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EX-32 - EXHIBIT 32 - UGI UTILITIES INC | c91709exv32.htm |
EX-23 - EXHIBIT 23 - UGI UTILITIES INC | c91709exv23.htm |
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INC | c91709exv31w1.htm |
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INC | c91709exv31w2.htm |
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INC | c91709exv12w1.htm |
EX-10.10 - EXHIBIT 10.10 - UGI UTILITIES INC | c91709exv10w10.htm |
EX-10.18 - EXHIBIT 10.18 - UGI UTILITIES INC | c91709exv10w18.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2009
Commission file number 1-1398
UGI UTILITIES, INC.
(Exact Name of Registrant as Specified in Its Charter)
Pennsylvania | 23-1174060 | |
(State or Other Jurisdiction of | (I.R.S. Employer | |
Incorporation or Organization) | Identification No.) |
P. O. Box 1267, 2525 N. 12th Street, Suite 360
Reading, PA 19612
(Address of Principal Executive Offices) (Zip Code)
Reading, PA 19612
(Address of Principal Executive Offices) (Zip Code)
(610) 796-3400
(Registrants telephone number, including area code)
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. Yes þ No o
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 o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
(§229.405) is not contained herein, and will not be contained, to the best of registrants
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. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o No þ
At September 30, 2009, 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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FORWARD-LOOKING INFORMATION
Information contained in this Annual 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) inability to timely
recover costs through utility rate proceedings; (5) the impact of pending and future legal
proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability
for environmental claims; (8) customer conservation measures due to high energy prices and
improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor
relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible
accounts expense; (12) 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; (13) political,
regulatory and economic conditions in the United States; (14) capital market conditions, including
reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity
market prices resulting in significantly higher cash collateral requirements.
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.
PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
UGI Utilities, Inc. (UGI Utilities or the Company) is a public utility company that owns
and operates three natural gas distribution utilities and an electric utility in Pennsylvania. We
are a wholly owned subsidiary of UGI Corporation (UGI).
On October 1, 2008, UGI Utilities completed the acquisition of all of the issued and
outstanding stock of PPL Gas Utilities Corporation (PPL Gas), the natural gas distribution
utility of PPL Corporation, and its wholly owned subsidiary, Penn Fuel Propane, LLC (Penn Fuel
Propane). Immediately following the closing of the acquisition, Penn Fuel Propane sold its retail
propane distribution assets to AmeriGas Propane, L.P., an affiliate of UGI. PPL Gas, now known as
UGI Central Penn Gas, Inc. (CPG), distributes natural gas to approximately 76,000 customers in 34
counties in eastern and central Pennsylvania, and also distributes natural gas to several hundred
customers in portions of one Maryland county. On August 24, 2006, UGI Utilities, through its
subsidiary UGI Penn Natural Gas, Inc. (PNG), acquired the natural gas distribution business of
Southern Union Companys PG Energy Division, which significantly increased our natural gas
distribution business in northeastern Pennsylvania.
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The Gas Utility segment (Gas Utility) consists of the regulated natural gas distribution
businesses of UGI Utilities, PNG, and CPG. Gas Utility serves approximately 563,000 customers in
eastern, northeastern, and central Pennsylvania. UGI Utilities natural gas distribution utility
is referred to as UGI Gas; PNGs natural gas
distribution utility is referred to as PNG Gas; and CPGs natural gas distribution utility
is referred to as CPG Gas. Beginning Fiscal 2009, CPG was included in the Companys Gas Utility
segment. See Note 4 to Consolidated Financial Statements. The Electric Utility segment (Electric
Utility) consists of the regulated electric distribution business of UGI Utilities, serving
approximately 62,000 customers in northeastern Pennsylvania. Gas Utility is regulated by the
Pennsylvania Public Utility Commission (PUC) and the Maryland Public Service Commission.
Electric Utility is regulated by the PUC.
UGI Utilities was incorporated in Pennsylvania in 1925. Our executive offices are located at
P. O. Box 12677, 2525 N. 12th Street, Suite 360, Reading, Pennsylvania 19612, and our telephone
number is (610) 796-3400. In this report, the terms Company and UGI Utilities, as well as the
terms, our, we, and its, are sometimes used to refer to UGI Utilities, Inc. or, collectively
UGI Utilities, Inc. and its consolidated subsidiaries. The terms Fiscal 2009 and Fiscal 2008
refer to the fiscal years ended September 30, 2009 and September 30, 2008, respectively.
GAS UTILITY
Service Area; Revenue Analysis
Gas Utility is authorized to distribute natural gas to approximately 563,000 customers in
portions of 45 eastern, northeastern and central Pennsylvania counties through its distribution
system of approximately 11,900 miles of gas mains. The service area includes the cities of
Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton,
Wilkes-Barre, Lock Haven, Pittston, Pottsville and Williamsport, Pennsylvania, and the boroughs of
Honesdale and Milford, Pennsylvania. Located in Gas Utilitys service area are major production
centers for basic industries such as specialty metals, aluminum, glass and paper product
manufacturing.
System throughput (the total volume of gas sold to or transported for customers within Gas
Utilitys distribution system) for Fiscal 2009 was approximately 150 billion cubic feet (bcf).
System sales of gas accounted for approximately 44% of system throughput, while gas transported for
residential, commercial and industrial customers (who bought their gas from others) accounted for
approximately 56% 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 long-term
agreements with a number of pipeline companies, including Texas Eastern Transmission Corporation,
Columbia Gas Transmission Corporation, Transcontinental Gas Pipeline Corporation, Dominion
Transmission, ANR Pipeline and Tennessee Gas Pipeline.
Gas Supply Contracts
During Fiscal 2009, Gas Utility purchased approximately 94 bcf of natural gas for sale to
retail core-market customers (principally comprised of firm- residential, commercial and industrial
customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and
small commercial customers who purchase their gas from alternate suppliers) and off-system sales
customers. Approximately 77% of the volumes purchased were supplied under agreements with 10
suppliers. The remaining 23% of gas purchased by Gas Utility was supplied by approximately 20
producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 1 year.
Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the
months of November through March.
Seasonality
Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal.
Approximately 65% to 70% of Gas Utilitys sales volume is supplied, and approximately 85% to 90% of
Gas Utilitys operating income is earned, during the peak heating season from October through
March.
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Competition
Natural gas is a fuel that competes with electricity and oil, and to a lesser extent, with
propane and coal. Competition among these fuels is primarily a function of their comparative price
and the relative cost and efficiency of fuel utilization equipment. In parts of Gas Utilitys
service area, electricity may have a competitive price advantage over natural gas due to government
regulated rate caps on electricity. Rate caps for electric utilities serving a significant portion
of Gas Utilitys service territory are currently scheduled to expire at the end of 2009 and 2010
which will likely result in electricity losing all or some of its competitive price advantage.
Additionally, high efficiency electric heat pumps have led to a decrease in the cost of heating
with electricity. Government subsidies currently favor ground source heat pumps over fossil fueled
systems. 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 territories, Gas Utility 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 natural gas distribution utility companies. As a result of
Pennsylvanias Natural Gas Choice and Competition Act, effective July 1, 1999 all of Gas Utilitys
customers, including retail core-market customers, have been afforded this opportunity.
A number of Gas Utilitys 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.
Approximately 24% of Gas Utilitys commercial and industrial customers annual throughput volume,
including certain customers served under interruptible rates, have locations which afford them the
opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing
Gas Utility. The majority of customers in this group are served under transportation contracts
having 3 to 20 year terms. Included in these two customer groups are 25 customers, most of which
are among the 10 largest customers for each of UGI Gas, PNG and CPG in terms of annual volumes. All
of these customers have contracts, 19 of which extend beyond the 2010 fiscal year. No single
customer represents, or is anticipated to represent, more than 5% of Gas Utilitys 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 2010.
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 Utilitys larger customers.
During Fiscal 2009, Gas Utility supplied transportation service to 2 major co-generation
installations and 5 electric generation facilities. Gas Utility continues to pursue opportunities
to supply natural gas to electric generation projects located in its service area. 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 10,700
residential heating customers during Fiscal 2009. These customers
consisted primarily of (1) customers converting from other energy sources,
mainly oil and electricity, (2) existing non-heating gas customers who have added gas heating
systems to replace other energy sources and (3) new home construction
customers. As a result of the decline in the real estate
market, customers from new home construction decreased approximately 24% compared to Fiscal 2008.
If the slowdown in new home construction continues in fiscal year 2010 in Gas Utilitys service
area, customer growth will be adversely affected.
UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and
individual rate and tariff proceedings before 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 (1) the pricing of
pipeline services in a competitive energy marketplace; (2) the flexibility of the terms and
conditions of pipeline service tariffs and contracts; and (3) pipelines requests to increase
their base rates, or change the terms and conditions of their storage and transportation services.
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UGI Utilities 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, UGI Utilities 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.
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 2,150 miles of transmission and distribution lines and 13 transmission substations.
For Fiscal 2009, approximately 54% of sales volume came from residential customers, 34% from
commercial customers and 12% from industrial and other customers. Sales of electricity for
residential heating purposes accounted for approximately 19% of total sales of electricity during
Fiscal 2009.
Sources of Supply
In accordance with Electric Utilitys default service settlement with the PUC effective
January 1, 2010, Electric Utility will be permitted to recover prudently incurred electricity
costs, including costs to obtain supply to meet its customers energy requirements, pursuant to a
supply plan filed with the PUC. See Managements Discussion and Analysis of Financial Condition
and Results of Operations Market Risk Disclosures and Note 5 to Consolidated Financial
Statements. Electric Utility distributes electricity that it purchases from wholesale markets and
electricity that customers purchase from other suppliers, if any. See Gas Utility and Electric
Utility Regulation and Rates Electric Utility Rates.
As of September 30, 2009, 17 of Electric Utilitys customers have selected an alternative
electricity generation supplier. Beginning in 2010, while Electric Utility expects to see an
increasing number of customers selecting alternative electricity generation suppliers, it will
continue to provide energy to the majority of its distribution customers for the foreseeable
future.
Competition
As a result of the Electricity Generation Customer Choice and Competition Act (ECC Act), all
Pennsylvania retail electric customers have the ability to choose their electric generation
supplier. Electric Utility remains the provider of last resort (POLR) for its customers who do
not choose an alternate electric generation supplier. In Fiscal 2009, Electric Utility served
nearly all of the electric customers within its service territory and is the only regulated
electric utility having the right, granted by the PUC or by law, to distribute electricity in its
service territory. Electricity competes with natural gas, oil, propane and other heating fuels for
residential heating purposes.
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 POLR Settlements). Consistent with the terms of the POLR
Settlements, Electric Utilitys total average residential heating customer POLR rates were
increased in January 2009 by approximately 1.5% over rates in effect during calendar year 2008.
For current rates, see Gas Utility and Electric Utility Regulation and Rates Electric Utility
Rates. Beginning January 1, 2010, Electric Utility will be assured recovery of prudently incurred
costs and will no longer be subject to the risk that actual costs for purchased power will exceed
POLR revenues, but will, however, forego the opportunity to recover revenues in excess of actual
costs.
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GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES
Pennsylvania Public Utility Commission Jurisdiction
UGI 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. PJM is a regional transmission organization that regulates and
coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives
certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in
June of each year to reflect annual changes in Electric Utilitys electric transmission revenue
requirements, when its transmission facilities are used by third parties.
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 UGI Gas became effective in 1995. In accordance
with a statutory mechanism, a rate increase for Gas Utilitys retail core-market customers became effective
October 1, 2000 along with a Purchased Gas Cost (PGC) variable credit equal to a portion of the
margin received from customers served under interruptible rates to the extent such interruptible
customers use capacity contracted for by UGI Gas for retail core-market customers.
On August 27, 2009, the PUC approved PNGs and CPGs rate case settlement agreements, which
resulted in a $19.75 million base rate operating revenue increase for PNG and a $10 million base
rate operating revenue increase for CPG. The increases became effective on August 28, 2009.
The gas service tariffs for UGI Gas, PNG and CPG contain PGC rates applicable to firm retail
rate schedules. These PGC rates permit recovery of substantially all of the prudently incurred
costs of natural gas that UGI Gas, PNG, and CPG sell to their customers. PGC rates are reviewed and
approved annually by the PUC. UGI Gas, PNG, and CPG may request quarterly or, under certain
conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become
effective on 1 days 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 6 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.
UGI Gas 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. PNG and CPG each have
one PGC rate applicable to all customers. See Note 5 to Consolidated Financial Statements.
