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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, 20032004
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]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 ][X]
At November 30, 2003,2004, 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 CorporationCorporation.
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...................................................................1
Items 11. and 2. Business and Properties........................................................ 1
General........................................................................ 1
Gas Utility Operations......................................................... 1
Electric Utility Operations.................................................... 5Properties..........................1
Item 3. Legal Proceedings.............................................................. 8Proceedings................................7
PART II: SECURITIES AND FINANCIAL INFORMATION................................................................... 11..................................................................10
Item 5. Market for Registrant's Common Equity,
and Related Stockholder Matters.......... 11Matters and Issuer
Purchases of Equity Securities..................10
Item 7. Management's Discussion and Analysis of
Financial Condition and Results
of Operations..................................................................... 12Operations...................................11
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk..................... 26Risk...............................26
Item 8. Financial Statements and Supplementary
Data.................................... 26Data............................................26
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure..................................................................... 26Disclosure............................26
Item 9A. Controls and Procedures........................................................ 26Procedures.........................26
Item 9B. Other Information...............................27
PART III: INTENTIONALLY OMITTED.................................................................................. 28OMITTED.............................................28
PART IV: ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS............................................................. 29..................................................................29
Item 15. Exhibits and Financial Statement
Schedule, and Reports on Form 8-K................ 29
Signatures..................................................................... 35Schedules.......................................29
Signatures........................................................36
Index to Financial Statements and Financial
Statement Schedule................. F-2Schedule.............................F-2
(i)
PART I:
BUSINESS
ITEMS 11. AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. ("Utilities",Utilities," "UGI Utilities" or the "Company") is a
public utility company that owns and operates (i) a natural gas distribution
utility serving 15customers in 14 counties in eastern and southeastern
Pennsylvania ("Gas Utility"), and (ii) an electric utility serving parts of
Luzerne and Wyoming counties in northeastern Pennsylvania ("Electric Utility").
We are a wholly owned subsidiary of UGI Corporation ("UGI"). 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 yearsyear 2003 2002 or
2001.2002.
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 292,000300,000 customers in
portions of 1514 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 4,8004,900 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 20032004 fiscal year was
approximately 83.882.2 billion cubic feet ("bcf"). System sales of gas to
firm-residential, commercial and industrial ("retail core-market") customers
accounted for approximately 43%42% of system throughput, while gas delivery service
(gas transported for residential, commercial and industrial customers (whowho bought
their gas from others) accounted for approximately 57%58% of system throughput.
Based on the most recent available industry data for 2001,(2002), residential customers
account for approximately 34%35% of total system throughput by LDCsnatural gas
distribution companies in the United States. By contrast,
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for the 20032004 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, UtilitiesGas Utility 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 2003,2004, Gas Utility purchased approximately 3750 bcf of
natural gas for sale to retail core-market and off-system sales customers.
Approximately 88%77% of the volumes purchased were supplied under agreements with
ten major suppliers. The remaining 12%23% of gas purchased was supplied by
approximately 2520 different 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'sUtility
sales are seasonal. Approximately 60%59% of fiscal year 20032004 throughput occurred
during the months ofwinter season from November through March.
COMPETITION
Natural gas is a fuel that competes with electricity and oil, and to a
lesser extent, with propane and coal. Competition among these fuels is primarily
a function of their perceived reliability, 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 UtilityUtilities is the only
regulated gas distribution utility having the right, granted by the PUC or by
law, to provide gas distribution services. UnderSince the Gas Competition Act, retail1980s, larger commercial
and industrial customers mayhave been able to purchase their natural gas supplies from a supplierentities
other than Gas Utility. CommercialAs a result of Pennsylvania's Natural Gas Choice and
industrial customers inCompetition Act ("Gas Competition Act"), which became effective July 1, 1999,
all of Gas Utility's service territory have been
able to do this since 1982. As of October 2003, two marketers have qualified to
servecustomers, including residential and small commercial and industrial customers. Together they
serve approximately 4,500 customers. Gas Utility provides transportation
services for residential and smallsmaller commercial and
industrial customers who
purchase natural gas from others.have been afforded this opportunity.
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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 profitabilityProfitability 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.cost, and the frequency and
duration of interruptions. See "Utility"Gas Utility and Electric Utility Regulation and
Rates - Gas Utility Rates." Commercial and industrial customers representing 18%22%
of total system throughput have locations which afford them the opportunity,
although none has
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have 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'Gas Utility's ten largest
customers in terms of annual volume. All of these customers have contracts,
with Utilities,
nineeight of which extend beyond fiscal year 2004.2005. No single customer represents, or
is anticipated to represent, more than 5% of the total revenues of Gas Utility.
OUTLOOK FOR GAS SERVICE AND SUPPLY
Gas Utility anticipates having adequate pipeline capacity and sources of
supply available to it to meet the full requirements of all firm customers on
its system through fiscal year 2004.2005. 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'Gas
Utility's larger customers.
During fiscal year 2003,2004, 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 9,60010,600 new residential heating customers during fiscal year 2003,2004,
which represented a record annual increase. Of those new customers, new home
construction accounted for over 7,3008,000 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.
Utilitiesapproximately 1,200.
Gas Utility 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.
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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 needachievable for security of supply.reliable and secure
supplies. Consistent with that objective, Gas Utility negotiates the terms of
firm transportation capacity on all pipelines serving Gas Utility,it, 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 61,60062,000
customers in portions of Luzerne and Wyoming Counties in northeastern
Pennsylvania through a system consisting of approximately 2,100 miles of
transmission and distribution lines and 14 transmission substations. For fiscal
year 2003,2004, about 53% of sales volume came from residential customers, 36%35% from
commercial customers and 11%12% from industrial customers. Electricity transported
for customers who purchased their power from others pursuant to the ECC Actother suppliers represented approximatelyless
than 1% of fiscal year 20032004 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 2004.2005.
Electric Utility distributes both electricity that it purchases from others and
electricity that customers purchase from other suppliers. At September 30, 2003,2004,
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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As a result of the Electricity Generation Customer Choice and Competition
Act ("ECC Act") that became effective in 1997, all Pennsylvania retail electric
customers have the ability to choose their electric generation supplier. Under
the ECC Act, Electric Utility remains the provider of last resort ("POLR") for
its customers who do not choose an alternate electric generation supplier. The
terms and conditions under which Electric Utility provides POLR service, and
rules governing the rates that may be charged for such service, have been
established in a series of PUC-approved settlements, the most recent of which
became effective in June 2004 (collectively, the "POLR Settlement.") Consistent
with the terms of the POLR Settlement, Electric Utility's POLR rates will
increase beginning January 2005 and Electric Utility is permitted, but not
required, to further increase its POLR rates in January 2006. Electric Utility
is the only regulated electric utility having the right, granted by the PUC or
by law, to distribute electricity in its service territory. Sales of electricity
for residential heating purposes
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accounted for approximately 20% of total sales of electricity during the 2004
fiscal year. Electricity competes with natural gas, oil, propane and other
heating fuels for this use.
GAS UTILITY AND ELECTRIC 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
TheEffective October 1, 2000, Gas Restructuring Order included an increase in firm-residential,
commercial and industrial ("retail core-market")Utility increased its base rates effective
October 1, 2000. The increase, calculated in accordance with the Gas Competition
Act, was designedfor retail
core-market customers and implemented a credit 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(described below). Since December 1, 2001, Gas Utility was required to reducehas reduced 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 ofcompetition from 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 RATESfuels in commercial and
industrial markets.
Gas Utility's gas service tariff contains Purchased Gas Costpurchased gas cost ("PGC") rates
whichthat provide for annual increases or decreases in the rate per thousand cubic
feet ("mcf") whichthat Gas Utility
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charges for natural gas sold by it, to reflect Utilities'Gas
Utility's projected cost of purchased gas. PGC rates may also be adjusted
quarterly, or, under certain conditions monthly, to reflect purchased gas costs.the actual cost of
gas. 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. UtilitiesGas Utility has two PGC
rates. PGC (1) is applicable to small, firm, retail core-market customers
consisting of the residential and small commercial
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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'Utility's PGC rates commencing December 1, 2001,are adjusted 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 commercial2005 and
industrial customers, and June 2004 for residential
customers.
Additionally, pursuantElectric Utility is permitted, but not required, to further increase its POLR
rates in January 2006. Pursuant to the requirements of the ECC 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, 2003,2004, 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 effecteffects
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."
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EMPLOYEES
At September 30, 2003,2004, 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 2004,
2003 2002 and 20012002 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 -8-
contemplated by governmental authorities other
than claims arising in the ordinary course of the Company's business.
ENVIRONMENTAL MATTERS - MANUFACTURED GAS PLANTS
InFrom 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)private parties allege MGPs were formerly owned or
operated by itUtilities or owned or operated by its former subsidiaries and (2) either environmental
agencies or privatesubsidiaries. Such
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
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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 claimBy orders issued in November 2003 and is
defending the suit.
In November 2003,March 2004, 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 withdismissed ConEd's predecessors. The court reserved decision on the remaining theory of liability,
that UGI Utilities was a direct operator of the remaining MGPs.complaint. ConEd
has appealed.
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 -9-
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
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 cleaning up tar deposits in the site range between $5Penobscot River.
Citizens alleges that Utilities and its predecessors owned and operated the
plant from 1901 to 1928. The City believes it could cost as much as $50 million
and $50 million.
Utilities is unable to estimate what portion of this potential cost may be
associated with MGP wastes.clean up the river. Utilities believes that it has good defenses to the claim.claim
and is defending the suit.
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.
Savannah, Georgia Matter. AGL previously informed Utilities that it was
investigating contamination that appeared to be related to MGP operations at a
site owned by AGL in Savannah, Georgia. A former subsidiary of Utilities
operated the MGP in the early 1900s. AGL has recently informed Utilities that it
has begun remediation of MGP wastes at the site and believes that the total cost
of remediation could be as high as $55 million. AGL has not filed suit against
Utilities for a share of these costs. Utilities believes that it will have good
defenses to any action that may arise out of this site.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy
("KeySpan") informed Utilities that KeySpan has spent $2.3 million and expects
to spend another $11 million to clean up an MGP site it owns in Sag Harbor, New
York. KeySpan believes that Utilities is responsible for approximately 50% of
these costs as a result of Utilities' alleged direct ownership and operation of
the plant from 1885 to 1902. Utilities is in the process of reviewing the
information provided by KeySpan and is investigating this claim.
