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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, 2005
Commission file number 1-1398
UGI UTILITIES, INC.
Pennsylvania 23-1174060
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
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)
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
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 if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act. Yes [X] No [ ].
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X].
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).Yes[ ] No[X].
Indicate by check mark whether registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes [ ] No [X].
At September 30, 2005, there were 26,781,785 shares of UGI Utilities Common
Stock, par value $2.25 per share, outstanding, all of which were held,
beneficially and of record, by UGI Corporation.
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
<Table>
<Caption>
PAGE
PART I: ............................................................2
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Items 1. and 2. Business and Properties...............................2
Item 1A. Risk Factors..........................................8
Item 1B. Unresolved Staff Comments............................10
Item 3. Legal Proceedings....................................10
PART II: ............................................................13
Item 5. Market for Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities...........................................13
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................13
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk..........................................29
Item 8. Financial Statements and Supplementary Data..........29
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..................29
Item 9A. Controls and Procedures..............................29
Item 9B. Other Information....................................30
PART III: ............................................................31
Item 14. Principal Accounting Fees and Services...............32
PART IV: ............................................................32
Item 15. Exhibits and Financial Statement Schedules...........32
Signatures.............................................................39
Index to Financial Statements and Financial Statement Schedule...............F-2
</Table>
(i)
PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. ("Utilities," "UGI Utilities" or the "Company") is a
public utility company that owns and operates (i) a natural gas distribution
utility serving customers in 15 counties in eastern and southeastern
Pennsylvania ("Gas Utility"), and (ii) an electric utility serving parts of
Luzerne and Wyoming counties in northeastern Pennsylvania ("Electric Utility").
We are a wholly owned subsidiary of UGI Corporation ("UGI").
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
SERVICE AREA; REVENUE ANALYSIS
Gas Utility distributes natural gas to approximately 307,000 customers in
portions of 15 eastern and southeastern Pennsylvania counties through its
distribution system of approximately 5,000 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 2005 fiscal year was
approximately 84.7 billion cubic feet ("bcf"). System sales of gas accounted for
approximately 41% of system throughput, while gas transported for residential,
commercial and industrial customers (who bought their gas from others) accounted
for approximately 59% of 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 marketers and producers, along with 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, Gas Utility has agreements with a
number of pipeline companies, including Texas Eastern Transmission Corporation,
Columbia Gas Transmission Corporation and Transcontinental Gas Pipeline
Corporation.
-2-
GAS SUPPLY CONTRACTS
During fiscal year 2005, Gas Utility purchased approximately 40 bcf of
natural gas for sale to retail core market and off-system sales customers.
Approximately 80% of the volumes purchased were supplied under agreements with
ten suppliers. The remaining 20% of gas purchased was supplied by approximately
20 producers and marketers. Gas supply contracts are generally no longer than
one year.
SEASONAL VARIATION
Because many of its customers use gas for heating purposes, Gas Utility
sales are seasonal. Approximately 57% of fiscal year 2005 throughput occurred
during the winter season from November through March.
COMPETITION
Natural gas is a fuel that competes with electricity and oil, and to a
lesser extent, with propane and coal. Competition among these fuels is primarily
a function of their comparative price and the relative cost and efficiency of
fuel utilization equipment. Electric utilities in Gas Utility's service area are
seeking new load, primarily in the new construction market. 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, Utilities is the only
regulated gas distribution utility having the right, granted by the PUC or by
law, to provide gas distribution services. Since the 1980s, larger commercial
and industrial 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 Competition Act"), effective July 1, 1999 all of Gas
Utility's customers, including residential and smaller commercial and industrial
customers ("Core Market Customers"), have been afforded this opportunity. Under
the Gas Competition Act, retail customers may purchase their natural gas from a
supplier other than Gas Utility. As of October 2005, one marketer provides gas
supplies to approximately 3,800 Core Market Customers. Gas Utility provides
transportation services for its customers who purchase natural gas from others.
A number of Gas Utility's commercial and industrial customers have the
ability to switch to an alternate fuel at any time and, therefore, are served on
an interruptible basis under rates which are competitively priced with respect
to the alternate fuel. Margin from these customers, therefore, is affected by
the difference or "spread" between the customers' delivered cost of gas and the
customers' delivered cost of the alternate fuel, as well as the frequency and
duration of interruptions. See "Gas Utility and Electric Utility Regulation and
Rates -- Gas Utility Rates." In accordance with the PUC's June 29, 2000 Gas
Restructuring Order, margin from certain of these customers (who use pipeline
capacity contracted by Gas Utility to serve retail customers) is used to reduce
purchased gas cost rates for retail customers. Approximately 27% of Gas
Utility's commercial and industrial customers, including certain customers
served under interruptible rates, have locations which afford them the
opportunity, although none have exercised it, of seeking transportation service
directly from interstate pipelines, thereby bypassing Gas Utility.
-3-
The majority of customers in this group are served under transportation
contracts having three-year to twenty-year terms. Included in these two customer
groups are Gas Utility's ten largest customers in terms of annual volumes. All
of these customers have contracts, seven of which extend beyond Fiscal 2006. No
single customer represents, or is anticipated to represent, more than 5% of Gas
Utility's total revenues.
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 2006. Supply mix is diversified, market priced,
and delivered pursuant to a number of long-term and short-term firm
transportation and storage arrangements, including transportation contracts held
by some of Gas Utility's larger customers. Hurricane activity during late fiscal
year 2005 caused temporary losses of gas supply and temporary pipeline force
majeure declarations. We do not expect these disruptions to adversely affect Gas
Utility's ability to obtain adequate supply.
During fiscal year 2005, Gas Utility supplied transportation service to
two major co-generation installations and one electric generation facility. 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 9,900 residential heating customers during fiscal year 2005. Of
those new customers, new home construction accounted for over 7,300 heating
customers. Customers converting from other energy sources, primarily oil and
electricity, and existing non-heating gas customers who have added gas heating
systems to replace other energy sources, accounted for the balance of the
additions. The number of new commercial and industrial customers was
approximately 1,400.
Gas Utility continues to monitor and participate, where appropriate, in
rulemaking and individual rate and tariff proceedings before the Federal Energy
Regulatory Commission ("FERC") affecting the rates and the terms and conditions
under which Gas Utility transports and stores natural gas. Among these
proceedings are those arising out of certain FERC orders and/or pipeline filings
which relate to (i) the pricing of pipeline services in a competitive energy
marketplace; (ii) the flexibility of the terms and conditions of pipeline
service tariffs and contracts; and (iii) pipelines' requests to increase their
base rates, or change the terms and conditions of their storage and
transportation services.
Gas Utility's objective in negotiations with interstate pipeline and
natural gas suppliers, and in proceedings before regulatory agencies, is to
assure availability of supply, transportation and storage alternatives to serve
market requirements at the lowest cost possible, taking into account the need
for security of supply. Consistent with that objective, Gas Utility negotiates
the terms of firm transportation capacity on all pipelines serving 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.
-4-
ELECTRIC UTILITY
SERVICE AREA; SALES ANALYSIS
Electric Utility supplies electric service to approximately 62,000
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 2005, about 53% of sales volume came from residential customers, 35% from
commercial customers and 12% from industrial customers. Electricity transported
for customers who purchased their power from other suppliers represented less
than 1% of fiscal year 2005 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 2006.
Electric Utility distributes both electricity that it purchases from others and
electricity that customers purchase from other suppliers. At September 30, 2005,
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. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Market Risk Disclosures" for a discussion of risks related to Electric Utility's
supply contracts.
COMPETITION
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 were
increased 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 accounted for approximately 19% of total sales
of electricity during the 2005 fiscal year. Electricity competes with natural
gas, oil, propane and other heating fuels for this use.
-5-
GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES
PENNSYLVANIA PUBLIC UTILITY COMMISSION JURISDICTION
Utilities' gas and electric utility operations are subject to regulation
by the PUC as to rates, terms and conditions of service, accounting matters,
issuance of securities, contracts and other arrangements with affiliated
entities, and various other matters.
ELECTRIC TRANSMISSION AND WHOLESALE POWER SALE RATES
FERC has jurisdiction over the rates and terms and conditions of service
of electric transmission facilities used for wholesale or retail choice
transactions. Electric Utility owns electric transmission facilities that are
within the control area of the PJM Interconnection, LLC ("PJM") and are
dispatched in accordance with a FERC-approved open access tariff and associated
agreements administered by PJM. Electric Utility receives certain revenues
collected by PJM when its transmission facilities are used by third parties.
In addition, FERC has jurisdiction over the rates and terms and conditions
of service of wholesale sales of electric capacity and energy. Electric Utility
has a tariff on file with FERC pursuant to which it may make power sales to
wholesale customers at market-based rates.
GAS UTILITY RATES
The most recent general base rate increase for Gas Utility became
effective in 1995. A rate increase for firm-residential, commercial and
industrial customers ("retail core-market") became effective October 1, 2000.
Effective December 1, 2001, Gas Utility was required to reduce its Purchased Gas
Cost ("PGC") rates to retail core-market customers by an amount equal to the
margin it receives from customers served under interruptible rates to the extent
interruptible customers use capacity contracted for by Gas Utility for retail
core-market customers.
Gas Utility's gas service tariff contains PGC rates that provide for
annual increases or decreases in the rate per thousand cubic feet ("mcf") that
Gas Utility charges for natural gas sold by it, to reflect Gas Utility's
projected cost of purchased gas. PGC rates may also be adjusted quarterly, or,
under certain conditions monthly, to reflect the actual cost of gas. Quarterly
adjustments become effective on one day's notice to the PUC and are subject to
review during the next annual PGC filing. 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. Gas Utility has two PGC rates. PGC (1) is applicable to small,
firm, retail core-market customers consisting of the residential and small
commercial and industrial classes; PGC (2) is applicable to firm, contractual,
high-load factor customers served on three separate rates. In addition,
residential customers maintaining a high load factor may qualify for the PGC (2)
rate. As described above, Gas Utility's PGC rates are adjusted to reflect
margins, if any, from interruptible rate customers who do not obtain their own
pipeline capacity.
-6-
ELECTRIC UTILITY RATES
The most recent general base rate increase for Electric Utility became
effective in 1996. Electric Utility's POLR rates were increased beginning
January 2005, and Electric 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 POLR regulations that are expected to
further define POLR service obligations and pricing. As of September 30, 2005,
fewer than 1% of Electric Utility's customers have an alternative electricity
generation supplier.
FERC MARKET MANIPULATION RULES AND OTHER FERC ENFORCEMENT AND REGULATORY POWERS
Both Gas Utility and Electric Utility are subject to FERC regulations
governing the manner in which certain jurisdictional sales or transportation are
conducted. Section 315 of the Energy Policy Act of 2005 ("EPAct 2005") became
effective on August 8, 2005 and prohibits any manipulative or deceptive devices
or contrivances in connection with the purchase or sale of natural gas, electric
energy or transportation or transmission services subject to the jurisdiction of
FERC. FERC is in the process of adopting regulations to implement this statute,
which would apply to interstate transportation and sales by the Electric
Utility, and to a much more limited extent, to certain sales and transportation
by the Gas Utility that are subject to FERC. Gas Utility and Electric Utility
are subject to certain other regulations and obligations for FERC-regulated
activities and EPAct 2005 also conferred upon FERC substantially expanded
authority to impose civil penalties for the violation of any regulations, orders
or provisions under the Federal Power Act and Natural Gas Act.
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 effects
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.
-7-
OTHER GOVERNMENT REGULATION
In addition to regulation by the PUC and FERC, 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. Utilities is subject to the requirements of the
federal Resource Conservation and Recovery Act, CERCLA and comparable state
statutes with respect to the release of hazardous substances on property owned
or operated by Utilities. See ITEM 3. "LEGAL PROCEEDINGS - Environmental
Matters-Manufactured Gas Plants."
EMPLOYEES
At September 30, 2005, Utilities had approximately 1,000 employees.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income and
identifiable assets attributable to Utilities' operating segments for the 2005,
2004 and 2003 fiscal years appears in Note 10 to the Consolidated Financial
Statements included in this Report and is incorporated herein by reference.
ITEM 1A. RISK FACTORS
DECREASES IN THE DEMAND FOR NATURAL GAS AND ELECTRICITY BECAUSE OF
WARMER-THAN-NORMAL HEATING SEASON WEATHER COULD ADVERSELY AFFECT OUR RESULTS OF
OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS BECAUSE OUR RATE STRUCTURE DOES
NOT CONTAIN WEATHER NORMALIZATION PROVISIONS.
Because many of our customers rely on natural gas or electricity to heat
their homes, our results of operations are adversely affected by
warmer-than-normal heating season weather. Weather conditions have a significant
impact on the demand for natural gas and electricity for heating purposes.
Accordingly, demand for natural gas and electricity is generally at its highest
during the five-month peak heating season of November through March and is
directly affected by the severity of the winter weather. Our rate structure does
not contain weather normalization provisions to compensate for
warmer-than-normal weather conditions, and we have historically sold less
natural gas and electricity when weather conditions are milder and,
consequently, earned less income. As a result, warmer-than-normal heating season
weather could reduce our net income and harm our financial condition and
adversely affect our cash flows.