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Electric Utility Rates
The most recent general base rate increase for Electric Utility became effective in 1996.
Electric Utilitys rates were unbundled into distribution, transmission and generation (POLR or
default service) components in 1998. In accordance with the POLR Settlements, Electric Utility
increased POLR rates annually from 2005 through 2009. The increase implemented January 1, 2009 raised total average residential heating customer
rates by approximately 1.5% over rates in effect during calendar year 2008. Electric Utility is
also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its
customers.
PUC default service regulations are applicable to Electric Utilitys provision of default
service effective January 1, 2010. Electric Utility, consistent with these regulations, acquired a
portion of its default service supplies for certain customer groups for the period of January 1,
2010 through April 30, 2014. Electric Utility received approval from the PUC of (1) default service
tariff rules applicable for service rendered on or after January 1, 2010, (2) a reconcilable
default service cost rate recovery mechanism to become effective January 1, 2010, (3) a plan for
meeting the post-2009 requirements of the Alternative Energy Portfolio Standards Act (AEPS Act),
which requires Electric Utility to directly or indirectly acquire certain percentages of its
supplies from designated alternative energy sources and (4) a reconcilable AEPS Act cost recovery
rate mechanism to become effective January 1, 2010. Under these rules, default service rates for
most customers will be adjusted quarterly.
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 4A of the Natural Gas
Act and Section 222 of the Federal Power Act prohibit the use or employment of any manipulative or
deceptive devices or contrivances in connection with the purchase or sale of natural gas, electric
energy, or natural gas transportation or electric transmission services subject to the jurisdiction
of FERC. FERC has adopted regulations to implement these statutory provisions which 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 FERCs jurisdiction. Gas
Utility and Electric Utility are subject to certain other regulations and obligations for
FERC-regulated activities. Under provisions of the Energy Policy Act of 2005 (EPACT 2005),
Electric Utility is subject to certain electric reliability standards established by FERC and
administered by an Electric Reliability Organization (ERO). Electric Utility anticipates that
substantially all the costs of complying with the ERO standards will be recoverable through its PJM
formulary electric transmission rate schedule.
EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation
of any regulations, orders or provisions under the Federal Power Act and Natural Gas Act, and
clarified FERCs authority over certain utility or holding company mergers or acquisitions of
electric utilities or electric transmitting utility property valued at $10 million or more.
State Tax Surcharge Clauses
UGI 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 UGI Utilities from the effects of increases in most of the Pennsylvania taxes
to which it is subject.
Utility Franchises
UGI Utilities, PNG and CPG each hold 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 each of them believes are adequate to authorize them to carry on their
business in substantially all of the territories to which they now render gas or electric service.
Under applicable Pennsylvania law, UGI Utilities, PNG, and CPG also have certain rights of eminent
domain as well as the right to maintain their facilities in streets and highways in their
territories.
Other Government Regulation
In addition to regulation by the PUC and FERC, the gas and electric utility operations of UGI
Utilities are subject to various federal, state and local laws governing environmental matters,
occupational health and safety, pipeline safety and other matters. UGI Utilities is subject to the
requirements of the federal Resource Conservation and Recovery Act,
the Comprehensive Environmental Response, Compensation and Liability
Act and comparable state
statutes with respect to the release of hazardous substances on property owned or operated by UGI
Utilities. See Note 13 to Consolidated Financial Statements.
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EMPLOYEES
At September 30, 2009, UGI Utilities had approximately 1,430 employees, of which approximately
94% are dedicated to Gas Utility and 6% to Electric Utility. Union employees represent
approximately 41% of the total employees.
GLOBAL CLIMATE CHANGE
There is a growing concern, both nationally and internationally, about climate change and the
contribution of greenhouse gas (GHG) emissions, most notably carbon dioxide, to global warming.
While some states have adopted laws regulating the emission of GHGs for some industry sectors,
there is currently no federal regulation mandating the reduction of GHG emissions in the United
States. In June of 2009, the United States House of Representatives passed the American Clean
Energy and Security Act (ACES Act). The ACES Act would establish an economy-wide GHG
cap-and-trade system to reduce GHG emissions over time. Subsequently, the United States Senate
offered a draft of its own climate change bill, the Clean Energy Jobs and American Power Act.
While the Senates bill is based on the ACES Act, there are differences between the bills and no
legislation can be enacted until a final combined bill is approved by both the House of
Representatives and the Senate.
In September of 2009, the Environmental Protection Agency issued a final rule establishing an
economy-wide system for mandatory reporting of GHG emissions. Facilities subject to the rule,
which include our natural gas distribution businesses, are required to begin emissions monitoring
in January of 2010 and to submit detailed annual reports beginning in March of 2011. The rule does
not require affected facilities to implement GHG emission controls or reductions.
Because natural gas is considered a clean alternative fuel under the federal Clean Air Act
Amendments of 1990, we anticipate that this will provide us with a competitive advantage over other
sources of energy, such as fuel oil and coal, when new climate change regulations become effective.
In addition, we are in the process of refining and implementing our strategy to identify both our
GHG emissions and our energy consumption in order to be in a position to comply with new
regulations and to take advantage of any opportunities that may arise from the regulation of such
emissions.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income and identifiable assets
attributable to UGI Utilities operating segments for the 2009, 2008 and 2007 fiscal years appears
in Note 16 to 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 peak heating season of October 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, harm our financial condition
and adversely affect our cash flows.
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Energy efficiency and technology advances, as well as price induced customer conservation, may
result in reduced demand for our energy products and services.
The trend toward increased conservation and technological advances, including installation of
improved insulation and the development of more efficient furnaces and other heating devices, may
reduce the demand for energy products. Prices for natural gas are subject to volatile fluctuations
in response to changes in supply and other market conditions. During periods of high energy
commodity costs, our prices generally increase which may lead to customer conservation. A reduction
in demand could lower our revenues, and, therefore, lower our net income and adversely affect our
cash flows. State and/or federal regulation may require mandatory conservation measures which would
reduce the demand for our energy products. We cannot predict the materiality of the effect of
future conservation measures or the effect that any technological advances in heating,
conservation, energy generation or other devices might have on our operations.
Volatility in credit and capital markets may restrict our ability to grow, increase the
likelihood of defaults by our customers and counterparties and adversely affect our operating
results.
The recent volatility in credit and capital markets may create additional risks to our
business in the future. We are exposed to financial market risk (including refinancing risk)
resulting from, among other things, changes in interest rates and conditions in the credit and capital
markets. Recent developments in the credit markets increase our possible exposure to the liquidity,
default and credit risks of our suppliers, counterparties associated with derivative financial
instruments and our customers. Although we believe that recent financial market conditions, if they
were to continue for the foreseeable future, will not have a significant impact on our ability to
fund our existing operations, such market conditions could restrict our ability to grow, limit the
scope of major capital projects if access to credit and capital markets is limited or could
adversely affect our operating results.
The economic recession, volatility in the stock market and the low interest rate environment may
negatively impact our pension liability.
The economic recession, the recent decline in the stock market and the low interest rate
environment have had a significant impact on our pension liability and funded status. Additional
declines in the stock market and valuation of stocks, combined with continued low interest rates,
could further impact our pension liability and increase the amount of required contributions to our
pension plans.
Changes in commodity market prices may have a negative effect on our liquidity.
Depending on the terms of our contracts with suppliers as well as our use of financial
instruments including natural gas futures contracts to reduce volatility in the cost of natural gas
we purchase, changes in the market price of electricity and natural gas could create payment
obligations for the Company and expose us to an increased liquidity risk.
Our transmission and distribution systems may not operate as planned, which may increase our
expenses or decrease our revenues and, thus, have an adverse effect on our financial results.
Our ability to manage operational risk with respect to our transmission and distribution
systems is critical to our financial results. Our business also faces several risks, including the
breakdown or failure of or damage to equipment or processes (especially due to severe weather or
natural disasters), accidents and other factors. Operation of our transmission and distribution
systems below our expectations may result in lost revenues or increased expenses, including higher
maintenance costs.
Our need to comply with comprehensive, complex, and sometimes unpredictable government
regulations may increase our costs and limit our revenue growth, which may result in reduced
earnings.
There are many governmental regulations that have an impact on our businesses. Existing
statutes and regulations may be revised or reinterpreted and new laws and regulations may be
adopted or become applicable to the Company which may affect our businesses in ways that we cannot
predict.
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Regulators may not allow timely recovery of costs for us in the future, which may adversely
affect our results of operations.
Our Gas Utility and Electric Utility operations are subject to regulation by the PUC. The PUC,
among other things, approves the rates that we may charge to our utility customers, thus impacting
the returns that we may earn on the assets that are dedicated to those operations. We expect that
PNG and CPG will periodically file requests with the PUC to increase base rates that they charge
customers. If we are required in a rate proceeding to reduce the rates we charge our utility
customers, or if we are unable to obtain approval for timely rate increases from the PUC,
particularly when necessary to cover increased costs, our revenue growth will be limited and
earnings may decrease.
Our operations, capital expenditures and financial results may be affected by regulatory changes
and/or market responses to global climate change.
There is a growing concern, both nationally and internationally, about climate change and the
contribution of GHG emissions, most notably carbon dioxide, to global warming. In response to this
concern, the United States House of Representatives passed the ACES Act in June of 2009 to
establish an economy-wide GHG cap-and-trade system to reduce GHG emissions over time.
Subsequently, the United States Senate offered a draft climate change bill, the Clean Energy Jobs
and American Power Act, based on the ACES Act. The proposed legislation includes a cap-and-trade
policy structure in which GHG emissions from a broad cross-section of the economy would be subject
to an overall cap. The legislation establishes mechanisms for GHG sources to obtain allowances to
emit GHGs during the course of a year which may be used to cover their own allowances or sell them
to other sources that do not hold enough emissions for their own operations.
It is expected that climate change legislation will continue to be a priority in the
foreseeable future and it is possible that federal legislation mandating the reduction of GHG
emissions on an economy-wide basis may be enacted during calendar year 2010. Increased regulation
of GHG emissions could impose significant additional costs on the Company and our customers. The
impact of legislation and regulations on us will depend on a number of factors, including (i) what
industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG
emissions cap level, (iv) the allocation of emission allowances to specific sources and (v) the
costs and opportunities associated with compliance. At this time, we cannot predict the effect that
climate change regulation may have on our business, financial condition or results of operations in
the future.
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. There can be no
assurance that our insurance will be adequate to protect us from all material expenses related to
pending and future claims or that such levels of insurance will be available in the future at
economical prices.
Remediation costs resulting from liability from contamination claims could reduce our net
income.
We have 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 or
conducted other operations. Costs we incur at sites outside of Pennsylvania cannot be recovered in
future UGI Utilities rate proceedings, and insurance may not cover all or even part of these
costs. Our actual costs related to these sites may exceed our current estimates due to factors
beyond our control, such as:
| the discovery of presently unknown conditions; |
| changes in environmental laws and regulations; |
| judicial rejection of our legal defenses to the third-party claims; or |
| the insolvency of other responsible parties at the sites at which we are involved. |
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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 |
For information regarding legal proceedings, including environmental matters, see Note 13 to
Consolidated Financial Statements.
PART II:
ITEM 5. | MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES |
Market Information
All of the outstanding shares of the Companys Common Stock are owned by UGI and are not
publicly traded.
Dividends
Cash dividends declared on the Companys Common Stock totaled $61.2 million in Fiscal 2009,
$68.8 million in Fiscal 2008, and $40.0 million in Fiscal 2007.
ITEM 7. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS |
Managements Discussion and Analysis of Financial Condition and Results of Operations (MD&A)
discusses our results of operations and our financial condition. MD&A should be read in conjunction
with our Items 1 & 2, Business and Properties, our Item 1A, Risk Factors and our Consolidated
Financial Statements in Item 8 below including Segment Information included in Note 16 to
Consolidated Financial Statements.
EXECUTIVE OVERVIEW
Our net income in Fiscal 2009 was $78.7 million, an increase of 6.4% from Fiscal 2008 net
income of $74.0 million. The increase in net income reflects the accretive effect of the
acquisition of all the stock of PPL Gas Utilities Corporation (the CPG Acquisition) which closed
on October 1, 2008, partially offset by the impact of higher pension expense, higher environmental
matters expense and reduced income from our Electric Utility. During Fiscal 2009, our Gas Utility
and Electric Utility benefited from heating-season weather that was colder than in Fiscal 2008.