Connecticut Gas Plants Matter. By letter dated August 5, 2004, Yankee Gas
Services Company and Connecticut Light and Power Company, subsidiaries of
Northeast Utilities, (together the "Northeast Companies"), demanded contribution
from Utilities for past and future
-8-
remediation costs related to MGP operations on thirteen sites owned by the
Northeast Companies in nine cities in the State of Connecticut. The Northeast
Companies allege that Utilities controlled operations of the plants from 1883 to
1941. According to the letter, investigation and remedial costs at the sites to
date total approximately $10 million and complete remediation costs for all
sites could total $182 million. The Northeast Companies seek an unspecified fair
and equitable allocation of these costs to Utilities. Utilities is in the
process of reviewing the information provided by Northeast Companies and is
investigating this claim.
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. Thedefendants
and the suit has been stayed pending resolution of the remaining claims.
-10-dismissed.
-9-
PART II: SECURITIES AND FINANCIAL INFORMATION
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, AND RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
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 $45 million
in fiscal year 2004, $33.9 million in fiscal year 2003 and $37.9 million in
fiscal year 2002 and $35.3 million
in fiscal year 2001.
-11-2002.
-10-
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 electricitythe electric generation
business of UGI Development Company ("UGID") 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 2004 COMPARED WITH FISCAL 2003
Increase
Year Ended September 30, 2004 2003 (Decrease)
- ------------------------ ------ ------ --------------
(Millions of dollars)
GAS UTILITY:
Revenues $560.4 $539.9 $ 20.5 3.8 %
Total margin (a) $191.5 $196.9 $ (5.4) (2.7)%
Operating income $ 80.1 $ 96.1 $(16.0) (16.6)%
Income before income taxes $ 64.2 $ 80.7 $(16.5) (20.4)%
System throughput - bcf 82.2 83.8 (1.6) (1.9)%
Degree days - % (warmer) colder
than normal (2.9)% 7.0% -- --
ELECTRIC OPERATIONS:
Revenues $ 89.7 $ 96.9 $ (7.2) (7.4)%
Total margin (a) $ 41.5 $ 42.2 $ (0.7) (1.7)%
Operating income $ 20.9 $ 21.8 $ (0.9) (4.1)%
Income before income taxes $ 18.9 $ 19.5 $ (0.6) (3.1)%
Distribution sales - gwh 983.9 980.0 3.9 0.4 %
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 in both Fiscal 2004 and Fiscal
2003. For financial statement purposes, Gas Utility's and Electric
Operations' cost of sales is included in "gas, fuel and purchased
power" and 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 2.9% warmer than normal in Fiscal 2004 compared with weather
that was 7.0% colder than normal in Fiscal 2003. Total distribution system
throughput decreased 1.6 bcf or 1.9% as the adverse effects of the warmer
weather on heating-related sales to firm- residential, commercial and industrial
("retail core-market") customers were partially offset by greater volumes
transported for delivery service customers and the volume effects of
year-over-year retail core-market customer growth. The increase in Gas Utility
revenues during Fiscal 2004 includes a $20.1 million increase in revenues from
off-system sales partially offset by lower retail core-market
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and delivery service revenues. The decline in retail core-market revenues
reflects the effects of the reduced retail core-market volumes partially offset
by higher average purchased gas costs ("PGC") rates reflecting higher natural
gas costs. Gas Utility's cost of gas was $368.9 million in Fiscal 2004 compared
to $343.0 million in Fiscal 2003 Comparedreflecting greater cost of gas associated with
the higher off-system sales and the higher average retail core-market PGC rates
partially offset by the effects of the lower retail core-market volumes sold.
Increases or decreases in Gas Utility's cost of gas associated with retail
core-market customers result from changes in retail core-market volumes, the
price of the gas purchased and the level of gas costs collected through the PGC
recovery mechanism. Under this recovery mechanism, Gas Utility records the cost
of gas associated with sales to retail core-market customers equal to the amount
included in rates and defers the difference on the balance sheet as a regulatory
asset or liability representing an amount to be collected from or refunded to
customers in a future period. As a result, increases or decreases in the cost of
gas associated with retail core-market customers have no direct effect on retail
core-market margin.
Gas Utility total margin declined $5.4 million principally reflecting a $4.0
million decline in retail core-market margin and the effects of lower margins on
delivery-service.
Gas Utility operating income declined $16.0 million in Fiscal 2004 principally
reflecting the previously mentioned decline in total margin, lower other income
and higher operating and administrative expenses. Other income declined $5.4
million due in large part to a decline in non-tariff service income, costs
related to settling a regulatory claim and the absence of pension income in
Fiscal 2004. Operating and administrative expenses increased $3.8 million due
primarily to higher compensation and benefits expense, including the effects of
a lump-sum payment made to a participant of UGI Utilities' unfunded executive
retirement plan, partially offset by the absence of costs related to settling an
environmental claim recorded in the prior year and lower Fiscal 2004
distribution system maintenance expenses. The decrease in Gas Utility income
before income taxes reflects the decline in operating income and slightly higher
interest expense in Fiscal 2004 resulting from classifying dividends paid on
preferred shares subject to mandatory redemption as interest expense, beginning
July 1, 2003, in accordance with Statement of Financial Accounting Standards
("SFAS") No. 150 ("SFAS 150").
ELECTRIC OPERATIONS. Electric Utility's Fiscal 2004 kilowatt-hour sales were
slightly higher than in Fiscal 2003 due in large part to greater air
conditioning sales partially offset by the adverse effects of slightly warmer
winter weather on heating-related sales.
The decline in Electric Operations revenues in Fiscal 2004 principally reflects
the absence of $8.0 million of revenues from UGID's electricity generation
business recorded in the prior year. Electric Operations' cost of sales
declined $6.6 million in Fiscal 2004 reflecting the absence of $6.2 million of
costs related to UGID's operations and approximately $0.4 million of lower
Electric Utility purchased power costs.
Electric Operations total margin in Fiscal 2004 declined $0.7 million
principally reflecting the absence of $1.8 million of total margin related to
UGID's operations partially offset by a $1.1 million increase in Electric
Utility total margin. Operating income and income before income
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taxes were lower in Fiscal 2004 principally reflecting the decline in total
margin.
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$539.9 $404.5 $135.4 33.5%
Total margin (a) $ 196.9 $ 162.9$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")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.
-12-
Gas Utility revenues in Fiscal 2003 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")PGC rates resulting from higher natural gas
costs. Gas UtilityUtility's cost of gas was $343.0 million in Fiscal 2003, an increase
of $101.3 million from the prior year,Fiscal 2002, reflecting the higher retail core-market
volumes sold and the higher retail core-market PGC rates.
The increase in Gas Utility total margin in Fiscal 2003 compared to Fiscal 2002
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.
-13-
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, the classification of dividends on preferred shares.shares as
interest expense.
ELECTRIC OPERATIONS. Electric Utility's Fiscal 2003 kilowatt-hour sales
increased principally as a result of weather based upon heating degree days 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.
-13-
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
-14-
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$278.1 million at September 30, 2003.2004.
Included in this amount is $40.7$60.9 million of borrowings outstanding under
revolving credit agreements.
-14-
Utilities has revolving credit commitments under which it may borrow up to a
total of $107$110 million. These agreements are currently scheduled to expire in
June 20052007. In addition, UGI Utilities has an uncommitted arrangement with a
major bank under which it may borrow up to $20 million. At September 30, 2004,
there were no borrowings outstanding under this arrangement. Amounts outstanding
under the revolving credit agreements and 2006.the uncommitted arrangement are
classified as bank loans on the Consolidated Balance Sheets. The revolving
credit agreements have restrictions on such items as total debt, debt service
and payments for investments.
At September 30,
2003, UtilitiesOn July 27, 2004, UGI Utilities' Board of Directors approved the redemption on
October 1, 2004 of all 200,000 shares of the $7.75 Series Preferred Stock at a
price of $100 per share together with full cumulative dividends. The redemption
on October 1, 2004 of all 200,000 shares of the $7.75 Series Preferred Stock was
in compliancefunded with these covenants.proceeds from the issuance of $20 million of 6.13% Medium-Term Notes
due October 2034. Utilities has a shelf registration statement with the U.S.
Securities and Exchange Commission under which it may issue up to an additional
$40$20 million of Medium-Term Notes or other debt securities.
In order to provide additional short-term liquidity during the peak-heating
season, on November 1, 2004, Utilities borrowed $20 million under the
uncommitted arrangement with a major bank, which is scheduled to mature on March
1, 2005. Based upon cash expected to be generated from Gas Utility and Electric
Utility operations, and
-15-
short-term borrowings, including borrowings available under
revolving credit agreements and the availability of its Medium-Term Notes,
management believes that Utilities will be able to meet its anticipated
contractual and projected cash commitments during Fiscal 2004.2005. 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 generallyusually 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 and the uncommitted arrangement with a major bank to satisfy its
seasonal operating cash flow needs. Cash flow from operating activities was
$67.0 million in Fiscal 2004, $97.8 million in Fiscal 2003, and $55.1 million in
Fiscal 2002, and $76.1 million in Fiscal 2001.2002. Cash flow from operating activities before changes in operating
working capital was $92.9 million in Fiscal 2004, $91.8 million in Fiscal 2003
and $78.4 million in Fiscal 2002, and $72.3 million in Fiscal 2001.2002. Changes in operating working capital used
$26.0 million of operating cash flow in Fiscal 2004, provided $6.0 million of
operating cash flow in Fiscal 2003 and used $23.3 million of operating cash flow
in Fiscal 2002, and provided
$3.8 million of operating cash flow2002. The decrease in Fiscal 2001. The increase in Fiscal 20032004 cash flow from operating activities
compared to Fiscal 2003 principally reflects, the increased operating
results and greateramong other things, a decline in
cash flow from changes in Gas Utility deferred fuel overcollectionscosts and accrued income taxesan increase in
accounts receivable partially offset by higher inventories
resulting from greater natural gas prices.noncash deferred income taxes.
-15-
INVESTING ACTIVITIES. Cash flow used in investing activities was $42.4 million
in Fiscal 2004, $43.1 million in Fiscal 2003 and $36.6 million in Fiscal 2002, and $44.2 million in Fiscal 2001.2002.
Expenditures for property, plant and equipment were $40.7 million in Fiscal
2004, $41.3 million in Fiscal 2003 and $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.2002. Net costs
of property, plant and equipment disposals which principally represent net costs
associated with retirements of distribution system assets were also higher$1.7 million in
Fiscal 2004, $1.8 million in Fiscal 2003 principally reflecting
greater gas main replacement activity.and $0.7 million in Fiscal 2002.
