracts in place
for substantially all of its expected energy requirements for fiscal year 2004.
Electric Utility distributes both electricity that it purchases from others and
electricity that customers purchase from other suppliers. At September 30, 2003,
alternate suppliers served customers representing less than 1% of system load.
Electric Utility expects to continue to provide energy to the great majority of
its distribution customers for the foreseeable future.
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UTILITY REGULATION AND RATES
PENNSYLVANIA PUBLIC UTILITY COMMISSION JURISDICTION
Utilities' gas and electric utility operations, which exclude electric
generation, are subject to regulation by the PUC as to rates, terms and
conditions of service, accounting matters, issuance of securities, contracts and
other arrangements with affiliated entities, and various other matters.
FERC ORDERS 888 AND 889
In April 1996, FERC issued Orders No. 888 and 889, which established
rules for the use of electric transmission facilities for wholesale
transactions. FERC has also asserted jurisdiction over the transmission
component of electric retail choice transactions. In compliance with these
orders, the PJM Interconnection, LLC ("PJM"), of which Utilities is a member,
has filed an open access transmission tariff with the FERC establishing
transmission rates and procedures for transmission within the PJM control area.
Under the PJM tariff and associated agreements, Electric Utility is entitled to
receive certain revenues when its transmission facilities are used by third
parties.
GAS UTILITY RATES
The Gas Restructuring Order included an increase in firm-residential,
commercial and industrial ("retail core-market") base rates, effective
October 1, 2000. The increase, calculated in accordance with the Gas Competition
Act, was designed to generate approximately $16.7 million in additional annual
revenues. The Order also provided that Gas Utility reduce its purchased gas cost
rates by an annualized amount of $16.7 million for the first 14 months following
the base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its
purchased gas cost rates to retail core-market customers by an amount equal to
the margin it receives from customers served under interruptible rates to the
extent they use capacity contracted for by Gas Utility for retail core-market
customers. As a result of these changes in its regulated rates, since December
1, 2001, Gas Utility's operating results have been more sensitive to heating
season weather and less sensitive to the market prices of alternative fuel.
BASE RATES
As stated above, Gas Utility's current base rates went into effect
October 1, 2000 pursuant to The Gas Restructuring Order. See Note 2 to the
Company's Consolidated Financial Statements.
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
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charges for natural gas sold by it, to reflect Utilities' projected cost of
purchased gas. PGC rates may also be adjusted quarterly, or, under certain
conditions monthly, to reflect purchased gas costs. Each proposed annual PGC
rate is required to be filed with the PUC six months prior to its effective
date. During this period the PUC holds hearings to determine whether the
proposed rate reflects a least-cost fuel procurement policy consistent with the
obligation to provide safe, adequate and reliable service. After completion of
these hearings, the PUC issues an order permitting the collection of gas costs
at levels which meet that standard. The PGC mechanism also provides for an
annual reconciliation. Utilities has two PGC rates. PGC (1) is applicable to
small, firm, core-market customers consisting of the residential and small
commercial and industrial classes; PGC (2) is applicable to firm, contractual,
high-load factor customers served on three separate rates. In addition,
residential customers maintaining a high load factor may qualify for the PGC (2)
rate. As described above, the Gas Restructuring Order provided for ongoing
adjustments to Gas Utilities' PGC rates, commencing December 1, 2001, to reflect
margins, if any, from interruptible rate customers who do not obtain their own
pipeline capacity.
ELECTRIC UTILITY RATES
The PUC approved a settlement establishing rules for Electric Utility's
Provider of Last Resort ("POLR") service on March 28, 2002, and a separate
settlement that modified these rules on June 13, 2002 (collectively, the "POLR
Settlement") under which Electric Utility terminated stranded cost recovery
through its CTC and is no longer subject to the statutory generation rate caps
as of August 1, 2002 for commercial and industrial ("C&I") customers and as of
November 1, 2002 for residential customers. Charges for generation service (1)
were initially set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times by up to 5% of the total rate for distribution,
transmission and generation through December 2004; and (3) may be set at market
rates thereafter. Electric Utility may also offer multiple year POLR contracts
to its customers. The POLR Settlement provides for annual shopping periods
during which customers may elect to remain on POLR service or choose an
alternate supplier. Customers who do not select an alternate supplier will be
obligated to remain on POLR service until the next shopping period. Residential
customers who return to POLR service at a time other than during the annual
shopping period must remain on POLR service until the date of the second open
shopping period after returning. C&I customers who return to POLR service at a
time other than during the annual shopping period must remain on POLR service
until the next open shopping period, and may, in certain circumstances, be
subject to generation rate surcharges. Consistent with the terms of the POLR
Settlement, Electric Utility's POLR rates will increase beginning January 2004
for commercial and industrial customers, and June 2004 for residential
customers.
Additionally, pursuant to the requirements of the ECC, the PUC is
currently developing post-rate cap POLR regulations that are expected to further
define post-rate cap POLR service obligations and pricing. As of September 30,
2003, fewer than 1% of Electric Utility's customers have chosen an alternative
electricity generation supplier.
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STATE TAX SURCHARGE CLAUSES
Utilities' gas and electric service tariffs contain state tax surcharge
clauses. The surcharges are recomputed whenever any of the tax rates included in
their calculation are changed. These clauses protect Utilities from the effect
of increases in most of the Pennsylvania taxes to which it is subject.
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-Manufactured
Gas Plants."
EMPLOYEES
At September 30, 2003, Utilities had approximately 1,000 employees.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and
identifiable assets attributable to Utilities' operating segments for the 2003,
2002 and 2001 fiscal years appears in Note 10 "Segment Information" of Notes to
Consolidated Financial Statements included in this Report and is incorporated
herein by reference.
ITEM 3. LEGAL PROCEEDINGS
With the exception of the matters set forth below, no material legal
proceedings are pending involving Utilities, or any of its properties, and no
such proceedings are known to be
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contemplated by governmental authorities other than claims arising in the
ordinary course of the Company's business.
ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
In the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the business of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, by 1953, UGI Utilities had divested all of
its utility operations other than those which now constitute Gas Utility and
Electric Utility.
UGI Utilities does not expect its costs for investigation and
remediation of hazardous substances at Pennsylvania MGP sites to be material to
its results of operations because UGI Utilities is currently permitted to
include in rates, through future base rate proceedings, prudently incurred
remediation costs associated with such sites. UGI Utilities has been notified of
several sites outside Pennsylvania on which (1) MGPs were formerly operated by
it or owned or operated by its former subsidiaries and (2) either environmental
agencies or private parties are investigating the extent of environmental
contamination or performing environmental remediation. UGI Utilities is
currently litigating three claims against it relating to out-of-state sites.
Consolidated Edison Company of New York v. UGI Utilities, Inc. On
September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed suit
against Utilities, Inc. in the United States District Court for the Southern
District of New York, seeking contribution from Utilities for an allocated share
of response costs associated with investigating and assessing gas plant related
contamination at former MGP sites in Westchester County, New York. The complaint
alleges that Utilities "owned and operated" the MGPs prior to 1904. The
complaint also seeks a declaration that Utilities is responsible for an
allocated percentage of future investigative and remedial costs at the sites.
ConEd believes that the cost of remediation for all of the sites could exceed
$70 million. Utilities believes that it has good defenses to the claim and is
defending the suit.
In November 2003, the court granted Utilities' motion for summary
judgment in part, dismissing all claims premised on a disregard of the separate
corporate form of Utilities' former subsidiaries and dismissing claims premised
on Utilities' operation of three of the MGPs under operating leases with ConEd's
predecessors. The court reserved decision on the remaining theory of liability,
that UGI Utilities was a direct operator of the remaining MGPs.
City of Bangor, Maine v. Citizens Communications Co. In April 2003,
Citizens Communications Company ("Citizens") served a complaint naming Utilities
as a third-party defendant in a civil action pending in United States District
Court for the District of Maine. In
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that action, the plaintiff, City of Bangor, sued Citizens to recover
environmental response costs associated with MGP wastes generated at a plant
allegedly operated by Citizens' predecessors at a site on the Penobscot River.
Citizens subsequently joined Utilities and ten other third-party defendants
alleging that the third-party defendants are responsible for an equitable share
of any response costs Citizens may be required to pay to the City of Bangor.
Remedial proposals for the site range between $5 million and $50 million.
Utilities is unable to estimate what portion of this potential cost may be
associated with MGP wastes. Utilities believes that it has good defenses to the
claim.
Atlanta Gas Light Company v. UGI Utilities, Inc. By letter dated July
29, 2003, Atlanta Gas Light Company ("AGL") served Utilities with a complaint
filed in the United States District Court for the Middle District of Florida in
which AGL alleges that Utilities is responsible for 20% of approximately $8
million incurred by AGL in the investigation and remediation of a former MGP
site in St. Augustine, Florida. Utilities formerly owned stock of the St.
Augustine Gas Company, the owner and operator of the MGP. Utilities believes
that it has good defenses to the claim and is defending the suit.
RELATED MATTER
UGI Utilities, Inc. v. Insurance Co. of North America, et al. On
February 11, 1999, UGI Utilities, Inc. filed suit in the Court of Common Pleas
of Montgomery County, Pennsylvania against more than fifty insurance companies,
including Insurance Services, Ltd. (AEGIS). The complaint alleges that the
defendants breached contracts of insurance by failing to indemnify Utilities for
certain environmental costs. Utilities has now settled with all known solvent
defendants. The suit has been stayed pending resolution of the remaining claims.
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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
Cash dividends declared on the Company's Common Stock totaled $33.9
million in fiscal year 2003, $37.9 million in fiscal year 2002 and $35.3 million
in fiscal year 2001.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
In the following Management's Discussion and Analysis of Financial Condition and
Results of Operations ("MD&A"), Electric Utility and UGID's electricity
generation business prior to its distribution to UGI in June 2003 are
collectively referred to as "Electric Operations." The MD&A should be read in
conjunction with our Consolidated Financial Statements and Notes to Consolidated
Financial Statements including the business segment information in Note 10.
Fiscal 2003 Compared with Fiscal 2002
Year Ended September 30, 2003 2002 Increase
- --------------------------------------------------------------------------------------------------------------------
(Millions of dollars)
GAS UTILITY:
Revenues $ 539.9 $ 404.5 $ 135.4 33.5%
Total margin (a) $ 196.9 $ 162.9 $ 34.0 20.9%
Operating income $ 96.1 $ 77.1 $ 19.0 24.6%
Income before income taxes $ 80.7 $ 62.9 $ 17.8 28.3%
System throughput - bcf 83.8 70.5 13.3 18.9%
Degree days - % colder (warmer)
than normal 7.0% (17.4)% - -
ELECTRIC OPERATIONS:
Revenues $ 96.9 $ 86.0 $ 10.9 12.7%
Total margin (a) $ 42.2 $ 32.8 $ 9.4 28.7%
Operating income $ 21.8 $ 13.2 $ 8.6 65.2%
Income before income taxes $ 19.5 $ 10.7 $ 8.8 82.2%
Distribution sales - gwh 980.0 933.6 46.4 5.0%
bcf - billions of cubic feet. gwh - millions of kilowatt hours.
(a) Gas Utility's total margin represents total revenues less cost
of sales. Electric Operation's total margin represents total
revenues less cost of sales and revenue-related taxes, i.e.
Electric Utility gross receipts taxes of $4.8 million and $4.6
million in Fiscal 2003 and Fiscal 2002, respectively. For
financial statement purposes, revenue-related taxes are
included in "taxes other than income taxes" on the
Consolidated Statements of Income.
GAS UTILITY. Weather in Gas Utility's service territory based upon heating
degree days was 7.0% colder than normal during Fiscal 2003 compared to weather
that was 17.4% warmer than normal during Fiscal 2002. The significantly colder
weather resulted in higher heating-related sales to firm- residential,
commercial and industrial ("retail core-market") customers and, to a lesser
extent, greater volumes transported for residential, commercial and industrial
delivery service customers. System throughput in Fiscal 2003 also benefited from
a year-over-year increase in the number of customers.
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Gas Utility revenues increased principally as a result of the previously
mentioned greater retail core-market and delivery service volumes and higher
average retail core-market purchased gas cost ("PGC") rates resulting from
higher natural gas costs. Gas Utility cost of gas was $343.0 million in Fiscal
2003, an increase of $101.3 million from the prior year, reflecting the higher
retail core-market volumes sold and the higher retail core-market PGC rates.
The increase in Gas Utility total margin principally reflects a $27.1 million
increase in retail core-market total margin due to the higher retail core-market
sales and increased margin from greater delivery service volumes.
The increase in Gas Utility operating income principally reflects the increase
in total margin partially offset by a $12.7 million increase in operating and
administrative expenses and lower other income. Fiscal 2003 operating and
administrative expenses include higher costs associated with litigation-related
costs and expenses, greater distribution system maintenance expenses, higher
uncollectible accounts expenses and increased incentive compensation costs.
Other income declined $3.2 million principally reflecting a $2.2 million
decrease in pension income and lower interest income on PGC undercollections.
The increase in Gas Utility income before income taxes reflects the increase in
operating income offset by higher interest expense on PGC overcollections and,
beginning July 1, 2003, dividends on preferred shares.
ELECTRIC OPERATIONS. Electric Utility's Fiscal 2003 kilowatt-hour sales
increased principally as a result of weather that was 8.4% colder than normal
compared to weather that was 14.5% warmer than normal in the prior year.
The higher Electric Operations revenues reflect greater Electric Utility sales
and greater sales of electricity produced by UGID's electricity generation
assets to third parties prior to its distribution to UGI in June 2003. Prior to
September 2002, UGID sold substantially all of the electricity it produced to
Electric Utility with the associated revenue and margin eliminated in our
consolidated results. Beginning September 2002, Electric Utility began
purchasing its power needs exclusively from third-party electricity suppliers
under fixed-price energy and capacity contracts and, to a much lesser extent, on
the spot market, and UGID began selling electric power produced from its
interests in electricity generating facilities to third parties on the spot
market. Notwithstanding the significant increase in Electric Operations'
revenues, cost of sales increased only $1.3 million in Fiscal 2003 as the impact
on cost of sales resulting from the greater Electric Utility and electric
generation third-party sales was partially offset by lower Electric Utility
per-unit purchased power costs.