Summer temperatures in our Electric Utility were cooler, however, reducing electricity demand for
air conditioning. The colder heating-season weather helped offset some of the effects of the
recession on general economic activity in our Gas Utility and Electric Utility service territories
and the effects of customer conservation. In January 2009, CPG Gas and PNG Gas filed separate
requests to increase base operating revenues. We received PUC approval of increased rates that
went into effect in late August 2009. The combined increases in annual base rate revenues approved
totaled $29.8 million. Due to the timing of the new rates, they did not have a
material impact on Fiscal 2009 results but will have a full-years impact on Fiscal 2010 results.
Electric Utility results were impacted by higher costs under fixed-price electricity purchase
agreements which exceeded increases in POLR rate increases. While the number of
Fiscal 2009 customer additions in our Gas Utility was about equal with Fiscal 2008, a substantial
portion of the Fiscal 2009 growth resulted from the conversion market while growth in the new home
market suffered due to the economic recession.
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Looking ahead, our results in Fiscal 2010 will be influenced by a number of factors including
temperatures during the heating-season months and the length and severity of the economic recession
on economic activity in our service territories. Our Electric Utilitys default service settlement
with the PUC, which becomes effective January 1, 2010,
allows for the recovery of prudently incurred electricity costs but eliminates the opportunity
for Electric Utility to realize revenue in excess of such costs on electricity sales. This will
result in a reduction in Electric Utilitys Fiscal 2010 operating income.
We
believe that we have sufficient liquidity in the form of our
revolving credit facility to fund
business operations for the foreseeable future. We do not have significant amounts of long-term
debt maturing or revolving credit agreements terminating until late in Fiscal 2011.
ANALYSIS OF RESULTS OF OPERATIONS
The following results of operations covers Fiscal 2009, Fiscal 2008 and the year ended
September 30, 2007 (Fiscal 2007). On October 1, 2008, we consummated the CPG Acquisition,
expanding our Gas Utility operations in Pennsylvania (see Acquisition of PPL Gas Utilities
Corporation below). Our Fiscal 2009 results reflect the
full-year impact of the operations of CPG.
Fiscal 2009 Compared with Fiscal 2008
Increase | ||||||||||||||||
(Millions of dollars) | 2009 | 2008 | (Decrease) | |||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 1,241.0 | $ | 1,138.3 | $ | 102.7 | 9.0 | % | ||||||||
Total margin (a) |
$ | 387.8 | $ | 307.3 | $ | 80.5 | 26.2 | % | ||||||||
Operating income |
$ | 153.5 | $ | 137.6 | $ | 15.9 | 11.6 | % | ||||||||
Income before income taxes |
$ | 111.3 | $ | 100.5 | $ | 10.8 | 10.7 | % | ||||||||
System throughput billions of cubic feet (bcf) |
149.7 | 133.7 | 16.0 | 12.0 | % | |||||||||||
Degree days % colder (warmer) than normal (b) |
4.1 | % | (2.7 | )% | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 138.5 | $ | 139.2 | $ | (0.7 | ) | (0.5 | )% | |||||||
Total margin (a) |
$ | 39.3 | $ | 47.0 | $ | (7.7 | ) | (16.4 | )% | |||||||
Operating income |
$ | 15.4 | $ | 24.4 | $ | (9.0 | ) | (36.9 | )% | |||||||
Income before income taxes |
$ | 13.7 | $ | 22.5 | $ | (8.8 | ) | (39.1 | )% | |||||||
Distribution sales millions of kilowatt-hours (gwh) |
965.7 | 1,004.4 | (38.7 | ) | (3.9 | )% |
(a) | Gas Utilitys total margin represents total revenues less cost of sales. Electric
Utilitys total margin represents total revenues less cost of sales and revenue-related taxes,
i.e. Electric Utility gross receipts taxes of $7.6 million in Fiscal 2009 and $7.9 million in
Fiscal 2008. For financial statement purposes, revenue-related taxes are included in Taxes
other than income taxes on the Consolidated Statements of Income. |
|
(b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (NOAA)
for airports located within Gas Utilitys service territory. |
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days
were 4.1% colder than normal in Fiscal 2009 compared with temperatures that were 2.7% warmer than
normal in Fiscal 2008. In Fiscal 2009, Gas Utility began calculating normal degree days using the
15-year period 19902004. Previously, normal degree days were
based upon recent 30-year periods.
For comparison purposes, the Fiscal 2008 weather variance has been recalculated using the new
15-year period. Total distribution throughput increased 16.0 bcf in Fiscal 2009 principally
reflecting the effects of the October 1, 2008 CPG Acquisition and increases in core-market volumes
resulting from the colder Fiscal 2009 weather and year-over-year customer growth. Gas Utilitys
core-market customers principally comprise firm- residential, commercial and industrial (retail
core-market) customers who purchase their gas from Gas Utility and, to a much lesser extent,
residential and small commercial customers who purchase their gas from alternate suppliers. These
increases in system throughput were partially offset by the effects on volumes sold and transported
due to lower demand from commercial and industrial customers as a result of the deterioration in
general economic activity and customer conservation.
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Gas Utility revenues increased $102.7 million in Fiscal 2009 principally reflecting $187.4
million of incremental revenues from CPG Gas largely offset by lower revenues from low-margin
off-system sales. Increases or decreases in retail core-market revenues and cost of sales
principally result from changes in retail core-market volumes and the level of gas costs collected
through the PGC recovery mechanism. Under the PGC 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 amounts 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 this 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 Utilitys cost of gas was $853.2 million in Fiscal 2009 compared with
$831.1 million in Fiscal 2008 principally reflecting incremental cost of sales of $117.0 million
associated with CPG Gas partially offset principally by the cost of sales effect of the lower
off-system sales.
Gas Utility total margin increased $80.5 million in Fiscal 2009 principally reflecting
incremental margin from CPG Gas and higher total core-market margin resulting from the higher
core-market volumes sold.
The increase in Gas Utility operating income during Fiscal 2009 principally reflects the
previously mentioned greater total margin partially offset by higher operating and administrative
and depreciation expenses, principally incremental expenses associated with CPG Gas, and, to a
lesser extent, higher pension expense, costs associated with environmental matters and greater
distribution system maintenance expenses. Income before income taxes also increased reflecting the
previously mentioned higher operating income partially offset by higher interest expense associated
with $108 million Senior Notes issued to finance a portion of the CPG Acquisition.
Electric Utility. Electric Utilitys kilowatt-hour sales in Fiscal 2009 were lower than in Fiscal
2008. Temperatures based upon heating degree days in Electric Utilitys service territory were
approximately 5.0% colder than last year resulting in greater sales to Electric Utilitys
residential heating customers. These greater sales were more than offset, however, by lower sales
to commercial and industrial customers as a result of the deterioration in general economic
activity and lower weather-related air-conditioning sales during the summer of Fiscal 2009.
Notwithstanding the lower sales, Electric Utility revenues were about equal with last year as a
result of higher POLR rates and greater revenues from spot market sales of electricity. Electric
Utility cost of sales increased to $91.6 million in Fiscal 2009 from $84.3 million in Fiscal 2008
principally reflecting greater purchased power costs.
Electric Utility total margin decreased $7.7 million during Fiscal 2009 principally reflecting
the higher cost of sales and the effects of the lower sales volumes.
Electric Utility operating income and income before income taxes in Fiscal 2009 were $9.0
million and $8.8 million lower than in Fiscal 2008, respectively, reflecting the previously
mentioned lower total margin and higher operating and administrative costs including higher
customer assistance expenses and greater pension expense.
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Fiscal 2008 Compared with Fiscal 2007
Increase | ||||||||||||||||
(Millions of dollars) | 2008 | 2007 | (Decrease) | |||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 1,138.3 | $ | 1,044.9 | $ | 93.4 | 8.9 | % | ||||||||
Total margin (a) |
$ | 307.3 | $ | 303.5 | $ | 3.8 | 1.3 | % | ||||||||
Operating income |
$ | 137.6 | $ | 136.6 | $ | 1.0 | 0.7 | % | ||||||||
Income before income taxes |
$ | 100.5 | $ | 96.7 | $ | 3.8 | 3.9 | % | ||||||||
System throughput billions of cubic feet (bcf) |
133.7 | 131.8 | 1.9 | 1.4 | % | |||||||||||
Degree days % (warmer) than normal (b) |
(2.7 | )% | (2.4 | )% | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 139.2 | $ | 121.9 | $ | 17.3 | 14.2 | % | ||||||||
Total margin (a) |
$ | 47.0 | $ | 47.3 | $ | (0.3 | ) | (0.6 | )% | |||||||
Operating income |
$ | 24.4 | $ | 26.0 | $ | (1.6 | ) | (6.2 | )% | |||||||
Income before income taxes |
$ | 22.5 | $ | 23.6 | $ | (1.1 | ) | (4.7 | )% | |||||||
Distribution sales millions of kilowatt-hours (gwh) |
1,004.4 | 1,010.6 | (6.2 | ) | (0.6 | )% |
(a) | Gas Utilitys total margin represents total revenues less cost of sales. Electric Utilitys
total margin represents total revenues less cost of sales and revenue-related taxes, i.e.
Electric Utility gross receipts taxes of $7.9 million in Fiscal 2008 and $6.8 million in
Fiscal 2007. For financial statement purposes, revenue-related taxes are included in Taxes
other than income taxes on the Consolidated Statements of Income. |
|
(b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (NOAA)
for airports located within Gas Utilitys service territory. |
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days
were 2.7% warmer than normal in Fiscal 2008 compared with temperatures that were 2.4% warmer than
normal in Fiscal 2007. Total distribution system throughput increased 1.9 bcf in Fiscal 2008
principally reflecting greater interruptible delivery service volumes (principally volumes
associated with low margin cogeneration customers) and an increase in the number of Gas Utility
core- market customers partially offset by lower average usage per customer due in large part to
price-induced customer conservation and a weak economy.
Gas Utility revenues increased $93.4 million in Fiscal 2008 principally reflecting a $57.4
million increase in revenues from off-system sales and the effects of higher average PGC rates on
retail core-market revenues. Gas Utilitys cost of sales was $831.1 million in Fiscal 2008 compared
with $741.5 million in Fiscal 2007 principally reflecting the greater off-system sales and the
increase in average retail core-market PGC rates.
Gas Utility total margin increased $3.8 million in Fiscal 2008 primarily reflecting modest
increases in interruptible delivery service and core market total margin.
The increase in Gas Utility operating income principally reflects the previously mentioned
$3.8 million increase in total margin and a $5.3 million increase in other income partially offset
by modestly higher operating and administrative expenses. The higher other income reflects in large
part greater storage contract fees and a $2.2 million postretirement benefit plan curtailment gain.
The increase in operating and administrative expenses includes, among other things, higher
environmental legal costs and greater uncollectible accounts expense. Gas Utility income before
income taxes also reflects lower interest expense on bank loans.
Electric Utility. Electric Utilitys kilowatt-hour sales in Fiscal 2008 were about equal to Fiscal
2007 on heating-season weather that was slightly warmer and cooling-season weather that was
slightly cooler. Electric Utility revenues increased $17.3 million principally as a result of
higher POLR rates. Electric Utility cost of sales increased to $84.3 million in Fiscal 2008 from
$67.8 million in the prior year principally reflecting higher per-unit purchased power costs.
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Electric Utility total margin in Fiscal 2008 was about equal to Fiscal 2007 reflecting the
effects of the higher POLR rates offset principally by the higher per-unit purchased power costs
and higher revenue-related taxes.
The decrease in Fiscal 2008 Electric Utility operating income reflects slightly higher
operating and administrative costs including higher system maintenance and uncollectible accounts
expense. Income before income taxes reflects the lower operating income partially offset by lower
interest expense on bank loans.
FINANCIAL CONDITION AND LIQUIDITY
Capitalization and Liquidity
UGI Utilities total debt outstanding was $794 million at September 30, 2009 compared with
total debt outstanding of $589 million at September 30, 2008. Included in these amounts are $154
million and $57 million, respectively, of bank loans outstanding under UGI Utilities Revolving
Credit Agreement. UGI Utilities total debt outstanding at September 30, 2009, other than bank
loans, comprises $383 million of Senior Notes and $257 million of Medium-Term Notes. In conjunction
with the October 1, 2008 CPG Acquisition, on September 25, 2008 UGI
made a $120 million cash contribution to UGI Utilities. This cash contribution was used by UGI
Utilities to reduce its bank loans outstanding. On October 1, 2008, UGI Utilities borrowed under
the Revolving Credit Facility to fund a portion of the CPG Acquisition (see Acquisition of PPL Gas
Utilities Corporation below).
UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At
September 30, 2009 and 2008, there was $154 million and $57 million outstanding under this
Revolving Credit Agreement. As previously mentioned, the September 30, 2008 amount was reduced by a
$120 million cash contribution made by UGI on September 25, 2008 to finance a portion of the CPG
Acquisition on October 1, 2008. The Revolving Credit Agreement requires UGI Utilities to maintain a
maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
During Fiscal 2009 and Fiscal 2008, average daily bank loan borrowings totaled $180.0 million and
$121.0 million, respectively, and peak bank loan borrowings totaled $312 million and $267 million,
respectively. Peak bank loan borrowings typically occur during the peak heating season months of
December and January when UGI Utilities investment in working capital, principally accounts
receivable and inventories, is generally greatest. Average bank loan borrowings were higher in
Fiscal 2009 than in Fiscal 2008 due in large part to increases in margin deposits associated with
natural gas futures contracts as a result of declines in wholesale natural gas prices (see Market
Risk Disclosures below).
Based upon cash expected to be generated from operations and borrowings under our Revolving
Credit Agreement, management believes the Company will be able to meet its anticipated contractual
and projected cash commitments during Fiscal 2010. For additional discussion of UGI Utilities
long-term debt and Revolving Credit Agreement, see Note 8 to Consolidated Financial Statements.
Cash Flows
Operating activities. Due to the seasonal nature of UGI Utilities businesses, cash flows from our
operating activities are generally strongest during the second and third fiscal quarters when
customers pay for natural gas and electricity consumed during the peak heating season months.
Conversely, operating cash flows are generally at their lowest levels during the first and fourth
fiscal quarters when the Companys investment in working capital, principally accounts receivable
and inventories, is generally greatest. UGI Utilities uses borrowings under its Revolving Credit
Agreement to manage seasonal cash flow needs.
Cash provided by operating activities was $176.4 million in Fiscal 2009, $142.6 million in
Fiscal 2008 and $133.5 million in Fiscal 2007. Cash provided by operating activities before changes
in operating working capital was $187.1 million in Fiscal 2009, $143.3 million in Fiscal 2008 and
$150.6 million in Fiscal 2007. Changes in operating working capital used $10.7 million of cash in
Fiscal 2009, $0.8 million of cash in Fiscal 2008 and $17.1 million of cash in Fiscal 2007. The
greater cash flow required for changes in operating working capital in Fiscal 2009 as compared with
Fiscal 2008 principally reflects greater cash used for purchases of natural gas inventories, the
timing of payments of accounts payable and lower net recoveries of purchased gas costs partially
offset by $19 million of collateral deposits received under storage contract administrative
agreements. The lower cash flow required for changes in operating working capital in Fiscal 2008 as
compared with Fiscal 2007 principally reflects the timing of cash recoveries through Gas Utilitys
PGC recovery mechanism in excess of purchased gas costs, including cash from settled gains on
natural gas futures contracts, partially offset by the timing of interest payments and payments for
accounts payable.
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Investing activities. Cash used by investing activities was $310.4 million in Fiscal 2009, $92.3
million in Fiscal 2008, and $55.2 million in Fiscal 2007. Fiscal 2009 cash flow from investing
activities includes net cash used for the acquisition of CPG. It also includes net cash proceeds
from the concurrent sale of the assets of Penn Fuel Propane, CPGs wholly owned subsidiary, to
AmeriGas OLP. Expenditures for property, plant and equipment were higher in Fiscal 2009 compared
with Fiscal 2008 reflecting in large part expenditures for CPG. Expenditures for property, plant
and equipment decreased $9.1 million in Fiscal 2008 compared with Fiscal 2007 principally
reflecting lower Gas Utility capital expenditures associated with its multi-year automated meter
reading project. Fiscal 2009 investing activity cash flows also reflect a reduction in restricted
cash in natural gas futures brokerage accounts of $34.0 million compared with an increase of $27.4
million in Fiscal 2008. Changes in restricted cash in futures brokerage accounts are the result of
the timing of settlement of natural gas futures contracts and changes in natural gas prices. Cash
flow from investing activities in Fiscal 2007 includes a $23.7 million working capital adjustment
associated
with UGI Utilities Fiscal 2006 acquisition of Southern Union Companys PG Energy Division (see
Note 4 to Consolidated Financial Statements).
Financing activities. Cash provided (used) by financing activities was $144.1 million in Fiscal
2009, ($63.0) million in Fiscal 2008 and ($65.0) million in Fiscal 2007. Financing activities cash
flows are primarily the result of issuances and repayments of long-term debt, borrowings under the
Revolving Credit Agreement, cash dividends to UGI, and capital contributions from UGI. During
Fiscal 2009 net bank loan borrowings totaled $97 million compared with net bank loan repayments of
$133 million in Fiscal 2008 and $26 million in Fiscal 2007. The significant increase in net cash
from bank loan borrowings in Fiscal 2009 was due in large part to the timing and use of cash
contributions made by UGI in September 2008 to fund the CPG Acquisition on October 1, 2008. As
previously mentioned, a $120 million cash contribution made by UGI on September 25, 2008 was
temporarily used by UGI Utilities in September 2008 to reduce bank loan borrowings. This amount was
then reborrowed on October 1, 2008, along with additional bank loan borrowings, to fund a portion
of the CPG Acquisition. During Fiscal 2009, we issued $108 million of 6.375% Senior Notes due 2013
the proceeds of which were used to fund a portion of the CPG Acquisition. In January 2008, UGI
Utilities issued $20 million of 5.67% Medium-Term Notes and used the proceeds to reduce Revolving
Credit Agreement borrowings. In June 2007, UGI Utilities refinanced $20 million of maturing 7.17%
Medium-Term Notes with proceeds from the issuance of $20 million of 6.17% Medium-Term Notes.
Capital Expenditures
In the following table, we present capital expenditures by business segment for Fiscal 2009,
Fiscal 2008 and Fiscal 2007. We also provide amounts we expect to spend in Fiscal 2010. We expect
to finance a substantial portion of Fiscal 2010 capital expenditures from cash generated by
operations and the remainder from borrowings under our Revolving Credit Agreement.
(Millions of dollars) | 2010 | 2009 | 2008 | 2007 | ||||||||||||
(estimate) | ||||||||||||||||
Gas Utility |
$ | 71.1 | $ | 73.8 | $ | 58.3 | $ | 66.2 | ||||||||
Electric Utility |
12.9 | 5.3 | 6.0 | 7.2 | ||||||||||||
$ | 84.0 | $ | 79.1 | $ | 64.3 | $ | 73.4 | |||||||||
The greater Electric Utility capital expenditures forecast for Fiscal 2010 includes
expenditures related to increased transmission capacity associated with additions to electric
generating capacity in its service territory.
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Contractual Cash Obligations and Commitments
UGI Utilities has contractual cash obligations that extend beyond Fiscal 2009 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, 2009.
Payments Due by Period | ||||||||||||||||||||
Fiscal | Fiscal | Fiscal | ||||||||||||||||||
(Millions of dollars) | Total | 2010 | 2011-2012 | 2013-2014 | Thereafter | |||||||||||||||
Long-term debt (a) |
$ | 640.0 | $ | | $ | 40.0 | $ | 133.0 | $ | 467.0 | ||||||||||
Interest on long-term fixed rate debt (b) |
399.8 | 37.1 | 75.0 | 61.9 | 225.8 | |||||||||||||||
Operating leases |
22.4 | 5.0 | 7.7 | 5.0 | 4.7 | |||||||||||||||
Gas Utility
and Electric Utility supply, storage and transportation contracts |
704.1 | 240.8 | 233.4 | 121.4 | 108.5 | |||||||||||||||
Total |
$ | 1,766.3 | $ | 282.9 | $ | 356.1 | $ | 321.3 | $ | 806.0 | ||||||||||
(a) | Based upon stated maturity dates. |
|
(b) | Based upon stated interest rates. |
|
The components of the other noncurrent liabilities included in our Consolidated Balance Sheet
at September 30, 2009 principally consist of pension and other postretirement benefit liabilities
recorded in accordance with GAAP and estimated obligations for environmental investigation and
remediation. These liabilities are not included in the table of Contractual Cash Obligations and
Commitments above because they are estimates of future payments and not contractually fixed as to
timing or amount. For additional information on these liabilities see Notes 10 and 13 to
Consolidated Financial Statements.
Acquisition of PPL Gas Utilities Corporation
On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas
Utilities Corporation (now CPG), the natural gas distribution utility of PPL Corporation (the
CPG Acquisition), and its subsidiaries for cash consideration of $267.6 million plus estimated
working capital of $35.4 million. Immediately after the closing of the CPG Acquisition, CPGs
wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, CPP),
its retail propane distributor, sold its assets to AmeriGas Propane, L.P. (AmeriGas OLP), an
affiliate of UGI, for cash consideration of $32 million plus estimated working capital of $1.6
million. CPG distributes natural gas to approximately 76,000 customers in eastern and central
Pennsylvania and also distributes natural gas to several hundred customers in portions of one
Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities
funded the CPG Acquisition with a combination of $120 million cash contributed by UGI on September
25, 2008, proceeds from the issuance on October 1, 2008 of $108 million principal amount of 6.375%
Senior Notes due 2013 and approximately $75 million of borrowings under UGI Utilities Revolving
Credit Agreement. The cash proceeds of $33.6 million from the sale of the assets of CPP to AmeriGas
OLP were used to reduce borrowings under UGI Utilities Revolving Credit Agreement.
Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to
adjustment for the difference between an estimated $35.4 million and the actual working capital as
of the closing date agreed to by both UGI Utilities and PPL Corporation (PPL). During Fiscal
2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to
which PPL paid UGI Utilities $9.7 million in cash plus interest. Also during Fiscal 2009, UGI
Utilities and AmeriGas OLP reached an agreement on the working capital adjustment associated with
UGI Utilities sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities paid
AmeriGas OLP $1.4 million.
For additional information regarding the CPG Acquisition, see Note 4 to Consolidated Financial
Statements.
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Pension Plans
As of September 30, 2009, we sponsor two defined benefit pension plans (Pension Plans) for
employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGIs other
domestic wholly owned subsidiaries.
Effective December 31, 2008, we merged two of our defined benefit pension plans. As a result
of the merger, we were required under U.S. generally accepted accounting principles (GAAP) to
remeasure the combined plans assets and benefit obligations as of December 31, 2008. As a result
of the remeasurement, Fiscal 2009 pension expense increased
approximately $3.9 million for the
period subsequent to the remeasurement due to the amortization of actuarial losses resulting from
the general decline in the financial markets and a lower discount rate. The fair value of Pension
Plans assets totaled $276.4 million and $241.0 million at September 30, 2009 and 2008,
respectively. At September 30, 2009 and 2008, the underfunded position of Pension Plans, defined as
the excess of the projected benefit obligations (PBOs) over the Pension Plans assets, was $145.6
million and $59.6 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans,
including Employee Retirement Income Security Act of 1974 (ERISA) rules and regulations. We
anticipate that we will be required to make contributions to the Pension Plans during Fiscal 2010 but
such contributions are not expected to be material. Pre-tax pension costs associated with Pension Plans in Fiscal 2009 were $7.1 million. Pension cost
associated with Pension Plans in Fiscal 2010 is expected to be approximately $7.9 million.
GAAP guidance associated with pension and other postretirement plans generally requires
recognition of an asset or liability in the statement of financial position reflecting the funded
status of pension and other postretirement benefit plans with current year changes recognized in
shareholders equity unless such amounts are subject to regulatory recovery. In accordance with
this guidance, through September 30, 2009 we have recorded cumulative after-tax charges to Common
Stockholders Equity of $79.1 million in order to reflect the funded status of these plans. For a
more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 10
to Consolidated Financial Statements.
REGULATORY MATTERS
Gas Utility. On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base
operating revenues by $38.1 million annually for PNG and $19.6 million annually for CPG to fund
system improvements and operations necessary to maintain safe and reliable natural gas service and
energy assistance for low income customers as well as energy conservation programs for all
customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on
agreements with the opposing parties regarding the requested base operating revenue increases. On
August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 million base
operating revenue increase for PNG Gas and a $10.0 million base operating revenue increase for CPG
Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal
2009 results.
Electric Utility. As a result of Pennsylvanias Electricity Generation Customer Choice and
Competition Act that became effective January 1, 1997, all of Electric Utilitys customers are
permitted 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 through December 31,
2009, were established in a series of PUC approved settlements (collectively, the POLR
Settlement), the latest of which became effective June 23, 2006.