FINANCING ACTIVITIES. Cash flow used by financing activities was $24.8 million
in Fiscal 2004, $60.5 million in Fiscal 2003 and $20.1 million in Fiscal 2002, and $39.8 million in Fiscal 2001.2002.
Financing activity cash flow changes are primarily due to issuances and
repayments of long-term debt, net short-term borrowings including borrowings
under revolving credit facilities, dividends on common stock and, prior to the
adoption of SFAS 150, effective July 1, 2003, 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 2004, 2003 and 2002, we paid cash dividends to UGI of $45.0
million, $33.9 million and $37.9 million, respectively. Although we paid
dividends on our preferred shares subject to mandatory redemption of $1.6
million in all three periods, dividends paid on the preferred shares subject to
mandatory redemption for all periods beginning July 1, 2003 are reflected in
cash flow from operations as a result of which
$0.4 million has been classified as
-16-
interest expensethe application of SFAS 150 (see
"Preferred Shares Subject to Mandatory Redemption" below).
PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION
Beginning July 1, 2003 through the date of their redemption on October 1, 2004,
the Company accounted for its preferred shares subject to mandatory redemption
in accordance with StatementSFAS 150. SFAS 150 establishes guidelines on how an issuer
classifies and measures certain financial instruments with characteristics of
Financial Accounting Standards
("SFAS") No.both liabilities and equity. The adoption of SFAS 150, (see "Recently Issued Accounting Pronouncements" below).effective July 1, 2003,
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. Prior to July 1, 2003, these dividends were
reflected as a deduction from net income. Because SFAS 150 specifically
prohibits the restatement of financial statements prior to its adoption, prior
period amounts have not been reclassified. The amount of such dividends
reflected in interest expense was $1.6 million in Fiscal 2004 and $0.4 million
in Fiscal 2003.
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 beenwas eliminated from the consolidated balance
sheet.sheet and reflected as a dividend from retained earnings. 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 2001.2002.
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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, theThe
fair value of Pension Plan assets increased towas $196.4 million and $183.8 million at
September 30, 2004 and 2003, compared to $166.1 million at September 30, 2002.respectively. At September 30, 20032004 and 2002,2003, the
Pension Plan's assets exceeded its accumulated benefit obligations by $7.3$9.2
million and $7.2$7.3 million, respectively. The Company is in full compliance with
regulations governing defined benefit pension plans, including ERISAEmployee
Retirement Income Security Act of 1974 ("ERISA") rules and regulations, and does
not anticipate it will be required to make a contribution to the Pension Plan in
Fiscal 2004.2005. Pre-tax pension incomeexpense (income) reflected in Fiscal 2004, 2003 2002 and
20012002 results was $1.2$1.0 million, $3.9$(1.2) million and $5.7$(3.9) million, respectively.
The decrease in pension income during this period principally reflects the
significant declineschanges in the market value of Plan assets and decreases in the discount rate
assumptions.assumption. Pension expense in Fiscal 20042005 is expected to be approximately $1.1$2.5
million compareddue in large part to pension
incomethe expiration of $1.2 million in Fiscal 2003 due to decreases in the discount rate and
expected return on Pension Plan assets assumptions.Plan's transition
asset amortization.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business segment for
Fiscal 2003,2004, Fiscal 20022003 and Fiscal 2001.2002. We also provide amounts we expect to
spend in Fiscal 2004.2005. We expect to finance a substantial portion of Fiscal 20042005
capital expenditures from cash generated by operations and the remainder from
borrowings under our credit facilities.
Year Ended September 30, 2005 2004 2003 2002 20012003(a) 2002(a)
- ----------------------------------------------------------------------------------------------------------------------------------------- ---------- ----- ------- -------
(Millions of dollars) (estimate)
Gas Utility $ 38.0 $ 37.2 $ 31.0 $ 31.8$41.4 $35.5 $37.2 $31.0
Electric Utility 4.9Operations 9.6 5.2 4.1 4.9
5.0
- -----------------------------------------------------------------------------------------------------------------
$ 42.9 $ 41.3 $ 35.9 $ 36.8----- ----- ----- -----
$51.0 $40.7 $41.3 $35.9
===== ===== ===== =====
(a) Includes capital expenditures for both the Electric Utility and UGID
businesses.
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CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
Utilities has certain contractual cash obligations that extend beyond Fiscal
20032004 including scheduled repayments of long-term debt and, redeemableprior to their
redemption on October 1, 2004, preferred stock,shares subject to mandatory redemption,
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, 20032004 (in
millions).
Payments Due by Period
---------------------------------------------------
Less than--------------------------------------------
1 year 2 - 3 4 - 5 After
Total 1 yearor less years years 5 years
- ----------------------------------------------------------------------------------------------------- ------- ------ ------ -------
Long-term debt $217.0 $ -20.0 $ 70.0 $ 20.0-- $127.0
UGI Utilities preferred shares subject
to mandatory redemption 20.0 - 2.0 2.0 16.020.0 -- -- --
Operating leases 13.414.8 3.5 5.7 2.7 2.9 4.5 2.8 3.2
Gas Utility and Electric Utility supply,
storage and servicetransportation contracts 406.9 157.1 136.0 39.8 74.0
- -----------------------------------------------------------------------------------------------598.3 188.5 181.3 112.2 116.3
------ ------- ------ ------ ------
Total $657.3 $160.0 $212.5 $ 64.6 $220.2
- -----------------------------------------------------------------------------------------------$850.1 $232.0 $257.0 $114.9 $246.2
====== ====== ====== ====== ======
RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative and general supportservices to UGI Utilities. UGI
bills UGI Utilities monthly for all direct and for an allocated share of
its generalindirect corporate expenses. This
allocation is based upon a three-factor formula which includes revenues, costs
and expenses and net assets.incurred or paid on behalf of UGI Utilities. These
billed expenses totaled $11.2 million in Fiscal 2004, $9.4 million in Fiscal
2003 and $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 termsaddition, UGI Utilities provides limited administrative services to
UGI and certain of an Affiliated Interest Agreement ("Affiliated
Agreement") approvedUGI's subsidiaries, largely payroll related services.
Amounts billed to these entities by the PUC,UGI Utilities is not material.
Gas Utility enters into wholesale natural gas transactions with UGI Energy
Services, Inc. ("Energy Services"), a wholly owned second-tier subsidiary of
UGI, for winter storagepeaking service and, from time to time, purchases of natural gas.gas
or pipeline capacity. In addition, from time to time, the Company sells natural
gas to Energy Services pursuant to the terms of the Affiliated
Agreement.Services. These transactions did not have a material effect on the
Company's net income during Fiscal2004, 2003 2002 and 2001.2002. For additional information on
these transactions, see Note 1312 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. Thesedo not have any off-balance sheet arrangements enable usthat are expected to lease facilitieshave an
effect on the Company's financial condition, revenues and equipment from
third parties rather than, among other options, purchasing the equipment and
facilities using on-balance sheet financing. For a summaryexpenses, results of
operations, liquidity, capital expenditures or capital resources.
-18-
scheduled future payments under these lease arrangements, see "Contractual Cash
ObligationsREGULATORY MATTERS
Since the 1980s, larger commercial and Commitments."
REGULATORY MATTERSindustrial customers have been able to
purchase gas supplies from entities other than Gas Utility. As a result of
Pennsylvania's Natural Gas Choice and Competition Act ("Gas(the "Gas Competition
Act") signed into law on June 22,that became effective July 1, 1999, all natural gas consumers in
Pennsylvania, including residential and smaller commercial and industrial
customers ("core-market customers"), have the ability to purchase their gas supplies from the supplier
of their choice.been afforded this opportunity. Under
the Gas Competition Act, localnatural gas distribution companies ("LDCs"NGDCs"), like Gas
Utility, may continue to sell gas toserve as the supplier of last resort for all core-market
customers, and such sales of gas, as well as the distribution servicesservice provided
by LDCs,NGDCs, 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, 2003,2004, less than fivetwo percent of Gas Utility's retailcore-market 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 sensitiveof the Electricity Generation Customer Choice and Competition Act
("Electric Competition Act") that became effective January 1, 1997, all of
Electric Utility's customers have the ability to the effects of heating-season weather and less sensitive to
the market prices of alternative fuels.
The PUC approved a settlement establishing rules foracquire their electricity from
entities other than Electric Utility. Electric Utility Providerremains the provider of
Last Resortlast resort ("POLR") for its customers that are not served by an alternate
electric generation provider. The terms and conditions under which Electric
Utility provides POLR service, on March 28, 2002, and rules governing the rates that may be charged
for such service, have been established in a separate settlement
that modified these rulesseries of PUC-approved settlements,
the last of which became effective on June 13, 20027, 2004 (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 forUtility's POLR service under the statutory rate caps; (2) may be
raised by up to 5% of the total raterules provide 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&ICommercial and industrial 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 2004,2005, and for residential customers
beginning June 2004. Also, Electric Utility is permitted, but not
required, to further increase its POLR rates beginning January 2006. Electric
Utility is also permitted to, and has, offered and entered into multiple-year fixed-rate
POLR contracts with certain of its customers.
Additionally,
pursuantPursuant to the requirements of the Electricity ChoiceElectric Competition Act, the PUC is
currently developing post-rate cappost-rate-cap POLR regulations that are expected to further
define
post-rate cap POLR service obligations and pricing. As of September 30, 2003,
less2004, fewer
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 requires us to record the effects of rate regulation in the
financial statements. SFAS 71 allows us to defer
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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. We believe that SFAS 71 continues to apply to our regulated
operations and that the recovery of our regulatory assets is probable.
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)private parties allege MGPs were formerly owned or
operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or privatesubsidiaries. Such 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-
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.
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-partythird 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
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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. Citizens alleges that UGI
Utilities and its predecessors owned and operated the MGP from 1901 to 1928. 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.claim and is defending
the suit.
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$8 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.
AGL previously informed UGI Utilities that it was investigating contamination
that appeared to be related to MGP operations at a site owned by AGL in
Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the
early 1900s. AGL has recently informed UGI Utilities that it has begun
remediation of MGP wastes at the site and believes that the total cost of
remediation could be as high as $55 million. AGL has not filed suit against UGI
Utilities for a share of these costs. UGI Utilities believes that it will have
good defenses to any action that may arise out of this site.