The increase in Electric Operations' total margin principally reflects lower
Electric Utility per-unit purchased power costs, the increase in Electric
Utility sales, and margin from the greater sales of electricity produced by
UGID's electricity generation assets to third parties. The higher Fiscal 2003
operating income reflects the greater total margin and higher other income
partially offset by slightly higher operating and administrative expenses. The
increase in Electric Operations income before income taxes reflects the increase
in operating income and slightly lower interest expense.
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Fiscal 2002 Compared with Fiscal 2001
Increase
Year Ended September 30, 2002 2001 (Decrease)
- --------------------------------------------------------------------------------------------------------------------
(Millions of dollars)
GAS UTILITY:
Revenues $ 404.5 $ 500.8 $ (96.3) (19.2)%
Total margin $ 162.9 $ 177.9 $ (15.0) (8.4)%
Operating income $ 77.1 $ 87.8 $ (10.7) (12.2)%
Income before income taxes $ 62.9 $ 71.6 $ (8.7) (12.2)%
System throughput - bcf 70.5 77.3 (6.8) (8.8)%
Degree days - % colder (warmer)
than normal (17.4)% 2.0% - -
ELECTRIC OPERATIONS:
Revenues $ 86.0 $ 83.9 $ 2.1 2.5%
Total margin (a) $ 32.8 $ 28.6 $ 4.2 14.7%
Operating income $ 13.2 $ 10.7 $ 2.5 23.4%
Income before income taxes $ 10.7 $ 8.0 $ 2.7 33.8%
Distribution sales - gwh 933.6 945.5 (11.9) (1.3)%
(a) Electric Operation's total margin represents total revenues
less cost of sales and Electric Utility gross receipts taxes
of $4.6 million and $3.4 million in Fiscal 2002 and Fiscal
2001, respectively.
GAS UTILITY.
Weather in Gas Utility's service territory during Fiscal 2002 based upon heating
degree days was 17.4% warmer than normal compared to weather that was 2.0%
colder than normal in Fiscal 2001. As a result of the significantly warmer
weather and the effects of a weak economy on commercial and industrial natural
gas usage, distribution system throughput declined 8.8%.
The $96.3 million decrease in Fiscal 2002 Gas Utility revenues reflects the
impact of lower PGC rates, resulting from the pass through of lower natural gas
costs to retail core-market customers, and the lower distribution system
throughput. Gas Utility cost of gas was $241.7 million in Fiscal 2002 compared
to $322.9 million in Fiscal 2001 reflecting lower natural gas costs and the
decline in retail core-market throughput in Fiscal 2002.
The decline in Gas Utility margin principally reflects a $6.0 million decline in
retail core-market margin due to the lower sales; a $6.6 million decline in
interruptible margin due principally to the flowback of certain interruptible
customer margin to retail core-market customers beginning December 1, 2001
pursuant to the Gas Restructuring Order; and lower firm delivery service total
margin due to lower delivery service volumes. Interruptible customers are those
who have the ability to switch to alternate fuels.
Gas Utility operating income declined $10.7 million in Fiscal 2002 reflecting
the previously mentioned decline in total margin and a decrease in pension
income partially offset by lower
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operating expenses. Operating expenses declined $4.1 million primarily as a
result of lower charges for uncollectible accounts and lower distribution system
expenses. Depreciation expense declined $1.2 million due to a change effective
April 1, 2002 in the estimated useful lives of Gas Utility's natural gas
distribution assets resulting from an asset life study required by the PUC. The
decline in Gas Utility income before income taxes reflects the decrease in
operating income offset by lower interest expense resulting from lower levels of
bank loans outstanding and lower short-term interest rates.
ELECTRIC OPERATIONS. The decline in kilowatt-hour sales in Fiscal 2002 reflects
the effects on heating-related sales of significantly warmer winter weather
partially offset by the beneficial effect on air conditioning sales of warmer
summer weather. Notwithstanding the decrease in total kilowatt-hour sales,
revenues increased $2.1 million principally due to an increase in state tax
surcharge revenue and greater third-party sales of electricity produced by
UGID's electric generation facilities. Electric Operations cost of sales was
$48.6 million in Fiscal 2002 compared to $51.9 million in Fiscal 2001
principally reflecting the impact of the lower sales and lower purchased power
unit costs partially offset by the full-period increase in cost of sales
resulting from the December 2000 transfer of our Hunlock Creek electricity
generation assets to our electricity generation joint venture, Energy Ventures.
Subsequent to the formation of Energy Ventures, our electricity generating
business purchases its share of the power produced by Energy Ventures rather
than producing this electricity itself. As a result, the purchased cost of this
power is reflected in cost of sales whereas prior to the formation of Energy
Ventures electricity generation costs were reflected in operating and
administrative expenses.
Electric Operations total margin increased $4.2 million in Fiscal 2002 as a
result of lower purchased power unit costs partially offset by the
weather-driven decline in sales. Operating income increased $2.5 million
reflecting the greater total margin and lower operating and administrative costs
subsequent to the formation of Energy Ventures partially offset by a decline in
other income. The increase in Electric Operations income before income taxes
reflects the increase in operating income and lower interest expense.
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
Utilities total debt outstanding was $258.0 million at September 30, 2003.
Included in this amount is $40.7 million under revolving credit agreements.
Utilities has revolving credit commitments under which it may borrow up to a
total of $107 million. These agreements are currently scheduled to expire in
June 2005 and 2006. The revolving credit agreements have restrictions on such
items as total debt, debt service and payments for investments. At September 30,
2003, Utilities was in compliance with these covenants. Utilities has a shelf
registration statement with the U.S. Securities and Exchange Commission under
which it may issue up to an additional $40 million of Medium-Term Notes or other
debt securities.
Based upon cash expected to be generated from Gas Utility and Electric Utility
operations and
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borrowings available under revolving credit agreements, management believes that
Utilities will be able to meet its anticipated contractual and projected cash
commitments during Fiscal 2004. For a more detailed discussion of Utilities'
long-term debt and credit facilities, see Note 3 to Consolidated Financial
Statements.
CASH FLOWS
OPERATING ACTIVITIES. Due to the seasonal nature of Utilities' businesses, cash
flows from operating activities are generally strongest during the second and
third fiscal quarters when customers pay for natural gas and electricity
consumed during the peak heating season months. Conversely, operating cash flows
are generally at their lowest levels during the first and fourth quarters when
the Company's investment in working capital, principally accounts receivable and
inventories, is generally greatest. Utilities uses its revolving credit
agreements to satisfy its seasonal operating cash flow needs. Cash flow from
operating activities was $97.8 million in Fiscal 2003, $55.1 million in Fiscal
2002, and $76.1 million in Fiscal 2001. Cash flow from operating activities
before changes in operating working capital was $91.8 million in Fiscal 2003,
$78.4 million in Fiscal 2002, and $72.3 million in Fiscal 2001. Changes in
operating working capital provided $6.0 million of operating cash flow in Fiscal
2003, used $23.3 million of operating cash flow in Fiscal 2002, and provided
$3.8 million of operating cash flow in Fiscal 2001. The increase in Fiscal 2003
cash flow from operating activities principally reflects the increased operating
results and greater cash flow from changes in Gas Utility deferred fuel
overcollections and accrued income taxes partially offset by higher inventories
resulting from greater natural gas prices.
INVESTING ACTIVITIES. Cash flow used in investing activities was $43.1 million
in Fiscal 2003, $36.6 million in Fiscal 2002, and $44.2 million in Fiscal 2001.
Expenditures for property, plant and equipment were $41.3 million in Fiscal
2003, $35.9 million in Fiscal 2002, and $36.8 million in Fiscal 2001. The higher
Fiscal 2003 level of capital expenditures reflects greater Gas Utility
distribution system capital expenditures. Net costs of property, plant and
equipment disposals were also higher in Fiscal 2003 principally reflecting
greater gas main replacement activity.
FINANCING ACTIVITIES. Cash flow used by financing activities was $60.5 million
in Fiscal 2003, $20.1 million in Fiscal 2002, and $39.8 million in Fiscal 2001.
Financing activity cash flow changes are primarily due to issuances and
repayments of long-term debt, net borrowings under revolving credit facilities,
dividends on preferred shares subject to mandatory redemption and dividends to,
and capital contributions from, UGI.
In October 2002, Utilities repaid $26 million of maturing long-term debt. In
August 2003, Utilities issued $25 million face amount of ten-year notes at an
interest rate of 5.37% and $20 million face amount of 30-year notes at an
interest rate of 6.50% under its Medium-Term Note program. The net proceeds from
these issuances along with existing cash balances were used to repay $50 million
of 6.50% Senior Notes maturing in August 2003.
During Fiscal 2003 we paid cash dividends to UGI of $33.9 million and dividends
on our preferred shares subject to mandatory redemption of $1.6 million of which
$0.4 million has been classified as
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interest expense in accordance with Statement of Financial Accounting Standards
("SFAS") No. 150 (see "Recently Issued Accounting Pronouncements" below).
DIVIDEND OF UGID
In June 2003, the Company dividended all of the common stock of UGID, and UGID's
subsidiaries, to UGI. The net book value of the assets and liabilities of UGID
and its subsidiaries on the date of distribution totaling $15.4 million
(including $2.6 million of cash) has been eliminated from the consolidated
balance sheet. The results of operations of UGID and its subsidiaries through
the date of distribution did not have a material effect on the Company's net
income in Fiscal 2003, 2002 or 2001.
UTILITIES PENSION PLAN
UGI Utilities sponsors a defined benefit pension plan ("Pension Plan") for
employees of UGI Utilities, UGI, and certain of UGI's other subsidiaries. During
Fiscal 2002 and 2001, the market value of plan assets was negatively affected by
declines in the equity markets. Equity market performance improved in Fiscal
2003 and, as a result, the fair value of Pension Plan assets increased to $183.8
million at September 30, 2003 compared to $166.1 million at September 30, 2002.
At September 30, 2003 and 2002, the Pension Plan's assets exceeded its
accumulated benefit obligations by $7.3 million and $7.2 million, respectively.
The Company is in full compliance with regulations governing defined benefit
pension plans, including ERISA rules and regulations, and does not anticipate it
will be required to make a contribution to the Pension Plan in Fiscal 2004.
Pre-tax pension income reflected in Fiscal 2003, 2002 and 2001 results was $1.2
million, $3.9 million and $5.7 million, respectively. The decrease in pension
income during this period reflects the significant declines in the market value
of Plan assets and decreases in the discount rate assumptions. Pension expense
in Fiscal 2004 is expected to be approximately $1.1 million, compared to pension
income of $1.2 million in Fiscal 2003 due to decreases in the discount rate and
expected return on Pension Plan assets assumptions.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business segment for
Fiscal 2003, Fiscal 2002 and Fiscal 2001. We also provide amounts we expect to
spend in Fiscal 2004. We expect to finance a substantial portion of Fiscal 2004
capital expenditures from cash generated by operations and the remainder from
borrowings under our credit facilities.
Year Ended September 30, 2004 2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------
(Millions of dollars) (estimate)
Gas Utility $ 38.0 $ 37.2 $ 31.0 $ 31.8
Electric Utility 4.9 4.1 4.9 5.0
- -----------------------------------------------------------------------------------------------------------------
$ 42.9 $ 41.3 $ 35.9 $ 36.8
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CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
Utilities has certain contractual cash obligations that extend beyond Fiscal
2003 including scheduled repayments of long-term debt and redeemable preferred
stock, operating lease obligations and unconditional purchase obligations for
pipeline capacity, pipeline transportation and natural gas storage services, and
commitments to purchase natural gas and electricity. The following table
presents significant contractual cash obligations under agreements existing as
of September 30, 2003 (in millions).
Payments Due by Period
---------------------------------------------------
Less than 2 - 3 4 - 5 After
Total 1 year years years 5 years
- -----------------------------------------------------------------------------------------------
Long-term debt $217.0 $ - $ 70.0 $ 20.0 $127.0
UGI Utilities preferred shares subject
to mandatory redemption 20.0 - 2.0 2.0 16.0
Operating leases 13.4 2.9 4.5 2.8 3.2
Gas Utility and Electric Utility supply,
storage and service contracts 406.9 157.1 136.0 39.8 74.0
- -----------------------------------------------------------------------------------------------
Total $657.3 $160.0 $212.5 $ 64.6 $220.2
- -----------------------------------------------------------------------------------------------
RELATED PARTY TRANSACTIONS
UGI provides administrative and general support to UGI Utilities. UGI bills UGI
Utilities monthly for an allocated share of its general corporate expenses. This
allocation is based upon a three-factor formula which includes revenues, costs
and expenses, and net assets. These billed expenses totaled $9.4 million in
Fiscal 2003, $6.7 million in Fiscal 2002 and $5.3 million in Fiscal 2001 and are
classified as operating and administrative expenses - related parties in the
Consolidated Statements of Income.
In accordance with the terms of an Affiliated Interest Agreement ("Affiliated
Agreement") approved by the PUC, Gas Utility enters into wholesale natural gas
transactions with Energy Services, Inc. ("Energy Services"), a wholly owned
second-tier subsidiary of UGI, for winter storage service and, from time to
time, purchases of natural gas. In addition, from time to time, the Company
sells natural gas to Energy Services pursuant to the terms of the Affiliated
Agreement. These transactions did not have a material effect on the Company's
net income during Fiscal 2003, 2002 and 2001. For additional information on
these transactions, see Note 13 to Consolidated Financial Statements included
elsewhere in this Form 10-K.
OFF-BALANCE SHEET ARRANGEMENTS
We lease various buildings and other facilities, transportation, computer and
office equipment. We account for these arrangements as operating leases. These
off-balance sheet arrangements enable us to lease facilities and equipment from
third parties rather than, among other options, purchasing the equipment and
facilities using on-balance sheet financing. For a summary of
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scheduled future payments under these lease arrangements, see "Contractual Cash
Obligations and Commitments."