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to
certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement,
Electric Utility increased its POLR rates effective January 1, 2009, which increased the average
cost to a residential heating customer by approximately 1.5% over such costs in effect during
calendar year 2008. Effective January 1, 2008, Electric Utility increased its POLR rates which
increased the average cost to a residential heating customer by approximately 5.5% over such costs
in effect during calendar year 2007. Effective January 1, 2007, Electric Utility increased the
average cost to a residential heating customer by approximately 35% over such costs in effect
during calendar year 2006.
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On July 17, 2008, the PUC approved Electric Utilitys default service procurement,
implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed
in accordance with the PUCs default service regulations. These plans do not affect Electric
Utilitys existing POLR settlement effective through December 31, 2009. The approved plans specify
how Electric Utility will solicit and acquire default service supplies for residential customers
for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers
for the period January 1, 2010 through May 31, 2011 (collectively, the Settlement Term). UGI
Utilities filed a rate plan on August 29, 2008 for the Settlement Term. On January 22, 2009, the
PUC approved a settlement of the rate filing that provides for Electric Utility to fully recover
its default service costs. On October 1, 2009, UGI Utilities filed a default service plan to
establish procurement rules applicable to the period after May 31, 2011 for its commercial and
industrial customers.
Because Electric Utility will be assured the recovery of prudently incurred costs during the
Settlement Term, beginning January 1, 2010 Electric Utility will no longer be subject to the risk
that actual costs for purchased power will exceed POLR revenues. However, beginning January 1,
2010, Electric Utility will forego the opportunity to recover revenues in excess of actual costs as
currently permitted under the POLR Settlement. This will result in a
reduction in Electric Utilitys Fiscal 2010 operating income.
MANUFACTURED GAS PLANTS
CPG is party to a Consent Order and Agreement (CPG-COA) with the Pennsylvania Department of
Environmental Protection (DEP) requiring CPG to perform a specified level of activities
associated with environmental investigation and remediation work at certain properties in
Pennsylvania on which manufactured gas plant (MGP) related facilities were operated (CPG MGP
Properties) and to plug a minimum number of non-producing natural gas wells per year. In addition,
PNG is a party to a Multi-Site Remediation Consent Order and Agreement (PNG-COA) with the DEP. The PNG-COA
requires PNG to perform annually a specified level of activities associated with environmental
investigation and remediation work at certain properties on which MGP-related facilities were
operated (PNG MGP Properties). Under these agreements, environmental expenditures relating to the
CPG MGP Properties and the PNG MGP Properties are capped at $1.8 million and $1.1 million,
respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP
Properties and at the end of 2013 for well plugging activities. The PNG-COA terminates in 2019 but
may be terminated by either party effective at the end of any two-year period beginning with the
original effective date in March 2004. At September 30, 2009, our accrued liabilities for
environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled
$25.0 million. In accordance with GAAP related to rate-regulated entities, we have recorded
associated regulatory assets totaling $25.0 million.
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and
operated a number of 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, by the early 1950s UGI Utilities divested all of
its utility operations other than certain Pennsylvania operations, including those which now
constitute UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous
substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is
currently permitted to include in rates, through future base rate proceedings, a five-year average
of such prudently incurred remediation costs. At September 30, 2009 and 2008, neither UGI Gas
undiscounted nor its accrued liability for environmental investigation and cleanup costs was
material.
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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.
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 subsidiarys 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 subsidiarys MGP.
For additional information on the MGP sites outside of Pennsylvania currently subject to
third-party claims or litigation, see Note 13 to Consolidated Financial Statements.
We cannot predict with certainty the final results of any of the MGP actions described above.
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.
RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI
Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an
allocated share of indirect corporate expenses incurred or paid with respect to services provided
to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI Utilities utilizes a
weighted, three-component formula based upon the relative percentage of UGI Utilities revenues,
operating expenses and net assets employed to the total of such items for UGIs other operating
subsidiaries for which general and administrative services are provided. Management believes that
this allocation method is reasonable and equitable to UGI Utilities and this allocation method has
been accepted by the PUC in past rate case proceedings and management audits as a reasonable method
of allocating such expenses. These billed expenses totaled $15.0 million in Fiscal 2009, $11.8
million in Fiscal 2008 and $11.6 million in Fiscal 2007 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 UGIs subsidiaries, principally
payroll-related services. Amounts billed to these entities by UGI Utilities were not material.
At September 30, 2009, UGI Utilities was a party to a one-year storage contract administrative
agreement (SCAA) with Energy Services expiring on October 31, 2009. At September 30, 2008, UGI
Utilities was a party to a one-year SCAA with Energy Services expiring on October 31, 2008.
Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and
transportation contracts for the terms of the storage SCAAs. UGI Utilities also transferred certain
associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage
inventories at the end of the SCAAs, and makes payments associated with refilling storage
inventories during the terms of the SCAAs. Energy Services, in turn, provides a firm delivery
service and makes certain payments to UGI Utilities for its various obligations under the SCAAs.
UGI Utilities incurred costs associated with the SCAAs totaling $55.8 million in Fiscal 2009,
$111.8 million in Fiscal 2008 and $92.7 million in Fiscal 2007. 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, 2009, comprising approximately 7.7 billion cubic feet of natural gas,
was $67.4 million. The carrying value of these gas storage inventories at September 30, 2008,
comprising approximately 8.3 billion cubic feet of natural gas, was $70.8 million. Effective
November 1, 2009, UGI Utilities entered into a new SCAA with Energy Services expiring on October
31, 2012.
UGI Utilities also has a Gas Supply and Delivery Service Agreement with Energy Services
pursuant to which Energy Services provides certain gas supply and related delivery service to UGI
Utilities during the peak heating-season months of November to March. In addition, from time to
time, UGI Utilities purchases natural gas or pipeline capacity from Energy Services. The aggregate
amount of these transactions during Fiscal 2009, Fiscal 2008 and Fiscal 2007 (exclusive of Storage
Agreement transactions described above) totaled $24.4 million, $52.6 million and $36.3 million,
respectively.
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From time to time, UGI Utilities sells natural gas or pipeline capacity to Energy Services.
During Fiscal 2009, Fiscal 2008 and Fiscal 2007, revenues associated with sales to Energy Services
totaled $30.9 million, $66.1 million, and $39.6 million, respectively. Also from time to time, the
Company purchases natural gas or pipeline capacity from Energy Services (in addition to those
transactions already described above). During Fiscal 2009, Fiscal 2008 and Fiscal 2007, such
purchases totaled $17.3 million, $29.5 million and $2.0 million, respectively. These transactions
did not have a material effect on the Companys financial position, results of operations or cash
flows.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements that are expected to have an effect on the
Companys financial condition, revenues and expenses, results of operations, liquidity, capital
expenditures or capital resources.
MARKET RISK DISCLOSURES
As previously mentioned, Gas Utilitys tariffs contain clauses that permit recovery of 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 derivative financial instruments including natural gas futures contracts traded on the
New York Mercantile Exchange (NYMEX) to reduce volatility in the cost of gas it purchases for its
retail core-market customers. There were no natural gas futures contracts outstanding at September
30, 2009. The fair value of natural gas futures contracts at September 30, 2008 were losses of
$23.3 million. The cost of natural gas derivative financial instruments, net of any associated
gains or losses, is included in Gas Utilitys PGC recovery mechanism. The change in market value of
natural gas futures contracts can require daily deposits of cash in futures accounts. At September
30, 2008, Gas Utility had approximately $34.0 million of restricted cash associated with natural
gas futures accounts with brokers. At September 30, 2009, there were no restricted cash balances.
Our Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline
futures and swap contracts for a portion of gasoline volumes expected to be used in their
operations. These gasoline futures and swap contracts are recorded at fair value with changes in
fair value reflected in other income. The amount of the unrealized gains or loss on these contracts
and associated volumes under contract at September 30, 2009 were not material. A 10% adverse change
in the market value of gasoline futures contracts would not have a material effect on the Companys
operating income.
Electric Utility purchases its electric power needs from electricity suppliers under
fixed-price energy contracts and, to a much lesser extent, on the spot market. Wholesale prices for
electricity can be volatile especially during periods of high demand or tight supply. As previously
mentioned and in accordance with POLR settlements approved by the PUC, Electric Utility may
increase its POLR rates up to certain limits through December 31, 2009. Electric Utilitys
fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR
service rate limits in effect through December 31, 2009. With respect to its existing fixed-price
power contracts, should any of the counterparties fail to provide electric power under the terms of
such contracts, any increases in the cost of replacement power could negatively impact Electric
Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its
purchases across several suppliers and entered into bilateral collateral arrangements with certain
of them. Changes in electricity prices could require Electric Utility to provide cash collateral to
its supply counterparties. Electric Utility also obtains financial transmission rights (FTRs)
through an annual PJM Interconnection (PJM) auction process and, to a lesser extent, by purchases
at monthly PJM auctions. FTRs are financial instruments that entitle the holder to receive
compensation for electricity transmission congestion charges that result when there is insufficient
electricity transmission capacity on the electricity transmission grid. PJM is a regional
transmission organization that coordinates the movement of wholesale electricity in all or parts of
14 eastern and midwestern states. Although FTRs are economically effective as hedges of congestion
charges, they do not currently qualify for hedge accounting treatment. At September 30, 2009, the
fair value of Electric Utilitys FTRs was $0.8 million. A 10% adverse change in the market value of
FTRs would not have a material impact on the Companys operating income.
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As previously mentioned, on January 22, 2009, the PUC approved a settlement of a rate filing
that provides for Electric Utility to fully recover its default service costs. Because Electric
Utility will be assured the recovery of prudently incurred costs during the Settlement Term,
beginning January 1, 2010, Electric Utility will no longer be subject to the risk that actual costs
for purchased power, including FTRs, will exceed POLR revenues.
Our variable-rate debt includes our bank loan borrowings. These agreements provide for
interest rates on borrowings that are indexed to short-term market interest rates. Based upon the
average level of borrowings outstanding under these agreements in Fiscal 2009 and Fiscal 2008, an
increase in short-term interest rates of 100 basis points (1%) would have increased annual interest
expense by $1.8 million and $1.2 million, respectively.
Our long-term debt is typically issued at fixed rates of interest based upon market rates for
debt having similar terms and credit ratings. As these long-term debt issues mature, we expect to
refinance such debt with new debt having interest rates reflecting then-current market conditions.
A 100 basis point increase in market interest rates
would result in decreases in the fair value of this fixed-rate debt of $51.8 million and $34.4
million at September 30, 2009 and 2008, respectively. A 100 basis point decrease in market interest
rates would result in increases in the fair value of this fixed-rate debt of $58.9 million and
$38.8 million at September 30, 2009 and 2008, respectively.
In order to reduce interest rate risk associated with near or medium term issuances of
fixed-rate debt, we may enter into interest rate protection agreements.
Our unsettled derivative instruments at September 30, 2009 comprised Electric Utilitys FTRs
and exchange-traded gasoline futures and swap contracts.
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 accounting principles appropriate to the relevant facts and circumstances of the
Companys operations and the use of estimates made by management. The Company has identified the
following critical accounting policies and estimates that are most important to the portrayal of
the Companys financial condition and results of operations. Changes in these policies and
estimates could have a material effect on the financial statements. The application of these
accounting policies and estimates necessarily requires managements 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 Companys Audit Committee. In
addition, management has reviewed the following disclosures regarding the application of these
critical accounting policies and estimates with the Audit Committee.
Purchase Price Allocations. In the event that the Company enters into a material business
combination, in accordance with accounting guidance associated with business combinations the
purchase price is allocated to the various assets and liabilities acquired at their estimated fair
value. Fair values of assets are based upon available information and we may involve an independent
third-party to perform appraisals. Estimating fair values can be complex and subject to significant
business judgment and most commonly impacts property, plant and equipment and intangible assets,
including those with indefinite lives. Generally, we have, if necessary, up to one year from the
acquisition date to finalize the purchase price allocation.
Impairment of Goodwill. Our allocation of the purchase price of acquisitions has resulted in the
Company recording goodwill. In accordance with GAAP, a reporting unit with goodwill is required to
perform impairment tests annually or whenever events or circumstances indicate that the value of
goodwill may be impaired. In order to perform these impairment tests, management must determine the
reporting units fair value using quoted market prices or, in the absence of quoted market prices,
valuation techniques which use discounted estimates of future cash flows to be generated by the
reporting unit. These cash flow estimates involve management judgments based on a broad range of
information and historical results. To the extent estimated cash flows are revised downward, the
reporting unit may be required to write down all or a portion of its goodwill which would adversely
impact our results of operations. As of September 30, 2009, our goodwill totaled $180.1 million. We
did not record any impairments of goodwill during Fiscal 2009, Fiscal 2008 or Fiscal 2007.