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
claimBy orders issued in November 2003 and is defending the suit. In November 2003,March 2004, the court
granted UGI Utilities' motion for summary judgment and dismissed ConEd's
complaint. ConEd has appealed.
By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed UGI Utilities
that KeySpan has spent $2.3 million and expects to spend another $11 million to
clean up an MGP site it owns in part, dismissing all claims premised
onSag Harbor, New York. KeySpan believes that UGI
Utilities is responsible for approximately 50% of these costs as a disregard of the separate corporate formresult of UGI
Utilities' former
subsidiariesalleged direct ownership and dismissing claims premised on UGI Utilities' operation of threethe plant from 1885 to
1902. UGI Utilities is in the process of reviewing the MGPs under operating leases withinformation provided by
KeySpan and is investigating this claim.
-21-
ConEd's predecessors.By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut
Light and Power Company, subsidiaries of Northeast Utilities, (together, the
"Northeast Companies"), demanded contribution from UGI Utilities for past and
future remediation costs related to MGP operations on thirteen sites owned by
the Northeast Companies in nine cities in the State of Connecticut. The
court reserved decision on the remaining theory of
liability,Northeast Companies allege that UGI Utilities was a direct operatorcontrolled operations of the
remaining MGPs.plants from 1883 to 1941. According to the letter, investigation and remedial
costs at the sites to date total approximately $10 million and complete
remediation costs for all sites could total $182 million. The Northeast
Companies seek an unspecified fair and equitable allocation of these costs to
UGI Utilities. UGI Utilities is in the process of reviewing the information
provided by Northeast Companies and is investigating this claim.
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 any 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 purchasingpurchases 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. AlthoughIn accordance with POLR settlements approved by the
PUC, Electric Utility may increase its POLR rates up to certain limits through
December 31, 2006. In accordance with these settlements, effective January 1,
2005 and January 1, 2006, POLR generation componentrates for all metered customers may
increase up to 4.5% and 7.5%, respectively, of Electric Utility'stotal rates is subject to various rate cap provisions as a result of the POLR
Settlement,in effect on December
31, 2004. Currently, Electric Utility's fixed-price contracts with electricity
suppliers mitigate most risks associated with offering customers a fixed price during the contract periods.POLR service rate limits in
effect through December 31, 2006. However, should any of the suppliers under
these contracts fail to provide electric power under the terms of the power and
capacity contracts, any increases if any, in the cost of replacement power or capacity
wouldcould 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. At September 30, 2004, the fair value of our electricity price
swap was a gain of $2.0 million. Fair value reflects the estimated amount that
we would expect to receive or pay to terminate the contract based upon quoted
market prices of comparable contracts at September 30, 2004. An adverse change
in electricity prices of ten percent would result in a $1.0 million decrease in
the fair value of the swap.
-22-
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 20032004 and Fiscal 2002,2003, an
increase in short-term interest rates of 100 basis points (1%) would have
increased annual interest expense by $0.3$0.4 million and $0.5$0.3 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$13.8 million and $11.0$14.0 million at
September 30, 20032004 and 2002,2003, respectively. A 100 basis point
-22-
decrease in market
interest rates would result in increases in the fair value of this fixed-rate
debt of $15.7$15.5 million and $12.0$15.7 million at September 30, 20032004 and 2002,2003,
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,agreements, which hashave been
designated and qualifiesqualify as a cash flow hedge,hedges, was $0.4a loss of $1.0 million at
September 30, 2003.2004. An adverse change in interest rates of ten percent on
ten-year U.S. treasury notes of 50
basis points would result in a $0.4$2.3 million decrease in the fair
value of thisthese interest rate protection agreement.agreements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance
with accounting principles generally accepted accounting principlesin the United States of America
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
-23-
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.Commission ("PUC"). 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.operations and cash flows. As of September 30, 2003,2004, our regulatory assets
totaled $60.3$65.1 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.funds.
Changes in plan assumptions as well as fluctuations in actual equity or bond
market returns could have a material impact on future pension costs. We believe
the two most critical assumptions are the expected rate of return on plan assets
and the discount rate. An unfavorable change in the expected rate of return on
plan assets of 50 basis points would result in higher pre-tax pension expense of
approximately $1.0 million in Fiscal 2005. An unfavorable change in the discount
rate of 50 basis points would result in higher pre-tax pension expense of
approximately $1.5 million in Fiscal 2005.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In AprilDecember 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities"Financial Accounting Standards Board ("SFAS 149"FASB"). 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 revised
Financial Interpretation No. 46, "Consolidation of Variable Interest Entities"
("FIN 46"), which was originally issued in January 2003 and clarifies Accounting
Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 iswas
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 iswas effective for the first
fiscal orbeginning with our interim period beginningended March
-24-
31, 2004. The Company has not created or obtained any variable interest entities
after December 15,January 31, 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.entities. The
adoption of FIN 46 isdid not expected tohave any impact on the Company's financial position
or results of operations.
On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the "Act") was signed into law. Among other things,
the Act provides for a prescription drug benefit to Medicare beneficiaries on a
voluntary basis beginning in 2006. To encourage employers to continue to offer
retiree prescription drug benefits, the Act provides for a tax-free subsidy to
employers who offer a prescription drug benefit that is at least actuarially
equivalent to the standard benefit offered under the Act. In May 2004, the FASB
issued Staff Position No. FAS 106-2, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003" ("FSP 106-2"). FSP 106-2 is effective for periods beginning after June 15,
2004.
The Company provides postretirement health care benefits to certain of its
retirees and a limited number of active employees meeting certain age and
service requirements. See Note 5 to the Consolidated Financial Statements for
information on our Employee Retirement Plans. These postretirement benefits
include certain retiree prescription drug benefits. The Company has determined
that, as currently designed, its prescription drug benefit for eligible retirees
is not actuarially equivalent to the standard benefit offered under the Act and,
as a result, does not qualify for the tax-free subsidy.
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
-25-
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 the 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-1F-2 to F-28F-27 and page S-1 of this Report are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
During fiscal year 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.None.
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
-26-
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.
ITEM 9B. OTHER INFORMATION
Not applicable.
-27-
PART III: INTENTIONALLY OMITTED
-28-
PART IV:
ADDITIONAL EXHIBITS, SCHEDULES AND REPORTS
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-KSCHEDULES
(A) DOCUMENTS FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS:
Included under Item 8 are the following financial statements and
supplementary data:
ReportsReport of Independent Registered Public AccountantsAccounting Firm
Consolidated Balance Sheets as of September 30, 20032004 and
20022003
Consolidated Statements of Income for the fiscal years ended
September 30, 2004, 2003 2002
and 20012002
Consolidated Statements of Cash Flows for the fiscal years
ended September 30, 2004, 2003 2002 and 20012002
Consolidated Statements of Stockholders'Stockholder's Equity for the
fiscal years ended September 30, 2004, 2003 2002 and 20012002
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULE:
For the years ended September 30, 2004, 2003 2002 and 20012002
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)(3) LIST OF EXHIBITS:
The exhibits filed as part of this report are as follows
(exhibits incorporated by reference are set forth with the name
of the registrant, the type of report and registration number or
last date of the period for which it was filed, and the exhibit
number in such filing):
-29-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- -------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------- ---------- ------------- --------
3.1 Utilities' Articles of Incorporation Utilities Registration 3
Statement No.
333-72540
*3.23.2 Bylaws of UGI Utilities as amended through September 30, Utilities Form 10-K 3.2
2003 (9/30/03)
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[Intentionally omitted]
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)
-30-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ----------- -------------------------------------------------------- ---------- --------- -------
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.FERC 61,365 (1993)
10.2 Service Agreement (Rate FTS) dated June 1, 1987 Utilities10.2** UGI Corporation 2004 Omnibus Equity Compensation Plan, UGI Form 10-K (10)o.
between Utilities and Columbia,10.17
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 Utilitiesamended December 7, 2004 (9/30/04)
10.3** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K (10)p.
November 1, 1989 between Utilities and Columbia Gulf (12/31/90)
Transmission Company,10.2
Directors Stock Unit Grant Letter dated 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)January 8, (9/30/04)
2004
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'2004 Omnibus Equity Compensation Plan UGI Form 10-Q10-K 10.3
Amended and RestatedDirectors Nonqualified Stock Option Grant Letter dated (9/30/04)
as of April 29, 2003 (3/31/03)January 8, 2004
10.7** [Intentionally omitted]UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.36
UGI Employees Nonqualified Stock Option Grant Letter (9/30/04)
dated as of January 1, 2004
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 Pay UGI Form 10-K 10.12
Pay Plan effective January 1, 1997as amended December 7, 2004 (9/30/97)04)
-31-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ----------- -------------------------------------------------------- ---------- --------- -------
10.12** UGI Corporation 1992 Non-Qualified Stock Option Plan, as 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**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, 199910.19 [Intentionally omitted]
10.20** Description of Change of Control arrangementsarrangement for Mr. UGI Form 10-K 10.33
Greenberg (9/30/99)
*10.21*10.21** ChangeUGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.5
UGI Employees Stock Unit Grant Letter dated as of Control Agreement for Mr. Chaney
*10.22*(9/30/04)
January 1, 2004
10.22** Form of Change of Control Agreement for executive Utilities Form 10-K 10.22
officers other than Messrs. Chaney andMr. Greenberg 10.23 [Intentionally omitted](9/30/03)
10.23** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.7
UGI Employees Performance Unit Grant Letter dated as of (9/30/04)
January 1, 2004
-32-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ----------- ---------------------------------------------------------------------------------------------------------- ---------- --------- -------
10.24 [Intentionally omitted]10.24** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.4
Utilities Employees Performance Unit Grant Letter dated (9/30/04)
as of January 1, 2004
10.25 Storage Transportation Service Agreement (Rate Schedule Utilities Form 10-K 10.25
Schedule
SST) between Utilities and Columbia dated November 1, (9/30/02)
November 1,
1993, as modified pursuant to orders of the Federal
Energy Regulatory Commission
10.26 No-Notice Transportation*10.26 Amendment No. 1 dated November 1, 2004, to the Service
Agreement (Rate Utilities Form 10-K 10.26
Schedule NTS)FSS) dated as of November 1, 1989
between Utilities and Columbia, dated (9/30/02)
November 1, 1993, as modified pursuant to
the orders of the Federal Energy Regulatory Commission
at Docket No. RS92-5-000 reported at Columbia Gas
Transmission Corp., 64 FERC 61,060 (1993), order on
rehearing, 64 FERC 61,365 (1993)
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 Schedule Utilities Form 10-K 10.29
FT-1) between Utilities and Texas Eastern Transmission (9/30/02)
dated June 15, 1999, as modified pursuant to various
orders of the Federal Energy Regulatory Commission
*10.30 Amendment No. 1 dated November 1, 2004, to the No-Notice
Transportation Service Agreement (Rate Schedule CDS)
between Utilities and Texas Eastern Transmission dated
February 23, 1999, as modified pursuant to various
orders of the Federal Energy Regulatory Commission
-33-
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- ----------- -------------------------------------------------------- ---------- --------- --------
10.31 Firm Transportation Service Agreement (Rate Schedule FT) Utilities Form 10-K 10.31
between Utilities and Transcontinental Gas Pipe Line (9/30/02)
dated October 1, 1996, as modified pursuant to various
orders of the Federal Energy Regulatory Commission
*10.32 Gas Service Delivery and Supply Agreement between
Utilities and UGI Energy Services, Inc. dated August 26,
2004
*10.33 Amendment No. 1 dated November 1, 2004, to the Firm
Transportation Service Agreement (Rate 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*10.34 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.30
Schedule
FT-1)FTS) between Utilities and Texas Eastern (9/30/02)Columbia Gas Transmission
dated October 31, 2000, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission
10.31 Firm Transportation Service Agreement (Rate UtilitiesNovember 1, 2004
10.35** UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Form 10-K 10.31
Schedule FT) between10.36(a)
UGI Utilities and TranscontinentalEmployees Nonqualified Stock Option Grant (9/30/02)
Gas Pipe Line04)
Letter dated Octoberas of January 1, 1996, as modified
pursuant to various orders of the Federal Energy
Regulatory Commission2004
*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
*1414 Code of Ethics for principal executive, financial and Utilities Form 10-K 14
accounting officers (9/30/03)
*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, 20032004 pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
-33--34-
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, 20032004 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, 20032004
* 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--35-
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, 20037, 2004 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, 20037, 2004 by the following persons on
behalf of the Registrant in the capacities indicated.