INCREASES IN NATURAL GAS AND ELECTRICITY MARKET PRICES COULD ADVERSELY
AFFECT OUR BUSINESS.
Prices for natural gas are subject to volatile fluctuations in response to
changes in supply and other market conditions. During periods of high natural
gas costs, our prices generally increase. High prices can lead to customer
conservation, resulting in reduced demand for our product.
Similarly, beginning in 2007 when our current mandatory rate caps expire,
increases in the market price of electricity could cause us to raise the prices
that we charge our customers, which in turn could reduce demand for our
electricity. This could lower our revenues, and, therefore, lower our net income
and adversely affect our cash flows.
-8-
ELECTRICITY SUPPLIER DEFAULTS MAY ADVERSELY AFFECT OUR RESULTS OF
OPERATIONS.
Generally, we purchase our power needs from electricity suppliers under
fixed-price energy and capacity contracts. Should any of the suppliers under
these contracts fail to provide electric power under the terms of these
contracts, any increases in the cost of replacement power or capacity could
negatively impact our results and adversely affect our cash flows because of our
inability to recover these potential cost increases in our current rates.
IF THE PUC DOES NOT INCREASE THE PROVIDER OF LAST RESORT RATES FOR 2007,
ELECTRIC UTILITY'S RESULTS MAY BE ADVERSELY AFFECTED.
Electric Utility remains the provider of last 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, and
rules governing the rates that may be charged for such service, have been
established through December 31, 2006 in a series of PUC-approved settlements.
Electric Utility has no agreement currently in place for POLR rates to be
effective after December 31, 2006. Although Electric Utility expects it will be
able to recover electric power costs incurred in serving POLR customers after
December 31, 2006, it is unable to forecast the level of margins, if any, from
providing POLR service.
WE ARE SUBJECT TO OPERATING AND LITIGATION RISKS THAT MAY NOT BE COVERED
BY INSURANCE.
Our business operations are subject to all of the operating hazards and
risks normally incidental to the handling, storage and distribution of
combustible products, such as natural gas. These risks could result in
substantial losses due to personal injury and/or loss of life, severe damage to
and destruction of property and equipment. As a result, we are sometimes a
defendant in legal proceedings and litigation arising in the ordinary course of
business. We maintain insurance policies with insurers in such amounts and with
such coverages and deductibles as we believe are reasonable and prudent. There
can be no assurance, however, that such insurance will be adequate to protect us
from all material expenses related to potential future claims for personal and
property damage or that such levels of insurance will be available in the future
at economical prices.
-9-
REMEDIATION COSTS RESULTING FROM LIABILITY FROM CONTAMINATION CLAIMS COULD
REDUCE OUR NET INCOME.
We are investigating and remediating contamination at a number of present
and former operating sites in the United States, including former sites where we
operated manufactured gas plants. We have also received claims from third
parties that allege that we are responsible for costs to clean up properties
where we or our former subsidiaries operated a manufactured gas plant. Costs we
incur to remediate sites outside of Pennsylvania cannot be recovered in future
utility rate proceedings, and insurance may not cover all or even part of these
costs. Our actual costs to clean up these sites may exceed our current estimates
due to factors beyond our control, such as:
o the discovery of presently unknown conditions;
o changes in environmental laws and regulations;
o judicial rejection of our legal defenses to the third-party claims; or
o the insolvency of other responsible parties at the sites at which we are
involved.
In addition, if we discover additional contaminated sites, we could be
required to incur material costs, which would reduce our net income.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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 contemplated by governmental authorities other
than claims arising in the ordinary course of the Company's business.
ENVIRONMENTAL MATTERS - 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
-10-
of former MGPs. Between 1882 and 1953, 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, Utilities divested all of its utility
operations other than those which now constitute Gas Utility and Electric
Utility by the early 1950s.
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 Utilities 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 private parties allege MGPs were formerly owned or
operated by Utilities or owned or operated by its former subsidiaries. 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.
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 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 costs Citizens may be
required to pay to the City for cleaning up tar deposits in the Penobscot River.
Citizens alleges that Utilities and its predecessors owned and operated the
plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that
it could cost up to $18 million to clean up the river. Citizens' third-party
claims have been stayed pending a resolution of the City's suit against
Citizens, which was tried in September 2005 and has not yet been decided.
Utilities believes that it has good defenses to the claim and is defending the
suit.
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 in the United States District Court for the Southern District
of New York, seeking contribution from Utilities for an allocated share of
response costs associated with investigating and assessing gas plant related
contamination at former MGP sites in Westchester County, New York. The complaint
alleges that Utilities "owned and operated" the MGPs prior to 1904. The
complaint also seeks a declaration that Utilities is responsible for an
allocated percentage of future investigative and remedial costs at the sites.
ConEd believes that the cost of remediation for all of the sites could exceed
$70 million.
The trial court granted Utilities' motion for summary judgment and
dismissed ConEd's complaint. The grant of summary judgment was entered April 1,
2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit
Court of Appeals affirmed in part and reversed in part the decision of the trial
court. The appellate panel affirmed the trial court's decision dismissing claims
that Utilities was liable under CERCLA as an operator of MGPs owned and operated
by its former subsidiaries. The appellate panel reversed the trial court's
decision that Utilities was released from liability at three sites where
Utilities operated MGPs under lease. On
-11-
October 7, 2005 Utilities filed for reconsideration of the panel's order.
Utilities believes that any liability it may have for a share of the response
costs at the three leased MGP sites will not have a material effect on its
financial condition or results of operations.
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. On March 22, 2005, the court granted
Utilities' motion for summary judgment. AGL has appealed.
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 a 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 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.
-12-
PART II:
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, 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 $38.5
million in fiscal year 2005, $45.0 million in fiscal year 2004 and $33.9 million
in fiscal year 2003.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
BUSINESS OVERVIEW
UGI Utilities, a wholly owned subsidiary of UGI Corporation, owns and operates a
natural gas distribution utility in parts of eastern and southeastern
Pennsylvania, and an electricity distribution utility in northeastern
Pennsylvania. UGI Utilities is regulated by the Pennsylvania Public Utility
Commission ("PUC"). UGI Utilities' operations are managed with the goal of
growing its business in a profitable manner without the need for frequent base
rate increases. Gas Utility's rate of customer growth exceeds the national
averages for local gas distribution companies ("LDCs"), and its proximity to
major population centers and its extensive transportation infrastructure makes
its service territory a desired location for homes and businesses. Because many
customers use natural gas and electricity for heating purposes, Gas Utility's
and to a lesser extent Electric Utility's results are seasonal with the
peak-heating season comprising the months of November through March.
In conducting its business operations, UGI Utilities' management focuses its
attention on those factors it believes have a significant effect on the
successful operation of the business. These factors include, among others,
regulation by the PUC, pursuing customer growth in its service territory and
controlling operating costs in order to maintain competitive prices.
Year-to-year weather variations can have a significant impact on the Company's
results. To a lesser extent, customer behavior in response to increases and
volatility in natural gas costs can also affect the Company's results. Gas
Utility's tariffs contain purchased gas cost rates that permit recovery of
substantially all of the prudently incurred costs of natural gas it sells to its
customers. These tariffs provide for annual increases or decreases in rates that
Gas Utility charges for natural gas sold by it to reflect projected costs of
purchased gas. These rates may be adjusted quarterly or, under certain
-13-
conditions monthly, to reflect the actual cost of gas. Because of this
ratemaking process, there is limited commodity price risk associated with Gas
Utility operations. Electric Utility is subject to commodity price risk for
electricity as its rates for electric generation under Provider of Last Resort
("POLR") settlements contain rate caps which provide limited protection against
electricity price increases. Management attempts to reduce natural gas product
cost volatility through the use of call options, fixed-price forward contracts
and storage services. Management attempts to reduce electric price volatility by
entering into price swap agreements and fixed-price forward contracts. Because a
number of Gas Utility's customers have the ability to switch to an alternate
fuel at any time and are therefore served on an interruptible basis,
profitability for these customers is affected by the difference between the
delivered cost of gas and the delivered cost of the alternate fuel in addition
to the frequency and duration of service interruptions.
The following Management's Discussion and Analysis of Financial Condition and
Results of Operations ("MD&A") compares the results of the Company's operations
covering the three-year period ended September 30, 2005. Electric Utility and
the electric generation business of UGI Development Company ("UGID") prior to
its distribution to UGI in June 2003 are collectively referred to herein 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 2005 COMPARED WITH FISCAL 2004
<Table>
<Caption>
Year Ended September 30, 2005 2004 Increase
- -----------------------------------------------------------------------------------
(Millions of dollars)
GAS UTILITY:
Revenues $ 585.1 $ 560.4 $ 24.7 4.4 %
Total margin (a) $ 195.0 $ 191.5 $ 3.5 1.8 %
Operating income $ 81.6 $ 80.1 $ 1.5 1.9 %
Income before income taxes $ 65.0 $ 64.2 $ 0.8 1.2 %
System throughput - bcf 84.7 82.2 2.5 3.0 %
Degree days - % warmer
than normal 1.4% 2.9% -- --
ELECTRIC UTILITY:
Revenues $ 96.1 $ 89.7 $ 6.4 7.1 %
Total margin (a) $ 43.1 $ 41.5 $ 1.6 3.9 %
Operating income $ 21.6 $ 20.9 $ 0.7 3.3 %
Income before income taxes $ 19.9 $ 18.9 $ 1.0 5.3 %
Distribution sales - gwh 1,021.8 983.9 37.9 3.9 %
</Table>
bcf -- billions of cubic feet. gwh -- millions of kilowatt hours.
(a) Gas Utility's total margin represents total revenues less total cost
of sales. Electric Utility's total margin represents total revenues
less total cost of sales and revenue-related taxes, i.e. Electric
Utility gross receipts taxes of $5.2 million in Fiscal 2005 and $4.8
million in Fiscal 2004. For financial statement purposes, Gas Utility's
and Electric Utility's cost of sales are 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.
-14-
GAS UTILITY. Weather in Gas Utility's service territory based upon heating
degree days was 1.4% warmer than normal in Fiscal 2005 compared with weather
that was 2.9% warmer than normal in Fiscal 2004. Total distribution system
throughput increased in Fiscal 2005 due primarily to greater interruptible
delivery service volumes. Notwithstanding the volume effects of the slightly
colder weather and an increase in the number of firm- residential, commercial
and industrial ("retail core-market") customers, Fiscal 2005 retail core-market
throughput was substantially equal to Fiscal 2004 primarily due to a reduction
in customer usage per degree day. We believe that the lower usage per degree day
was primarily the result of conservation in response to higher natural gas
prices. These higher natural gas prices are passed through to retail core-market
customers through higher purchased gas cost ("PGC") rates.
The increase in Gas Utility revenues during Fiscal 2005 is principally the
result of a $53.4 million increase in retail core-market revenues reflecting
higher average PGC rates and, to a lesser extent, the increase in throughput
and higher revenues from interruptible customers. These increases were partially
offset by a $37.2 million decrease in revenues from low-margin off-system sales.
Increases or decreases in retail core-market customer revenues and cost of sales
results principally from changes in retail core-market volumes 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 at amounts included in PGC rates. The difference between
actual gas costs and the amount included in rates is deferred on the balance
sheet as a regulatory asset or liability and represents amounts to be collected
from or refunded to customers in a future period. As a result of the PGC
recovery mechanism, 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's cost of gas was $390.1 million in Fiscal 2005 compared to $368.9
million in Fiscal 2004 reflecting the effects of the higher PGC rates partially
offset by lower cost of sales associated with lower off-system sales.
The $3.5 million increase in Gas Utility total margin in Fiscal 2005 principally
reflects greater margin generated from higher interruptible delivery service
volumes and higher average interruptible delivery service unit margins. The
increase in average interruptible delivery service unit margins reflects an
increase in the spread between delivered prices for natural gas and alternative
fuels, principally oil. Gross margin from retail core-market customers was
relatively stable as lower usage per degree day was offset by an increase in the
number of customers.
Gas Utility operating income increased $1.5 million in Fiscal 2005 as the $3.5
million increase in total margin and a $1.9 million increase in other income
were partially offset by higher operating and administrative expenses and a $1.2
million increase in depreciation and amortization. The increase in other income
is due in large part to the absence of costs recorded in Fiscal 2004 related to
a regulatory claim resulting from the discontinuance of natural gas service to
certain customers. Fiscal 2005 operating and administrative expenses were
slightly higher than in Fiscal 2004 as a $1.9 million increase in uncollectible
accounts and customer assistance expenses, the absence of environmental
insurance settlements received in the prior year and higher professional
services expenses were partially offset by lower injuries and damages and
distribution system expenses. The increase in depreciation expense reflects the
normal effects of yearly capital expenditures. The increase in Gas Utility
income before income taxes in Fiscal 2005 reflects the increase in operating
income partially offset by higher interest expense resulting from higher average
short-term debt outstanding and higher short-term interest rates.