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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, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in
Pennsylvania and elsewhere and PNG Gas and CPG Gas owned and operated a number of MGP sites located
in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, we
establish reserves for pending claims and legal actions or environmental remediation obligations
when it is probable that a liability exists and the amount or range of amounts can be reasonably
estimated. Reasonable estimates involve management judgments based on a broad range of information
and prior experience. These judgments are reviewed quarterly as more information is received and
the amounts reserved are updated as necessary. Such estimated reserves may differ materially from
the actual liability and such reserves may change materially as more information becomes available
and estimated reserves are adjusted.
Depreciation of Property, Plant and Equipment. We compute depreciation on UGI 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, 2009, UGI Utilities net property, plant and
equipment totaled $1,364.8 million and we recorded depreciation expense of $48.9 million during
Fiscal 2009.
Regulatory Assets and Liabilities. Gas Utility and Electric Utilitys distribution businesses are
subject to regulation by the PUC. In accordance with accounting guidance associated with
rate-regulated entities, 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, 2009,
our regulatory assets totaled $141.5 million. For additional information on our regulatory assets,
see Note 5 to the Consolidated Financial Statements.
Pension Plan Assumptions. The costs of providing benefits under our Pension Plans is 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
used to determine pension expense including the discount rate applied to benefit obligations, the
expected rate of return on plan assets and the rate of compensation increase, among others. Assets
of the Pension Plans 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 fixed income market
returns could have a material impact on future pension costs. We believe the two most critical
assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A
decrease in the expected rate of return on plan assets of 50 basis points to a rate of 8.0% would
result in an increase in pre-tax pension cost of approximately $1.1 million in Fiscal 2010. A
decrease in the discount rate of 50 basis points to a rate of 5.0% would result in an increase in
pre-tax pension cost of approximately $1.7 million in Fiscal 2010.
NEWLY ADOPTED AND RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
See Note 3 to Consolidated Financial Statements for a discussion of the effects of accounting
guidance we adopted in Fiscal 2009, Fiscal 2008 and Fiscal 2007 as well as recently issued
accounting guidance not yet adopted.
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Quantitative and Qualitative Disclosures About Market Risk are contained in
Item 7 Managements Discussion and Analysis of Financial Condition and Results of
Operations under the caption Market Risk Disclosures and are incorporated herein by
reference.
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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 Companys management, with the participation of the Companys Chief Executive
Officer and Chief Financial Officer, evaluated the effectiveness of the Companys
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 Companys 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 SECs 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, of the Companys
internal control over financial reporting using the criteria in Internal Control
Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO Framework). |
||
Internal control over financial reporting refers to the process, designed under the
supervision and participation of management including our Chief Executive Officer and
Chief Financial Officer, 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 and includes policies and procedures that, among other things, provide
reasonable assurance that assets are safeguarded and that transactions are executed in
accordance with managements 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, 2009, based on
the COSO Framework. |
(c) | No change in the Companys internal control over financial reporting occurred during
the Companys most recent fiscal quarter that has materially affected, or is reasonably
likely to materially affect, the Companys internal control over financial reporting. |
ITEM 9B. | OTHER INFORMATION |
None.
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PART III:
ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The aggregate fees billed by PricewaterhouseCoopers LLP, the Companys independent registered
public accountants, in Fiscal 2009 and Fiscal 2008 were as follows:
2009 | 2008 | |||||||
Audit Fees |
$ | 991,250 | $ | 848,898 | ||||
Audit-Related Fees |
- 0 - | - 0 - | ||||||
Tax Fees |
- 0 - | - 0 - | ||||||
All Other Fees |
- 0 - | - 0 - | ||||||
Total Fees for Services Provided |
$ | 991,250 | $ | 848,898 | ||||
Consistent with SEC policies regarding auditor independence, the Audit Committee has
responsibility for appointing, setting compensation and overseeing the work of the Companys
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 Companys independent accountants for the next years 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, 2009 and 2008
Consolidated Statements of Income for the fiscal years ended September 30, 2009, 2008
and 2007
Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2009,
2008 and 2007
Consolidated Statements of Stockholders Equity for the fiscal years ended
September 30, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
(2) Financial Statement Schedule:
For the years ended September 30, 2009, 2008 and 2007
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.
25
Table of Contents
(3) List of Exhibits:
The exhibits filed as part of this report are as follows (exhibits incorporated by
reference are set forth with the name of the registrant, the type of report and
registration number or last date of the period for which it was filed, and the exhibit
number in such filing):
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
3.1 | UGI Utilities Amended and Restated Articles of
Incorporation
|
Utilities | Registration Statement No. 333-72540 (10/31/01) | 3 | ||||||||
3.2 | Bylaws of UGI Utilities as amended through
September 30, 2003
|
Utilities | Form 10-K (9/30/03) | 3.2 | ||||||||
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 | UGI Utilities Articles of Incorporation and
Bylaws referred to in Exhibit Nos. 3.1 and 3.2
|
UGI | Form 8-B/A (4/17/96) | 3. | (4) | |||||||
4.2 | Indenture, dated as of August 1, 1993, by and
between UGI Utilities, Inc., as Issuer, and U.S.
Bank National Association, as successor trustee,
incorporated by reference to the Registration
Statement on Form S-3 filed on April 8, 1994
|
Utilities | Registration Statement No. 33-77514 (4/8/94) | 4 | (c) | |||||||
4.3 | Supplemental Indenture, dated as of September
15, 2006, by and between UGI Utilities, Inc., as
Issuer, and U.S. Bank National Association,
successor trustee to Wachovia Bank, National
Association
|
Utilities | Form 8-K (9/12/06) | 4.2 | ||||||||
4.4 | Form of Fixed Rate Medium-Term Note
|
Utilities | Form 8-K (8/26/94) | (4)i | ||||||||
4.5 | Form of Fixed Rate Series B Medium-Term Note
|
Utilities | Form 8-K (8/1/96) | 4(i) | ||||||||
4.6 | Form of Floating Rate Series B Medium-Term Note
|
Utilities | Form 8-K (8/1/96) | 4(ii) | ||||||||
4.7 | Officers Certificate establishing Medium-Term
Notes Series
|
Utilities | Form 8-K (8/26/94) | 4(iv) | ||||||||
4.8 | Form of Officers Certificate establishing
Series B Medium-Term Notes under the Indenture
|
Utilities | Form 8-K (8/1/96) | 4(iv) | ||||||||
4.9 | Form of Officers Certificate establishing
Series C Medium-Term Notes under the Indenture
|
Utilities | Form 8-K (5/21/02) | 4.2 | ||||||||
4.10 | Forms of Floating Rate and Fixed Rate Series C
Medium-Term Notes
|
Utilities | Form 8-K (5/21/02) | 4.1 | ||||||||
10.1 | ** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Amended and Restated as of December 5, 2006
|
UGI | Form 8-K (3/27/07) | 10.1 | |||||||
10.2 | ** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Amended and Restated as of December 5, 2006
Terms and Conditions as amended and restated
effective January 1, 2009
|
UGI | Form 10-K (9/30/09) | 10.2 | |||||||
10.3 | ** | UGI Corporation 1997 Stock Option and Dividend
Equivalent Plan Amended and Restated as of May
24, 2005
|
UGI | Form 10-K (9/30/06) | 10.10 | |||||||
10.4 | ** | UGI Corporation 2000 Stock Incentive Plan
Amended and Restated as of May 24, 2005
|
UGI | Form 10-K (9/30/06) | 10.14 |
26
Table of Contents
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
10.5** | UGI Corporation 2009 Deferral Plan
|
UGI | Form 8-K (12/12/08) | 10.1 | ||||||||
10.6** | UGI Corporation Senior Executive Employee
Severance Plan as in effect as of January 1,
2008
|
UGI | Form 10-Q (3/31/08) | 10.1 | ||||||||
10.7** | UGI Corporation Supplemental Executive
Retirement Plan and Supplemental Savings Plan,
as Amended and Restated effective January 1,
2009
|
UGI | Form 10-K (9/30/09) | 10.11 | ||||||||
10.8** | UGI Corporation Executive Annual Bonus Plan
effective as of October 1, 2006
|
UGI | Form 10-K (9/30/07) | 10.8 | ||||||||
10.9** | UGI Utilities, Inc. Executive Annual Bonus Plan
effective as of October 1, 2006
|
Utilities | Form 10-K (9/30/07) | 10.5 | ||||||||
*10.10** | UGI Utilities, Inc. Senior Executive Employee
Severance Plan as in effect as of November 1,
2008 |
|||||||||||
10.11** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Stock Unit Grant Letter for UGI Employees,
dated January 1, 2009
|
UGI | Form 10-Q (3/31/09) | 10.8 | ||||||||
10.12** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Stock Unit Grant Letter for Utilities
Employees, dated January 1, 2009
|
UGI | Form 10-K (9/30/09) | 10.23 | ||||||||
10.13** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Nonqualified Stock Option Grant Letter for
UGI Employees, dated January 1, 2009
|
UGI | Form 10-Q (3/31/09) | 10.5 | ||||||||
10.14** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Nonqualified Stock Option Grant Letter for
Utilities Employees, dated January 1, 2009
|
UGI | Form 10-Q (3/31/09) | 10.6 | ||||||||
10.15** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Performance Unit Grant Letter for UGI
Employees, dated January 1, 2009
|
UGI | Form 10-Q (3/31/09) | 10.1 | ||||||||
10.16** | UGI Corporation 2004 Omnibus Equity Compensation
Plan Performance Unit Grant Letter for Utilities Employees, dated January 1, 2009
|
UGI | Form 10-Q (3/31/09) | 10.2 | ||||||||
10.17** | Form of Change in Control Agreement Amended and
Restated as of May 12, 2008 for Messrs.
Greenberg and Walsh
|
UGI | Form 10-Q (6/30/08) | 10.3 | ||||||||
*10.18** | Form of Change in Control Agreement Amended and
Restated as of May 12, 2008 for Messrs. Barney
and Terranova and Ms. Ebner |
27
Table of Contents
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
10.19 | Credit Agreement, dated as of August 11, 2006,
among UGI Utilities, Inc., as borrower, and
Citibank, N.A., as agent, Wachovia Bank,
National Association, as syndication agent, and
Citizens Bank of Pennsylvania, Credit Suisse,
Cayman Islands Branch, Deutsche Bank AG New York
Branch, JPMorgan Chase Bank, N.A., Mellon Bank,
N.A., PNC Bank, National Association, and the
other financial institutions from time to time
parties thereto
|
Utilities | Form 8-K (8/11/06) | 10.1 | ||||||||
10.20 | Stock Purchase Agreement by and between PPL
Corporation, as Seller, and UGI Utilities, Inc.,
as Buyer, dated as of March 5, 2008
|
Utilities | Form 8-K (3/5/08) | 10.1 | ||||||||
10.21 | Amendment dated May 2, 2008 to the Stock
Purchase Agreement by and between PPL
Corporation, as Seller, and UGI Utilities, Inc.,
as Buyer, dated as of March 5, 2008
|
Utilities | Form 10-Q (3/31/08) | 10.2 | ||||||||
10.22 | Purchase and Sale Agreement by and between
Southern Union Company, as Seller, and UGI
Corporation, as Buyer, dated as of January 26,
2006
|
UGI | Form 8-K (1/26/06) | 10.1 | ||||||||
10.23 | Gas Service Delivery and Supply Agreement
between Utilities and UGI Energy Services, Inc. dated August 1, 2004
|
Utilities | Form 10-K (9/30/04) | 10.32 | ||||||||
10.24 | Service Agreement (Rate FSS) dated as of
November 1, 1989 between Utilities and Columbia,
as modified pursuant to the orders of the
Federal Energy Regulatory Commission at Docket
No. RS92-5-000 reported at Columbia Gas
Transmission Corp., 64 FERC ¶61,060 (1993),
order on rehearing, 64 FERC ¶61,365 (1993)
|
UGI | Form 10-K (9/30/95) | 10.5 | ||||||||
10.25 | Storage Transportation Service Agreement (Rate
Schedule SST) between Utilities and Columbia
dated November 1, 1993, as modified pursuant to
orders of the Federal Energy Regulatory
Commission
|
Utilities | Form 10-K (9/30/02) | 10.25 | ||||||||
10.26 | Amendment No. 1 dated November 1, 2004, to the
Service Agreement (Rate FSS) dated as of
November 1, 1989 between UGI Utilities and Columbia,
as modified pursuant to the orders of the
Federal Energy Regulatory Commission at Docket
No. RS92-5-000 reported at Columbia Gas
Transmission Corp., 64 FERC ¶61,060 (1993),
order on rehearing, 64 FERC ¶61,365 (1993)
|
Utilities | Form 10-K (9/30/04) | 10.26 | ||||||||
10.27 | Firm Transportation Service Agreement (Rate
Schedule FTS) between Utilities and Columbia Gas
Transmission dated November 1, 2004
|
Utilities | Form 10-K (9/30/04) | 10.34 |
28
Table of Contents
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
10.28 | Service Agreement (Rate FSS) dated August 16,
2004 between Columbia Gas Transmission
Corporation and PG Energy
|
Utilities | Form 8-K (8/24/06) | 10.4 | ||||||||
10.29 | Service Agreement (Rate SST) dated August 16,
2004 between Columbia Gas Transmission
Corporation and PG Energy
|
Utilities | Form 8-K (8/24/06) | 10.5 | ||||||||
10.30 | FSS Service Agreement No. 49789, dated November
20, 1995, by and between Columbia Gas
Transmission Corporation and UGI Central Penn
Gas, Inc. (as successor to Penn Fuel Gas, Inc.)