SIGNATURE TITLE
--------- -----
Robert J. ChaneyDavid W. Trego President and Chief
- -------------------------------------------------- Executive Officer
Robert J. ChaneyDavid W. Trego (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--36-
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on December 16, 20037, 2004 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--37-
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d)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
2003.2004.
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 20032004
F-1
UGI UTILITIES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULE
Pages
-----------------
Financial Statements:
ReportsReport of Independent AuditorsRegistered Public Accounting Firm F-3 to F-4
Consolidated Balance Sheets as of September 30,
2004 and 2003 and 2002F-4 to F-5 to F-6
Consolidated Statements of Income for the years
ended September 30, 2004, 2003 and 2002 and 2001 F-7F-6
Consolidated Statements of Cash Flows for the years
ended September 30, 2004, 2003 and 2002 and 2001 F-8F-7
Consolidated Statements of Stockholder's Equity
for the years ended September 30, 2004, 2003 and 2002 and 2001 F-9F-8
Notes to Consolidated Financial Statements F-10F-9 to F-28F-27
Financial Statement Schedule:
For the years ended September 30, 2004, 2003 2002 and 2001:2002:
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 AUDITORSREGISTERED PUBLIC ACCOUNTING FIRM
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,
20032004 and 2002,2003, and the results of their operations and their cash flows for
each of the twothree years in the period ended September 30, 20032004 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) presentpresents 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; ourmanagement. 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 auditingthe standards generally accepted inof the United States of America, whichPublic Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the auditsaudit 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./s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
November 17, 2003December 6, 2004
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,
---------------------
2004 2003 2002
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents $ 30421 $ 6,090304
Accounts receivable (less allowances for doubtful
accounts of $3,374 and $3,275, and $1,972, respectively) 38,897 30,101 38,554
Accrued utility revenues 9,742 7,431
8,069
Inventories 65,177 54,017 38,654
Deferred income taxes 7,230 10,375 2,610
Income taxes recoverable - 6,892
Deferred fuel costs - 4,304
Prepaid expenses and other current assets 8,723 5,552 3,151
--------- ---------
Total current assets 129,790 107,780 108,324
Property, plant and equipment
Gas utility 820,275 791,164 760,161
Electric operations 108,231 103,917
111,265
General 15,788 12,777 11,909
--------- ---------
944,294 907,858 883,335
Less accumulated depreciation and amortization (313,030) (296,871) (290,194)
--------- ---------
Net property, plant and equipment 631,264 610,987 593,141
Regulatory assets 65,060 60,253 57,685
Other assets 29,664 30,028 38,973
--------- ---------
Total assets $ 809,048855,778 $ 798,123809,048
========= =========
See accompanying notes to consolidated financial statements.
F-5F-4
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
September 30,
-------------------
2004 2003
2002
--------- ----------------- --------
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt $ -20,000 $ 76,000--
Bank loans 60,900 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--
Accounts payable 62,707 55,298
Employee compensation and contingencies (note 8)
--------- ---------benefits accrued 12,639 8,457
Dividends and interest accrued 6,254 6,466
Income taxes accrued 2,111 479
Customer deposits and refunds 17,024 15,074
Deferred fuel costs 7,862 14,734
Other current liabilities 13,450 11,703
-------- --------
Total current liabilities 554,296 540,269222,947 152,911
Long-term debt 197,151 217,271
Deferred income taxes 158,136 144,176
Deferred investment tax credits 7,589 7,987
Other noncurrent liabilities 9,924 11,951
Preferred shares subject to mandatory redemption, without par value --- 20,000
Commitments and contingencies (note 8)
-------- --------
Total liabilities 595,747 554,296
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 79,773 79,046 73,057
Retained earnings 121,454 117,496 107,312
Accumulated other comprehensive loss (1,455) (2,049)
(2,774)
--------- ----------------- --------
Total common stockholder's equity 260,031 254,752
237,854
--------- ----------------- --------
Total liabilities and stockholder's equity $ 809,048 $ 798,123
========= =========$855,778 $809,048
======== ========
See accompanying notes to consolidated financial statements.
F-6F-5
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
Year Ended
September 30,
-----------------------------------------------------------------
2004 2003 2002
2001
--------- --------- ----------------- -------- --------
Revenues $ 636,758 $ 490,552 $ 584,762
--------- --------- ---------$650,088 $636,758 $490,552
-------- -------- --------
Costs and expenses:
Gas, fuel and purchased power 412,240 392,901 290,282 374,781
Operating and administrative expenses 93,244 91,947 80,910 88,310
Operating and administrative expenses - related parties 11,223 9,352 6,664 5,277
Taxes other than income taxes 12,501 12,195 11,930 9,182
Depreciation and amortization 22,520 21,240 22,172 23,767
Other income, net (2,669) (8,745) (11,723)
(15,111)
--------- --------- ----------------- -------- --------
549,059 518,890 400,235
486,206
--------- --------- ----------------- -------- --------
Operating income 101,029 117,868 90,317
98,556
Interest expense 17,931 17,656 16,652
18,988
--------- --------- ----------------- -------- --------
Income before income taxes 83,098 100,212 73,665
79,568
Income taxes 34,140 39,540 29,570
31,431
--------- --------- ----------------- -------- --------
Net income 48,958 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 $ 48,958 $ 59,509 $ 42,545
$ 46,587
========= ========= ================= ======== ========
See accompanying notes to consolidated financial statements.
F-7F-6
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
Year Ended
September 30,
--------------------------------------------------------------
2004 2003 2002 2001
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 48,958 $ 60,672 $ 44,095 $ 48,137
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 22,520 21,240 22,172 23,767
Deferred income taxes, net 11,873 2,097 11,114 (2,016)
Provision for uncollectible accounts 6,971 7,778 5,270
8,269
Pension incomeexpense (income) 1,022 (1,242) (3,857)
(5,671)
Other 1,591 1,284 (391) (177)
Net change in:
Accounts receivable and accrued utility revenues (18,078) (610) (1,631)
(14,704)
Inventories (11,160) (15,601) 9,420 (14,508)
Deferred fuel costs (6,872) 19,038 (7,056)
9,948
Accounts payable 7,409 (454) (9,957) 13,318
Other current assets and liabilities 2,732 3,599 (14,123) 9,769
-------- -------- --------
Net cash provided by operating activities 66,966 97,801 55,056 76,132
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (40,737) (41,297) (35,884) (36,783)
Net costs of property, plant and equipment disposals (1,712) (1,831) (704) (1,407)
Cash contribution to partnership - - (6,000)
-------- -------- --------
Net cash used by investing activities (42,449) (43,128) (36,588) (44,190)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (45,000) (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) 20,200 3,500 (20,600) (42,600)
Capital contribution from UGI Corporation -- 5,000 - 4,000--
-------- -------- --------
Net cash used by financing activities (24,800) (60,459) (20,089) (39,806)
-------- -------- --------
Cash and cash equivalents decrease $ (283) $ (5,786) $ (1,621) $ (7,864)
======== ======== ========
CASH AND CASH EQUIVALENTS:
End of year $ 21 $ 304 $ 6,090
$ 7,711
Beginning of year 304 6,090 7,711 15,575
-------- -------- --------
Decrease $ (283) $ (5,786) $ (1,621) $ (7,864)
======== ======== ========
See accompanying notes to consolidated financial statements.
F-8F-7
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, 20002001 $60,259 $68,559$72,792 $102,706 $ 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-- $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
Net income 48,958 48,958
Net change in fair value of derivative
instruments (net of tax of $246) 347 347
Reclassifications of net losses on interest rate
protection agreements (net of tax of $176) 247 247
-------- ------- --------
Comprehensive income 48,958 594 49,552
Cash dividends - common stock (45,000) (45,000)
Other 727 727
------- ------- -------- ------- --------
Balance September 30, 2004 $60,259 $79,046 $117,496 $ (2,049) $ 254,752$79,773 $121,454 $(1,455) $260,031
======= ======= ======== ======= ======== =========
See accompanying notes to consolidated financial statements.
F-9F-8
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.consolidated subsidiaries for the
periods prior to June 2003 and those of UGI Utilities subsequent to May 2003. We
eliminate all significant intercompany accounts and transactions when we
consolidate. Our investment in Energy Ventures, prior to its distribution in
June 2003, 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.