REGULATORY MATTERS
As a result of Pennsylvania's Natural Gas Choice and Competition Act ("Gas
Competition Act") signed into law on June 22, 1999, all natural gas consumers in
Pennsylvania have the ability to purchase their gas supplies from the supplier
of their choice. Under the Gas Competition Act, local gas distribution companies
("LDCs") like Gas Utility may continue to sell gas to customers, and such sales
of gas, as well as distribution services provided by LDCs, continue to be
subject to rate regulation by the PUC. LDCs serve as the supplier of last resort
for all residential and small commercial and industrial customers. As of
September 30, 2003, less than five percent of Gas Utility's retail customers
purchase their gas from alternative suppliers.
On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving
Gas Utility's restructuring plan filed by Gas Utility pursuant to the Gas
Competition Act. Among other things, the implementation of the Gas Restructuring
Order resulted in an increase in Gas Utility's retail core-market base rates
effective October 1, 2000. This base rate increase was designed to generate
approximately $16.7 million in additional net annual revenues. In accordance
with the Gas Restructuring Order, Gas Utility reduced its retail core-market PGC
rates by an annualized amount of $16.7 million in the first 14 months following
the October 1, 2000 base rate increase.
Effective December 1, 2001, Gas Utility was required to reduce its retail
core-market PGC rates by amounts equal to the margin it receives from
interruptible customers using pipeline capacity contracted by Gas Utility for
retail core-market customers. As a result, Gas Utility operating results are
more sensitive to the effects of heating-season weather and less sensitive to
the market prices of alternative fuels.
The PUC approved a settlement establishing rules for Electric Utility Provider
of Last Resort ("POLR") service on March 28, 2002, and a separate settlement
that modified these rules on June 13, 2002 (collectively, the "POLR
Settlement"). Under the terms of the POLR Settlement, Electric Utility
terminated stranded cost recovery through its CTC from commercial and industrial
("C&I") customers on July 31, 2002, and from residential customers on October
31, 2002, and is no longer subject to the statutory generation rate caps as of
August 1, 2002 for C&I customers and as of November 1, 2002 for residential
customers. Stranded costs are electric generation-related costs that
traditionally would be recoverable in a regulated environment but may not be
recoverable in a competitive electric generation market. Charges for generation
service (1) were initially set at a level equal to the rates paid by Electric
Utility customers for POLR service under the statutory rate caps; (2) may be
raised by up to 5% of the total rate for distribution, transmission and
generation through December 2004; and (3) may be set at market rates thereafter.
Electric Utility may also offer multiple-year POLR contracts to its customers.
The POLR Settlement provides for annual
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shopping periods during which customers may elect to remain on POLR service or
choose an alternate supplier. Customers who do not select an alternate supplier
will be obligated to remain on POLR service until the next shopping period.
Residential customers who return to POLR service at a time other than during the
annual shopping period must remain on POLR service until the date of the second
open shopping period after returning. C&I customers who return to POLR service
at a time other than during the annual shopping period must remain on POLR
service until the next open shopping period, and may, in certain circumstances,
be subject to generation rate surcharges. Consistent with the terms of the POLR
Settlement, Electric Utility's POLR rates for commercial and industrial
customers will increase beginning January 2004, and for residential customers
beginning June 2004. Also, Electric Utility has offered and entered into
multiple-year POLR contracts with certain of its customers. Additionally,
pursuant to the requirements of the Electricity Choice Act, the PUC is currently
developing post-rate cap POLR regulations that are expected to further define
post-rate cap POLR service obligations and pricing. As of September 30, 2003,
less than 1% of Electric Utility's customers have chosen an alternative
electricity generation supplier.
We account for the operations of Gas Utility and Electric Utility in accordance
with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
("SFAS 71"). SFAS 71 allows us to defer expenses and revenues on the balance
sheet as regulatory assets and liabilities when it is probable that those
expenses and income will be allowed in the ratemaking process in a period
different from the period in which they would have been reflected in the income
statement of an unregulated company. These deferred assets and liabilities are
then flowed through the income statement in the period in which the same amounts
are included in rates and recovered from or refunded to customers. As required
by SFAS 71, we monitor our regulatory and competitive environments to determine
whether the recovery of our regulatory assets continues to be probable. If we
were to determine that recovery of these regulatory assets is no longer
probable, such assets would be written off against earnings.
MANUFACTURED GAS PLANTS
From the late 1800s through the mid-1900s, Utilities and its former subsidiaries
owned and operated a number of manufactured gas plants ("MGPs") prior to the
general availability of natural gas. Some constituents of coal tars and other
residues of the manufactured gas process are today considered hazardous
substances under the Superfund Law and may be present on the sites of former
MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas
companies in Pennsylvania and elsewhere and also operated the businesses of some
gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
Utilities does not expect its costs for investigation and remediation of
hazardous substances at Pennsylvania MGP sites to be material to its results of
operations because Gas Utility is currently permitted to include in rates,
through future base rate proceedings, prudently incurred remediation costs
associated with such sites. Utilities has been notified of several sites outside
Pennsylvania on which (1) MGPs were formerly operated by it or owned or operated
by its former subsidiaries and (2) either environmental agencies or private
parties are investigating the extent of environmental contamination or
performing environmental remediation. Utilities is currently litigating three
claims against it relating to out-of-state sites.
-20-
Management believes that under applicable law Utilities should not be liable in
those instances in which a former subsidiary owned or operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that Utilities
directly owned or operated, or that were owned or operated by former
subsidiaries of Utilities, if a court were to conclude that (1) the subsidiary's
separate corporate form should be disregarded or (2) Utilities should be
considered to have been an operator because of its conduct with respect to its
subsidiary's MGP.
With respect to a manufactured gas plant site in Manchester, New Hampshire,
EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit against UGI Utilities
seeking contribution from UGI Utilities for response and remediation costs
associated with the contamination on the site of a former MGP allegedly operated
by former subsidiaries of UGI Utilities. UGI Utilities and EnergyNorth agreed to
a settlement of this matter in June 2003. UGI Utilities recorded its estimated
liability for contingent payments to EnergyNorth under the terms of the
settlement agreement which did not have a material effect on Fiscal 2003 net
income.
In April 2003, Citizens Communications Company ("Citizens") served a complaint
naming UGI Utilities as a third-party defendant in a civil action pending in
United States District Court for the District of Maine. In that action, the
plaintiff, City of Bangor, Maine ("City") sued Citizens to recover environmental
response costs associated with MGP wastes generated at a plant allegedly
operated by Citizens' predecessors at a site on the Penobscot River. Citizens
subsequently joined UGI Utilities and ten other third-party defendants alleging
that the third-party defendants are responsible for an equitable share of costs
Citizens may be required to pay to the City for cleaning up tar deposits in the
Penobscot River. The City believes that it could cost as much as $50 million to
clean up the river. UGI Utilities believes that it has good defenses to the
claim.
By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served UGI
Utilities with a complaint filed in the United States District Court for the
Middle District of Florida in which AGL alleges that UGI Utilities is
responsible for 20% of approximately $8.0 million incurred by AGL in the
investigation and remediation of a former MGP site in St. Augustine, Florida.
UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner
and operator of the MGP. UGI Utilities believes that it has good defenses to the
claim and is defending the suit.
On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed
suit against UGI Utilities in the United States District Court for the Southern
District of New York, seeking contribution from UGI Utilities for an allocated
share of response costs associated with investigating and assessing gas plant
related contamination at former MGP sites in Westchester County, New York. The
complaint alleges that UGI Utilities "owned and operated" the MGPs prior to
1904. The complaint also seeks a declaration that UGI Utilities is responsible
for an allocated percentage of future investigative and remedial costs at the
sites. ConEd believes that the cost of remediation for all of the sites could
exceed $70 million. UGI Utilities believes that it has good defenses to the
claim and is defending the suit. In November 2003, the court granted UGI
Utilities' motion for summary judgment in part, dismissing all claims premised
on a disregard of the separate corporate form of UGI Utilities' former
subsidiaries and dismissing claims premised on UGI Utilities' operation of three
of the MGPs under operating leases with
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ConEd's predecessors. The court reserved decision on the remaining theory of
liability, that UGI Utilities was a direct operator of the remaining MGPs.
MARKET RISK DISCLOSURES
Gas Utility's tariffs contain clauses that permit recovery of substantially all
of the prudently incurred costs of natural gas it sells to its customers. The
recovery clauses provide for a periodic adjustment for the difference between
the total amounts actually collected from customers through PGC rates and the
recoverable costs incurred. Because of this ratemaking mechanism, there is
limited commodity price risk associated with our Gas Utility operations. Gas
Utility uses exchange-traded natural gas call option contracts to reduce
volatility in the cost of gas it purchases for its retail core-market customers.
The cost of these call option contracts, net of associated gains, is included in
Gas Utility's PGC recovery mechanism.
Prior to September 2002, Electric Utility purchased all of its electric power
needs, in excess of the electric power it obtained from its interests in
electric generating facilities, under third-party power supply arrangements of
various lengths and on the spot market. Beginning September 2002, Electric
Utility began purchasing its power needs exclusively from third-party
electricity suppliers under fixed-price energy and capacity contracts and, to a
much lesser extent, on the spot market and UGID, through the date of its
transfer to UGI in June 2003, began selling electric power produced from its
interests in electricity generating facilities to third parties on the spot
market. Prices for electricity can be volatile especially during periods of high
demand or tight supply. Although the generation component of Electric Utility's
rates is subject to various rate cap provisions as a result of the POLR
Settlement, Electric Utility's fixed-price contracts with electricity suppliers
mitigate most risks associated with offering customers a fixed price during the
contract periods. However, should any of the suppliers under these contracts
fail to provide electric power under the terms of the power and capacity
contracts, increases, if any, in the cost of replacement power or capacity would
negatively impact Electric Utility results. In order to reduce this
non-performance risk, Electric Utility has diversified its purchases across
several suppliers and entered into bilateral collateral arrangements with
certain of them.
We have both fixed-rate and variable-rate debt. Changes in interest rates impact
the cash flows of variable-rate debt but generally do not impact its fair value.
Conversely, changes in interest rates impact the fair value of fixed-rate debt
but do not impact their cash flows.
Our variable-rate debt includes borrowings under our revolving credit
agreements. These agreements provide for interest rates on borrowings that are
indexed to short-term market interest rates. Based upon the average level of
borrowings outstanding under these agreements in Fiscal 2003 and Fiscal 2002, an
increase in short-term interest rates of 100 basis points (1%) would have
increased annual interest expense by $0.3 million and $0.5 million,
respectively.
The remainder of our debt outstanding is subject to fixed rates of interest. A
100 basis point increase in market interest rates would result in decreases in
the fair value of this fixed-rate debt of $14.0 million and $11.0 million at
September 30, 2003 and 2002, respectively. A 100 basis point
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decrease in market interest rates would result in increases in the fair value of
this fixed-rate debt of $15.7 million and $12.0 million at September 30, 2003
and 2002, respectively.
In order to reduce interest rate risk associated with near-term issuances of
fixed-rate debt, we may enter into interest rate protection agreements. The fair
value of our unsettled interest rate protection agreement, which has been
designated and qualifies as a cash flow hedge, was $0.4 million at September 30,
2003. An adverse change in interest rates on ten-year U.S. treasury notes of 50
basis points would result in a $0.4 million decrease in the fair value of this
interest rate protection agreement.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance
with generally accepted accounting principles requires the selection and
application of appropriate accounting principles to the relevant facts and
circumstances of the Company's operations and the use of estimates made by
management. The Company has identified the following critical accounting
policies that are most important to the portrayal of the Company's financial
condition and results of operations. Changes in these policies could have a
material effect on the financial statements. The application of these accounting
policies necessarily requires management's most subjective or complex judgments
regarding estimates and projected outcomes of future events which could have a
material impact on the financial statements. Management has reviewed these
critical accounting policies, and the estimates and assumptions associated with
them, with its Audit Committee. In addition, management has reviewed the
following disclosures regarding the application of these critical accounting
policies with the Audit Committee.
LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are involved
in litigation regarding pending claims and legal actions that arise in the
normal course of our businesses. In addition, Utilities and its former
subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere
at which hazardous substances may be present. In accordance with accounting
principles generally accepted in the United States of America, we establish
reserves for pending claims and legal actions or environmental remediation
obligations when it is probable that a liability exists and the amount or range
of amounts can be reasonably estimated. Reasonable estimates involve management
judgments based on a broad range of information and prior experience. These
judgments are reviewed quarterly as more information is received and the amounts
reserved are updated as necessary. Such estimated reserves may differ materially
from the actual liability, and such reserves may change materially as more
information becomes available and estimated reserves are adjusted.
DEPRECIATION OF PROPERTY, PLANT AND EQUIPMENT. We compute depreciation on
Utilities property, plant and equipment on a straight-line basis over the
average remaining lives of its various classes of depreciable property. Changes
in the estimated useful lives of property, plant and equipment could have a
material effect on our results of operations.
REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility's
distribution businesses are subject to regulation by the Pennsylvania Public
Utility Commission. In accordance with SFAS
-23-
No. 71, "Accounting for the Effects of Certain Types of Regulation," we record
the effects of rate regulation in our financial statements as regulatory assets
or regulatory liabilities. We continually assess whether the regulatory assets
are probable of future recovery by evaluating the regulatory environment, recent
rate orders and public statements issued by the PUC, and the status of any
pending deregulation legislation. If future recovery of regulatory assets ceases
to be probable, the elimination of those regulatory assets would adversely
impact our results of operations. As of September 30, 2003, our regulatory
assets totaled $60.3 million.
DEFINED BENEFIT PENSION PLAN. The costs of providing benefits under our Pension
Plan are dependent on historical information such as employee age, length of
service, level of compensation and the actual rate of return on plan assets. In
addition, certain assumptions relating to the future are utilized including, the
discount rate applied to benefit obligations, the expected rate of return on
plan assets and the rate of compensation increase. Pension Plan assets are held
in trust and consist principally of equity and fixed income mutual funds and a
commingled bond fund. Changes in plan assumptions as well as fluctuations in
actual equity or bond market returns could have a material impact on future
pension costs.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 is
effective for contracts entered into or modified after June 30, 2003 and for
hedging relationships designated after June 30, 2003. SFAS 149 (1) clarifies
under what circumstances a contract with an initial net investment meets the
characteristic of a derivative, (2) clarifies when a derivative contains a
financing component, (3) amends the definition of an underlying- rate, price or
index to conform it to language used in FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," and (4) amends certain other existing
pronouncements. SFAS 149 did not change the methods the Company uses to account
for and report its derivatives and hedging activities.