|
Utilities | Form 8-K (10/1/08) | 10.2 | ||||||||
10.31 | FSS Service Agreement No. 49791, dated November
20, 1995, by and between Columbia Gas
Transmission Corporation and UGI Central Penn
Gas, Inc. (as successor to Penn Fuel Gas, Inc.)
|
Utilities | Form 8-K (10/1/08) | 10.3 | ||||||||
10.32 | FSS Service Agreement No. 80935, dated October
29, 2004, by and between Columbia Gas
Transmission, LLC and UGI Central Penn Gas, Inc.
|
Utilities | Form 10-Q (3/31/09) | 10.3 | ||||||||
10.33 | SST Service Agreement No. 49788, dated November
20, 1995, by and between Columbia Gas
Transmission Corporation and UGI Central Penn
Gas, Inc. (as successor to Penn Fuel Gas, Inc.)
|
Utilities | Form 8-K (10/1/08) | 10.5 | ||||||||
10.34 | SST Service Agreement No. 49790, dated November
20, 1995, by and between Columbia Gas
Transmission Corporation and UGI Central Penn
Gas, Inc. (as successor to Penn Fuel Gas, Inc.)
|
Utilities | Form 8-K (10/1/08) | 10.6 | ||||||||
10.35 | SST Service Agreement No. 80934, dated as of
October 29, 2004, by and between Columbia Gas
Transmission, LLC and UGI Central Penn Gas, Inc.
|
Utilities | Form 10-Q (3/31/09) | 10.4 | ||||||||
10.36 | No-Notice Transportation Service Agreement (Rate
Schedule CDS) between Utilities and Texas
Eastern Transmission dated February 23, 1999, as
modified pursuant to various orders of the
Federal Energy Regulatory Commission
|
Utilities | Form 10-K (9/30/02) | 10.27 | ||||||||
10.37 | No-Notice Transportation Service Agreement (Rate
Schedule CDS) between Utilities and Texas
Eastern Transmission dated October 31, 2000, as
modified pursuant to various orders of the
Federal Energy Regulatory Commission
|
Utilities | Form 10-K (9/30/02) | 10.28 | ||||||||
10.38 | Firm Transportation Service Agreement (Rate
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
|
Utilities | Form 10-K (9/30/02) | 10.29 |
29
Table of Contents
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
10.39 | Service Agreement for comprehensive delivery
service (Rate CDS) dated February 23, 1999
between UGI Utilities, Inc. and Texas Eastern
Transmission Corporation
|
UGI | Form 10-K (9/30/00) | 10.41 | ||||||||
10.40 | Amendment No. 1 dated November 1, 2004, to the
No-Notice Transportation Service Agreement (Rate
Schedule CDS) between Utilities and Texas
Eastern Transmission dated February 23, 1999, as
modified pursuant to various orders of the
Federal Energy Regulatory Commission
|
Utilities | Form 10-K (9/30/04) | 10.30 | ||||||||
10.41 | Amendment No. 1 dated November 1, 2004, to the
Firm Transportation Service Agreement (Rate
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
|
Utilities | Form 10-K (9/30/04) | 10.33 | ||||||||
10.42 | Firm Transportation Service Agreement (Rate
Schedule FT) between Utilities and
Transcontinental Gas Pipe Line dated October 1,
1996, as modified pursuant to various orders of
the Federal Energy Regulatory Commission
|
Utilities | Form 10-K (9/30/02) | 10.31 | ||||||||
10.43 | Amendment dated March 20, 2007 to the Firm
Transportation Service Agreement (Rate Schedule
FT) dated October 1, 1996 between UGI Utilities
and Transcontinental Gas Pipe Line Corporation,
as modified pursuant to various orders of the
Federal Energy Regulatory Commission
|
Utilities | Form 8-K (3/20/07) | 10.1 | ||||||||
10.44 | Firm Transportation Service Agreement (Rate FT)
dated February 1, 1992 between Transcontinental
Gas Pipe Line Corporation and PG Energy (as
successor to Pennsylvania Gas and Water Company)
|
Utilities | Form 8-K (8/24/06) | 10.7 | ||||||||
10.45 | Firm Transportation Service Agreement (Rate FT)
dated July 10, 1997 between Transcontinental Gas
Pipe Line Corporation and PG Energy
|
Utilities | Form 8-K (8/24/06) | 10.6 | ||||||||
10.46 | Firm Storage and Delivery Service Agreement
(Rate GSS) dated July 1, 1996 between
Transcontinental Gas Pipe Line Corporation and
PG Energy
|
Utilities | Form 8-K (8/24/06) | 10.8 | ||||||||
*12.1 | Computation of Ratio of Earnings to Fixed Charges |
|||||||||||
14 | Code of Ethics for principal executive,
financial and accounting officers
|
UGI | Form 10-K (9/30/03) | 14 | ||||||||
*23 | Consent of PricewaterhouseCoopers LLP |
30
Table of Contents
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
*31.1 | Certification by the Chief Executive Officer
relating to the Registrants Report on Form 10-K
for the fiscal year ended September 30, 2009
pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002 |
|||||||||||
*31.2 | Certification by the Chief Financial Officer
relating to the Registrants Report on Form 10-K
for the fiscal year ended September 30, 2009
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
Registrants Report on Form 10-K for the fiscal
year ended September 30, 2009, pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 |
* | Filed herewith. |
|
** | As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement. |
31
Table of Contents
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: November 20, 2009 | By: | /s/ 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 November 20, 2009 by the following persons on behalf of the Registrant in the
capacities indicated.
Signature | Title | |
/s/ John L. Walsh
|
President and Chief Executive Officer (Principal Executive Officer), Vice Chairman and Director |
|
/s/ Lon R. Greenberg
|
Chairman and Director | |
/s/ John C. Barney
|
Sr. Vice President Finance and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) |
|
/s/ Stephen D. Ban
|
Director | |
/s/ Richard C. Gozon
|
Director | |
/s/ Ernest E. Jones
|
Director | |
/s/ Anne Pol
|
Director | |
/s/ M. Shawn Puccio
|
Director | |
/s/ Marvin O. Schlanger
|
Director | |
/s/ Roger B. Vincent
|
Director | |
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 2009.
32
Table of Contents
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2009
F-1
Table of Contents
UGI UTILITIES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
Pages | ||||
Financial Statements: |
||||
F-3 | ||||
F-4 | ||||
F-5 | ||||
F-6 | ||||
F-7 | ||||
F-8 to F-31 | ||||
Financial Statement Schedule: |
||||
For the years ended September 30, 2009, 2008 and 2007: |
||||
S-1 | ||||
We have omitted all other financial statement schedules because the required information
is either (1) not present; (2) not present in amounts sufficient to require submission of
the schedule; or (3) included elsewhere in the financial statements or related notes.
F-2
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Utilities, Inc.:
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, 2009 and 2008, and the results
of their operations and their cash flows for each of the three years in the period ended
September 30, 2009 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. Also in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of September
30, 2009, based on criteria established in Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The
Companys management is responsible for these financial statements and financial
statement schedule, for maintaining effective internal control over financial reporting,
and for its assessment of the effectiveness of internal control over financial reporting,
included in Managements Report on Internal Control over Financial Reporting. Our
responsibility is to express opinions on these financial statements, on the financial
statement schedule, and on the Companys internal control over financial reporting based
on our integrated audits. We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal control over
financial reporting was maintained in all material respects. Our audits of the financial
statements included 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. Our audit of internal control over financial reporting included obtaining
an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 3 to the consolidated financial statements, the Company has
adopted new accounting guidance for uncertain tax positions effective October 1, 2007.
A companys 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 companys 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
companys 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
November 20, 2009
Philadelphia, Pennsylvania
November 20, 2009
F-3
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
September 30, | ||||||||
2009 | 2008 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 13,523 | $ | 3,483 | ||||
Restricted cash |
| 34,037 | ||||||
Accounts receivable (less allowances for doubtful
accounts of $11,384 and $10,369, respectively) |
74,286 | 70,259 | ||||||
Accounts receivable related parties |
3,378 | 1,946 | ||||||
Accrued utility revenues |
20,980 | 20,823 | ||||||
Inventories |
196,598 | 161,272 | ||||||
Deferred income taxes |
24,905 | 13,712 | ||||||
Regulatory assets |
19,584 | 15,987 | ||||||
Derivative financial instruments |
867 | 506 | ||||||
Prepaid expenses & other current assets |
5,167 | 3,380 | ||||||
Total current assets |
359,288 | 325,405 | ||||||
Property, plant and equipment |
2,056,877 | 1,669,056 | ||||||
Less accumulated depreciation and amortization |
(692,082 | ) | (562,135 | ) | ||||
Net property, plant and equipment |
1,364,795 | 1,106,921 | ||||||
Goodwill |
180,145 | 161,726 | ||||||
Regulatory assets |
121,960 | 91,396 | ||||||
Other assets |
4,049 | 9,018 | ||||||
Total assets |
$ | 2,030,237 | $ | 1,694,466 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Bank loans |
$ | 154,000 | $ | 57,000 | ||||
Accounts payable |
53,265 | 57,384 | ||||||
Accounts payable related parties |
8,746 | 14,680 | ||||||
Employee compensation and benefits accrued |
12,504 | 9,105 | ||||||
Dividends and interest accrued |
10,507 | 8,797 | ||||||
Customer deposits and refunds |
48,073 | 40,422 | ||||||
Derivative financial instruments |
| 23,488 | ||||||
Deferred fuel refunds |
30,846 | | ||||||
Other current liabilities |
39,882 | 13,287 | ||||||
Total current liabilities |
357,823 | 224,163 | ||||||
Long-term debt |
640,000 | 532,000 | ||||||
Deferred income taxes |
168,830 | 171,623 | ||||||
Deferred investment tax credits |
5,670 | 6,039 | ||||||
Pension and postretirement benefit obligations |
150,499 | 59,993 | ||||||
Other noncurrent liabilities |
61,372 | 33,078 | ||||||
Total liabilities |
1,384,194 | 1,026,896 | ||||||
Commitments and contingencies (note 13) |
||||||||
Common stockholders 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 |
467,160 | 466,888 | ||||||
Retained earnings |
201,710 | 184,201 | ||||||
Accumulated other comprehensive loss |
(83,086 | ) | (43,778 | ) | ||||
Total common stockholders equity |
646,043 | 667,570 | ||||||
Total liabilities and stockholders equity |
$ | 2,030,237 | $ | 1,694,466 | ||||
See accompanying notes to consolidated financial statements.
F-4
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
Year Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Revenues |
$ | 1,381,260 | $ | 1,289,053 | $ | 1,183,247 | ||||||
Costs and expenses: |
||||||||||||
Cost of sales gas, fuel and purchased power (excluding
depreciation
shown below) |
944,793 | 920,413 | 816,451 | |||||||||
Operating and administrative expenses |
191,263 | 147,131 | 140,013 | |||||||||
Operating and administrative expenses related parties |
14,964 | 11,802 | 11,584 | |||||||||
Taxes other than income taxes |
16,917 | 18,264 | 17,736 | |||||||||
Depreciation |
48,873 | 39,464 | 39,176 | |||||||||
Amortization |
2,239 | 1,861 | 1,758 | |||||||||
Other income, net |
(7,261 | ) | (12,924 | ) | (8,564 | ) | ||||||
1,211,788 | 1,126,011 | 1,018,154 | ||||||||||
Operating income |
169,472 | 163,042 | 165,093 | |||||||||
Interest expense |
43,918 | 39,065 | 42,327 | |||||||||
Income before income taxes |
125,554 | 123,977 | 122,766 | |||||||||
Income taxes |
46,832 | 49,950 | 48,579 | |||||||||
Net income |
$ | 78,722 | $ | 74,027 | $ | 74,187 | ||||||
See accompanying notes to consolidated financial statements.