InAs previously mentioned, 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, prior to their distribution, 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.2002.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in
conformity with accounting principles generally accepted in the United States.States of
America. 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. CertainSFAS 71
allows us to defer expenses and credits subject to utility regulation and normally reflected in
income as incurred are deferredrevenues on the balance sheet as regulatory
assets and recognizedliabilities 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 asstatement of an unregulated
company. These deferred assets and
F-9
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
liabilities are then flowed through the relatedincome statement in the period in which
the same 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,We believe that SFAS 71 continues to apply to our regulated
operations and that 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
provisionsrecovery of the Gas Restructuring Order and the Gas Competition Act, we
believe Gas Utility'sour 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"), seeis probable. 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 $18,143 in 2004, $16,046 in 2003 and $16,348 in 2002 and $17,543 in 2001.2002.
We paid income taxes totaling $19,910 in 2004, $29,372 in 2003 and $36,282 in
2002 and $29,000 in
2001.2002.
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. UGI Utilities reduces
its deferred income tax liability for the future tax benefits that will occur
when the deferred investment tax credits, which are not taxable, are
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
F-10
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 UGI 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 both 2004 and 2003
and 2.5% in 2002
and 2.6% in 2001.2002. Depreciation expense as a percentage of the related average
depreciable base for Electric Utility was 2.8% in 2004 and 3.0% in each ofboth 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.2002. Depreciation expense was $21,860 in 2004, $20,754 in 2003 and $21,649 in
2002
and $22,701 in 2001.2002.
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)The balance sheet
caption "deferred fuel costs" reflects amounts related to this PGC recovery
mechanism.
PREFERRED SHARES SUBJECT TO MANDATORY REDEMPTION
Beginning July 1, 2003 through the date of their redemption on October 1, 2004
(see Note 7), the Company accountsaccounted 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, resultseffective July 1, 2003, resulted in the
Company presenting its preferred shares subject to mandatory redemption in the
liabilities section of the balance sheet, and reflecting
F-11
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
dividends paid on these shares as a component of interest expense, for periods
presented after June 30, 2003. Prior to July 1, 2003, these dividends were
reflected as a deduction from net income. Because SFAS 150 specifically
prohibits the restatement of financial statements prior to its adoption, prior
period amounts have not been reclassified.
STOCK-BASED COMPENSATION
Certain members of Utilities' management may be granted stock options and other
equity-based awards of UGI Common Stock under UGI's current equity compensation
plans. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation"
("SFAS 123"), we apply the provisions of Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" ("APB 25"), in recording
compensation expense for grants of equity instruments to employees.
We use the intrinsic value method prescribed by APB 25 for UGI's equity-based
employee compensation plans. We recorded equity-based compensation expense of
$2,652 in 2004, $1,372 in 2003 and $1,168 in 2002, respectively. If we had
determined stock-based compensation expense under the fair value method
prescribed by the provisions of SFAS 123, net income after dividends on
preferred shares subject to mandatory redemption would have been as follows at
September 30:
2004 2003 2002
------- ------- -------
Net income after dividends on preferred shares subject to
mandatory redemption, as reported $48,958 $59,509 $42,545
Add: Stock-based employee compensation
expense included in reported net income, net
of related tax effects 1,551 803 684
Deduct: Total stock-based employee compensation
expense determined under the fair value method
for all awards, net of related tax effects (1,715) (927) (812)
------- ------- -------
Pro forma net income after dividends on preferred shares
subject to mandatory redemption $48,794 $59,385 $42,417
======= ======= =======
ENVIRONMENTAL LIABILITIESAND OTHER LEGAL MATTERS
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. Amounts accrued generally reflect our best estimate of costs expected
to be incurred or the minimum liability associated with a range of expected
environmental response costs. 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, 2003,2004, the Company's accrued
F-12
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
liability for environmental investigation and cleanup costs was not material.
Similar to environmental matters, we accrue investigation and other legal costs
when it is probable that a liability exists and the amount or range of amounts
can be reasonably estimated (see Note 8).
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 amountFor a detailed description 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
ofderivative
instruments we use, our unsettled IRPAs were a gain of $369 at September 30, 2003objectives for using them, 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 withrelated supplemental
information required by 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.see Note 9.
COMPREHENSIVE INCOME
Comprehensive income comprises net income and other comprehensive income (loss).
Other comprehensive income (loss) of $594, $725 and $(2,774) for the years ended
September 30, 2004, 2003 and 2002, respectively, is the result of gains or
losses on IRPAsinterest rate protection agreements ("IRPAs") and in 2004, changes in
the fair value of an electric price swap agreement 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 AprilDecember 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 issuedrevised
Financial Interpretation No. 46, "Consolidation of Variable Interest Entities"
("FIN 46"), which was originally issued in January 2003 and clarifies Accounting
Research Bulletin No. 51, "Consolidated Financial Statements." FIN 46 iswas
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 iswas effective for the first fiscal orbeginning with our interim period beginningended March 31,
2004. The Company has not created or obtained any variable interest entities
after December 15,January 31, 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.entities. The
adoption of FIN 46 isdid not expected tohave any impact on the Company's financial position,
or results of operations.
2. UTILITY REGULATORY MATTERS
Gas Utility
Gas Restructuring Order.operations or cash flows.
On June 29, 2000,December 8, 2003, the PUC issued the Gas Restructuring
Order approving Gas Utility's restructuring plan filed by Gas Utility pursuant
to the Gas Competition Act. The purposeMedicare Prescription Drug, Improvement and
Modernization Act of the Gas Competition Act, which2003 (the "Act") 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.law. Among other things,
the implementation ofAct provides for a prescription drug benefit to Medicare beneficiaries on a
voluntary basis beginning in 2006. To encourage employers to continue to offer
retiree prescription drug benefits, 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 designedAct provides for a tax-free subsidy 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 equalemployers who offer a prescription drug benefit that is at least actuarially
equivalent 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 sensitivestandard benefit offered under the Act. In May 2004, the FASB
issued Staff Position No. FAS 106-2, "Accounting and Disclosure Requirements
Related to the effectsMedicare Prescription Drug, Improvement and Modernization Act of
heating-season weather2003" ("FSP 106-2"). FSP 106-2 is effective for periods beginning after June 15,
2004.
The Company provides postretirement health care benefits principally to certain
of its retirees and less sensitive to
the market pricesa limited number 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")active employees meeting certain age and
propane air
("LP") facilities, along with related assets, to an unregulated affiliate,
Energy Services, Inc. ("Energy Services"), a second-tier wholly
F-15service requirements. See
F-13
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
owned subsidiary of UGI. Gas Utility transferredNote 6 for information on our employee retirement plans. These postretirement
benefits include certain retiree prescription drug benefits. The Company has
determined that, as currently designed, its prescription drug benefit for
retirees is not actuarially equivalent to the LNGstandard benefit offered under the
Act 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, adjustedresult, does not qualify 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.tax-free subsidy.
2. UTILITY REGULATORY ASSETS 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 LiabilitiesLIABILITIES
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
2004 2003
2002
- --------------------------------------------------------------- -------
Regulatory assets:
Income taxes recoverable $62,039 $57,625 $54,727
Other postretirement benefits 1,926 2,162
2,397
Deferred fuel costs - 4,304
Other 1,095 466
561
- --------------------------------------------------------------- -------
Total regulatory assets $65,060 $60,253
$61,989
- --------------------------------------------------------------- -------
Regulatory liabilities:
Other postretirement benefits $ 3,7462,976 $ 4,3323,746
Deferred fuel costs 7,862 14,734
-
- --------------------------------------------------------------- -------
Total regulatory liabilities $10,838 $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:
2004 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$151 and $392,$271, respectively, effective rate - 6.64%) 30,151 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 -25,000
6.50% Notes due August 2033 20,000 -
6.50% Senior Notes, due August 2003 (less unamortized
discount of $23) - 49,977
- -------------------------------------------------------------------------------------------------20,000
-------- --------
Total long-term debt 217,151 217,271 248,369
Less current maturities - (76,000)
- -------------------------------------------------------------------------------------------------(20,000) --
-------- --------
Long-term debt due after one year $ 217,271 $ 172,369
- -------------------------------------------------------------------------------------------------$197,151 $217,271
-------- --------
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; 2009 - $0.
F-14
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
At September 30, 2003,2004, UGI Utilities had revolving credit agreements with five
banks providing for borrowings of up to $107,000.$110,000. These agreements are currently
scheduled to expire in June 2005 and 2006.2007. 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 $60,900 at September 30, 2004 and $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 2.35% at September 30, 2004 and 1.63% at
September 30, 2003
and 2.35% at September 30, 2002.2003.
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, 2003,2004, 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:
2004 2003 2002
2001
- -------------------------------------------------------------------------- ------- -------
Current expense:
Federal $ 27,027 $ 13,341 $ 25,344$15,413 $27,027 $13,341
State 6,854 10,416 5,115
8,103
- -------------------------------------------------------------------------- ------- -------
Total current expense 22,267 37,443 18,456
33,447
Deferred expense (benefit)12,271 2,495 11,512 (1,618)
Investment tax credit amortization (398) (398) (398)
- -------------------------------------------------------------------------- ------- -------
Total income tax expense $ 39,540 $ 29,570 $ 31,431
- -------------------------------------------------------------------$34,140 $39,540 $29,570
======= ======= =======
A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:
2004 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 5.7 5.6 6.3 6.5
Deferred investment tax credit amortization (0.4) (0.5)(0.4) (0.5)
Other, net 0.8 (0.7) (0.7)
(1.5)
- --------------------------------------------------------------------------- ---- ----
Effective tax rate 41.1% 39.5% 40.1%
39.5%
- -----------------------------------------------------------------------==== ==== ====
Deferred tax liabilities (assets) comprise the following at September 30:
F-15
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2004 2003
2002
- ---------------------------------------------------------------------------------------- --------
Excess book basis over tax basis of property, plant
and equipment $ 117,891 $ 107,627$130,297 $117,891
Regulatory assets 27,589 25,001 25,721
Pension plan asset 10,541 11,019
10,546
Other 1,550 2,170
164
- ---------------------------------------------------------------------------------------- --------
Gross deferred tax liabilities 169,977 156,081
144,058
- ---------------------------------------------------------------------------------------- --------
Deferred investment tax credits (3,149) (3,314) (3,479)
Employee-related expenses (6,973) (7,072) (6,371)
Regulatory liabilities (3,967) (7,667) (1,797)
Accumulated other comprehensive loss (1,032) (1,454)
(1,968)
Other (3,950) (2,773)
(1,570)
- ---------------------------------------------------------------------------------------- --------
Gross deferred tax assets (19,071) (22,280)
(15,185)
- ---------------------------------------------------------------------------------------- --------
Net deferred tax liabilities $ 133,801 $ 128,873
- --------------------------------------------------------------------------------$150,906 $133,801
-------- --------
F-19
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
UGI Utilities had recorded deferred tax liabilities of approximately $39,445 as
of September 30, 2004 and $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 $3,149 at September 30, 2004 and $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$62,039 at September 30, 20032004 and $54,727$57,625 as of September 30, 2002.2003. 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 domestic active and retired employees.