-15-
ELECTRIC UTILITY. Electric Utility's Fiscal 2005 kilowatt-hour sales increased
principally reflecting slightly colder Fiscal 2005 heating-season weather and
warmer Fiscal 2005 cooling-season weather which increased sales for air
conditioning. The increase in Electric Utility revenues principally reflects the
effects of a 4.5% increase in its Provider of Last Resort ("POLR") electric
generation rates effective January 1, 2005 and the higher kilowatt-hour sales.
Electric Utility's cost of sales increased $4.5 million as a result of higher
per-unit purchased power costs and the higher sales.
Electric Utility total margin in Fiscal 2005 increased $1.6 million principally
as a result of the previously mentioned increase in POLR rates and the higher
kilowatt-hour sales partially offset by the increase in per-unit purchased power
costs. Operating income and income before income taxes in Fiscal 2005 were
higher than the prior year as the increase in total margin was partially offset
by higher operating and administrative costs, principally higher incentive
compensation and distribution system maintenance expenses.
FISCAL 2004 COMPARED WITH FISCAL 2003
<Table>
<Caption>
Increase
Year Ended September 30, 2004 2003 (Decrease)
- ----------------------------------------------------------------------------------
(Millions of dollars)
GAS UTILITY:
Revenues $560.4 $539.9 $ 20.5 3.8 %
Total margin $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 (a):
Revenues $ 89.7 $ 96.9 $ (7.2) (7.4)%
Total margin (b) $ 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 %
</Table>
(a) Fiscal 2003 includes the results of UGID prior to its distribution to
UGI in June 2003.
(b) Electric Operations' 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.
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
-16-
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 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 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 rates reflecting the pass through of 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 reflecting 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.
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
from delivery-service customers.
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
on 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 part to greater air conditioning
sales partially offset by the adverse effects of warmer 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 reflected 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 taxes were lower
in Fiscal 2004 principally reflecting the decline in total margin.
-17-
FINANCIAL CONDITION AND LIQUIDITY
CAPITALIZATION AND LIQUIDITY
UGI Utilities' total debt outstanding was $318.2 million at September 30, 2005.
Included in this amount is $81.2 million of bank loans outstanding.
UGI Utilities has revolving credit commitments under which it may borrow up to a
total of $110 million. These agreements are currently scheduled to expire in
June 2007 through June 2008. UGI Utilities from time to time enters into
short-term borrowings under uncommitted arrangements with major banks in order
to meet liquidity needs during the peak heating season. At September 30, 2005,
UGI Utilities had two separate $35 million borrowings outstanding under these
uncommitted arrangements and $11.2 million under the revolving credit
facilities. Borrowings under the uncommitted arrangements mature in February and
March 2006. Amounts outstanding under the revolving credit agreements and the
uncommitted arrangements 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.
In November 2004, UGI Utilities borrowed $20 million from a major bank which was
repaid on March 1, 2005. During Fiscal 2005 and Fiscal 2004, peak bank loan
borrowings totaled $91.4 million and $90.9 million, respectively. Peak bank loan
borrowings typically occur during the peak heating season months of December and
January. Average daily bank loan borrowings were $52.9 million in Fiscal 2005
and $44.5 million in Fiscal 2004. The higher amounts outstanding in Fiscal 2005
reflect, in large part, higher natural gas prices and the associated increase in
working capital. Average and peak bank loan borrowings are expected to increase
in Fiscal 2006 due in large part to higher natural gas costs.
On October 1, 2004, UGI Utilities redeemed all 200,000 shares of its $7.75
Series Preferred Stock at a price of $100 per share together with full
cumulative dividends. The redemption was funded with 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 $125 million of Medium-Term Notes or other debt
securities. Medium-Term Notes of $50 million maturing in December 2005 are
expected to be refinanced through the issuance of debt under this shelf
registration.
Based upon cash expected to be generated from Gas Utility and Electric Utility
operations, short-term borrowings under revolving credit agreements and
uncommitted arrangements, and the Company's ability to issue debt under its
Medium-Term Note program, management believes that Utilities will be able to
meet its anticipated contractual and projected cash commitments during Fiscal
2006. For additional discussion of Utilities' long-term debt and revolving
credit facilities, see Note 3 to Consolidated Financial Statements.
CASH FLOWS
OPERATING ACTIVITIES. Due to the seasonal nature of UGI 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 usually at their lowest levels during the first and fourth fiscal quarters
when the Company's investment in working capital, principally accounts
receivable
-18-
and inventories, is generally greatest. UGI Utilities uses its revolving credit
agreements and uncommitted arrangements with major banks to satisfy its seasonal
operating cash flow needs. Cash flow from operating activities was $68.3 million
in Fiscal 2005, $67.0 million in Fiscal 2004, and $97.8 million in Fiscal 2003.
Cash flow from operating activities before changes in operating working capital
was $86.3 million in Fiscal 2005, $92.9 million in Fiscal 2004 and $91.8 million
in Fiscal 2003. Changes in operating working capital used $18.0 million of
operating cash flow in Fiscal 2005, used $26.0 million of operating cash flow in
Fiscal 2004 and provided $6.0 million of operating cash flow in Fiscal 2003.
Fiscal 2005 changes in operating working capital includes $11.0 million of cash
flow from electric supplier collateral deposits and greater cash from purchased
gas cost overcollections partially offset by a decrease in accounts payable.
INVESTING ACTIVITIES. Cash flow used in investing activities was $47.5 million
in Fiscal 2005, $42.4 million in Fiscal 2004 and $43.1 million in Fiscal 2003.
Expenditures for property, plant and equipment were $46.3 million in Fiscal
2005, $40.7 million in Fiscal 2004 and $41.3 million in Fiscal 2003. The higher
2005 capital expenditures principally reflect higher Electric Utility
distribution and transmission system capital expenditures and greater
information system expenditures. Net costs of property, plant and equipment
disposals which principally represent net costs associated with retirements of
distribution system assets were $1.2 million in Fiscal 2005, $1.7 million in
Fiscal 2004 and $1.8 million in Fiscal 2003.
FINANCING ACTIVITIES. Cash flow used by financing activities was $18.2 million
in Fiscal 2005, $24.8 million in Fiscal 2004 and $60.5 million in Fiscal 2003.
Financing activity cash flow changes are primarily due to issuances and
repayments of long-term debt and preferred stock, net short-term borrowings
including borrowings under revolving credit facilities, dividends on common
stock, capital contributions from UGI and, prior to the adoption of SFAS 150
effective July 1, 2003, dividends on preferred shares subject to mandatory
redemption.
As previously mentioned, in September 2005, UGI Utilities entered into two $35
million borrowings which are scheduled to mature in February and March 2006. In
May 2005, UGI Utilities refinanced $20 million of its maturing 6.62% Medium-Term
Notes through the issuance of 5.16% Medium-Term Notes due in May 2015. Also
during Fiscal 2005, UGI Utilities borrowed and repaid $20 million associated
with a short-term loan that matured on March 1, 2005. On October 1, 2004, UGI
Utilities redeemed all 200,000 shares of $7.75 Series Preferred Stock at a price
of $100 per share together with full cumulative dividends. The redemption of the
$7.75 Series Preferred Stock was funded with proceeds from the October 2004
issuance of $20 million of 6.13% Medium-Term Notes due 2034.
During Fiscal 2005, 2004 and 2003, we paid cash dividends to UGI of $38.5
million, $45.0 million and $33.9 million, respectively. Although we paid
dividends on our preferred shares subject to mandatory redemption of $1.6
million in Fiscal 2004 and 2003, only dividends paid on the preferred shares
subject to mandatory redemption before July 1, 2003 are reflected in cash flow
from investing activities (see "Preferred Shares Subject to Mandatory
Redemption" below).
-19-
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 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 on 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, dividends on these preferred shares were
reflected as a deduction from net income. 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) was eliminated from the consolidated balance
sheet and reflected as a dividend from retained earnings.
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. The
fair value of Pension Plan assets was $211.7 million and $196.4 million at
September 30, 2005 and 2004, respectively. At September 30, 2005 and 2004, the
Pension Plan's assets exceeded its accumulated benefit obligations by $7.4
million and $9.2 million, respectively. The Company is in full compliance with
regulations governing defined benefit pension plans, including Employee
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 2006. Pre-tax pension expense (income) reflected in Fiscal 2005, 2004 and
2003 results was $2.5 million, $1.0 million and $(1.2) million, respectively.
The increase in pension expense over this period reflects the changes in the
market value of Pension Plan assets and decreases in the discount rate
assumption. In addition, Fiscal 2005 pension expense reflects the expiration of
the Pension Plan's transition asset amortization. Pension expense in Fiscal 2006
is expected to be approximately $2.3 million.
CAPITAL EXPENDITURES
In the following table, we present capital expenditures by business segment for
Fiscal 2005, Fiscal 2004 and Fiscal 2003. We also provide amounts we expect to
spend in Fiscal 2006. We expect to finance a substantial portion of Fiscal 2006
capital expenditures from cash generated by operations and the remainder from
borrowings under our credit facilities.
-20-
<Table>
<Caption>
Year Ended September 30, 2006 2005 2004 2003
- --------------------------------------------------------------------------------
(Millions of dollars) (estimate)
Gas Utility $47.6 $38.8 $35.5 $37.2
Electric Utility 8.6 7.5 5.3 4.1
----- ----- ----- -----
$56.2 $46.3 $40.8 $41.3
----- ----- ----- -----
</Table>
CONTRACTUAL CASH OBLIGATIONS AND COMMITMENTS
Utilities has contractual cash obligations that extend beyond Fiscal 2005
including scheduled repayments of long-term debt and interest, operating lease
obligations, unconditional purchase obligations for 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, 2005 (in millions of
dollars).
<Table>
<Caption>
Payments Due by Period
---------------------------------------------------
1 year 2 - 3 4 - 5 After
Total or less years years 5 years
- -------------------------------------------------------------------------------------------------
Long-term debt and associated interest $387.5 $ 63.8 $ 41.9 $ 20.4 $261.4
Operating leases 14.8 3.9 5.8 2.4 2.7
Gas Utility and Electric Utility supply,
storage and transportation contracts 570.2 250.9 149.0 95.4 74.9
------ ------ ------ ------ ------
Total $972.5 $318.6 $196.7 $118.2 $339.0
------ ------ ------ ------ ------
</Table>
RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI
bills UGI Utilities monthly for all direct corporate expenses and for an
allocated share of indirect corporate expenses incurred or paid on behalf of UGI
Utilities. These billed expenses totaled $12.9 million in Fiscal 2005, $11.2
million in Fiscal 2004 and $9.4 million in Fiscal 2003 and are classified as
operating and administrative expenses - related parties in the Consolidated
Statements of Income. UGI Utilities provides limited administrative services to
UGI and certain of UGI's subsidiaries, principally payroll related services.
Amounts billed to these entities by UGI Utilities were not material.
Effective December 1, 2004, following a competitive bidding process, UGI
Utilities entered into a Storage Contract Administration Agreement ("Storage
Agreement") with UGI Energy Services, Inc. ("Energy Services"), a wholly owned,
indirect subsidiary of UGI. The Storage Agreement was initially scheduled to
expire on October 31, 2005, but effective November 1, 2005, UGI Utilities and
Energy Services agreed to extend the Storage Agreement through October 31, 2008.
Under the Storage Agreement, UGI Utilities released certain gas transportation
and storage contracts through October 31, 2008 and transferred associated gas
storage inventories to Energy Services. UGI Utilities may recall such released
transportation and storage contracts without penalty if recalled to meet
operational requirements, and if not recalled, the releases will terminate at
the end of the term of the Storage Agreement. In the event that
-21-
released contracts are recalled or at the expiration of the Storage Agreement,
Energy Services is required to transfer associated gas storage inventories to
UGI Utilities. In exchange for the ability to utilize these assets, Energy
Services pays a monthly fee to UGI Utilities and provides a firm natural gas
delivery service to UGI Utilities. In accordance with the bidding process, UGI
has provided UGI Utilities with performance security in the amount of $20
million. UGI Utilities reflects the historical cost of the gas storage
inventories and any exchange receivable from Energy Services (for any amounts of
gas inventories used but not yet replenished by Energy Services) on its balance
sheet under the caption "Inventories." The carrying value of these gas storage
inventories at September 30, 2005, comprising 8.7 billion cubic feet of natural
gas, was $63.0 million. During Fiscal 2005, UGI Utilities purchased natural gas
storage inventories from Energy Services under the Storage Agreement totaling
$64.4 million, and incurred associated pipeline transportation and storage
capacity charges of $16.3 million.
Gas Utility enters into wholesale natural gas transactions with Energy Services
for winter peaking service and, from time to time, purchases of natural gas or
pipeline capacity. During Fiscal 2005, 2004 and 2003, the aggregate amount of
these transactions (exclusive of Storage Agreement transactions) totaled $8.5
million, $6.3 million, and $4.7 million, respectively. In addition, from time to
time, the Company sells natural gas or pipeline capacity to Energy Services.