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" ("SFAS 150").
SFAS 150 is effective at the beginning of the first interim period beginning
after June 15, 2003. SFAS 150 establishes guidelines on how an issuer classifies
and measures certain financial instruments with characteristics of both
liabilities and equity. SFAS 150 further defines and requires that certain
instruments within its scope be classified as liabilities on the financial
statements. The adoption of SFAS 150 resulted in the Company presenting its
preferred shares subject to mandatory redemption in the liabilities section of
the balance sheet, and reflecting dividends paid on these shares as a component
of interest expense, for periods presented after June 30, 2003. Because SFAS 150
specifically prohibits the restatement of financial statements prior to its
adoption, prior period amounts have not been reclassified.
In January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"), which clarifies Accounting Research
Bulletin No. 51, "Consolidated Financial Statements." FIN 46 is effective
immediately for variable interest
-24-
entities created or obtained after January 31, 2003. For variable interests
created or acquired before February 1, 2003, FIN 46 is effective for the first
fiscal or interim period beginning after December 15, 2003. If certain
conditions are met, FIN 46 requires the primary beneficiary to consolidate
certain variable interest entities in which the other equity investors lack the
essential characteristics of a controlling financial interest or their
investment at risk is not sufficient to permit the variable interest entity to
finance its activities without additional subordinated financial support from
other parties. The adoption of FIN 46 is not expected to impact the Company's
financial position or results of operations.
FORWARD-LOOKING STATEMENTS
Information contained above in this Management's Discussion and Analysis of
Financial Condition and Results of Operations and elsewhere in this Report on
Form 10-K may contain forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. Such statements use forward-looking words such as "believe," "plan,"
"anticipate," "continue," "estimate," "expect," "may," "will," or other similar
words. These statements discuss plans, strategies, events or developments that
we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases
underlying the forward-looking statement. We believe that we have chosen these
assumptions or bases in good faith and that they are reasonable. However, we
caution you that actual results almost always vary from assumed facts or bases,
and the differences between actual results and assumed facts or bases can be
material, depending on the circumstances. When considering forward-looking
statements, you should keep in mind the following important factors which could
affect our future results and could cause those results to differ materially
from those expressed in our forward-looking statements: (1) adverse weather
conditions resulting in reduced demand; (2) price volatility and availability of
oil, electricity and natural gas and the capacity to transport them to market
areas; (3) changes in laws and regulations, including safety, tax and accounting
matters; (4) competitive pressures from the same and alternative energy sources;
(5) liability for environmental claims; (6) customer conservation measures and
improvements in energy efficiency and technology resulting in reduced demand;
(7) adverse labor relations; (8) large customer, counterparty or supplier
defaults; (9) liability for personal injury and property damage arising from
explosions and other catastrophic events, including acts of terrorism, resulting
from operating hazards and risks incidental to generating and distributing
electricity and transporting, storing and distributing natural gas, including
liability in excess of insurance coverage; (10) political, regulatory and
economic conditions in the United States; and (11) interest rate fluctuations
and other capital market conditions.
These factors are not necessarily all of the important factors that could cause
actual results to differ materially from those expressed in any of our
forward-looking statements. Other unknown or unpredictable factors could also
have material adverse effects on future results. We undertake no obligation to
update publicly any forward-looking statement whether as a result of new
information or future events except as required by federal securities laws.
-25-
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
"Quantitative and Qualitative Disclosures About Market Risk" are
contained in Management's Discussion and Analysis of Financial Condition and
Results of Operations under the caption "Market Risk Disclosures" and are
incorporated here by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the financial statement schedule set forth
on pages F-1 to F-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 2002, the Company engaged a new independent auditor,
PricewaterhouseCoopers LLP. The information required by Item 9 is incorporated
in this Report by reference to the Company's Current Report on Form 8-K dated
May 21, 2002.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
The Company's management, with the participation of the Company's Chief
Executive Officer and Chief Financial Officer, evaluated the effectiveness of
the Company's disclosure controls and procedures as of the end of the period
covered by this report. Based on that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that the Company's disclosure controls and
procedures as of the end of the period covered by this report were designed and
functioning effectively to provide reasonable assurance that the information
required to be disclosed by the Company in reports filed under the Securities
Exchange Act of 1934, as amended, is recorded, processed, summarized and
reported within the time periods specified in the SEC's rules and forms. The
Company believes that a controls system, no matter how well designed and
operated, cannot provide absolute assurance that the objectives of the controls
system are met, and no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within a company have
been detected.
(b) Change in Internal Control over Financial Reporting
-26-
No change in the Company's internal control over financial reporting occurred
during the Company's most recent fiscal quarter that has materially affected, or
is reasonably likely to materially affect, the Company's internal control over
financial reporting.
-27-
PART III: INTENTIONALLY OMITTED
-28-
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(A) DOCUMENTS FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS:
Included under Item 8 are the following financial
statements and supplementary data:
Reports of Independent Public Accountants
Consolidated Balance Sheets as of September
30, 2003 and 2002
Consolidated Statements of Income for the
fiscal years ended September 30, 2003, 2002
and 2001
Consolidated Statements of Cash Flows for
the fiscal years ended September 30, 2003,
2002 and 2001
Consolidated Statements of Stockholders'
Equity for the fiscal years ended September
30, 2003, 2002 and 2001
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULE:
For the years ended September 30, 2003, 2002 and 2001
II - Valuation and Qualifying Accounts
We have omitted all other financial statement
schedules because the required information is (1) not
present; (2) not present in amounts sufficient to
require submission of the schedule; or (3) included
elsewhere in the financial statements or notes
thereto contained in this report.
NOTICE REGARDING ARTHUR ANDERSEN LLP
Arthur Andersen LLP audited our consolidated
financial statements for the three years in the
period ended September 30, 2001 and issued a report
thereon dated November 16, 2001. Arthur Andersen LLP
has not reissued its report or consented to the
incorporation by reference of such report into the
Company's prospectuses relating to offering and sale
of our debt
-29-
securities. On June 15, 2002, Arthur Andersen LLP was
convicted of obstruction of justice by a federal jury
in Houston, Texas in connection with Arthur Andersen
LLP's work for Enron Corp. On September 15, 2002, a
federal judge upheld this conviction. Arthur Andersen
LLP ceased its audit practice before the SEC on
August 31, 2002. Effective May 21, 2002, we
terminated the engagement of Arthur Andersen LLP as
our independent accountants and engaged
PricewaterhouseCoopers LLP to serve as our
independent accountants for the fiscal year ending
September 30, 2002. Because of the circumstances
currently affecting Arthur Andersen LLP, as a
practical matter it may not be able to satisfy any
claims arising from the provision of auditing
services to us, including claims available to
security holders under federal and state securities
laws.
(4) LIST OF EXHIBITS:
The exhibits filed as part of this report are as
follows (exhibits incorporated by reference are set
forth with the name of the registrant, the type of
report and registration number or last date of the
period for which it was filed, and the exhibit number
in such filing):
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ---------------------------------------------------------------------------------------------------------------
3.1 Utilities' Articles of Incorporation Utilities Registration 3
Statement
No. 333-72540
*3.2 Bylaws of UGI Utilities as amended through September
30, 2003
4 Instruments defining the rights of security holders,
including indentures. (The Company agrees to furnish
to the Commission upon request a copy of any
instrument defining the rights of holders of its
long-term debt not required to be filed pursuant to
the description of Exhibit 4 contained in Item 601 of
Regulation S-K)
4.1 Utilities' Articles of Incorporation and Bylaws
referred to in Exhibit Nos. 3.1 and 3.2
4.2 [Intentionally omitted]
4.3 Form of Fixed Rate Medium-Term Note Utilities Form 8-K (4)i
(8/26/94)
4.4 Form of Fixed Rate Series B Medium-Term Note Utilities Form 8-K 4(i)
(8/1/96)
-30-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ---------------------------------------------------------------------------------------------------------------
4.5 Form of Floating Rate Series B Medium-Term Note Utilities Form 8-K 4(ii)
(8/1/96)
4.6 Service Agreement for comprehensive delivery service UGI Form 10-K 10.40
(Rate CDS) dated February 23, 1998 between UGI (9/30/00)
Utilities, Inc. and Texas Eastern Transmission
Corporation
4.7 Officer's Certificate establishing Medium-Term Notes Utilities Form 8-K 4(iv)
series (8/26/94)
4.8 [Intentionally omitted]
4.9 Form of Officer's Certificate establishing Series B Utilities Form 8-K 4(iv)
Medium-Term Notes under the Indenture (8/1/96)
4.10 Forms of Floating Rate and Fixed Rate Series C Utilities Form 8-K 4.1
Medium-Term Notes (5/21/02)
4.11 Form of Officers' Certificate establishing Series C Utilities Form 8-K 4.2
Medium-Term Notes under the Indenture (5/21/02)
10.1 Service Agreement (Rate FSS) dated as of November 1, UGI Form 10-K 10.5
1989 between Utilities and Columbia, as modified (9/30/95)
pursuant to the orders of the Federal Energy
Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
P. 61,060 (1993), order on rehearing, 64 FERCP. 61,365
(1993)
10.2 Service Agreement (Rate FTS) dated June 1, 1987 Utilities Form 10-K (10)o.
between Utilities and Columbia, as modified by (12/31/90)
Supplement No. 1 dated October 1, 1988; Supplement No.
2 dated November 1, 1989; Supplement No. 3 dated
November 1, 1990; Supplement No. 4 dated November 1,
1990; and Supplement No. 5 dated January 1, 1991, as
further modified pursuant to the orders of the Federal
Energy Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
P. 61,060 (1993), order on rehearing, 64 FERCP. 61,365
(1993)
10.3 Transportation Service Agreement (Rate FTS-1) dated Utilities Form 10-K (10)p.
November 1, 1989 between Utilities and Columbia Gulf (12/31/90)
Transmission Company, as modified pursuant to the
orders of the Federal Energy Regulatory Commission in
Docket No. RP93-6-000 reported at Columbia Gulf
Transmission Co., 64 FERCP. 61,060 (1993), order on
rehearing, 64 FERCP. 61,365 (1993)
10.4** UGI Corporation 1992 Directors' Stock Plan Amended and UGI Form 10-Q 10.2
Restated as of April 29, 2003 (3/31/03)
-31-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ---------------------------------------------------------------------------------------------------------------
10.5** UGI Corporation Directors' Deferred Compensation Plan UGI Form 10-K 10.6
Amended and Restated as of January 1, 2000 (9/30/00)
10.6** UGI Corporation Directors' Equity Compensation Plan UGI Form 10-Q 10.3
Amended and Restated as of April 29, 2003 (3/31/03)
10.7** [Intentionally omitted]
10.8** UGI Corporation Annual Bonus Plan dated March 8, 1996 UGI Form 10-Q 10.4
(6/30/96)
10.9** UGI Utilities, Inc. Annual Bonus Plan dated March 8, Utilities Form 10-Q 10.4
1996 (6/30/96)
10.10** 1997 Stock Purchase Loan Plan UGI Form 10-K 10.16
(9/30/97)
10.11** UGI Corporation Senior Executive Employee Severance UGI Form 10-K 10.12
Pay Plan effective January 1, 1997 (9/30/97)
10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan, UGI Form 10-K 10.39
as amended (9/30/00)
10.13** UGI Corporation 2000 Directors' Stock Option Plan UGI Form 10-Q 10.1
Amended and Restated as of April 29, 2003 (3/31/03)
10.14** UGI Corporation 2000 Stock Incentive Plan Amended and UGI Form 10-Q 10.5
Restated as of April 29, 2003 (3/31/03)
10.15 Service Agreement for comprehensive delivery service UGI Form 10-K 10.41
(Rate CDS) dated February 23, 1999 between UGI (9/30/00)
Utilities, Inc. and Texas Eastern Transmission
Corporation
10.16** UGI Corporation 1997 Stock Option and Dividend UGI Form 10-Q 10.4
Equivalent Plan Amended and Restated as of April 29, (3/31/03)
2003
10.17** UGI Corporation Supplemental Executive Retirement Plan UGI Form 10-Q 10
Amended and Restated effective October 1, 1996 (6/30/98)
10.18** UGI Corporation 1992 Non-Qualified Stock Option Plan UGI Form 10-Q 10.3
Amended and Restated as of April 29, 2003 (3/31/03)
*10.19** UGI Utilities, Inc. Severance Plan for Exempt
Employees in Salary Grades 34-37 and Salary Grades
18-23 effective January 1, 1999
10.20** Description of Change of Control arrangements for Mr. UGI Form 10-K 10.33
Greenberg (9/30/99)
*10.21** Change of Control Agreement for Mr. Chaney
*10.22** Form of Change of Control Agreement for executive
officers other than Messrs. Chaney and Greenberg
10.23 [Intentionally omitted]
-32-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ----------- -------------------------------------------------- ---------- --------- -------
10.24 [Intentionally omitted]
10.25 Storage Transportation Service Agreement (Rate Utilities Form 10-K 10.25
Schedule SST) between Utilities and Columbia dated (9/30/02)
November 1, 1993, as modified pursuant to orders
of the Federal Energy Regulatory Commission
10.26 No-Notice Transportation Service Agreement (Rate Utilities Form 10-K 10.26
Schedule NTS) between Utilities and Columbia dated (9/30/02)
November 1, 1993, as modified pursuant to orders
of the Federal Energy Regulatory Commission
10.27 No-Notice Transportation Service Agreement (Rate Utilities Form 10-K 10.27
Schedule CDS) between Utilities and Texas Eastern (9/30/02)
Transmission dated February 23, 1999, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.28 No-Notice Transportation Service Agreement (Rate Utilities Form 10-K 10.28
Schedule CDS) between Utilities and Texas Eastern (9/30/02)
Transmission dated October 31, 2000, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.29 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.29
Schedule FT-1) between Utilities and Texas Eastern (9/30/02)
Transmission dated June 15, 1999, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.30 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.30
Schedule FT-1) between Utilities and Texas Eastern (9/30/02)
Transmission dated October 31, 2000, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.31 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.31
Schedule FT) between Utilities and Transcontinental (9/30/02)
Gas Pipe Line dated October 1, 1996, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
*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
*14 Code of Ethics for principal executive, financial
and accounting officers
*23 Consent of PricewaterhouseCoopers LLP
*31.1 Certification by the Chief Executive Officer
relating to the Registrant's Report on Form 10-K
for the year ended September 30, 2003 pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
-33-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ----------- -------------------------------------------------- ---------- --------- -------
*31.2 Certification by the Chief Financial Officer
relating to the Registrant's Report on Form 10-K
for the year ended September 30, 2003 pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
*32 Certification by the Chief Executive Officer and
the Chief Financial Officer relating to the
Registrant's Report on Form 10-K for the fiscal
year ended September 30, 2003
* Filed herewith.