F-20F-16
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
---------------------- ----------------------------------------- --------------------
2004 2003 20022004 2003
2002
- -------------------------------------------------------------------------- ------------------------------ -------- -------- --------
CHANGE IN BENEFIT OBLIGATIONS:Change in benefit obligations:
Benefit obligations - beginning of year $209,459 $190,873 $ 190,873 $ 165,15424,567 $ 23,397
$ 18,179
Service cost 4,953 4,544 3,582120 117 90
Interest cost 12,996 12,976 12,4801,514 1,518 1,474
Actuarial loss 2,608 10,472 18,5891,208 863 5,051
Plan amendments - 395 - --- -- -- --
Benefits paid (9,530) (9,406) (9,327)(2,261) (1,328)
(1,397)
- ------------------------------------------------------------------------------------------------------------ -------- -------- --------
Benefit obligations - end of year $220,486 $209,459 $ 209,459 $ 190,87325,148 $ 24,567
$ 23,397
- ----------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:-------- -------- -------- --------
Change in plan assets:
Fair value of plan assets - beginning of year $183,840 $166,064 $ 166,064 $ 183,7369,000 $ 7,846 $ 6,994
Actual return on plan assets 22,045 27,182 (8,345)826 172 144
Employer contributions - --- -- 2,461 2,310 2,105
Benefits paid (9,530) (9,406) (9,327)(2,115) (1,328)
(1,397)
- ------------------------------------------------------------------------------------------------------------ -------- -------- --------
Fair value of plan assets - end of year $196,355 $183,840 $ 183,840 $ 166,06410,172 $ 9,000
$ 7,846
- ------------------------------------------------------------------------------------------------------------ -------- -------- --------
Funded status of the plans $ (25,619) $ (24,809) $ (15,567) $ (15,551)$(24,131) $(25,619) $(14,976) $(15,567)
Unrecognized net actuarial loss 47,884 51,205 50,1906,932 6,870 5,945
Unrecognized prior service cost 1,651 2,345 3,038 - --- --
Unrecognized net transition (asset) obligation -- (1,374) (3,004)5,690 6,375
7,059
- ------------------------------------------------------------------------------------------------------------ -------- -------- --------
Prepaid (accrued) benefit cost - end of year $ 25,404 $ 26,557 $ 25,415(2,354) $ (2,322)
$ (2,547)
- ----------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER-------- -------- -------- --------
Assumptions as of September 30:
Discount rate 6.1% 6.2% 6.8%6.1% 6.2% 6.8%
Expected return on plan assets 9.0% 9.5% 6.0%9.0% 5.8% 6.0%
Rate of increase in salary levels 4.0% 4.5% 4.0% 4.5%
- ----------------------------------------------------------------------------------------------------4.0% 4.0%
Net pension incomeexpense (income) is determined using assumptions as of the
beginning of each fiscal year. Funded status is determined using assumptions as
of the end of each fiscal year. The expected rate of return on assets
assumption is based on the rates of return for certain asset classes and the
allocation of plan assets among those asset classes as well as actual historic
long-term rates of return on our plan assets.
Included in the end of year pension benefit obligations above are $23,581 at
September 30, 2004 and $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 $735 at September 30, 2004 and $658 at
September 30, 2003 and $649 at
September 30, 2002 relating to employees of UGI and certain of its other
subsidiaries.
F-21F-17
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Net periodic pension expense (income) and other postretirement benefit costs
relating to UGI Utilities employees include the following components:
Pension Other Postretirement
Benefits Benefits
-------------------------------- -------------------------------------------------------------- ------------------------
2004 2003 2002 20012004 2003 2002
2001
- ------------------------------------------------------------------------------ ---------------------------------------- -------- -------- ------ ------ ------
Service cost $ 4,318 $ 4,051 $ 3,193 $ 2,785110 $ 109 $ 84
$ 82
Interest cost 11,642 12,004 11,600 11,3191,487 1,497 1,453 1,326
Expected return on assets (15,412) (16,646) (17,778) (17,766)(459) (414) (366) (366)
Amortization of:
Transition (asset) obligation (1,233) (1,510) (1,518) (1,530) 680 680 679680
Prior service cost 622 643 646 625 - - --- -- --
Actuarial (gain) loss 1,085 216 - (1,104)-- 316 203 20
-
- -------------------------------------------------------------------------------------------------------------------------- -------- -------- ------ ------ ------
Net benefit cost (income) 1,022 (1,242) (3,857) (5,671)2,134 2,075 1,871 1,721
Change in regulatory assets and
liabilities - - --- -- -- 965 1,024 1,228
1,378
- -------------------------------------------------------------------------------------------------------------------------- -------- -------- ------ ------ ------
Net expense (income) $ 1,022 $ (1,242) $ (3,857) $ (5,671) $ 3,099 $ 3,099 $ 3,099
- ------------------------------------------------------------------------------------------------------------------$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.trust. Although the UGI Utilities
Pension Plan projected benefit obligations exceeded plan assets at September 30,
20032004 and 2002,2003, plan assets exceeded accumulated benefit obligations by $9,160
and $7,346, and $7,154, respectively. The Company did not make any contributions in 2004 nor
does it believe it will be required to make any contributions to the UGI
Utilities Pension Plan during the year ending September 30, 2005.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary
Employees' Beneficiary Association ("VEBA") trust to fund the UGI Utilities'
postretirement obligations and 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."Pensions" ("SFAS 106"). The difference
between such amounts calculated under SFAS 106 and the amounts included in UGI
Utilities' rates is deferred for future recovery from, or refund to, ratepayers.
The Company expects to contribute approximately $2,500 to the VEBA investments consist principallyduring the
year ending September 30, 2005.
Expected payments for pension benefits and for other postretirement
welfare benefits are as follows:
Other
Pension Postretirement
Benefits Benefits
-------- --------------
Fiscal 2005 $ 9,881 $ 2,045
Fiscal 2006 9,876 2,121
Fiscal 2007 10,121 2,184
Fiscal 2008 10,276 2,236
Fiscal 2009 10,801 2,270
Fiscal 2010-2014 64,300 10,988
F-18
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In accordance with our investment strategy to obtain long-term growth, our
target allocations are to maintain a mix of equity60% equities and the remainder in
fixed income mutual funds.funds or cash equivalents.
The targets and actual allocations for the UGI Utilities Pension Plan assets and
VEBA trust assets at September 30 are as follows:
Target Pension Plan VEBA
-------------- ------------ -----------
Pension
Plan VEBA 2004 2003 2004 2003
------- ---- ---- ---- ---- ----
Equities 60% 60% 63% 60% 58% 57%
Fixed income funds 40% 30% 37% 40% 27% 29%
Cash equivalents N/A 10% N/A N/A 15% 14%
UGI Common Stock comprised approximately 8% and 7% of pension plan assets at
September 30, 2004 and 2003, respectively.
The assumed health care cost trend rates are 11.0%10.0% for fiscal 2004,2005, decreasing
to 5.5% in fiscal 2010. A one percentage point change in the assumed health care
cost trend rate would change the 20032004 postretirement benefit cost and obligation
as follows:
1% 1%
Increase Decrease
- ------------------------------------------------------------------------------- --------
Effect on total service and interest costs $ 9193 $ (80)(82)
Effect on postretirement benefit obligation 1,460 (1,286)
- -----------------------------------------------------------------------1,468 (1,300)
We also sponsor an unfunded and non-qualified supplemental executive retirement
benefit plans for certain key employees.income plan. At September 30, 20032004 and 2002,2003, the projected benefit obligations
of these plansthis plan were $3,469$1,600 and $2,816,$3,469, respectively. We recorded expense for these plansthis
plan of $460 in 2004, $353 in 2003 and $269 in 2002 and $2352002. We also recorded a
settlement loss of $1,537 in 2001.
F-22
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)2004 associated with this plan.
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 plansplan totaled $915 in 2004, $968 in 2003 and $932 in
2002 and $936 in
2001.2002.
F-19
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. INVENTORIES
Inventories comprise the following at September 30:
2004 2003
2002
- -------------------------------------------------------- -------
Utility fuel and gases $62,673 $51,505 $36,208
Appliances for sale 537 548 480
Materials, supplies and other 1,967 1,964
1,966
- -------------------------------------------------------- -------
Total inventories $65,177 $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, 20032004 and 2002,2003, we had outstanding 200,000 shares of $7.75
Series cumulative preferred stock. We are required to establish a sinking fund
to redeemOn July 27, 2004, UGI Utilities' Board of
Directors approved the redemption on October 1, in each year, commencing October 1, 2004 10,000of all 200,000 shares of
ourthe $7.75 Series Preferred Stock at a price of $100 per share.share together with full
cumulative dividends. 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 price2004 of $100 per share.all 200,000 shares of
the $7.75 Series Preferred Stock was funded with proceeds from the October 2004
issuance of $20,000 of 6.13% Medium-Term Notes due October 2034.
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 $4,431 in 2004, $4,303 in 2003 and $4,690 in 2002 and $4,624 in 2001.
F-23
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)2002.
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;$3,510; 2006 - $2,115;$3,079; 2007 - $1,754;$2,633; 2008 - $1,024;$1,798;
2009 - $922; after 20082009 - $3,203.$2,931.
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 natural gas storage capacityservice which Gas Utility may terminate
at various dates through 2016. Gas Utility's costs associated with
transportation and storage capacityservice 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.
F-20
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 fiscal
2008.
Future contractual cash obligations under Gas Utility and Electric Utility
supply, storage and service agreements existing at September 30, 20032004 are as
follows: 2004 - $157,050; 2005 - $87,850;$188,484; 2006 - $48,156;$100,630; 2007 - $25,074;$80,680; 2008 - $14,714;$60,552; 2009
- - $51,650; after 20082009 - $73,997.$116,288.
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)private parties allege MGPs were formerly owned or
operated by it or owned or operated by its former subsidiaries and (2) either environmental agencies or
privatesubsidiaries. Such 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 owned or 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. Citizens alleges that UGI Utilities and its predecessors owned
and operated the MGP from 1901 to 1928. 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.claim and is defending the suit.