During Fiscal 2005, 2004 and 2003, revenues associated with these sales to
Energy Services totaled $4.2 million, $1.7 million and $4.2 million,
respectively. These transactions did not have a material effect on the Company's
net income during Fiscal 2005, 2004 and 2003.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements that are expected to have an
effect on the Company's financial condition, revenues and expenses, results of
operations, liquidity, capital expenditures or capital resources.
REGULATORY MATTERS
Since the 1980s, larger commercial and industrial 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 (the "Gas Competition
Act"), since July 1, 1999, all natural gas consumers in Pennsylvania, including
residential and smaller commercial and industrial customers ("core-market
customers"), have been afforded this opportunity. Gas Utility's gross margin is
not negatively affected by customers who use its transportation service and
purchase natural gas from another supplier because its tariff is designed so
that no profit is earned on the commodity portion of sales to firm customers.
Under the Gas Competition Act, natural gas distribution companies ("NGDCs"),
like Gas Utility, continue to serve as the supplier of last resort for all
core-market customers, and such sales of gas, as well as the distribution
service provided by NGDCs, continue to be subject to rate regulation by the PUC.
As of September 30, 2005, less than two percent of Gas Utility's core-market
customers purchase their gas from alternate suppliers.
-22-
As a result of the Electricity Generation Customer Choice and Competition Act
that became effective January 1, 1997, all of Electric Utility's customers have
the ability to acquire their electricity from entities other than Electric
Utility. Electric Utility remains the provider of last 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, and
rules governing the rates that may be charged for such service, have been
established in a series of PUC approved settlements, the last of which became
effective on June 7, 2004 (collectively, the "POLR Settlement").
Electric Utility's POLR service rules provide 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 must remain on POLR service until the date of the second
open shopping period after returning. Commercial and industrial customers who
return to POLR service must remain on POLR service until the next open shopping
period, and may, in certain circumstances, be subject to generation rate
surcharges. As of September 30, 2005, fewer than 1% of Electric Utility's
customers have chosen an alternative electric generation supplier. In October
2005, Electric Utility was notified by the only alternative electric generation
provider supplying electricity in its service territory that it would cease
providing electric generation service during the first quarter of Fiscal 2006.
In accordance with the POLR Settlement, Electric Utility may increase its POLR
rates up to certain limits through December 31, 2006. Consistent with the terms
of the POLR Settlement, Electric Utility's POLR rates increased 4.5% on January
1, 2005, and Electric Utility is permitted to further increase its POLR rates
beginning January 2006 to no more than 7.5% above the total rates in effect on
December 31, 2004. Electric Utility expects to increase POLR rates by 3%
beginning January 1, 2006. Electric Utility is also permitted to and has entered
into multiple-year fixed-rate POLR contracts with certain of its customers. The
PUC is currently developing post-rate-cap POLR regulations that are expected to
further define POLR service obligations and pricing.
Electric Utility has no agreement currently in place for POLR rates to be
effective after December 31, 2006. The terms of the POLR Settlement require the
POLR Settlement parties to begin discussions on post-2006 POLR rates by April 1,
2006. Although Electric Utility expects it will be able to recover electric
power costs incurred in serving POLR customers after December 31, 2006, it is
unable to forecast the level of margins, if any, from providing POLR service.
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 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.
-23-
MANUFACTURED GAS PLANTS
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 private parties allege MGPs were formerly owned or
operated by it or owned or operated by its former subsidiaries. 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. 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 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.
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 plant from 1901 to 1928. Studies conducted
by the City and Citizens suggest that it could cost up to $18 million to clean
up the river. Citizens' third-party claims have been stayed pending a resolution
of the City's suit against Citizens, which was tried in September 2005 and has
not yet been decided. UGI Utilities believes that it has good defenses to the
claim and is defending the suit.
-24-
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 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. In March 2005, the court granted UGI Utilities' motion
for summary judgment and dismissed AGL's complaint. AGL has appealed.
AGL has informed UGI Utilities that it has begun remediation of MGP wastes at a
site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities
operated the MGP in the early 1900s. AGL 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.
The trial court granted UGI Utilities' motion for summary judgment and dismissed
ConEd's complaint. The grant of summary judgment was entered April 1, 2004.
ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of
Appeals affirmed in part and reversed in part the decision of the trial court.
The appellate panel affirmed the trial court's decision dismissing claims that
UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated
by its former subsidiaries. The appellate panel reversed the trial court's
decision that UGI Utilities was released from liability at three sites where UGI
Utilities operated MGPs under lease. UGI Utilities filed for reconsideration of
the panel's order. UGI Utilities believes that any liability it may have for a
share of the response costs at the three leased MGP sites will not have a
material effect on its financial condition or results of operations.
By letter dated June 24, 2004, KeySpan Energy ("KeySpan") informed UGI Utilities
that KeySpan has spent $2.3 million and expects to spend another $11.0 million
to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that
UGI Utilities is responsible for approximately 50% of these costs as a result of
UGI Utilities' alleged direct ownership and operation of the plant from 1885 to
1902. UGI Utilities is in the process of reviewing the information provided by
KeySpan and is investigating this claim.
-25-
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
Northeast Companies allege that UGI 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 $182.0 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 periodic adjustments 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.
Electric Utility purchases its power needs from electricity suppliers under
fixed-price energy and capacity contracts and, to a much lesser extent, on the
spot market. Prices for electricity can be volatile especially during periods of
high demand or tight supply. In 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, POLR generation rates for all metered customers increased 4.5% of its
total rates in effect on December 31, 2004 and expects to increase POLR rates by
3% beginning January 1, 2006. Currently, Electric Utility's fixed-price
contracts with electricity suppliers mitigate most risks associated with the
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 in the cost of
replacement power or capacity could 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, 2005, Electric Utility held
$13.5 million in collateral deposits which are reflected in other current
liabilities on the Balance Sheet.
Electric Utility has and may enter into electric price swap agreements to reduce
the volatility in the cost of a portion of its anticipated electricity
requirements. Electric Utility has an electric price swap agreement associated
with purchases of a portion of electricity anticipated to occur in 2007. At
September 30, 2005, the fair value of our electric price swap was a gain of $6.1
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, 2005. An adverse change in electricity
prices of ten percent would result in a $1.4 million decrease in the fair value
of the swap.
-26-
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 our short-term borrowings. These debt 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 2005 and Fiscal 2004, an increase in short-term
interest rates of 100 basis points (1%) would have increased annual interest
expense by $0.5 million and $0.4 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 $16.4 million and $13.8 million at
September 30, 2005 and 2004, respectively. A 100 basis point decrease in market
interest rates would result in increases in the fair value of this fixed-rate
debt of $18.7 million and $15.5 million at September 30, 2005 and 2004,
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 agreements, which have been
designated and qualify as cash flow hedges, was a loss of $2.5 million at
September 30, 2005. An adverse change in interest rates of ten percent on
ten-year U.S. treasury notes would result in a $2.2 million decrease in the fair
value of these interest rate protection agreements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance
with accounting principles generally accepted in 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 the Company's Audit Committee. In addition,
management has reviewed the following disclosures regarding the application of
these critical accounting policies with the Audit Committee.
LITIGATION ACCRUALS AND ENVIRONMENTAL REMEDIATION LIABILITIES. We are involved
in litigation regarding pending claims and legal actions that arise in the
normal course of our businesses. In addition, Utilities and its former
subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere
at which hazardous substances may be present. In accordance with accounting
principles generally accepted in the United States of America, we establish
reserves for pending claims and legal actions or environmental remediation
obligations when it is probable that a liability exists and the amount or range
of amounts can be reasonably estimated. Reasonable
-27-
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. As of September 30, 2005,
Utilities net property, plant and equipment totaled $655.3 million and we
recorded depreciation expense of $23.0 million during Fiscal 2005.
REGULATORY ASSETS AND LIABILITIES. Gas Utility and Electric Utility's
distribution businesses are subject to regulation by the PUC. In accordance with
SFAS 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 and cash flows. As of September 30,
2005, our regulatory assets totaled $61.3 million. See Note 2 to the
Consolidated Financial Statements.
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.
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 an increase in pre-tax pension
expense of approximately $1.0 million in Fiscal 2006. An unfavorable change in
the discount rate of 50 basis points would result in an increase in pre-tax
pension expense of approximately $1.5 million in Fiscal 2006.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Below is a listing of recently issued accounting pronouncements by the Financial
Accounting Standards Board. None of them had or are expected to have a material
effect on our financial position or results of operations. SFAS No. 154 applies
only to changes in accounting and corrections of errors. See Note 1 to the
Consolidated Financial Statements for additional discussion of such
pronouncements.
-28-
<Table>
<Caption>
TITLE OF PRONOUNCEMENT MONTH OF ISSUE
- ----------------------------------------------------------------------------------------------
SFAS No. 154, "Accounting Changes and Error Corrections" May 2005
Interpretation No. 47, "Accounting for Conditional Asset March 2005
Retirement Obligations"
SFAS No. 123 (revised 2004), "Share-Based Payment" December 2004
SFAS No. 153, "Exchanges of Nonmonetary Assets - An Amendment December 2004
of APB Opinion No. 29, Accounting for Nonmonetary Transactions"
</Table>
FORWARD-LOOKING STATEMENTS
Information contained above in this Management's Discussion and Analysis of
Financial Condition and Results of Operations and elsewhere in this Report on
Form 10-K may contain forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. Such statements use forward-looking words such as "believe," "plan,"
"anticipate," "continue," "estimate," "expect," "may," "will," or other similar
words. These statements discuss plans, strategies, events or developments that
we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases
underlying the forward-looking statement. We believe that we have chosen these
assumptions or bases in good faith and that they are reasonable. However, we
caution you that actual results almost always vary from assumed facts or bases,
and the differences between actual results and assumed facts or bases can be
material, depending on the circumstances. When considering forward-looking
statements, you should keep in mind the following important factors which could
affect our future results and could cause those results to differ materially
from those expressed in our forward-looking statements: (1) adverse weather
conditions resulting in reduced demand; (2) price volatility and availability of
oil, electricity and natural gas and the capacity to transport them to market
areas; (3) changes in laws and regulations, including safety, tax and accounting
matters; (4) competitive pressures from the same and alternative energy sources;
(5) liability for environmental claims; (6) customer conservation measures due
to high energy prices and improvements in energy efficiency and technology
resulting in reduced demand; (7) adverse labor relations; (8) large customer,
counterparty or supplier defaults; (9) increased uncollectible accounts expense;
(10) 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; (11) political, regulatory and
economic conditions in the United States; and (12) reduced access to capital
markets and interest rate fluctuations.
-29-
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.
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 referred to
in the Index contained on page F-2 of this Report are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) The Company's management, with the participation of the Company's
Chief Executive Officer and Chief Financial Officer, evaluated the
effectiveness of the Company's disclosure controls and procedures as of
the end of the period covered by this Report. Based on that evaluation,
the Chief Executive Officer and Chief Financial Officer concluded that
the Company's disclosure controls and procedures as of the end of the
period covered by this Report were designed and functioning effectively
to provide reasonable assurance that the information required to be
disclosed by the Company in reports filed under the Securities Exchange
Act of 1934, as amended, is (i) recorded, processed, summarized and
reported within the time periods specified in the SEC's rules and forms
and (ii) accumulated and communicated to our management, including the
Chief Executive Officer and Chief Financial Officer, as appropriate to
allow timely decisions regarding disclosure.
(b) Management is responsible for establishing and maintaining adequate
internal control over financial reporting for the Company. In order to
evaluate the effectiveness of internal control over financial
reporting, as required by Section 404 of the Sarbanes-Oxley Act of
2002, management has conducted an assessment, including testing, using
the criteria in Internal Control -- Integrated Framework, issued by the
Committee of Sponsoring Organizations of the Treadway
-30-
Commission ("COSO Framework"). The Company's system of internal control
over financial reporting is designed to provide reasonable, but not
absolute, assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in
accordance with accounting principles generally accepted in the United
States. Management also believes the system of internal control over
financial reporting provides reasonable assurance that assets are
safeguarded and that transactions are executed in accordance with
management's authorization and are properly recorded to permit the
preparation of reliable financial information. Because of its inherent
limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls
may become inadequate due to changing conditions, or the degree of
compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company
maintained effective internal control over financial reporting as of
September 30, 2005, based on the COSO Framework. Management's
assessment of the effectiveness of the Company's internal control over
financial reporting as of September 30, 2005, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting
firm, as stated in their report.
For the related report of PricewaterhouseCoopers LLP, our Independent
Registered Public Accounting Firm, see Item 8 of this Report (which
information is incorporated herein by reference).
(c) 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.