** As required by Item 14(a)(3), this exhibit is identified as a
compensatory plan or arrangement.
(b) REPORTS ON FORM 8-K:
The Company furnished information in a Current Report on Form 8-K
during the fourth quarter of fiscal year 2003 as follows:
Date of Report Item Number(s) Content
- -------------- -------------- -------
07/30/03 7, 12 Press Release reporting financial results for the
third fiscal quarter ended June 30, 2003
-34-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UGI UTILITIES, INC.
Date: December 16, 2003 By: John C. Barney
--------------------------------
John C. Barney
Senior Vice President - Finance
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below on December 16, 2003 by the following persons
on behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
Robert J. Chaney President and Chief
- --------------------------- Executive Officer
Robert J. Chaney (Principal Executive
Officer) and Director
Lon R. Greenberg Chairman and Director
- ---------------------------
Lon R. Greenberg
John C. Barney Senior Vice President -
- --------------------------- Finance
John C. Barney (Principal Financial
Officer and Principal
Accounting Officer)
Stephen D. Ban Director
- ---------------------------
Stephen D. Ban
Thomas F. Donovan Director
- ---------------------------
Thomas F. Donovan
-35-
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below on December 16, 2003 by the following persons
on behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
Ernest E. Jones Director
- ---------------------------
Ernest E. Jones
Richard C. Gozon Director
- ---------------------------
Richard C. Gozon
Anne Pol Director
- ---------------------------
Anne Pol
Marvin O. Schlanger Director
- ---------------------------
Marvin O. Schlanger
James W. Stratton Director
- ---------------------------
James W. Stratton
-36-
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT:
No annual report or proxy material was sent to security holders in fiscal year
2003.
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2003
F-1
UGI UTILITIES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULE
Pages
------------
Financial Statements:
Reports of Independent Auditors F-3 to F-4
Consolidated Balance Sheets as of September 30,
2003 and 2002 F-5 to F-6
Consolidated Statements of Income for the years
ended September 30, 2003, 2002 and 2001 F-7
Consolidated Statements of Cash Flows for the years
ended September 30, 2003, 2002 and 2001 F-8
Consolidated Statements of Stockholder's Equity
for the years ended September 30, 2003, 2002 and 2001 F-9
Notes to Consolidated Financial Statements F-10 to F-28
Financial Statement Schedule:
For the years ended September 30, 2003, 2002 and 2001:
II - Valuation and Qualifying Accounts S-1
We have omitted all other financial statement schedules because the required
information is either (1) not present; (2) not present in amounts sufficient to
require submission of the schedule; or (3) included elsewhere in the financial
statements or related notes.
F-2
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholder of
UGI Utilities, Inc.:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 15a (1) and (2) present fairly, in all material respects,
the financial position of UGI Utilities, Inc. and its subsidiaries at September
30, 2003 and 2002, and the results of their operations and their cash flows for
each of the two years in the period ended September 30, 2003 in conformity with
accounting principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedule listed in the index
appearing under Item 15a (1) and (2) present fairly, in all material respects,
the information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and financial
statement schedule are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The consolidated financial
statements of UGI Utilities, Inc. and its subsidiaries as of and for the year
ended September 30, 2001 were audited by other independent accountants who have
ceased operations. Those independent accountants expressed an unqualified
opinion on those financial statements in their report dated November 16, 2001.
PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
November 17, 2003
F-3
THIS REPORT IS A COPY OF THE PREVIOUSLY ISSUED ACCOUNTANT'S
REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY
ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholder of
UGI Utilities, Inc.:
We have audited the accompanying consolidated balance sheets of UGI Utilities,
Inc. and subsidiaries as of September 30, 2001 and 2000, and the related
consolidated statements of income, cash flows and stockholder's equity for each
of the three years in the period ended September 30, 2001. These financial
statements and the schedule referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of UGI
Utilities, Inc. and subsidiaries as of September 30, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended September 30, 2001 in conformity with accounting principles
generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in the Index to
Financial Statements and Financial Statement Schedule is presented for purposes
of complying with the Securities and Exchange Commission's rules and is not part
of the basic financial statements. This schedule has been subjected to the
auditing procedures applied in the audit of the basic financial statements and,
in our opinion, fairly states in all material respects, the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
ARTHUR ANDERSEN LLP
Philadelphia, Pennsylvania
November 16, 2001
F-4
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
September 30,
2003 2002
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents $ 304 $ 6,090
Accounts receivable (less allowances for doubtful
accounts of $3,275 and $1,972, respectively) 30,101 38,554
Accrued utility revenues 7,431 8,069
Inventories 54,017 38,654
Deferred income taxes 10,375 2,610
Income taxes recoverable - 6,892
Deferred fuel costs - 4,304
Prepaid expenses and other current assets 5,552 3,151
--------- ---------
Total current assets 107,780 108,324
Property, plant and equipment
Gas utility 791,164 760,161
Electric operations 103,917 111,265
General 12,777 11,909
--------- ---------
907,858 883,335
Less accumulated depreciation and amortization (296,871) (290,194)
--------- ---------
Net property, plant and equipment 610,987 593,141
Regulatory assets 60,253 57,685
Other assets 30,028 38,973
--------- ---------
Total assets $ 809,048 $ 798,123
========= =========
See accompanying notes to consolidated financial statements.
F-5
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
September 30,
2003 2002
--------- ---------
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt $ - $ 76,000
Bank loans 40,700 37,200
Accounts payable 55,298 57,499
Employee compensation and benefits accrued 8,457 8,984
Dividends and interest accrued 6,466 5,443
Income taxes accrued 479 -
Customer deposits and refunds 15,074 14,515
Deferred fuel costs 14,734 -
Other current liabilities 11,703 16,576
--------- ---------
Total current liabilities 152,911 216,217
Long-term debt 217,271 172,369
Deferred income taxes 144,176 131,483
Deferred investment tax credits 7,987 8,385
Other noncurrent liabilities 11,951 11,815
Preferred shares subject to mandatory redemption, without par value 20,000 -
Commitments and contingencies (note 8)
--------- ---------
Total liabilities 554,296 540,269
Preferred shares subject to mandatory redemption, without par value - 20,000
Common stockholder's equity:
Common Stock, $2.25 par value (authorized - 40,000,000 shares;
issued and outstanding - 26,781,785 shares) 60,259 60,259
Additional paid-in capital 79,046 73,057
Retained earnings 117,496 107,312
Accumulated other comprehensive loss (2,049) (2,774)
--------- ---------
Total common stockholder's equity 254,752 237,854
--------- ---------
Total liabilities and stockholder's equity $ 809,048 $ 798,123
========= =========
See accompanying notes to consolidated financial statements.
F-6
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
Year Ended
September 30,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Revenues $ 636,758 $ 490,552 $ 584,762
--------- --------- ---------
Costs and expenses:
Gas, fuel and purchased power 392,901 290,282 374,781
Operating and administrative expenses 91,947 80,910 88,310
Operating and administrative expenses - related parties 9,352 6,664 5,277
Taxes other than income taxes 12,195 11,930 9,182
Depreciation and amortization 21,240 22,172 23,767
Other income, net (8,745) (11,723) (15,111)
--------- --------- ---------
518,890 400,235 486,206
--------- --------- ---------
Operating income 117,868 90,317 98,556
Interest expense 17,656 16,652 18,988
--------- --------- ---------
Income before income taxes 100,212 73,665 79,568
Income taxes 39,540 29,570 31,431
--------- --------- ---------
Net income 60,672 44,095 48,137
Dividends on preferred shares subject to mandatory redemption 1,163 1,550 1,550
--------- --------- ---------
Net income after dividends on preferred shares subject to
mandatory redemption $ 59,509 $ 42,545 $ 46,587
========= ========= =========
See accompanying notes to consolidated financial statements.
F-7
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
Year Ended
September 30,
--------------------------------
2003 2002 2001
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 60,672 $ 44,095 $ 48,137
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 21,240 22,172 23,767
Deferred income taxes, net 2,097 11,114 (2,016)
Provision for uncollectible accounts 7,778 5,270 8,269
Pension income (1,242) (3,857) (5,671)
Other 1,284 (391) (177)
Net change in:
Accounts receivable and accrued utility revenues (610) (1,631) (14,704)
Inventories (15,601) 9,420 (14,508)
Deferred fuel costs 19,038 (7,056) 9,948
Accounts payable (454) (9,957) 13,318
Other current assets and liabilities 3,599 (14,123) 9,769
-------- -------- --------
Net cash provided by operating activities 97,801 55,056 76,132
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (41,297) (35,884) (36,783)
Net costs of property, plant and equipment disposals (1,831) (704) (1,407)
Cash contribution to partnership - - (6,000)
-------- -------- --------
Net cash used by investing activities (43,128) (36,588) (44,190)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (35,081) (39,489) (36,809)
Cash portion of UGID dividend (2,572) - -
Issuance of long-term debt 44,694 40,000 50,603
Repayment of long-term debt (76,000) - (15,000)
Bank loans increase (decrease) 3,500 (20,600) (42,600)
Capital contribution from UGI Corporation 5,000 - 4,000
-------- -------- --------
Net cash used by financing activities (60,459) (20,089) (39,806)
-------- -------- --------
Cash and cash equivalents decrease $ (5,786) $ (1,621) $ (7,864)
======== ======== ========
CASH AND CASH EQUIVALENTS:
End of year $ 304 $ 6,090 $ 7,711
Beginning of year 6,090 7,711 15,575
-------- -------- --------
Decrease $ (5,786) $ (1,621) $ (7,864)
======== ======== ========
See accompanying notes to consolidated financial statements.
F-8
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of dollars)
Accumulated Total
Additional Other Common
Common Paid-in Retained Comprehensive Stockholder's
Stock Capital Earnings Loss Equity
----- ------- -------- ---- ------
Balance September 30, 2000 $60,259 $68,559 $ 95,655 $ - $ 224,473
Net income 48,137 48,137
Capital contribution by UGI Corporation 4,000 4,000
Cash dividends - common stock (35,259) (35,259)
Cash dividends - preferred stock (1,550) (1,550)
Dividends of net assets (4,277) (4,277)
Other 233 233
------- ------- -------- -------- ---------
Balance September 30, 2001 60,259 72,792 102,706 - 235,757
Net income 44,095 44,095
Net change in fair value of interest rate
protection agreements (net of tax of $1,968) (2,774) (2,774)
-------- -------- ---------
Comprehensive income 44,095 (2,774) 41,321
Cash dividends - common stock (37,939) (37,939)
Cash dividends - preferred stock (1,550) (1,550)
Other 265 265
------- ------- -------- -------- ---------
Balance September 30, 2002 60,259 73,057 107,312 (2,774) 237,854
Net income 60,672 60,672
Net change in fair value of interest rate
protection agreements (net of tax of $365) 515 515
Reclassifications of net loss on interest rate
protection agreements (net of tax of $149) 210 210
-------- -------- ---------
Comprehensive income 60,672 725 61,397
Capital contribution by UGI Corporation 5,000 5,000
Cash dividends - common stock (33,918) (33,918)
Cash dividends - preferred stock (1,163) (1,163)
Dividend of UGID common stock (15,407) (15,407)
Other 989 989
------- ------- -------- -------- ---------
Balance September 30, 2003 $60,259 $79,046 $117,496 $ (2,049) $ 254,752
======= ======= ======== ======== =========
See accompanying notes to consolidated financial statements.
F-9
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION PRINCIPLES
UGI Utilities, Inc. ("UGI Utilities"), a wholly owned subsidiary of UGI
Corporation ("UGI"), owns and operates a natural gas distribution utility ("Gas
Utility") in parts of eastern and southeastern Pennsylvania; owns and operates
an electricity distribution utility ("Electric Utility") in northeastern
Pennsylvania; and prior to the June 2003 distribution to UGI of UGI Development
Company ("UGID") and UGID's subsidiaries and 50%-owned joint-venture affiliate
Hunlock Creek Energy Ventures ("Energy Ventures"), owned interests in
Pennsylvania-based electricity generation assets through UGID. We refer to Gas
Utility, Electric Utility and UGID (prior to its distribution to UGI)
collectively as "the Company" or "we," and Electric Utility and UGID
collectively as "Electric Operations." Our consolidated financial statements
include the accounts of UGI Utilities and its majority-owned subsidiaries. We
eliminate all significant intercompany accounts and transactions when we
consolidate. Our investment in Energy Ventures was accounted for under the
equity method. Gas Utility and Electric Utility (collectively, "Utilities") are
subject to regulation by the Pennsylvania Public Utility Commission ("PUC").
UGID was granted "Exempt Wholesale Generator" status by the Federal Energy
Regulatory Commission.
In June 2003, the Company dividended all of the common stock of UGID and its
subsidiaries to UGI. The net book value of the assets and liabilities of UGID
and its subsidiaries totaling $15,407 (including $2,572 of cash) was eliminated
from the consolidated balance sheet and reflected as a dividend from retained
earnings. UGID and its subsidiaries' results of operations did not have a
material effect on the Company's results of operations in 2003, 2002 and 2001.
RECLASSIFICATIONS
We have reclassified certain prior-year balances to conform to the current-year
presentation.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in
conformity with accounting principles generally accepted in the United States.
These estimates and assumptions affect the reported amounts of assets and
liabilities, revenues and expenses, as well as the disclosure of contingent
assets and liabilities. Actual results could differ from these estimates.