F-21
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
AGL previously informed UGI Utilities that it was investigating contamination
that appeared to be related to MGP operations at a site owned by AGL in
Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the
early 1900s. AGL has recently informed UGI Utilities that it has begun
remediation of MGP wastes at the site and believes that the total cost of
remediation could be as high as $55,000. AGL has not filed suit against UGI
Utilities for a share of these costs. UGI Utilities believes that it will have
good defenses to any action that may arise out of this site.
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 claimBy orders issued in November 2003 and is defending the suit. In November 2003,March 2004, the court
granted UGI Utilities' motion for summary judgment and dismissed ConEd's
complaint. ConEd has appealed.
By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed UGI Utilities
that KeySpan has spent $2,300 and expects to spend another $11,000 to clean up
an MGP site it owns in part, dismissing all claims premised onSag Harbor, New York. KeySpan believes that UGI Utilities
is responsible for approximately 50% of these costs as a disregard of the separate corporate formresult of UGI
Utilities' former subsidiariesalleged direct ownership and dismissing claims premised on UGI Utilities' operation of threethe plant from 1885 to
1902. UGI Utilities is in the process of reviewing the MGPs
under operating leases with ConEd's predecessors.information provided by
KeySpan and is investigating this claim.
By letter dated August 5, 2004, Yankee Gas Services Company and Connecticut
Light and Power Company, subsidiaries of Northeast Utilities, (together, the
"Northeast Companies"), demanded contribution from UGI Utilities for past and
future remediation costs related to MGP operations on thirteen sites owned by
the Northeast Companies in nine cities in the State of Connecticut. The
court reserved decision on
the remaining theory of liability,Northeast Companies allege that UGI Utilities was a direct operatorcontrolled operations of the
remaining MGPs.plants from 1883 to 1941. According to the letter, investigation and remedial
costs at the sites to date total approximately $10,000 and complete remediation
costs for all sites could total $182,000. The Northeast Companies seek an
unspecified fair and equitable allocation of these costs to UGI Utilities. UGI
Utilities is in the process of reviewing the information provided by Northeast
Companies and is investigating this claim.
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
F-22
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
In accordance with its commodity hedging policy, the Company may enter into (1)
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 and (2) electric swap agreements in order to reduce the
volatility in the cost of anticipated electricity requirements. We designate
these contracts as cash flow or fair value hedges under SFAS 133. Because the
cost of the natural gas call option contracts and any associated gains will be
included in our PGC recovery mechanism, as these contracts are recorded at fair
value in accordance with SFAS 133, any gains are deferred for future recovery
from or refund to Gas Utility's ratepayers in deferred fuel costs. 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.
We enter into IRPAs in order to manage interest rate risk associated with
planned issuances of fixed-rate long-term debt. We designate these IRPAs as cash
flow hedges. Gains or losses on IRPAs are included in other comprehensive income
and are reclassified to interest expense as the interest on the associated debt
affects earnings.
During 2004, 2003 and 2002, 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. At September 30, 2004,
our unsettled derivative contracts included in accumulated other comprehensive
loss included an electric price swap agreement and two IRPAs.
Gains and losses included in accumulated other comprehensive loss at
September 30, 2004 relating to cash flow hedges will be reclassified into (1)
interest expense when interest on anticipated issuances of fixed-rate long-term
debt is reflected in net income and (2) cost of sales when the forecasted
purchase of electricity subject to the hedge impact net income. Included in
accumulated other comprehensive loss at September 30, 2004 are net after-tax
losses of approximately $2,599 associated with settled IRPAs and two unsettled
IRPAs associated with forecasted issuances of long-term debt anticipated to
occur during the next two years. The
F-23
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
amount of net loss on IRPAs expected to be reclassified into net
income during the next twelve months is not material. Also included in
accumulated other comprehensive loss at September 30, 2004 is an after-tax gain
of $1,143 associated with our electric price swap agreement for purchases of
electricity anticipated to occur during fiscal 2007. The actual amount of gains
or losses on unsettled derivative instruments that ultimately is reclassified
into net income will depend upon the value of such derivative contracts when
settled. The fair value of derivative instruments is included in prepaid
expenses and other current assets, other assets, other current liabilities and
other noncurrent liabilities in the Consolidated Balance Sheets.
The carrying amounts of financial instruments included in current assets and
current liabilities (excluding unsettled derivatives and current maturities of
long-term debt) approximate their fair values because of their short-term
nature.
The carrying amounts and estimated fair valuevalues of our long-term debt is approximately $233,000remaining financial
instruments (including unsettled derivative instruments) at September 30 2003 and
$263,000 at September 30, 2002.are:
Carrying Estimated
Amount Fair Value
-------- ----------
2004:
Electric swap agreement $ 1,954 $ 1,954
Interest rate protection agreements (993) (993)
Long-tem debt 217,151 231,000
Preferred shares subject to mandatory redemption (a) 20,000 20,000
2003:
Interest rate protection agreement $ 1,953 $ 1,953
Long-tem debt 217,271 233,000
Preferred shares subject to mandatory redemption (a) 20,000 20,900
(a) On October 1, 2004, we redeemed all preferred shares subject to mandatory
redemption.
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 Stockshares subject to mandatory redemption
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, 20032004 and 2002,2003, we had no significant
concentrations of credit risk.
F-26F-24
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.
F-25
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Financial information by business segment follows:
Gas Electric
Total Utility Operations
- ------------------------------------------------------------------------------------- -------- ----------
2004
Revenues $650,088 $560,400 $ 89,688
Cost of sales 412,240 368,906 43,334
Depreciation and amortization 22,520 19,516 3,004
Operating income 101,029 80,097 20,932
Interest expense 17,931 15,944 1,987
Income before income taxes 83,098 64,153 18,945
Total assets 855,778 765,954 89,824
Capital expenditures 40,737 35,470 5,267
2003
Revenues $ 636,758 $ 539,862$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$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 7,98073,665 62,924 10,741
Total assets 784,409 678,947 105,462798,123 689,080 109,043
Capital expenditures 36,783 31,757 5,02635,884 31,034 4,850
F - 27F-26
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. OTHER INCOME, NET
Other income, net, comprises the following:
2004 2003 2002
------ ------ -------
Non-tariff service income $2,048 $5,693 $ 5,701
Pension income -- 1,242 3,858
Interest income 183 128 1,110
Other, net 438 1,682 1,054
------ ------ -------
$2,669 $8,745 $11,723
====== ====== =======
12. RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities.
UGI bills UGI Utilities monthly for all direct and for an allocated share of
indirect corporate expenses incurred or paid on behalf of UGI Utilities. These
billed expenses are classified as operating and administrative expenses -
related parties in the Consolidated Statements of Income. In addition, UGI
Utilities provides limited administrative services to UGI and certain of UGI's
subsidiaries, largely payroll related services. Amounts billed to these
entities by UGI Utilities is not material.
Gas Utility enters into wholesale natural gas transactions with UGI Energy
Services, Inc. ("Energy Services"), a wholly owned second-tier subsidiary
of UGI, for winter peaking service and, from time to time, purchases of
natural gas or pipeline capacity. During 2004, 2003 and 2002, the aggregate
amount of these transactions totaled $6,257, $4,709 and $2,614, respectively. In
addition, from time to time, the Company sells natural gas or pipeline capacity
to Energy Services. During 2004, 2003 and 2002, revenues associated with these
sales to Energy Services totaled $1,698, $4,234 and $17,379, respectively. These
transactions did not have a material effect on the Company's net income during
2004, 2003 and 2002.
13. 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 2004 2003 20022004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------2004 2003
-------- -------- -------- -------- -------- -------- ------- -------
Revenues $170,684 $168,351 $141,481$268,217 $269,296 $179,945$118,717 $121,546 $ 88,249 $ 77,565 $ 80,877$92,470 $77,565
Operating income 33,950 38,830 27,60953,277 63,449 41,31912,282 10,005 13,2221,520 5,584 8,167
Net income (loss) 17,508 20,714 14,04529,149 35,399 22,5494,495 3,640 5,552(2,194) 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 - 28F-27
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, 2004
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 3,275 $ 6,971 $ (6,872) (1) $ 3,374
============= =============
Other reserves (3) $ 3,616 $ 3,552 $ (1,314) (2) $ 5,854
============= =============
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 Bylaws10.26 Amendment No. 1 dated November 1, 2004, to the Service Agreement
(Rate FSS) dated as amended through September 30, 2003
10.19of November 1, 1989 between Utilities and
Columbia, as modified pursuant to the orders of the Federal Energy
Regulatory Commission at Docket No. RS92-5-000 reported at
Columbia Gas Transmission Corp., 64 FERC 61,060 (1993), order on
rehearing, 64 FERC 61,365 (1993)
10.30 Amendment No. 1 dated November 1, 2004, to the No-Notice
Transportation Service Agreement (Rate Schedule CDS) between
Utilities and Texas Eastern Transmission dated February 23, 1999,
as modified pursuant to various orders of the Federal Energy
Regulatory Commission
10.32 Gas Service Delivery and Supply Agreement between Utilities and
UGI Energy Services, Inc. dated August 26, 2004
10.33 Amendment No. 1 dated November 1, 2004, to the Firm Transportation
Service Agreement (Rate Schedule FT-1) between Utilities Inc. Severance Plan for Exempt Employees
in Salary Grades 34-37 and Salary Grades 18-23 effective
JanuaryTexas
Eastern Transmission dated June 15, 1999, as modified pursuant to
various orders of the Federal Energy Regulatory Commission
10.34 Firm Transportation Service Agreement (Rate Schedule FTS) between
Utilities and Columbia Gas Transmission dated November 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 Greenberg2004
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 relatingpursuant to Section
302 of the Registrant's Report on Form 10-K forSarbanes-Oxley Act
31.2 Certification by the year ended
September 30, 2003Chief Financial Officer pursuant to Section
302 of the Sarbanes-Oxley Act
of 2002
31.2*32 Certification by theChief Executive Officer and 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 Act906 of 2002
32 Certification by Chief Executive Officer and Chief
Financial Officerthe Sarbanes-Oxley Act
* The Exhibit attached to this Form 10-K shall not be deemed "filed" for
purposes of Section 18 of the Securities Exchange Act of 1934, as amended
(the "Exchange Act"), or otherwise subject to liability under that section,
nor shall it be deemed incorporated by reference in any filing under the
Securities Act of 1933, as amended, or the Exchange Act, except as
expressly set forth by specific reference in such filing.