PART III:
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
-31-
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company's
independent registered public accountants, in fiscal years 2005 and 2004 were as
follows:
<Table>
<Caption>
2005 2004
-------- --------
Audit Fees(1)....................... $744,300 $173,500
Audit-Related Fees.................. - 0 - - 0 -
Tax Fees............................ - 0 - - 0 -
All Other Fees...................... - 0 - - 0 -
-------- --------
Total Fees for Services Provided.... $744,300 $173,500
======== ========
</Table>
- ----------
(1) Audit Fees were for audit services, including (i) the annual audit of the
consolidated financial statements of the Company, (ii) the audit of management's
assessment of the effectiveness of internal control over financial statements,
(iii) review of the interim financial statements included in the Quarterly
Reports on Form 10-Q of the Company, and (iv) services that only the independent
public accounting firm can reasonably be expected to provide, such as services
associated with SEC registration statements, and documents issued in connection
with securities offerings.
Consistent with SEC policies regarding auditor independence, the Audit
Committee has responsibility for appointing, setting compensation and overseeing
the work of the Company's independent accountants. In recognition of this
responsibility, the Audit Committee has a policy of pre-approving all audit and
permissible non-audit services provided by the independent accountants.
Prior to engagement of the Company's independent accountants for the next
year's audit, management submits a list of services and related fees expected to
be rendered during that year within each of the four categories of services
noted above to the Audit Committee for approval.
PART IV:
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) DOCUMENTS FILED AS PART OF THIS REPORT:
(1) FINANCIAL STATEMENTS:
Included under Item 8 are the following financial statements
and supplementary data:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of September 30, 2005 and
2004
Consolidated Statements of Income for the fiscal years
ended September 30, 2005, 2004 and 2003
-32-
Consolidated Statements of Cash Flows for the fiscal
years ended September 30, 2005, 2004 and 2003
Consolidated Statements of Stockholder's Equity for the
fiscal years ended September 30, 2005, 2004 and 2003
Notes to Consolidated Financial Statements
(2) FINANCIAL STATEMENT SCHEDULE:
For the years ended September 30, 2005, 2004 and 2003
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.
(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):
<Table>
<Caption>
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- -----------------------------------------------------------------------------------------------------------------------
3.1 Utilities' Amended and Restated Articles of Utilities Registration 3
Incorporation Statement No.
333-72540
(10/31/01)
3.2 Bylaws of UGI Utilities as amended through Utilities Form 10-K 3.2
September 30, 2003 (9/30/03)
</Table>
-33-
<Table>
<Caption>
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- -----------------------------------------------------------------------------------------------------------------------
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)
4.5 Form of Floating Rate Series B Medium-Term Note Utilities Form 8-K 4(ii)
(8/1/96)
4.6 [Intentionally omitted]
4.7 Officer's Certificate establishing Medium-Term Utilities Form 8-K 4(iv)
Notes series (8/26/94)
4.8 [Intentionally omitted]
4.9 Form of Officer's Certificate establishing Utilities Form 8-K 4(iv)
Series B 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 Utilities Form 8-K 4.2
Series C Medium-Term Notes under the Indenture (5/21/02)
10.1 Service Agreement (Rate FSS) dated as of UGI Form 10-K 10.5
November 1, 1989 between Utilities and Columbia, (9/30/95)
as modified pursuant to the orders of the Federal
Energy Regulatory Commission at Docket No. RS92-5-000
reported at Columbia Gas Transmission Corp., 64 FERC
Paragraph 61,060 (1993), order on rehearing, 64 FERC
Paragraph 61,365 (1993)
</Table>
-34-
<Table>
<Caption>
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- -----------------------------------------------------------------------------------------------------------------------
10.2** UGI Corporation 2004 Omnibus Equity UGI Form 10-K 10.17
Compensation Plan, as amended December 7, 2004 (9/30/04)
10.3** UGI Corporation 2004 Omnibus Equity UGI Form 8-K 10.10
Compensation Plan, as amended December 7, 2004 (12/6/05)
-- Terms and Conditions as amended December 6,
2005
10.4 [Intentionally omitted]
10.5 [Intentionally omitted]
10.6 [Intentionally omitted]
10.7** UGI Corporation 2004 Omnibus Equity UGI Form 8-K 10.4
Compensation Plan UGI Employees Nonqualified (12/6/05)
Stock Option Grant Letter
10.8** UGI Corporation Annual Bonus Plan dated March UGI Form 10-Q 10.4
8, 1996 (6/30/96)
10.9** UGI Utilities, Inc. Annual Bonus Plan dated Utilities Form 10-Q 10.4
March 8, 1996 (6/30/96)
10.10** 1997 Stock Purchase Loan Plan UGI Form 10-K 10.16
(9/30/97)
10.11** UGI Corporation Senior Executive Employee UGI Form 10-K 10.12
Severance Pay Plan as amended December 7, 2004 (9/30/04)
10.12 [Intentionally Omitted]
10.13 [Intentionally Omitted]
10.14** UGI Corporation 2000 Stock Incentive Plan UGI Form 10-Q 10.2
Amended and Restated as of December 16, 2003 (6/30/04)
10.15 Service Agreement for comprehensive delivery UGI Form 10-K 10.41
service (Rate CDS) dated February 23, 1999 (9/30/00)
between UGI 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 (3/31/03)
April 29, 2003
</Table>
-35-
<Table>
<Caption>
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- -----------------------------------------------------------------------------------------------------------------------
10.17** UGI Corporation Supplemental Executive UGI Form 10-Q 10
Retirement Plan Amended and Restated effective (6/30/98)
October 1, 1996
10.18 ** UGI Corporation 1992 Non-Qualified Stock Option UGI Form 10-Q 10.6
Plan Amended and Restated as of April 29, 2003 (3/31/03)
10.19 [Intentionally omitted]
10.20** Form of Change in Control Agreement for Messrs. UGI Form 8-K 10.1
Greenberg, Walsh and Knauss (12/6/05)
10.21** UGI Corporation 2004 Omnibus Equity UGI Form 8-K 10.9
Compensation Plan UGI Employees Stock Unit (12/6/05)
Grant Letter
10.22** Form of Change in Control Agreement for Messrs. Utilities Form 8-K 10.2
Trego and Barney (12/6/05)
10.23** UGI Corporation 2004 Omnibus Equity UGI Form 8-K 10.7
Compensation Plan UGI Employees Performance (12/6/05)
Unit Grant Letter
10.24** UGI Corporation 2004 Omnibus Equity UGI Form 8-K 10.8
Compensation Plan Utilities Employees (12/6/05)
Performance Unit Grant Letter
10.25 Storage Transportation Service Agreement (Rate Utilities Form 10-K 10.25
Schedule SST) between Utilities and Columbia (9/30/02)
dated November 1, 1993, as modified pursuant
to orders of the Federal Energy Regulatory
Commission
10.26 Amendment No. 1 dated November 1, 2004, to the Utilities Form 10-K 10.26
Service Agreement (Rate FSS) dated as of (9/30/04)
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 Paragraph 61,060 (1993), order on
rehearing, 64 FERC Paragraph 61,365 (1993)
10.27 No-Notice Transportation Service Agreement Utilities Form 10-K 10.27
(Rate Schedule CDS) between Utilities and (9/30/02)
Texas Eastern Transmission dated February 23, 1999,
as modified pursuant to various orders of the
Federal Energy Regulatory Commission
</Table>
-36-
<Table>
<Caption>
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- -----------------------------------------------------------------------------------------------------------------------
10.28 No-Notice Transportation Service Agreement Utilities Form 10-K 10.28
(Rate Schedule CDS) between Utilities and (9/30/02)
Texas Eastern Transmission dated October 31, 2000,
as modified pursuant to various orders of the
Federal Energy Regulatory
Commission
10.29 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.29
Schedule FT-1) between Utilities and Texas (9/30/02)
Eastern Transmission 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 Utilities Form 10-K 10.30
No-Notice Transportation Service Agreement (9/30/04)
(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
10.31 Firm Transportation Service Agreement (Rate Utilities Form 10-K 10.31
Schedule FT) between Utilities and (9/30/02)
Transcontinental Gas Pipe Line dated October 1,
1996, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
10.32 Gas Service Delivery and Supply Agreement Utilities Form 10-K 10.32
between Utilities and UGI Energy Services, Inc. (9/30/04)
dated August 1, 2004
10.33 Amendment No. 1 dated November 1, 2004, to the Utilities Form 10-K 10.33
Firm Transportation Service Agreement (Rate (9/30/04)
Schedule FT-1) between Utilities and Texas
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 Utilities Form 10-K 10.34
Schedule FTS) between Utilities and Columbia (9/30/04)
Gas Transmission dated November 1, 2004
10.35** UGI Corporation 2004 Omnibus Equity UGI Form 8-K 10.5
Compensation Plan UGI Utilities Employees (12/6/05)
Nonqualified Stock Option Grant Letter
10.36** 2002 Non-Qualified Stock Option Plan Amended UGI Form 10-Q 10.7
and Restated as of April 29, 2003 (3/31/03)
</Table>
-37-
<Table>
<Caption>
INCORPORATION BY REFERENCE
EXHIBIT NO. EXHIBIT REGISTRANT FILING EXHIBIT
- -----------------------------------------------------------------------------------------------------------------------
*10.37** Description of oral employment at-will
agreements for Messrs. Trego, Barney and Knauss
10.38** Description of oral employment at-will UGI Form 10-K 10.30
agreements for Messrs. Greenberg and Walsh Corporation (9/30/05)
*12.1 Computation of Ratio of Earnings to Fixed
Charges
14 Code of Ethics for principal executive, Utilities Form 10-K 14
financial and 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, 2005
pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002
*31.2 Certification by the Chief Financial Officer
relating to the Registrant's Report on Form
10-K for the year ended September 30, 2005
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, 2005
</Table>
* Filed herewith.
** As required by Item 14(a)(3), this exhibit is identified as a compensatory
plan or arrangement.
-38-
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 6, 2005 By: John C. Barney
-----------------------------------------
John C. Barney
Senior Vice President - Finance and Chief
Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below on December 6, 2005 by the following persons
on behalf of the Registrant in the capacities indicated.
<Table>
<Caption>
SIGNATURE TITLE
- --------------------------- --------------------------
David W. Trego President and Chief
- --------------------------- Executive Officer
David W. Trego (Principal Executive
Officer) and Director
Lon R. Greenberg Chairman and Director
- ---------------------------
Lon R. Greenberg
John L. Walsh Vice Chairman
- --------------------------- and Director
John L. Walsh
John C. Barney Sr. Vice President - Finance
- --------------------------- Chief Financial Officer (Principal
John C. Barney Financial Officer and Principal
Accounting Officer)
Stephen D. Ban Director
- ---------------------------
Stephen D. Ban
</Table>
-39-
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below on December 6, 2005 by the following persons on
behalf of the Registrant in the capacities indicated.
<Table>
<Caption>
SIGNATURE TITLE
- ----------------------------- ---------
Thomas F. Donovan Director
- -----------------------------
Thomas F. Donovan
Richard C. Gozon Director
- -----------------------------
Richard C. Gozon
Ernest E. Jones Director
- -----------------------------
Ernest E. Jones
Anne Pol Director
- -----------------------------
Anne Pol
Marvin O. Schlanger Director
- -----------------------------
Marvin O. Schlanger
James W. Stratton Director
- -----------------------------
James W. Stratton
</Table>
-40-
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT:
No annual report or proxy material was sent to security holders in fiscal year
2005.
-41-
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2005
F-1
UGI UTILITIES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULE
<Table>
<Caption>
Pages
------------
Financial Statements:
Report of Independent Registered Public Accounting Firm F-3 to F-4
Consolidated Balance Sheets as of September 30,
2005 and 2004 F-5 to F-6
Consolidated Statements of Income for the years
ended September 30, 2005, 2004 and 2003 F-7
Consolidated Statements of Cash Flows for the years
ended September 30, 2005, 2004 and 2003 F-8
Consolidated Statements of Stockholder's Equity
for the years ended September 30, 2005, 2004 and 2003 F-9
Notes to Consolidated Financial Statements F-10 to F-30
Financial Statement Schedule:
For the years ended September 30, 2005, 2004 and 2003:
II -- Valuation and Qualifying Accounts S-1
</Table>
We have omitted all other financial statement schedules because the
required information is either (1) not present; (2) not present in
amounts sufficient to require submission of the schedule; or (3) included
elsewhere in the financial statements or related notes.
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of UGI Utilities, Inc.:
We have completed an integrated audit of UGI Utilities, Inc.'s 2005 consolidated
financial statements and of its internal control over financial reporting as of
September 30, 2005 and audits of its 2004 and 2003 consolidated financial
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our opinions, based on our audits, are
presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index
appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of UGI Utilities, Inc. and its subsidiaries at September 30,
2005 and 2004, and the results of their operations and their cash flows for each
of the three years in the period ended September 30, 2005 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 15(a)(2) presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with the standards of the Public Company
Accounting Oversight Board (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 of financial statements
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.