REGULATED UTILITY OPERATIONS
We account for the operations of Gas Utility and Electric Utility in accordance
with Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting
for the Effects of Certain Types of Regulation" ("SFAS 71"). SFAS 71 requires us
to record the effects of rate regulation in the financial statements. Certain
expenses and credits subject to utility regulation and normally reflected in
income as incurred are deferred on the balance sheet and recognized in income as
the related amounts are included in rates and recovered from or refunded to
customers. As required
F-10
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
by SFAS 71, we monitor our regulatory and competitive environments to determine
whether the recovery of our regulatory assets continues to be probable. If we
were to determine that recovery of these regulatory assets is no longer
probable, such assets would be written off against earnings.
On June 29, 2000, the PUC issued its order ("Gas Restructuring Order") approving
Gas Utility's restructuring plan filed by Gas Utility pursuant to Pennsylvania's
Natural Gas Choice and Competition Act ("Gas Competition Act"). Based upon the
provisions of the Gas Restructuring Order and the Gas Competition Act, we
believe Gas Utility's regulatory assets continue to satisfy the criteria of SFAS
71. For further information on the impact of the Gas Competition Act and
Pennsylvania's Electricity Customer Choice Act ("Electricity Choice Act"), see
Note 2.
CONSOLIDATED STATEMENTS OF CASH FLOWS
We define cash equivalents as all highly liquid investments with maturities of
three months or less when purchased. We record cash equivalents at cost plus
accrued interest, which approximates market value.
We paid interest totaling $16,046 in 2003, $16,348 in 2002 and $17,543 in 2001.
We paid income taxes totaling $29,372 in 2003, $36,282 in 2002 and $29,000 in
2001.
REVENUE RECOGNITION
Gas Utility and Electric Utility record regulated revenues for service provided
to the end of each month which includes an accrual for certain unbilled amounts
based upon estimated usage. We reflect the impact of Gas Utility and Electric
Utility rate increases or decreases at the time they become effective.
Nonregulated revenues are recognized as services are performed or products are
delivered.
INVENTORIES
Our inventories are stated at the lower of cost or market. We determine cost
principally on an average cost method except for appliances for which we use the
specific identification method.
INCOME TAXES
Gas Utility and Electric Utility record deferred income taxes in the
Consolidated Statements of Income resulting from the use of accelerated
depreciation methods based upon amounts recognized for ratemaking purposes. They
also record a deferred tax liability for tax benefits that are flowed through to
ratepayers when temporary differences originate and record a regulatory income
tax asset for the probable increase in future revenues that will result when the
temporary differences reverse.
We are amortizing deferred investment tax credits related to Utilities' plant
additions over the service lives of the related property. Utilities reduces its
deferred income tax liability for the future tax benefits that will occur when
the deferred investment tax credits, which are not taxable, are
F-11
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
amortized. We also reduce the regulatory income tax asset for the probable
reduction in future revenues that will result when such deferred investment tax
credits amortize.
We join with UGI and its subsidiaries in filing a consolidated federal income
tax return. We are charged or credited for our share of current taxes resulting
from the effects of our transactions in the UGI consolidated federal income tax
return including giving effect to intercompany transactions. The result of this
allocation is generally consistent with income taxes calculated on a separate
return basis.
PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION
We record property, plant and equipment at cost. When Gas Utility and Electric
Utility retire depreciable utility plant and equipment, we charge the original
cost, net of removal costs and salvage value, to accumulated depreciation for
financial accounting purposes.
We record depreciation expense for Utilities' plant and equipment on a
straight-line method over the estimated average remaining lives of the various
classes of its depreciable property. Depreciation expense as a percentage of the
related average depreciable base for Gas Utility was 2.3% in 2003, 2.5% in 2002
and 2.6% in 2001. Depreciation expense as a percentage of the related average
depreciable base for Electric Utility was 3.0% in each of 2003 and 2002 and 3.3%
in 2001. The declines in the Gas Utility and Electric Utility percentages for
2003 and 2002 are the result of changes, effective April 1, 2002, in the
estimated remaining useful lives of Gas Utility's and Electric Utility's
distribution assets. Depreciation expense was $20,754 in 2003, $21,649 in 2002
and $22,701 in 2001.
We evaluate the impairment of long-lived assets whenever events or changes in
circumstances indicate that the carrying amount of such assets may not be
recoverable. We evaluate recoverability based upon undiscounted future cash
flows expected to be generated by such assets.
COMPUTER SOFTWARE COSTS
We include in property, plant and equipment costs associated with computer
software we develop or obtain for use in our businesses. We amortize computer
software costs on a straight-line basis over expected periods of benefit not
exceeding ten years once the installed software is ready for its intended use.
DEFERRED FUEL COSTS
Gas Utility's tariffs contain clauses which permit recovery of certain purchased
gas costs through the application of purchased gas cost ("PGC") rates. The
clauses provide for periodic adjustments to PGC rates for the difference between
the total amount of purchased gas costs collected from customers and the
recoverable costs incurred. In accordance with SFAS 71, we defer the difference
between amounts recognized in revenues and the applicable gas costs incurred
until they are subsequently billed or refunded to customers.
F-12
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION
Beginning July 1, 2003, the Company accounts for its preferred shares subject to
mandatory redemption in accordance with SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity"
("SFAS 150"). SFAS 150 establishes guidelines on how an issuer classifies and
measures certain financial instruments with characteristics of both liabilities
and equity. The adoption of SFAS 150 results in the Company presenting its
preferred shares subject to mandatory redemption in the liabilities section of
the balance sheet, and reflecting dividends paid on these shares as a component
of interest expense, for periods presented after June 30, 2003. Because SFAS 150
specifically prohibits the restatement of financial statements prior to its
adoption, prior period amounts have not been reclassified.
ENVIRONMENTAL LIABILITIES
We accrue environmental investigation and cleanup costs when it is probable that
a liability exists and the amount or range of amounts can be reasonably
estimated. Our estimated liability for environmental contamination is reduced to
reflect anticipated participation of other responsible parties but is not
reduced for possible recovery from insurance carriers. In those instances for
which the amount and timing of cash payments associated with environmental
investigation and cleanup are reliably determinable, we discount such
liabilities to reflect the time value of money. We intend to pursue recovery of
any incurred costs through all appropriate means, including regulatory relief.
Gas Utility is permitted to amortize as removal costs site-specific
environmental investigation and remediation costs, net of related third-party
payments, associated with Pennsylvania sites. Gas Utility is currently permitted
to include in rates, through future base rate proceedings, a five-year average
of such prudently incurred removal costs. At September 30, 2003, the Company's
liability for environmental investigation and cleanup costs was not material.
DERIVATIVE INSTRUMENTS
Effective October 1, 2000, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). SFAS 133, as amended,
establishes accounting and reporting standards for derivative instruments and
for hedging activities. It requires that all derivative instruments be
recognized as either assets or liabilities and measured at fair value. The
accounting for changes in fair value depends upon the purpose of the derivative
instrument and whether it is designated and qualifies for hedge accounting.
During 2003 and 2002, in order to manage interest rate risk associated with
forecasted issuances of fixed-rate long-term debt, we entered into interest rate
protection agreements ("IRPAs") which have been designated and qualify as cash
flow hedges in accordance with SFAS 133. Included in accumulated other
comprehensive loss at September 30, 2003 and 2002 are net after-tax losses of
$2,049 and $2,774, respectively, associated with settled and unsettled IRPAs.
The amount of the net loss at September 30, 2003 expected to be reclassified
into net income during the next twelve months is not material. The fair values
of our unsettled IRPAs were a gain of $369 at September 30, 2003 and a loss of
$1,205 at September 30, 2002. These amounts are included in other assets and
other current liabilities, respectively, on the Consolidated Balance Sheets. The
unsettled IRPA at September 30, 2003 hedges interest rate risk associated with
forecasted issuances of debt to occur during Fiscal 2005.
F-13
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
During 2003 and 2002, Gas Utility entered into natural gas call option contracts
to reduce volatility in the cost of gas it purchases for its firm- residential,
commercial and industrial ("retail core-market") customers. Because net gains or
losses associated with these contracts will be included in our PGC recovery
mechanism, as these contracts are recorded at fair value in accordance with SFAS
133, any gains or losses are deferred for future recovery from or refund to Gas
Utility's ratepayers.
During 2001, we used a managed program of natural gas and oil futures contracts
to preserve gross margin associated with certain of our natural gas customers.
These contracts were designated as cash flow hedges. During 2001, the amount of
cash flow hedge gains associated with these contracts that were reclassified to
earnings because it became probable that the original forecasted transactions
would not occur was $1,034 which amount is included in other income.
During 2003, 2002 and 2001, there were no gains or losses recognized in earnings
as a result of hedge ineffectiveness or from excluding a portion of a derivative
instrument's gain or loss from the assessment of hedge effectiveness, and there
were no gains or losses recognized in earnings as a result of a hedged firm
commitment no longer qualifying as a fair value hedge.
We are a party to a number of contracts that have elements of a derivative
instrument. These contracts include, among others, binding purchase orders,
contracts which provide for the purchase and delivery of natural gas and
electricity, and service contracts that require the counterparty to provide
commodity storage, transportation or capacity service to meet our normal sales
commitments. Although many of these contracts have the requisite elements of a
derivative instrument, these contracts are not subject to the accounting
requirements of SFAS 133, as amended, because they provide for the delivery of
products or services in quantities that are expected to be used in the normal
course of operating our business or the value of the contract is directly
associated with the price or value of a service.
COMPREHENSIVE INCOME
Comprehensive income comprises net income and other comprehensive income (loss).
Other comprehensive income (loss) of $725 and $(2,774) for the years ended
September 30, 2003 and 2002, respectively, is the result of gains or losses on
IRPAs qualifying as cash flow hedges, net of reclassifications to net income.
The Company's comprehensive income was the same as net income for the year ended
September 30, 2001.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No.
149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities" ("SFAS 149"). SFAS 149 is effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June
30, 2003. SFAS 149 (i) clarifies under what circumstances a contract with an
initial net investment meets the characteristic of a derivative, (ii) clarifies
when a derivative contains a financing component, (iii) amends the definition of
an underlying- rate, price or index to conform it to language used in FASB
Interpretation No. 45,
F-14
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others," and (iv) amends certain other
existing pronouncements. SFAS 149 did not change the methods the Company uses to
account for and report its derivatives and hedging activities.
In January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation
of Variable Interest Entities" ("FIN 46"), which clarifies Accounting Research
Bulletin No. 51, "Consolidated Financial Statements." FIN 46 is effective
immediately for variable interest entities created or obtained after January 31,
2003. For variable interests created or acquired before February 1, 2003, FIN 46
is effective for the first fiscal or interim period beginning after December 15,
2003. If certain conditions are met, FIN 46 requires the primary beneficiary to
consolidate certain variable interest entities in which the other equity
investors lack the essential characteristics of a controlling financial interest
or their investment at risk is not sufficient to permit the variable interest
entity to finance its activities without additional subordinated financial
support from other parties. The adoption of FIN 46 is not expected to impact the
Company's financial position or results of operations.
2. UTILITY REGULATORY MATTERS
Gas Utility
Gas Restructuring Order. On June 29, 2000, the PUC issued the Gas Restructuring
Order approving Gas Utility's restructuring plan filed by Gas Utility pursuant
to the Gas Competition Act. The purpose of the Gas Competition Act, which was
signed into law on June 22, 1999, is to provide all natural gas consumers in
Pennsylvania with the ability to purchase their gas supplies from the supplier
of their choice. Under the Gas Competition Act, local gas distribution companies
("LDCs") like Gas Utility may continue to sell gas to customers, and such sales
of gas, as well as distribution services provided by LDCs, continue to be
subject to price regulation by the PUC. LDCs serve as the supplier of last
resort for all residential and small commercial and industrial customers.
Among other things, the implementation of the Gas Restructuring Order resulted
in an increase in Gas Utility's retail core-market base rates effective October
1, 2000. This base rate increase was designed to generate approximately $16,700
in additional net annual revenues. In accordance with the Gas Restructuring
Order, Gas Utility reduced its retail core-market PGC rates by an annualized
amount of $16,700 in the first 14 months following the October 1, 2000 base rate
increase.
Effective December 1, 2001, Gas Utility was required to reduce its retail
core-market PGC rates by amounts equal to the margin it receives from
interruptible customers using pipeline capacity contracted by Gas Utility for
retail core-market customers. As a result, Gas Utility operating results are
more sensitive to the effects of heating-season weather and less sensitive to
the market prices of alternative fuels.
Transfer of Assets. On May 24, 2001, the PUC approved Gas Utility's application
for approval to transfer its liquefied natural gas ("LNG") and propane air
("LP") facilities, along with related assets, to an unregulated affiliate,
Energy Services, Inc. ("Energy Services"), a second-tier wholly
F-15
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
owned subsidiary of UGI. Gas Utility transferred the LNG and LP assets, which
had a net book value of $4,277, on September 30, 2001. The transfer is reflected
as a dividend of net assets in the 2001 Consolidated Statement of Stockholder's
Equity. The associated reduction in Gas Utility's base rates, adjusted for the
impact of the transfer on net operating expenses, did not have a material effect
on our results of operations.
Electric Utility
Electric Utility Restructuring Order. On June 19, 1998, the PUC entered its
Opinion and Order ("Electricity Restructuring Order") in Electric Utility's
restructuring proceeding pursuant to the Electricity Choice Act. Under the terms
of the Electricity Restructuring Order, Electric Utility was authorized to
recover $32,500 in stranded costs over a four-year period beginning January 1,
1999 through a Competitive Transition Charge ("CTC") together with carrying
charges on unrecovered balances of 7.94% and to charge unbundled rates for
generation, transmission and distribution services. Stranded costs are electric
generation-related costs that traditionally would be recoverable in a regulated
environment but may not be recoverable in a competitive electric generation
market. Under the terms of the Electricity Restructuring Order and in accordance
with the Electricity Choice Act, Electric Utility generally could not increase
the generation component of prices during the period that stranded costs were
being recovered through the CTC. Since January 1, 1999, all of Electric
Utility's customers have been permitted to choose an alternative generation
supplier.