Internal control over financial reporting
Also, in our opinion, management's assessment, included in Management's Report
on Internal Control over Financial Reporting appearing under Item 9A, that the
Company maintained effective internal control over financial reporting as of
September 30, 2005 based on criteria established in Internal Control --
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), is fairly stated, in all material respects, based on
those criteria. Furthermore, in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of
September 30, 2005, based on criteria established in Internal Control --
Integrated Framework issued by the COSO. The Company's management is responsible
for maintaining
F-3
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting. Our
responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial reporting based
on our audit. We conducted our audit of internal control over financial
reporting in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
December 13, 2005
F-4
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
<Table>
<Caption>
September 30,
2005 2004
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents $ 2,686 $ 21
Accounts receivable (less allowances for doubtful
accounts of $4,562 and $3,374, respectively) 49,660 38,897
Accrued utility revenues 10,360 9,742
Inventories 71,584 65,177
Deferred income taxes 12,484 6,658
Prepaid expenses 3,607 3,455
Income taxes recoverable 323 --
Other current assets 5,633 5,268
--------- ---------
Total current assets 156,337 129,218
Property, plant and equipment
Gas utility 855,109 821,836
Electric operations 114,347 108,231
General 16,195 14,227
--------- ---------
985,651 944,294
Less accumulated depreciation and amortization (330,329) (313,030)
--------- ---------
Net property, plant and equipment 655,322 631,264
Regulatory assets 61,334 65,060
Other assets 30,680 29,664
--------- ---------
Total assets $ 903,673 $ 855,206
========= =========
</Table>
See accompanying notes to consolidated financial statements.
F-5
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
<Table>
<Caption>
September 30,
2005 2004
--------- ---------
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt $ 50,000 $ 20,000
Bank loans 81,200 60,900
Preferred shares subject to mandatory redemption, without par value -- 20,000
Accounts payable 38,430 60,073
Accounts payable - related parties 14,371 2,634
Employee compensation and benefits accrued 9,007 11,340
Dividends and interest accrued 6,475 6,254
Income taxes accrued -- 2,111
Customer deposits and refunds 20,064 17,024
Deferred fuel costs 17,370 7,862
Electric supplier collateral deposits 13,500 2,500
Other current liabilities 8,969 7,050
--------- ---------
Total current liabilities 259,386 217,748
Long-term debt 187,030 197,151
Deferred income taxes 160,920 157,564
Deferred investment tax credits 7,193 7,589
Other noncurrent liabilities 14,213 15,123
Commitments and contingencies (note 8)
--------- ---------
Total liabilities 628,742 595,175
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 80,622 79,773
Retained earnings 133,807 121,454
Accumulated other comprehensive income (loss) 243 (1,455)
--------- ---------
Total common stockholder's equity 274,931 260,031
--------- ---------
Total liabilities and stockholder's equity $ 903,673 $ 855,206
========= =========
</Table>
See accompanying notes to consolidated financial statements.
F-6
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
<Table>
<Caption>
Year Ended
September 30,
---------------------------------------
2005 2004 2003
--------- --------- ---------
Revenues $ 681,152 $ 650,088 $ 636,758
--------- --------- ---------
Costs and expenses:
Cost of sales - gas, fuel and purchased power 437,930 412,240 392,901
Operating and administrative expenses 94,370 93,244 91,947
Operating and administrative expenses - related parties 12,900 11,223 9,352
Taxes other than income taxes 13,379 12,501 12,195
Depreciation and amortization 23,827 22,520 21,240
Other income, net (4,533) (2,669) (8,745)
--------- --------- ---------
577,873 549,059 518,890
--------- --------- ---------
Operating income 103,279 101,029 117,868
Interest expense 18,326 17,931 17,656
--------- --------- ---------
Income before income taxes 84,953 83,098 100,212
Income taxes 34,132 34,140 39,540
--------- --------- ---------
Net income 50,821 48,958 60,672
Dividends on preferred shares subject to mandatory redemption -- -- 1,163
--------- --------- ---------
Net income after dividends on preferred shares subject to
mandatory redemption $ 50,821 $ 48,958 $ 59,509
========= ========= =========
</Table>
See accompanying notes to consolidated financial statements.
F-7
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
<Table>
<Caption>
Year Ended
September 30,
---------------------------------------
2005 2004 2003
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 50,821 $ 48,958 $ 60,672
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and amortization 23,827 22,520 21,240
Deferred income taxes, net (631) 11,873 2,097
Provision for uncollectible accounts 8,210 6,971 7,778
Pension expense (income) (2,470) 1,022 (1,242)
Other 1,594 1,591 1,284
Net change in:
Accounts receivable and accrued utility revenues (19,591) (18,078) (610)
Inventories (6,407) (11,160) (15,601)
Deferred fuel costs 9,508 (6,872) 19,038
Accounts payable (9,906) 7,409 (454)
Electric supplier collateral deposits 11,000 1,800 700
Other current assets and liabilities (2,581) 932 2,899
--------- --------- ---------
Net cash provided by operating activities 68,314 66,966 97,801
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment (46,305) (40,737) (41,297)
Net costs of property, plant and equipment disposals (1,176) (1,712) (1,831)
--------- --------- ---------
Net cash used by investing activities (47,481) (42,449) (43,128)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends (38,468) (45,000) (35,081)
Cash portion of UGID dividend -- -- (2,572)
Issuance of debt 130,000 -- 44,694
Repayment of debt (40,000) -- (76,000)
(Decrease) increase in bank loans with maturities of
three months or less (49,700) 20,200 3,500
Retirement of preferred stock (20,000) -- --
Capital contribution from UGI Corporation -- -- 5,000
--------- --------- ---------
Net cash used by financing activities (18,168) (24,800) (60,459)
--------- --------- ---------
Cash and cash equivalents increase (decrease) $ 2,665 $ (283) $ (5,786)
========= ========= =========
CASH AND CASH EQUIVALENTS:
End of year $ 2,686 $ 21 $ 304
Beginning of year 21 304 6,090
--------- --------- ---------
Increase (Decrease) $ 2,665 $ (283) $ (5,786)
========= ========= =========
</Table>
See accompanying notes to consolidated financial statements.
F-8
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(Thousands of dollars)
<Table>
<Caption>
Accumulated Total
Additional Other Common
Common Paid-in Retained Comprehensive Stockholder's
Stock Capital Earnings Loss Equity
-------- ---------- -------- ------------- -------------
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 79,773 121,454 (1,455) 260,031
Net income 50,821 50,821
Net change in fair value of derivative
instruments (net of tax of $1,027) 1,448 1,448
Reclassifications of net losses on interest
rate protection agreements (net of tax of $177) 250 250
-------- ------------- -------------
Comprehensive income 50,821 1,698 52,519
Cash dividends - common stock (38,468) (38,468)
Other 849 849
-------- ---------- -------- ------------- -------------
Balance September 30, 2005 $ 60,259 $ 80,622 $133,807 $ 243 $ 274,931
======== ========== ======== ============= =============
</Table>
See accompanying notes to consolidated financial statements.
F-9
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION PRINCIPLES
UGI Utilities, Inc. ("UGI Utilities"), a wholly owned subsidiary of UGI
Corporation ("UGI"), owns and operates a natural gas distribution utility ("Gas
Utility") in parts of eastern and southeastern Pennsylvania and an electricity
distribution utility ("Electric Utility") in northeastern Pennsylvania. Prior to
June 2003, UGI Utilities also owned interests in Pennsylvania-based electricity
generation assets through its wholly owned subsidiary, UGI Development Company
("UGID"), and UGID's 50% owned joint-venture affiliate Hunlock Creek Energy
Ventures ("Energy Ventures"). In June 2003, the Company dividended all of the
common stock of UGID and its subsidiaries to UGI.
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 (prior
to its distribution to UGI) collectively as "Electric Operations." Our 2005 and
2004 consolidated financial statements include the accounts of UGI Utilities,
and our 2003 consolidated financial statements include the accounts of UGI
Utilities and UGID and its consolidated subsidiaries, prior to their dividend to
UGI. We eliminate all significant intercompany accounts when we consolidate.
UGID's investment in Energy Ventures was accounted for under the equity method.
Gas Utility and Electric Utility (collectively, "Utilities") are subject to
regulation by the Pennsylvania Public Utility Commission ("PUC"). UGID was
granted "Exempt Wholesale Generator" status by the Federal Energy Regulatory
Commission. UGID and its subsidiaries' results of operations did not have a
material effect on the Company's results of operations in 2003.
USE OF ESTIMATES
We make estimates and assumptions when preparing financial statements in
conformity with accounting principles generally accepted in the United 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. SFAS 71
allows us to defer expenses and revenues on the balance sheet as regulatory
assets and liabilities when it is probable that those expenses and income will
be allowed in the ratemaking process in a period different from the period in
which they would have been reflected in the income statement of an unregulated
company. These deferred assets and liabilities are then flowed through the
income statement in the period in which the same amounts are included in rates
and recovered from or refunded to customers. As required by SFAS 71, we monitor
our regulatory and competitive environments to determine whether the recovery of
our
F-10
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
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 $17,509 in 2005, $18,143 in 2004 and $16,046 in 2003.
We paid income taxes totaling $36,348 in 2005, $19,910 in 2004 and $29,372 in
2003.
REVENUE RECOGNITION
We 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
We 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. We 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 amortized.
We also reduce the regulatory income tax asset for the probable reduction in
future revenues that will result when such deferred investment tax credits
amortize.
We join with UGI and its subsidiaries in filing a consolidated federal income
tax return. We are charged or credited for our share of current taxes resulting
from the effects of our transactions in the UGI consolidated federal income tax
return including giving effect to intercompany transactions. The result of this
allocation is generally consistent with income taxes calculated on a separate
return basis.
F-11
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 2.4% in 2005 and 2.3% in
both 2004 and 2003. Depreciation expense as a percentage of the related average
depreciable base for Electric Utility was 2.9% in 2005, 2.8% in 2004 and 3.0% in
2003. Depreciation expense was $23,046 in 2005, $21,860 in 2004, and $20,754 in
2003.
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 fifteen 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. 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 accounted 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, 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.
F-12
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
$1,764 in 2005, $2,652 in 2004 and $1,372 in 2003. 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:
<Table>
<Caption>
- --------------------------------------------------------------------------------------------------------
2005 2004 2003
- --------------------------------------------------------------------------------------------------------
Net income after dividends on preferred shares subject to
mandatory redemption, as reported $ 50,821 $ 48,958 $ 59,509
Add: Stock-based employee compensation
expense included in reported net income, net
of related tax effects 1,032 1,551 803
Deduct: Total stock-based employee compensation
expense determined under the fair value method
for all awards, net of related tax effects (1,229) (1,715) (927)
- --------------------------------------------------------------------------------------------------------
Pro forma net income after dividends on preferred shares
subject to mandatory redemption $ 50,624 $ 48,794 $ 59,385
========================================================================================================
</Table>
ENVIRONMENTAL AND 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, 2005, the Company's undiscounted amount and accrued liability for
environmental investigation and cleanup costs were not material.
F-13
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("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. For a detailed description of the derivative
instruments we use, our objectives for using them, and related supplemental
information required by SFAS 133, see Note 9.
COMPREHENSIVE INCOME
Comprehensive income comprises net income and other comprehensive income. Other
comprehensive income of $1,698, $594 and $725 for the years ended September 30,
2005, 2004 and 2003, respectively, is the result of gains or losses on interest
rate protection agreements ("IRPAs") and changes in the fair value of an
electric price swap agreement qualifying as cash flow hedges, net of
reclassifications to net income.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In May 2005, the Financial Accounting Standards Board ("FASB") issued SFAS No.
154, "Accounting Changes and Error Corrections" ("SFAS 154"). SFAS 154 replaces
APB No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes
in Interim Financial Statements," and establishes retrospective application as
the required method for reporting a change in accounting principle. SFAS 154
provides guidance for determining whether retrospective application of a change
in accounting principle is impracticable and for reporting a change when
retrospective application is impracticable. SFAS 154 is effective for accounting
changes and corrections of errors made in fiscal years beginning after December
15, 2005.
In March 2005, the FASB issued Interpretation No. 47, "Accounting for
Conditional Asset Retirement Obligations" ("FIN 47"). It requires an entity to
recognize a liability for a conditional asset retirement obligation when
incurred if the liability can be reasonably estimated. FIN 47 clarifies that the
term "Conditional Asset Retirement Obligation" refers to a legal obligation to
perform an asset retirement activity in which the timing and/or method of
settlement are conditional on a future event that may or may not be within the
control of the entity. FIN 47 also clarifies when an entity would have
sufficient information to reasonably estimate the fair value of an asset
retirement obligation. FIN 47 is effective no later than the end of fiscal years
ending after December 15, 2005. We do not expect the adoption of FIN 47 to have
any impact on our financial position or results of operations.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), "Share-Based
Payment" ("SFAS 123R"). SFAS 123R replaces SFAS 123 and supersedes APB 25. SFAS
123, as originally issued in 1995, established as preferable a fair-value-based
method of accounting for share-based payment transactions with employees.