The PUC approved a settlement establishing rules for Electric Utility Provider
of Last Resort ("POLR") service on March 28, 2002, and a separate settlement
that modified these rules on June 13, 2002 (collectively, the "POLR Settlement")
under which Electric Utility terminated stranded cost recovery through its CTC
from commercial and industrial ("C&I") customers on July 31, 2002, and from
residential customers on October 31, 2002, and is no longer subject to the
statutory generation rate caps as of August 1, 2002 for C&I customers and as of
November 1, 2002 for residential customers. Charges for generation service (1)
were initially set at a level equal to the rates paid by Electric Utility
customers for POLR service under the statutory rate caps; (2) may be raised at
certain designated times by up to 5% of the total rate for distribution,
transmission and generation through December 2004; and (3) may be set at market
rates thereafter. Electric Utility may also offer multiple-year POLR contracts
to its customers. The POLR Settlement provides for annual shopping periods
during which customers may elect to remain on POLR service or choose an
alternate supplier. Customers who do not select an alternate supplier will be
obligated to remain on POLR service until the next shopping period. Residential
customers who return to POLR service at a time other than during the annual
shopping period must remain on POLR service until the date of the second open
shopping period after returning. C&I customers who return to POLR service at a
time other than during the annual shopping period must remain on POLR service
until the next open shopping period, and may, in certain circumstances, be
subject to generation rate surcharges. Consistent with the terms of the POLR
Settlement, Electric Utility's POLR rates for commercial and industrial
customers will increase beginning January 2004, and for residential customers
beginning June 2004. Also, Electric Utility has offered and entered into
multiple-year POLR contracts with certain of its customers. Additionally,
pursuant to the requirements of the Electricity Choice Act, the PUC is currently
developing post-rate cap POLR regulations that are expected to further define
post-rate cap POLR service obligations and pricing. As of September 30, 2003,
less than
F-16
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1% of Electric Utility's customers have chosen an alternative electricity
generation supplier.
Formation of Hunlock Creek Energy Ventures. On December 8, 2000, UGID
contributed its coal-fired Hunlock Creek generating station ("Hunlock") and
certain related assets having a net book value of $4,214, and $6,000 in cash, to
Energy Ventures, a general partnership jointly owned by a subsidiary of UGID and
a subsidiary of Allegheny Energy, Inc. ("Allegheny"). The contribution was
recorded at its carrying value and no gain was recognized by the Company. Also
on December 8, 2000, Allegheny contributed a newly constructed, gas-fired
combustion turbine generator to Energy Ventures to be operated at the Hunlock
site. Under the terms of our arrangement with Allegheny, each partner is
entitled to purchase 50% of the output of the joint venture at cost. Total
purchases from Energy Ventures in 2003 (prior to its June 2003 distribution to
UGI), 2002 and 2001 were $6,360, $9,751 and $7,966, respectively.
Regulatory Assets and Liabilities
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
2003 2002
- --------------------------------------------------------
Regulatory assets:
Income taxes recoverable $57,625 $54,727
Other postretirement benefits 2,162 2,397
Deferred fuel costs - 4,304
Other 466 561
- --------------------------------------------------------
Total regulatory assets $60,253 $61,989
- --------------------------------------------------------
Regulatory liabilities:
Other postretirement benefits $ 3,746 $ 4,332
Deferred fuel costs 14,734 -
- --------------------------------------------------------
Total regulatory liabilities $18,480 $ 4,332
- --------------------------------------------------------
The Company's regulatory liabilities relating to other postretirement benefits
are included in "other noncurrent liabilities" on the Consolidated Balance
Sheets. The Company does not recover a rate of return on its regulatory assets.
F-17
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. DEBT
Long-term debt comprises the following at September 30:
2003 2002
- -------------------------------------------------------------------------------------------------
Medium-Term Notes:
7.25% Notes, due November 2017 $ 20,000 $ 20,000
7.17% Notes, due June 2007 20,000 20,000
7.37% Notes, due October 2015 22,000 22,000
6.73% Notes, due October 2002 - 26,000
6.62% Notes, due May 2005 20,000 20,000
7.14% Notes, due December 2005 (including unamortized
premium of $271 and $392, respectively, effective rate - 6.64%) 30,271 30,392
7.14% Notes, due December 2005 20,000 20,000
5.53% Notes due September 2012 40,000 40,000
5.37% Notes due August 2013 25,000 -
6.50% Notes due August 2033 20,000 -
6.50% Senior Notes, due August 2003 (less unamortized
discount of $23) - 49,977
- -------------------------------------------------------------------------------------------------
Total long-term debt 217,271 248,369
Less current maturities - (76,000)
- -------------------------------------------------------------------------------------------------
Long-term debt due after one year $ 217,271 $ 172,369
- -------------------------------------------------------------------------------------------------
Scheduled principal repayments of long-term debt for each of the next five
fiscal years ending September 30 are as follows: 2004 - $0; 2005 - $20,000; 2006
- - $50,000; 2007 - $20,000; 2008 - $0.
At September 30, 2003, UGI Utilities had revolving credit agreements with five
banks providing for borrowings of up to $107,000. These agreements are currently
scheduled to expire in June 2005 and 2006. UGI Utilities may borrow at various
prevailing interest rates, including LIBOR and the banks' prime rate. UGI
Utilities pays quarterly commitment fees on these credit lines. UGI Utilities
had revolving credit agreement borrowings totaling $40,700 at September 30, 2003
and $37,200 at September 30, 2002 which we classify as bank loans. The
weighted-average interest rates on bank loans were 1.63% at September 30, 2003
and 2.35% at September 30, 2002.
UGI Utilities' credit agreements have restrictions on such items as total debt,
debt service, and payments for investments. They also require consolidated
tangible net worth of at least $125,000. At September 30, 2003, UGI Utilities
was in compliance with these financial covenants.
F-18
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES
The provisions for income taxes consist of the following:
2003 2002 2001
- -------------------------------------------------------------------
Current expense:
Federal $ 27,027 $ 13,341 $ 25,344
State 10,416 5,115 8,103
- -------------------------------------------------------------------
Total current expense 37,443 18,456 33,447
Deferred expense (benefit) 2,495 11,512 (1,618)
Investment tax credit amortization (398) (398) (398)
- -------------------------------------------------------------------
Total income tax expense $ 39,540 $ 29,570 $ 31,431
- -------------------------------------------------------------------
A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:
2003 2002 2001
- -----------------------------------------------------------------------
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal benefit 5.6 6.3 6.5
Deferred investment tax credit amortization (0.4) (0.5) (0.5)
Other, net (0.7) (0.7) (1.5)
- -----------------------------------------------------------------------
Effective tax rate 39.5% 40.1% 39.5%
- -----------------------------------------------------------------------
Deferred tax liabilities (assets) comprise the following at September 30:
2003 2002
- --------------------------------------------------------------------------------
Excess book basis over tax basis of property, plant and
equipment $ 117,891 $ 107,627
Regulatory assets 25,001 25,721
Pension plan asset 11,019 10,546
Other 2,170 164
- --------------------------------------------------------------------------------
Gross deferred tax liabilities 156,081 144,058
- --------------------------------------------------------------------------------
Deferred investment tax credits (3,314) (3,479)
Employee-related expenses (7,072) (6,371)
Regulatory liabilities (7,667) (1,797)
Accumulated other comprehensive loss (1,454) (1,968)
Other (2,773) (1,570)
- --------------------------------------------------------------------------------
Gross deferred tax assets (22,280) (15,185)
- --------------------------------------------------------------------------------
Net deferred tax liabilities $ 133,801 $ 128,873
- --------------------------------------------------------------------------------
F-19
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
UGI Utilities had recorded deferred tax liabilities of approximately $37,029 as
of September 30, 2003 and $35,498 as of September 30, 2002 pertaining to utility
temporary differences, principally a result of accelerated tax depreciation for
state income tax purposes, the tax benefits of which previously were or will be
flowed through to ratepayers. These deferred tax liabilities have been reduced
by deferred tax assets of $3,314 at September 30, 2003 and $3,479 at September
30, 2002, pertaining to utility deferred investment tax credits. UGI Utilities
had recorded regulatory income tax assets related to these net deferred taxes of
$57,625 at September 30, 2003 and $54,727 as of September 30, 2002. These
regulatory income tax assets represent future revenues expected to be recovered
through the ratemaking process. We will recognize this regulatory income tax
asset in deferred tax expense as the corresponding temporary differences reverse
and additional income taxes are incurred.
5. EMPLOYEE RETIREMENT PLANS
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS
We sponsor a defined benefit pension plan ("UGI Utilities Pension Plan") for
employees of UGI, UGI Utilities, and certain of UGI's other wholly owned
subsidiaries. In addition, we provide postretirement health care benefits to
certain of our retirees and a limited number of active employees meeting certain
age and service requirements, and postretirement life insurance benefits to
nearly all active and retired employees.
F-20
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following provides a reconciliation of projected benefit obligations, plan
assets, and funded status of the plans as of September 30:
Pension Other Postretirement
Benefits Benefits
---------------------- ----------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------- ----------------------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $ 190,873 $ 165,154 $ 23,397 $ 18,179
Service cost 4,544 3,582 117 90
Interest cost 12,976 12,480 1,518 1,474
Actuarial loss 10,472 18,589 863 5,051
Plan amendments - 395 - -
Benefits paid (9,406) (9,327) (1,328) (1,397)
- ----------------------------------------------------------------------------------------------------
Benefit obligations - end of year $ 209,459 $ 190,873 $ 24,567 $ 23,397
- ----------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets - beginning of year $ 166,064 $ 183,736 $ 7,846 $ 6,994
Actual return on plan assets 27,182 (8,345) 172 144
Employer contributions - - 2,310 2,105
Benefits paid (9,406) (9,327) (1,328) (1,397)
- ----------------------------------------------------------------------------------------------------
Fair value of plan assets - end of year $ 183,840 $ 166,064 $ 9,000 $ 7,846
- ----------------------------------------------------------------------------------------------------
Funded status of the plans $ (25,619) $ (24,809) $ (15,567) $ (15,551)
Unrecognized net actuarial loss 51,205 50,190 6,870 5,945
Unrecognized prior service cost 2,345 3,038 - -
Unrecognized net transition (asset) obligation (1,374) (3,004) 6,375 7,059
- ----------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ 26,557 $ 25,415 $ (2,322) $ (2,547)
- ----------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 6.2% 6.8% 6.2% 6.8%
Expected return on plan assets 9.0% 9.5% 6.0% 6.0%
Rate of increase in salary levels 4.0% 4.5% 4.0% 4.5%
- ----------------------------------------------------------------------------------------------------
Net pension income is determined using assumptions as of the beginning of each
year. Funded status is determined using assumptions as of the end of each year.
Included in the end of year pension benefit obligations above are $15,528 at
September 30, 2003 and $13,955 at September 30, 2002 relating to employees of
UGI and certain of its other subsidiaries. Included in the end of year
postretirement obligations above are $658 at September 30, 2003 and $649 at
September 30, 2002 relating to employees of UGI and certain of its other
subsidiaries.
F-21
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Net periodic pension and other postretirement benefit costs relating to UGI
Utilities employees include the following components:
Pension Other Postretirement
Benefits Benefits
-------------------------------- --------------------------------
2003 2002 2001 2003 2002 2001
- ------------------------------------------------------------------------------ --------------------------------
Service cost $ 4,051 $ 3,193 $ 2,785 $ 109 $ 84 $ 82
Interest cost 12,004 11,600 11,319 1,497 1,453 1,326
Expected return on assets (16,646) (17,778) (17,766) (414) (366) (366)
Amortization of:
Transition (asset) obligation (1,510) (1,518) (1,530) 680 680 679
Prior service cost 643 646 625 - - -
Actuarial (gain) loss 216 - (1,104) 203 20 -
- ------------------------------------------------------------------------------------------------------------------
Net benefit cost (income) (1,242) (3,857) (5,671) 2,075 1,871 1,721
Change in regulatory assets and liabilities - - - 1,024 1,228 1,378
- ------------------------------------------------------------------------------------------------------------------
Net expense (income) $ (1,242) $ (3,857) $ (5,671) $ 3,099 $ 3,099 $ 3,099
- ------------------------------------------------------------------------------------------------------------------
UGI Utilities Pension Plan assets are held in trust and consist principally of
equity and fixed income mutual funds and a commingled bond fund. UGI Common
Stock comprised approximately 7% of trust assets at September 30, 2003. Although
the UGI Utilities Pension Plan projected benefit obligations exceeded plan
assets at September 30, 2003 and 2002, plan assets exceeded accumulated benefit
obligations by $7,346 and $7,154, respectively.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary
Employees' Beneficiary Association ("VEBA") trust to pay retiree health care and
life insurance benefits and to fund the UGI Utilities' postretirement benefit
liability. UGI Utilities is required to fund its postretirement benefit
obligations by depositing into the VEBA the annual amount of postretirement
benefits costs determined under SFAS No. 106, "Employers Accounting for
Postretirement Benefits Other than Pensions." The difference between such
amounts and amounts included in UGI Utilities' rates is deferred for future
recovery from, or refund to, ratepayers. VEBA investments consist principally of
equity and fixed income mutual funds.
The assumed health care cost trend rates are 11.0% for fiscal 2004, decreasing
to 5.5% in fiscal 2010. A one percentage point change in the assumed health care
cost trend rate would change the 2003 postretirement benefit cost and obligation
as follows:
1% 1%
Increase Decrease
- -----------------------------------------------------------------------
Effect on total service and interest costs $ 91 $ (80)
Effect on postretirement benefit obligation 1,460 (1,286)
- -----------------------------------------------------------------------
We also sponsor unfunded retirement benefit plans for certain key employees. At
September 30, 2003 and 2002, the projected benefit obligations of these plans
were $3,469 and $2,816, respectively. We recorded expense for these plans of
$353 in 2003, $269 in 2002 and $235 in 2001.
F-22
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DEFINED CONTRIBUTION PLANS
We sponsor a 401(k) savings plan for eligible employees ("Utilities Savings
Plan"). Generally, participants in the Utilities Savings Plan may contribute a
portion of their compensation on a before-tax and after-tax basis. We may, at
our discretion, match a portion of participants' contributions. The cost of
benefits under the savings plans totaled $968 in 2003, $932 in 2002 and $936 in
2001.