However, SFAS 123 permitted entities the option of continuing to
F-14
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
apply the guidance in APB 25 as long as the footnotes to financial statements
disclosed what net income would have been had the preferable fair-value-based
method been used. SFAS 123R requires that the compensation cost relating to
share-based payment transactions be recognized in the financial statements. The
cost is required to be measured based on the fair value of the equity or
liability instruments issued. SFAS 123R covers a wide range of share-based
compensation arrangements including share options, restricted share plans,
performance-based awards, share appreciation rights and employee share purchase
plans. We adopted SFAS 123R effective October 1, 2005. Under the modified
prospective transition method, beginning October 1, 2005, unrecognized
compensation expense for awards that are not vested on the adoption date will be
recognized in the Company's statements of income through the end of the
requisite service period. We do not believe that the adoption of SFAS 123R will
have a material impact on our annual results of operations or financial
position. For disclosure regarding pro forma net income as if we had determined
stock-based compensation under the fair value method prescribed by SFAS 123, see
Stock-Based Compensation included elsewhere in this Note 1.
In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets
- - An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions"
("SFAS 153"). SFAS 153 eliminates the exception from fair value measurement for
nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB
Opinion No. 29, "Accounting for Nonmonetary Transactions," and replaces it with
an exception for exchanges that lack commercial substance. SFAS 153 specifies
that a nonmonetary exchange has commercial substance if the future cash flows of
the entity are expected to change significantly as a result of the exchange.
SFAS 153 was effective for our interim period beginning July 1, 2005. The
adoption of SFAS 153 did not have a material effect on our financial position or
results of operations.
RECLASSIFICATIONS
We have reclassified certain prior-year balances to conform to the current year
presentation.
2. UTILITY REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are included in our accompanying
balance sheets at September 30:
<Table>
<Caption>
- ----------------------------------------------------------------
2005 2004
- ----------------------------------------------------------------
Regulatory assets:
Income taxes recoverable $ 58,601 $ 62,039
Other postretirement benefits 1,690 1,926
Other 1,043 1,095
- ----------------------------------------------------------------
Total regulatory assets $ 61,334 $ 65,060
- ----------------------------------------------------------------
Regulatory liabilities:
Other postretirement benefits $ 2,823 $ 2,976
Deferred fuel costs 17,370 7,862
- ----------------------------------------------------------------
Total regulatory liabilities $ 20,193 $ 10,838
- ----------------------------------------------------------------
</Table>
F-15
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
3. DEBT
Long-term debt comprises the following at September 30:
<Table>
<Caption>
- --------------------------------------------------------------------------------------------------------------------
2005 2004
- --------------------------------------------------------------------------------------------------------------------
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
6.62% Notes, due May 2005 -- 20,000
7.14% Notes, due December 2005 (including unamortized premium of
$30 and $151 in 2005 and 2004, respectively, effective rate - 6.64%) 30,030 30,151
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 20,000
5.16% Notes due May 2015 20,000 --
6.13% Notes due October 2034 20,000 --
- --------------------------------------------------------------------------------------------------------------------
Total long-term debt 237,030 217,151
Less current maturities (50,000) (20,000)
- --------------------------------------------------------------------------------------------------------------------
Total long-term debt after one year $ 187,030 $ 197,151
- --------------------------------------------------------------------------------------------------------------------
</Table>
Scheduled principal repayments of long-term debt for each of the next five
fiscal years ending September 30 are as follows: 2006 - $50,000; 2007 - $20,000;
2008 - $0; 2009 - $0; 2010 - $0.
At September 30, 2005, UGI Utilities had revolving credit agreements with five
banks providing for borrowings of up to $110,000. These agreements are currently
scheduled to expire in June 2007 through June 2008. Under these agreements, 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
$11,200 at September 30, 2005 and $60,900 at September 30, 2004 which we
classify as bank loans. UGI Utilities from time to time enters into short-term
borrowings under uncommitted arrangements with major banks in order to meet
liquidity needs during the peak heating season. At September 30, 2005, there
were two separate $35,000 borrowings outstanding under these arrangements. These
borrowings are scheduled to mature on February 15 and March 14, 2006 and are
also classified as bank loans. The weighted-average interest rates on bank loans
outstanding were 4.41% at September 30, 2005 and 2.35% at September 30, 2004.
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, 2005, UGI Utilities
was in compliance with these financial covenants.
F-16
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES
The provisions for income taxes consist of the following:
<Table>
<Caption>
2005 2004 2003
- ---------------------------------------------------------------------------------
Current expense:
Federal $ 26,387 $ 15,413 $ 27,027
State 8,376 6,854 10,416
- ---------------------------------------------------------------------------------
Total current expense 34,763 22,267 37,443
Deferred expense (235) 12,271 2,495
Investment tax credit amortization (396) (398) (398)
- ---------------------------------------------------------------------------------
Total income tax expense $ 34,132 $ 34,140 $ 39,540
- ---------------------------------------------------------------------------------
</Table>
A reconciliation from the statutory federal tax rate to our effective tax rate
is as follows:
<Table>
<Caption>
- -------------------------------------------------------------------------------------------------
2005 2004 2003
- -------------------------------------------------------------------------------------------------
Statutory federal tax rate 35.0% 35.0% 35.0%
Difference in tax rate due to:
State income taxes, net of federal benefit 5.6 5.7 5.6
Deferred investment tax credit amortization (0.5) (0.4) (0.4)
Other, net 0.1 0.8 (0.7)
- -------------------------------------------------------------------------------------------------
Effective tax rate 40.2% 41.1% 39.5%
- -------------------------------------------------------------------------------------------------
</Table>
F-17
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Deferred tax liabilities (assets) comprise the following at September 30:
<Table>
<Caption>
- --------------------------------------------------------------------------------------
2005 2004
- --------------------------------------------------------------------------------------
Excess book basis over tax basis of property, plant and
equipment $ 132,222 $ 130,297
Regulatory assets 25,450 27,589
Pension plan asset 9,315 10,541
Other 2,453 1,550
- --------------------------------------------------------------------------------------
Gross deferred tax liabilities 169,440 169,977
- --------------------------------------------------------------------------------------
Deferred investment tax credits (2,985) (3,149)
Employee-related expenses (5,719) (6,973)
Regulatory liabilities (7,413) (3,967)
Accumulated other comprehensive loss -- (1,032)
Other (4,887) (3,950)
- --------------------------------------------------------------------------------------
Gross deferred tax assets (21,004) (19,071)
- --------------------------------------------------------------------------------------
Net deferred tax liabilities $ 148,436 $ 150,906
- --------------------------------------------------------------------------------------
</Table>
UGI Utilities had recorded deferred tax liabilities of approximately $37,270 as
of September 30, 2005 and $39,445 as of September 30, 2004 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 $2,985 at September 30, 2005 and $3,149 at September
30, 2004, pertaining to utility deferred investment tax credits. UGI Utilities
had recorded regulatory income tax assets related to these net deferred taxes of
$58,601 at September 30, 2005 and $62,039 at September 30, 2004. 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 postretirement life insurance benefits to nearly all
active and retired employees.
F-18
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:
<Table>
<Caption>
- --------------------------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
--------------------------- ---------------------------
2005 2004 2005 2004
- ---------------------------------------------------------------------------------- ---------------------------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations - beginning of year $ 220,486 $ 209,459 $ 25,148 $ 24,567
Service cost 5,217 4,953 129 120
Interest cost 13,467 12,996 1,259 1,514
Actuarial (gain) loss 8,277 2,608 (1,858) 1,208
Plan amendments -- -- (7,799) --
Benefits paid (10,026) (9,530) (1,720) (2,261)
- --------------------------------------------------------------------------------------------------------------------
Benefit obligations - end of year $ 237,421 $ 220,486 $ 15,159 $ 25,148
- --------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets - beginning of year $ 196,355 $ 183,840 $ 10,171 $ 9,000
Actual return on plan assets 25,347 22,045 834 826
Employer contributions -- -- 2,006 2,461
Benefits paid (10,026) (9,530) (1,720) (2,115)
- --------------------------------------------------------------------------------------------------------------------
Fair value of plan assets - end of year $ 211,676 $ 196,355 $ 11,291 $ 10,172
- --------------------------------------------------------------------------------------------------------------------
Funded status of the plans $ (25,745) $ (24,131) $ (3,868) $ (14,976)
Unrecognized net actuarial loss 47,107 47,884 4,358 6,932
Unrecognized prior service cost 1,088 1,651 (2,562) --
Unrecognized net transition (asset) obligation -- -- -- 5,690
- --------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost - end of year $ 22,450 $ 25,404 $ (2,072) $ (2,354)
- --------------------------------------------------------------------------------------------------------------------
ASSUMPTIONS AS OF SEPTEMBER 30:
Discount rate 5.7% 6.1% 5.7% 6.1%
Expected return on plan assets 9.0% 9.0% 5.8% 5.8%
Rate of increase in salary levels 4.0% 4.0% 4.0% 4.0%
- --------------------------------------------------------------------------------------------------------------------
</Table>
Net pension expense (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 $26,223 at
September 30, 2005 and $23,581 at September 30, 2004 relating to employees of
UGI and certain of its other subsidiaries. Included in the end of year
postretirement obligations above are $751 at September 30, 2005 and $735 at
September 30, 2004 relating to employees of UGI and certain of its other
subsidiaries.
F-19
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:
<Table>
<Caption>
- ---------------------------------------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefits Benefits
------------------------------------------ ------------------------------------------
2005 2004 2003 2005 2004 2003
- ---------------------------------------------------------------------------------- ------------------------------------------
Service cost $ 4,593 $ 4,318 $ 4,051 $ 117 $ 110 $ 109
Interest cost 12,402 11,642 12,004 1,235 1,487 1,497
Expected return on assets (16,439) (15,412) (16,646) (526) (459) (414)
Amortization of:
Transition (asset) obligation -- (1,233) (1,510) 510 680 680
Prior service cost 640 622 643 (55) -- --
Actuarial loss 1,274 1,085 216 238 316 203
- ---------------------------------------------------------------------------------------------------------------------------------
Net benefit cost (income) 2,470 1,022 (1,242) 1,519 2,134 2,075
Change in regulatory
assets and liabilities -- -- -- 1,580 965 1,024
- ---------------------------------------------------------------------------------------------------------------------------------
Net expense (income) $ 2,470 $ 1,022 $ (1,242) $ 3,099 $ 3,099 $ 3,099
- ---------------------------------------------------------------------------------------------------------------------------------
</Table>
UGI Utilities Pension Plan assets are held in trust. Although the UGI Utilities
Pension Plan projected benefit obligations exceeded plan assets at September 30,
2005 and 2004, plan assets exceeded accumulated benefit obligations by $7,404
and $9,160, respectively. The Company did not make any contributions to the
UGI Utilities Pension Plan in 2005, 2004 or 2003 and does not believe that it
will be required to make any contributions during the year ending September 30,
2006 for ERISA funding purposes.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary
Employees' Beneficiary Association ("VEBA") trust to fund the UGI Utilities'
postretirement benefit obligations and to pay retiree health care and life
insurance benefits 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" ("SFAS 106"). The
difference between such amounts calculated under SFAS 106 and the amounts
included in Utilities' rates is deferred for future recovery from, or refund to,
ratepayers. Effective July 1, 2005, substantially all retirees and their
beneficiaries participating in the UGI Utilities' postretirement benefit program
were enrolled in insured Medicare Advantage plans. As a result, the projected
benefit obligation of our postretirement benefits program was lower at September
30, 2005 as compared to such obligations at September 30, 2004. Additionally,
the Company's required contribution to the VEBA during the year ending September
30, 2006 is expected to be significantly lower than in 2005.
F-20
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Expected payments for pension benefits and for other postretirement welfare
benefits are as follows:
<Table>
<Caption>
- --------------------------------------------------------
Other
Pension Postretirement
Benefits Benefits
- --------------------------------------------------------
Fiscal 2006 $ 10,692 $ 1,301
Fiscal 2007 10,944 1,323
Fiscal 2008 11,431 1,346
Fiscal 2009 12,023 1,361
Fiscal 2010 12,775 1,375
Fiscal 2011-2015 75,274 6,552
- --------------------------------------------------------
</Table>
In accordance with our investment strategy to obtain long-term growth, our
target asset allocations are to maintain a mix of 60% equities and the remainder
in fixed income funds or cash equivalents. The target and actual allocations for
the UGI Utilities Pension Plan and VEBA trust assets at September 30 are as
follows:
<Table>
<Caption>
Target Pension Plan VEBA
-------------------------- -------------------------- --------------------------
Pension
Plan VEBA 2005 2004 2005 2004
- -----------------------------------------------------------------------------------------------------------------
Equities 60% 60% 60% 63% 62% 58%
Fixed income funds 40% 30% 40% 37% 31% 27%
Cash equivalents N/A 10% N/A N/A 7% 15%
=================================================================================================================
</Table>
UGI Common Stock comprised approximately 11% and 8% of pension plan trust assets
at September 30, 2005 and 2004, respectively.
The assumed health care cost trend rates are 10% for fiscal 2006, decreasing to
5.5% in fiscal 2011. A one percentage point change in the assumed health care
cost trend rate would increase (decrease) the 2005 postretirement benefit cost
and obligation as follows:
<Table>
<Caption>
- -------------------------------------------------------------------------
1% 1%
Increase Decrease
- -------------------------------------------------------------------------
Effect on total service and interest costs $ 87 $ (78)
Effect on postretirement benefit obligation 686 (615)
- -------------------------------------------------------------------------
</Table>
We also sponsor an unfunded and non-qualified supplemental executive retirement
income plan. At September 30, 2005 and 2004, the projected benefit obligations
of this plan were $2,700 and $1,600, respectively. We recorded expense for this
plan of $439 in 2005, $460 in 2004 and $353 in 2003. We also recorded a
settlement loss of $1,537 in 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'
F-21
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
contributions. The cost of benefits under the savings plan totaled $931 in 2005,
$915 in 2004, and $968 in 2003.
6. INVENTORIES
Inventories comprise the following at September 30:
<Table>
<Caption>
- -----------------------------------------------------------
2005 2004
- -----------------------------------------------------------
Utility fuel and gases $ 69,196 $ 62,673
Appliances for sale 583 537
Materials, supplies and other 1,805 1,967
- -----------------------------------------------------------
Total inventories $ 71,584 $ 65,177
- -----------------------------------------------------------
</Table>
Included in utility fuel and gases inventories at September 30, 2005 are amounts
associated with the Company's Storage Contract Administration Agreement
("Storage Agreement") with Energy Services, Inc. ("Energy Services"), a wholly
owned subsidiary of UGI. For a detailed description of the Storage Agreement and
the accounting for such inventories, see Note 12.
7. SERIES PREFERRED STOCK
We have 2,000,000 shares of Series Preferred Stock, including both series
subject to and series not subject to mandatory redemption, authorized for
issuance. We had no shares of Series Preferred Stock outstanding at September
30, 2005. Any holders of shares of Series Preferred Stock would have the right
to elect a majority of the Company's Board of Directors (without cumulative
voting) if dividend payments on any series were in arrears in an amount equal to
four quarterly dividends. This election right would continue until the arrearage
was cured. We paid cash dividends at the specified annual rates on all
outstanding Series Preferred Stock.
On October 1, 2004, we redeemed 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 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 $4,703 in 2005, $4,431 in 2004, and $4,303 in 2003.
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: 2006 - $3,855; 2007 - $3,359; 2008 - $2,403; 2009 - $1,410;
2010 - $966; after 2010-$2,707.
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
F-22
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
service which Gas Utility may terminate at various dates through 2016. Gas
Utility's costs associated with transportation and storage service agreements
are included in its annual PGC filing with the PUC and are recoverable through
PGC rates. In addition, Gas Utility has short-term gas supply agreements which
permit it to purchase certain of its gas supply needs on a firm or interruptible
basis at spot-market prices.
Electric Utility purchases its capacity requirements and electric energy needs
under contracts with various suppliers and on the spot market. Contracts with
producers for capacity and energy needs expire at various dates through fiscal
2008.
Future contractual cash obligations under Gas Utility and Electric Utility
supply, storage and service agreements existing at September 30, 2005 are as
follows: 2006 - $250,855; 2007 - $85,486; 2008 - $63,500; 2009 - $53,669; 2010 -
$41,705; after 2010 - $74,881.
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 private parties allege MGPs were formerly owned or
operated by it or owned or operated by its former subsidiaries. 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. 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 UGI Utilities should not be liable
in those instances in which a former subsidiary owned or operated an MGP. There
could be, however, significant future costs of an uncertain amount associated
with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities
directly operated, or that were owned or operated by former subsidiaries of UGI
Utilities, if a court were to conclude that (1) the subsidiary's separate
corporate form should be disregarded or (2) UGI Utilities should be considered
to have been an operator because of its conduct with respect to its subsidiary's
MGP.
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 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
F-23
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 plant from 1901 to 1928. Studies conducted by the City and
Citizens suggest that it could cost up to $18,000 to clean up the river.
Citizens' third-party claims have been stayed pending a resolution of the
City's suit against Citizens, which was tried in September 2005 and has not yet
been decided. UGI Utilities believes that it has good defenses to the 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 $8,000 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. In March 2005, the court granted UGI Utilities' motion for summary
judgment dismissing AGL's complaint. AGL has appealed.
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 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.
The trial court granted UGI Utilities' motion for summary judgment and dismissed
ConEd's complaint. The grant of summary judgment was entered April 1, 2004.
ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of
Appeals affirmed in part and reversed in part the decision of the trial court.
The appellate panel affirmed the trial court's decision dismissing claims that
UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated
by its former subsidiaries. The appellate panel reversed the trial court's
decision that UGI Utilities was released from liability at three sites where UGI
Utilities operated MGPs under lease. UGI Utilities has filed for reconsideration
of the panel's order. UGI Utilities believes that any liability it may have for
a share of the response costs at the three leased MGP sites will not have a
material effect on its financial condition or results of operations.
F-24
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 Sag Harbor, New York. KeySpan believes that UGI Utilities
is responsible for approximately 50% of these costs as a result of UGI
Utilities' alleged direct ownership and operation of the plant from 1885 to
1902. UGI Utilities is in the process of reviewing the 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
Northeast Companies allege that UGI Utilities controlled operations of the
plants from 1883 to 1941. According to the letter, investigation and remediation
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 environmental and other matters. However, it
is reasonably possible that some of them could be resolved unfavorably to us and
result in losses in excess of recorded amounts. We are unable to estimate any
possible losses in excess of recorded amounts. 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 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 price swap agreements 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 are
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.
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
F-25
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 expense on the
associated debt issue affects earnings.
During 2005, 2004 and 2003, there were no gains or losses recognized in earnings
as a result of hedge ineffectiveness or as a result of 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,
2005, our unsettled derivative contracts included in accumulated other
comprehensive income included an electric price swap agreement and two IRPAs.
Gains and losses included in accumulated other comprehensive income at September
30, 2005 relating to cash flow hedges will be reclassified into (1) interest
expense when interest on hedged issuances of fixed-rate long-term debt is
reflected in net income and (2) cost of sales when the forecasted purchases of
electricity subject to the hedge impact net income. Included in accumulated
other comprehensive income at September 30, 2005 are net after-tax losses of
approximately $3,310 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 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 income at September 30, 2005 is an
after-tax gain of $3,553 associated with our electric price swap agreement for
purchases of electricity anticipated to occur during 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
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.
F-26
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The carrying amounts and estimated fair values of our remaining financial
instruments (including unsettled derivative instruments) at September 30 are as
follows:
<Table>
<Caption>
Carrying Estimated
Amount Fair Value
- -----------------------------------------------------------------------------------------
2005:
Electric swap agreement $ 6,073 $ 6,073
Interest rate protection agreements (2,472) (2,472)
Long-tem debt 237,030 247,000
2004:
Electric swap agreement $ 1,954 $ 1,954
Interest rate protection agreement (993) (993)
Long-tem debt 217,151 231,000
Preferred shares subject to mandatory redemption 20,000 20,900
- -----------------------------------------------------------------------------------------
</Table>
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. We
estimated the fair value of our preferred shares 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, 2005 and 2004, we had no significant
concentrations of credit risk.
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-27
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Financial information by business segment follows:
<Table>
<Caption>
- --------------------------------------------------------------------------------
Gas Electric
Total Utility Operations
- --------------------------------------------------------------------------------
2005
Revenues $ 681,152 $ 585,078 $ 96,074
Cost of sales 437,930 390,099 47,831
Depreciation and amortization 23,827 20,729 3,098
Operating income 103,279 81,646 21,633
Interest expense 18,326 16,624 1,702
Income before income taxes 84,953 65,022 19,931
Total assets 903,673 803,848 99,825
Capital expenditures 46,305 38,846 7,459
- --------------------------------------------------------------------------------
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 855,206 765,488 89,718
Capital expenditures 40,737 35,470 5,267
- --------------------------------------------------------------------------------
2003
Revenues $ 636,758 $ 539,862 $ 96,896
Cost of sales 392,901 342,987 49,914
Depreciation and amortization 21,240 18,147 3,093
Operating income 117,868 96,086 21,782
Interest expense 17,656 15,409 2,247
Income before income taxes 100,212 80,677 19,535
Total assets 809,048 725,085 83,963
Capital expenditures 41,297 37,204 4,093
- --------------------------------------------------------------------------------
</Table>
F-28
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. OTHER INCOME, NET
Other income, net, comprises the following:
<Table>
<Caption>
- ---------------------------------------------------------------------------------------
2005 2004 2003
- ---------------------------------------------------------------------------------------
Non-tariff service income $ 1,329 $ 2,048 $ 5,693
Pension income -- -- 1,242
Interest income 32 183 128
Non-utility sales and installation income 2,608 2,419 1,598
Other, net 564 (1,981) 84
- ---------------------------------------------------------------------------------------
$ 4,533 $ 2,669 $ 8,745
- ---------------------------------------------------------------------------------------
</Table>
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, pricipally payroll related services. Amounts billed to these
entities by UGI Utilities for all periods presented was not material.
Effective December 1, 2004, following a competitive bidding process, UGI
Utilities entered into the Storage Agreement with Energy Services. The Storage
Agreement was initially scheduled to expire on October 31, 2005, but effective
November 1, 2005, UGI Utilities and Energy Services agreed to extend the Storage
Agreement through October 31, 2008. Under the Storage Agreement, UGI Utilities
released certain gas transportation and storage contracts through October 31,
2008 and transferred associated gas storage inventories to Energy Services. UGI
Utilities may recall such released transportation and storage contracts without
penalty if recalled to meet operational requirements, and if not recalled, the
releases will terminate at the end of the term of the Storage Agreement. In the
event that released contracts are recalled or at the expiration of the Storage
Agreement Energy Services is required to transfer associated gas storage
inventories to UGI Utilities. In exchange for the ability to utilize these
assets, Energy Services pays a monthly fee to UGI Utilities, and Energy Services
provides a firm natural gas delivery service to UGI Utilities. In accordance
with the bidding process, UGI has provided UGI Utilities with performance
security in the amount of $20,000. During 2005, UGI Utilities purchased natural
gas storage inventories from Energy Services under the Storage Agreement
totaling $64,421, and incurred associated pipeline transportation and storage
capacity charges of $16,324.
UGI Utilities reflects the historical cost of the gas storage inventories and
any exchange receivable from Energy Services (representing amounts of natural
gas inventories used but not yet replenished by Energy Services) on its balance
sheet under the caption "Inventories." The carrying value of these gas storage
inventories at September 30, 2005, comprising approximately 8.7 billion cubic
feet of natural gas, was $63,004.
F-29
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Gas Utility enters into wholesale natural gas transactions with Energy Services
for purchases of winter peaking service and, from time to time, purchases of
natural gas or pipeline capacity. During 2005, 2004 and 2003, the aggregate
amount of these transactions (exclusive of Storage Agreement transactions)
totaled $8,491, $6,257 and $4,709, respectively. In addition, from time to time
the Company sells natural gas or pipeline capacity to Energy Services. During
fiscal 2005, 2004 and 2003, revenues associated with these sales to Energy
Services totaled $4,249, $1,698 and $4,234, respectively. These transactions did
not have a material effect on the Company's net income during 2005, 2004 and
2003.
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.
<Table>
<Caption>
- --------------------------------------------------------------------------------------------------------------------------
December 31, March 31, June 30, September 30,
2004 2003 2005 2004 2005 2004 2005 2004
- --------------------------------------------------------------------------------------------------------------------------
Revenues $ 183,481 $ 170,684 $ 281,454 $ 268,217 $ 111,534 $ 118,717 $ 104,683 $ 92,470
Operating income 32,869 33,950 55,670 53,277 12,668 12,282 2,072 1,520
Net income (loss) 16,966 17,508 30,708 29,149 4,907 4,495 (1,760) (2,194)
- --------------------------------------------------------------------------------------------------------------------------
</Table>
F-30
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
<Table>
<Caption>
Balance at Charged to Balance at
beginning costs and end of
of year expenses Other year
------------- ------------ ------------ ------------
YEAR ENDED SEPTEMBER 30, 2005
Reserves deducted from assets in
the consolidated balance sheet:
Allowance for doubtful accounts $ 3,374 $ 8,210 $ (7,022) (1) $ 4,562
============= =============
Other reserves (3) $ 5,854 $ 2,021 $ (1,707) (2) $ 6,168
============= =============
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)
</Table>
- ----------
(1) Uncollectible accounts written off, net of recoveries.
(2) Payments, net
(3) Includes reserves for self-insured property and casualty liability, insured
property and casualty liability, environmental, litigation and other.
(4) Other adjustments
S-1
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
10.37 Description of Oral Employment-At-Will Agreements for
Messrs. Trego, Barney and Knauss
12.1 Computation of Ratio of Earnings to Fixed Charges
23 Consent of PricewaterhouseCoopers LLP
31.1 Certification by the Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act
31.2 Certification by the Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act
32 Certification by Chief Executive Officer and Chief Financial
Officer pursuant to Section 906 of the Sarbanes-Oxley Act
</Table>
-42-