6. INVENTORIES
Inventories comprise the following at September 30:
2003 2002
- -------------------------------------------------
Utility fuel and gases $51,505 $36,208
Appliances for sale 548 480
Materials, supplies and other 1,964 1,966
- -------------------------------------------------
Total inventories $54,017 $38,654
- -------------------------------------------------
7. SERIES PREFERRED STOCK
The Series Preferred Stock, including both series subject to and series not
subject to mandatory redemption, has 2,000,000 shares authorized for issuance.
The holders of shares of Series Preferred Stock have the right to elect a
majority of the Board of Directors (without cumulative voting) if dividend
payments on any series are in arrears in an amount equal to four quarterly
dividends. This election right continues until the arrearage has been cured. We
have paid cash dividends at the specified annual rates on all outstanding Series
Preferred Stock.
At September 30, 2003 and 2002, we had outstanding 200,000 shares of $7.75
Series cumulative preferred stock. We are required to establish a sinking fund
to redeem on October 1 in each year, commencing October 1, 2004, 10,000 shares
of our $7.75 Series at a price of $100 per share. The $7.75 Series is
redeemable, in whole or in part, at our option on or after October 1, 2004, at a
price of $100 per share. All outstanding shares of $7.75 Series are subject to
mandatory redemption on October 1, 2009, at a price of $100 per share.
8. COMMITMENTS AND CONTINGENCIES
We lease various buildings and transportation, computer and office equipment and
other facilities under operating leases. Certain of our leases contain renewal
and purchase options and also contain escalation clauses. Our aggregate rental
expense for such leases was $4,303 in 2003, $4,690 in 2002 and $4,624 in 2001.
F-23
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Minimum future payments under operating leases that have initial or remaining
noncancelable terms in excess of one year for the fiscal years ending September
30 are as follows: 2004 - $2,890; 2005 - $2,420; 2006 - $2,115; 2007 - $1,754;
2008 - $1,024; after 2008 - $3,203.
Gas Utility has gas supply agreements with producers and marketers with terms
not exceeding one year. Gas Utility also has agreements for firm pipeline
transportation and storage capacity which Gas Utility may terminate at various
dates through 2016. Gas Utility's costs associated with transportation and
storage capacity agreements are included in its annual PGC filing with the PUC
and are recoverable through PGC rates. In addition, Gas Utility has short-term
gas supply agreements which permit it to purchase certain of its gas supply
needs on a firm or interruptible basis at spot-market prices.
Electric Utility purchases its capacity requirements and electric energy needs
under contracts with various suppliers and on the spot market. Contracts with
producers for capacity and energy needs expire at various dates through 2008.
Future contractual cash obligations under Gas Utility and Electric Utility
supply, storage and service agreements existing at September 30, 2003 are as
follows: 2004 - $157,050; 2005 - $87,850; 2006 - $48,156; 2007 - $25,074; 2008 -
$14,714; after 2008 - $73,997.
From the late 1800s through the mid-1900s, UGI Utilities and its former
subsidiaries owned and operated a number of manufactured gas plants ("MGPs")
prior to the general availability of natural gas. Some constituents of coal tars
and other residues of the manufactured gas process are today considered
hazardous substances under the Superfund Law and may be present on the sites of
former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary
gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility.
UGI Utilities does not expect its costs for investigation and remediation of
hazardous substances at Pennsylvania MGP sites to be material to its results of
operations because Gas Utility is currently permitted to include in rates,
through future base rate proceedings, prudently incurred remediation costs
associated with such sites. UGI Utilities has been notified of several sites
outside Pennsylvania on which (1) MGPs were formerly operated by it or owned or
operated by its former subsidiaries and (2) either environmental agencies or
private parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating
three claims against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be liable
in those instances in which a former subsidiary owned or operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities
directly operated, or that were owned or operated by former subsidiaries of UGI
Utilities, if a court were to conclude that (1) the subsidiary's separate
corporate form should be disregarded or (2) UGI Utilities should be considered
to have been an operator because of its conduct with respect to its subsidiary's
MGP.
F-24
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
With respect to a manufactured gas plant site in Manchester, New Hampshire,
EnergyNorth Natural Gas, Inc. ("EnergyNorth") filed suit against UGI Utilities
seeking contribution from UGI Utilities for response and remediation costs
associated with the contamination on the site of a former MGP allegedly operated
by former subsidiaries of UGI Utilities. UGI Utilities and EnergyNorth agreed to
a settlement of this matter in June 2003. UGI Utilities recorded its estimated
liability for contingent payments to EnergyNorth under the terms of the
settlement agreement.
In April 2003, Citizens Communications Company ("Citizens") served a complaint
naming UGI Utilities as a third-party defendant in a civil action pending in
United States District Court for the District of Maine. In that action, the
plaintiff, City of Bangor, Maine ("City") sued Citizens to recover environmental
response costs associated with MGP wastes generated at a plant allegedly
operated by Citizens' predecessors at a site on the Penobscot River. Citizens
subsequently joined UGI Utilities and ten other third-party defendants alleging
that the third party defendants are responsible for an equitable share of costs
Citizens may be required to pay to the City for cleaning up tar deposits in the
Penobscot River. The City believes that it could cost as much as $50,000 to
clean up the river. UGI Utilities believes that it has good defenses to the
claim.
By letter dated July 29, 2003, Atlanta Gas Light Company ("AGL") served UGI
Utilities with a complaint filed in the United States District Court for the
Middle District of Florida in which AGL alleges that UGI Utilities is
responsible for 20% of approximately $8,000 incurred by AGL in the investigation
and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities
formerly owned stock of the St. Augustine Gas Company, the owner and operator of
the MGP. UGI Utilities believes that it has good defenses to the claim and is
defending the suit.
On September 20, 2001, Consolidated Edison Company of New York ("ConEd") filed
suit against UGI Utilities in the United States District Court for the Southern
District of New York, seeking contribution from UGI Utilities for an allocated
share of response costs associated with investigating and assessing gas plant
related contamination at former MGP sites in Westchester County, New York. The
complaint alleges that UGI Utilities "owned and operated" the MGPs prior to
1904. The complaint also seeks a declaration that UGI Utilities is responsible
for an allocated percentage of future investigative and remedial costs at the
sites. ConEd believes that the cost of remediation for all of the sites could
exceed $70,000. UGI Utilities believes that it has good defenses to the claim
and is defending the suit. In November 2003, the court granted UGI Utilities'
motion for summary judgment in part, dismissing all claims premised on a
disregard of the separate corporate form of UGI Utilities' former subsidiaries
and dismissing claims premised on UGI Utilities' operation of three of the MGPs
under operating leases with ConEd's predecessors. The court reserved decision on
the remaining theory of liability, that UGI Utilities was a direct operator of
the remaining MGPs.
In addition to these environmental matters, there are other pending claims and
legal actions arising in the normal course of our businesses. We cannot predict
with certainty the final results of environmental and other matters. However, it
is reasonably possible that some of them could be resolved unfavorably to us.
Although we currently believe, after consultation with counsel, that damages or
settlements, if any, recovered by the plaintiffs in such claims or actions will
not have a material adverse effect on our financial position, damages or
settlements could be material to our operating results or cash flows in future
periods depending on the nature and timing of future
F-25
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
developments with respect to these matters and the amounts of future operating
results and cash flows.
9. FINANCIAL INSTRUMENTS
The carrying amounts of financial instruments included in current assets and
current liabilities (excluding current maturities of long-term debt) approximate
their fair values because of their short-term nature. The estimated fair value
of our long-term debt is approximately $233,000 at September 30, 2003 and
$263,000 at September 30, 2002. We estimate the fair value of long-term debt by
using current market prices and by discounting future cash flows using rates
available for similar type debt. The estimated fair value of our Series
Preferred Stock is approximately $20,900 at September 30, 2003 and $20,400 at
September 30, 2002. We estimated the fair value of our Series Preferred Stock
based on the fair value of redeemable preferred stock with similar credit
ratings and redemption features.
We have financial instruments such as trade accounts receivable which could
expose us to concentrations of credit risk. The credit risk from trade accounts
receivable is limited because we have a large customer base which extends across
many different markets. At September 30, 2003 and 2002, we had no significant
concentrations of credit risk.
F-26
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SEGMENT INFORMATION
We have determined that we have two reportable segments: (1) Gas Utility and (2)
Electric Operations. Gas Utility revenues are derived principally from the sale
and distribution of natural gas to customers in eastern and southeastern
Pennsylvania. Electric Operations derives its revenues principally from the sale
and distribution of electricity in two northeastern Pennsylvania counties.
The accounting policies of our reportable segments are the same as those
described in Note 1. We evaluate the performance of our Gas Utility and Electric
Operations segments principally based upon their income before income taxes.
No single customer represents more than ten percent of our consolidated revenues
and there are no significant intersegment transactions. In addition, all of our
reportable segments' revenues are derived from sources within the United States,
and all of our reportable segments' long-lived assets are located in the United
States. Financial information by business segment follows:
Gas Electric
Total Utility Operations
- -----------------------------------------------------------------------------
2003
Revenues $ 636,758 $ 539,862 $ 96,896
Cost of sales 392,901 342,987 49,914
Depreciation and amortization 21,240 18,147 3,093
Operating income 117,868 96,086 21,782
Interest expense 17,656 15,409 2,247
Income before income taxes 100,212 80,677 19,535
Total assets 809,048 725,085 83,963
Capital expenditures 41,297 37,204 4,093
2002
Revenues $ 490,552 $ 404,519 $ 86,033
Cost of sales 290,282 241,669 48,613
Depreciation and amortization 22,172 18,983 3,189
Operating income 90,317 77,148 13,169
Interest expense 16,652 14,224 2,428
Income before income taxes 73,665 62,924 10,741
Total assets 798,123 689,080 109,043
Capital expenditures 35,884 31,034 4,850
2001
Revenues $ 584,762 $ 500,832 $ 83,930
Cost of sales 374,781 322,915 51,866
Depreciation and amortization 23,767 20,171 3,596
Operating income 98,556 87,846 10,710
Interest expense 18,988 16,258 2,730
Income before income taxes 79,568 71,588 7,980
Total assets 784,409 678,947 105,462
Capital expenditures 36,783 31,757 5,026
F - 27
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. QUARTERLY DATA (UNAUDITED)
The following quarterly information includes all adjustments (consisting only of
normal recurring adjustments), which we consider necessary for a fair
presentation of such information. Quarterly results fluctuate because of the
seasonal nature of UGI Utilities' businesses.
December 31, March 31, June 30, September 30,
2002 2001 2003 2002 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Revenues $168,351 $141,481 $269,296 $179,945 $121,546 $ 88,249 $ 77,565 $ 80,877
Operating income 38,830 27,609 63,449 41,319 10,005 13,222 5,584 8,167
Net income 20,714 14,045 35,399 22,549 3,640 5,552 919 1,949
- ------------------------------------------------------------------------------------------------------------------------
12. OTHER INCOME, NET
Other income, net, comprises the following:
2003 2002 2001
- ------------------------------------------------------------
Non-tariff service income $ 5,693 $ 5,701 $ 5,410
Pension income 1,242 3,858 5,671
Interest income 128 1,110 235
Other 1,682 1,054 3,795
- ------------------------------------------------------------
$ 8,745 $ 11,723 $ 15,111
- ------------------------------------------------------------
13. RELATED PARTY TRANSACTIONS
UGI provides administrative and general support to UGI Utilities. UGI bills UGI
Utilities monthly for an allocated share of its general corporate expenses. This
allocation is based upon a three-factor formula which includes revenues, costs
and expenses, and net assets. These billed expenses are classified as operating
and administrative expenses - related parties in the Consolidated Statements of
Income.
In accordance with the terms of an Affiliated Interest Agreement ("Affiliated
Agreement") approved by the PUC, Gas Utility enters into wholesale natural gas
transactions with Energy Services, Inc. ("Energy Services"), a wholly owned
second-tier subsidiary of UGI, for winter storage service and, from time to
time, purchases of natural gas. During 2003 and 2002, the aggregate amount of
these transactions totaled $4,709 and $2,614, respectively. Such amounts were
not material in 2001. In addition, from time to time, the Company sells natural
gas to Energy Services pursuant to the terms of the Affiliated Agreement. During
2003, 2002 and 2001, revenues associated with these sales to Energy Services
totaled $4,234, $17,379 and $10,976, respectively. These transactions did not
have a material effect on the Company's net income during 2003, 2002 and 2001.
F - 28
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, 2003
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 1,972 $ 7,778 $ (6,475)(1) $ 3,275
======= =======
Other reserves (3) $ 3,363 $ 3,164 $ (3,294)(2) $ 3,616
======= =======
383 (4)
YEAR ENDED SEPTEMBER 30, 2002
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 3,151 $ 5,270 $ (6,449)(1) $ 1,972
======= =======
Other reserves (3) $ 3,467 $ 748 $ (2,352)(2) $ 3,363
======= =======
1,500 (4)
YEAR ENDED SEPTEMBER 30, 2001
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 2,061 $ 8,269 $ (7,179)(1) $ 3,151
======= =======
Other reserves (3) $ 1,954 $ 1,696 $ (276)(2) $ 3,467
======= =======
93 (4)
(1) Uncollectible accounts written off, net of recoveries.
(2) Payments, net
(3) Includes reserves for self-insured property and casualty liability, insured
property and casualty liability, environmental, litigation and other.
(4) Other adjustments
S-1
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.2 Bylaws as amended through September 30, 2003
10.19 UGI Utilities, Inc. Severance Plan for Exempt Employees
in Salary Grades 34-37 and Salary Grades 18-23 effective
January 1, 1999
10.21 Change of Control Agreement for Mr. Chaney
10.22 Form of Change of Control Agreement for executive
officers other than Messrs. Chaney and Greenberg
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
14 Code of Ethics for principal executive, financial and
accounting officers
23 Consent of PricewaterhouseCoopers LLP
31.1 Certification by the Chief Executive Officer relating to
the Registrant's Report on Form 10-K for the year ended
September 30, 2003 pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
31.2 Certification by the Chief Financial Officer relating to
the Registrant's Report on Form 10-K for the year ended
September 30, 2003 pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
32 Certification by Chief Executive Officer and Chief
Financial Officer