F-5
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
Year Ended | ||||||||||||
September 30, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||||||
Net income |
$ | 78,722 | $ | 74,027 | $ | 74,187 | ||||||
Adjustments to reconcile net income to net cash provided
by operating activities: |
||||||||||||
Depreciation and amortization |
51,112 | 41,325 | 40,934 | |||||||||
Deferred income taxes, net |
17,530 | 7,516 | 16,281 | |||||||||
Pension expense |
7,124 | 134 | 1,871 | |||||||||
Provision for uncollectible accounts |
19,193 | 18,210 | 14,353 | |||||||||
Other, net |
13,456 | 2,115 | 2,962 | |||||||||
Net change in: |
||||||||||||
Accounts receivable and accrued utility revenues |
(15,133 | ) | (19,293 | ) | (27,934 | ) | ||||||
Inventories |
(12,742 | ) | 491 | 351 | ||||||||
Deferred fuel costs, net of changes in
unsettled derivatives |
10,272 | 21,521 | (26,953 | ) | ||||||||
Accounts payable |
(19,437 | ) | (3,311 | ) | 14,386 | |||||||
Storage agreement security deposits |
19,000 | | | |||||||||
Other current assets |
(1,072 | ) | 696 | 2,033 | ||||||||
Other current liabilities |
8,389 | (875 | ) | 21,021 | ||||||||
Net cash provided by operating activities |
176,414 | 142,556 | 133,492 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
Expenditures for property, plant and equipment |
(79,084 | ) | (64,351 | ) | (73,411 | ) | ||||||
Net costs of property, plant and equipment disposals |
(5,114 | ) | (521 | ) | (1,492 | ) | ||||||
Acquisitions of businesses, net of cash acquired |
(292,551 | ) | | 23,670 | ||||||||
Proceeds from sale of CPP |
32,269 | | | |||||||||
Decrease (increase) in restricted cash |
34,037 | (27,395 | ) | (3,945 | ) | |||||||
Net cash used by investing activities |
(310,443 | ) | (92,267 | ) | (55,178 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
Payment of dividends |
(61,211 | ) | (68,762 | ) | (40,006 | ) | ||||||
Increase (decrease) in bank loans |
97,000 | (133,000 | ) | (26,000 | ) | |||||||
Issuances of long-term debt |
108,000 | 20,000 | 20,000 | |||||||||
Repayments of long-term debt |
| | (20,000 | ) | ||||||||
Capital contribution from UGI Corporation |
| 120,000 | | |||||||||
Cash portion of UGI HVAC dividend |
| (1,381 | ) | | ||||||||
Excess tax benefits from equity-based payment arrangements |
280 | 130 | 957 | |||||||||
Net cash provided (used) by financing activities |
144,069 | (63,013 | ) | (65,049 | ) | |||||||
Cash and cash equivalents increase (decrease) |
$ | 10,040 | $ | (12,724 | ) | $ | 13,265 | |||||
CASH AND CASH EQUIVALENTS: |
||||||||||||
End of year |
$ | 13,523 | $ | 3,483 | $ | 16,207 | ||||||
Beginning of year |
3,483 | 16,207 | 2,942 | |||||||||
Increase (decrease) |
$ | 10,040 | $ | (12,724 | ) | $ | 13,265 | |||||
SUPPLEMENTAL CASH FLOW INFORMATION: |
||||||||||||
Cash paid for: |
||||||||||||
Interest |
$ | 40,452 | $ | 44,273 | $ | 32,944 | ||||||
Income taxes |
$ | 26,919 | $ | 40,625 | $ | 27,547 |
See accompanying notes to consolidated financial statements.
F-6
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(Thousands of dollars)
Accumulated | Total | |||||||||||||||||||
Additional | Other | Common | ||||||||||||||||||
Common | Paid-in | Retained | Comprehensive | Stockholders | ||||||||||||||||
Stock | Capital | Earnings | Income (Loss) | Equity | ||||||||||||||||
Balance September 30, 2006 |
$ | 60,259 | $ | 345,801 | $ | 144,833 | $ | (3,794 | ) | $ | 547,099 | |||||||||
Net income |
74,187 | 74,187 | ||||||||||||||||||
Net change in fair value of derivative
instruments (net of tax of $21) |
(30 | ) | (30 | ) | ||||||||||||||||
Reclassifications of net gains on derivative
instruments (net of tax of $1,068) |
(1,506 | ) | (1,506 | ) | ||||||||||||||||
Comprehensive income |
74,187 | (1,536 | ) | 72,651 | ||||||||||||||||
Adjustment to initially apply new accounting
for pension and postretirement benefits |
(9,987 | ) | (9,987 | ) | ||||||||||||||||
Cash dividends Common Stock |
(40,006 | ) | (40,006 | ) | ||||||||||||||||
Other |
957 | 957 | ||||||||||||||||||
Balance September 30, 2007 |
60,259 | 346,758 | 179,014 | (15,317 | ) | 570,714 | ||||||||||||||
Net income |
74,027 | 74,027 | ||||||||||||||||||
Cumulative effect from initial adoption of new
accounting for uncertain tax positions |
(230 | ) | (230 | ) | ||||||||||||||||
Net change in fair value of derivative
instruments (net of tax of $695) |
979 | 979 | ||||||||||||||||||
Reclassifications of net gains on derivative
instruments (net of tax of $176) |
(248 | ) | (248 | ) | ||||||||||||||||
Benefit plans, principally actuarial losses
(net of tax of $20,718) |
(29,211 | ) | (29,211 | ) | ||||||||||||||||
Reclassifications of benefit plans actuarial losses
and prior service costs (net of tax of $13) |
19 | 19 | ||||||||||||||||||
Comprehensive income |
73,797 | (28,461 | ) | 45,336 | ||||||||||||||||
Cash dividends Common Stock |
(68,762 | ) | (68,762 | ) | ||||||||||||||||
Capital contribution from UGI |
120,000 | 120,000 | ||||||||||||||||||
Dividend of UGI HVAC |
152 | 152 | ||||||||||||||||||
Other |
130 | 130 | ||||||||||||||||||
Balance September 30, 2008 |
60,259 | 466,888 | 184,201 | (43,778 | ) | 667,570 | ||||||||||||||
Net income |
78,722 | 78,722 | ||||||||||||||||||
Reclassifications of net losses on derivative
instruments (net of tax of $483) |
681 | 681 | ||||||||||||||||||
Benefit plans, principally actuarial losses
(net of tax of $29,978) |
(42,270 | ) | (42,270 | ) | ||||||||||||||||
Reclassifications of benefit plans actuarial losses
and prior service costs (net of tax of $1,617) |
2,281 | 2,281 | ||||||||||||||||||
Comprehensive income |
78,722 | (39,308 | ) | 39,414 | ||||||||||||||||
Cash dividends Common Stock |
(61,221 | ) | (61,221 | ) | ||||||||||||||||
Other |
272 | 8 | 280 | |||||||||||||||||
Balance September 30, 2009 |
$ | 60,259 | $ | 467,160 | $ | 201,710 | $ | (83,086 | ) | $ | 646,043 | |||||||||
See accompanying notes to consolidated financial statements.
F-7
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
1. | NATURE OF OPERATIONS |
Organization and Principles of Consolidation
UGI Utilities, Inc., a wholly owned subsidiary of UGI Corporation (UGI), and its
wholly owned subsidiaries UGI Penn Natural Gas, Inc. (PNG) and UGI Central Penn Gas,
Inc. (CPG) own and operate natural gas distribution utilities in eastern, northeastern
and central Pennsylvania. UGI Utilities also owns and operates an electric distribution
utility in northeastern Pennsylvania (Electric Utility). UGI Utilities natural gas
distribution utility is referred to as UGI Gas; PNGs natural gas distribution utility
is referred to as PNG Gas; and CPGs natural gas distribution utility is referred to as
CPG Gas. UGI Gas, PNG Gas and CPG Gas are collectively referred to as Gas Utility.
Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission
(PUC) and the Maryland Public Service Commission, and Electric Utility is subject to
regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as
Utilities.
Effective January 1, 2007, UGI Utilities contributed its heating, ventilation and
air conditioning services business to its wholly owned second-tier subsidiary, UGI HVAC
Services, Inc. (UGI HVAC). Effective April 1, 2008, UGI Utilities transferred by
dividend its ownership interest in UGI HVAC to UGI. UGI HVAC (prior to its dividend to
UGI) and UGI Penn HVAC Services, Inc. are hereafter referred to as the HVAC Business.
The term UGI Utilities is used sometimes as an abbreviated reference to UGI
Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.
2. SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting
principles generally accepted in the United States of America (GAAP).
The preparation of financial statements in accordance with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenue, expenses and costs. These estimates are based on managements
knowledge of current events, historical experience and various other assumptions that
are believed to be reasonable under the circumstances. As a result, actual results may
be different from these estimates and assumptions.
Certain prior-year amounts have been reclassified to conform to the current year
presentation.
Principles of Consolidation
Our consolidated financial statements include the accounts of UGI Utilities and its
subsidiaries (collectively, we or the Company). We eliminate all significant
intercompany accounts when we consolidate.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with
the Financial Accounting Standards Boards (FASBs) guidance on regulated entities
whose rates are designed to recover the costs of providing service. In accordance with
this guidance, incurred costs that would otherwise be charged to expense are capitalized
and recorded as regulatory assets when it is probable that the incurred costs will be
recovered in rates in the future. Likewise, we recognize regulatory liabilities when it
is probable that regulators will require customer refunds through future rates or when
revenue is collected from customers for expenditures that have not yet been incurred.
Generally, regulatory assets are amortized into expense and regulatory liabilities are
amortized into income over the period authorized by the regulator.
For additional information regarding the effects of rate-regulation, see Note 5.
F-8
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Fair Value Measurements
We apply fair value measurements to certain assets and liabilities, principally our
commodity derivative instruments. We adopted new accounting guidance with respect to determining
fair value measurements effective October 1, 2008. The new guidance defines fair value
as the price that would be received to sell an asset or paid to transfer a liability (an
exit price) in an orderly transaction between market participants at the measurement
date. The new guidance clarifies that fair value should be based upon assumptions that
market participants would use when pricing an asset or liability, including assumptions
about risk and risks inherent in valuation techniques and inputs to valuations. This
includes not only the credit standing of counterparties and credit enhancements but also
the impact of our own nonperformance risk on our liabilities. The new guidance requires
fair value measurements to assume that the transaction occurs in the principal market
for the asset or liability or in the absence of a principal market, the most
advantageous market for the asset or liability (the market for which the reporting
entity would be able to maximize the amount received or minimize the amount paid). We
evaluate the need for credit adjustments to our derivative instrument fair values in
accordance with the requirements noted above. Such adjustments were not material to the
fair values of our derivative instruments.
We use the following fair value hierarchy, which prioritizes the inputs to
valuation techniques used to measure fair value into three broad levels:
| Level 1 Quoted prices (unadjusted) in active markets for identical assets and
liabilities that we have the ability to access at the measurement date. Instruments
categorized in Level 1 consist of our exchange-traded commodity futures and swap
contracts. |
|
| Level 2 Inputs other than quoted prices included within Level 1 that are
either directly or indirectly observable for the asset or liability, including
quoted prices for similar assets or liabilities in active markets, quoted prices
for identical or similar assets or liabilities in inactive markets, inputs other
than quoted prices that are observable for the asset or liability, and inputs that
are derived from observable market data by correlation or other means. Instruments
categorized in Level 2 include financial transmission rights (FTRs). |
|
| Level 3 Unobservable inputs for the asset or liability including situations
where there is little, if any, market activity for the asset or liability. We did
not have any derivative financial instruments categorized as Level 3 at September
30, 2009. |
The fair value hierarchy gives the highest priority to quoted prices in active
markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases,
the inputs to measure fair value might fall into different levels of the fair value
hierarchy. The lowest level input that is significant to a fair value measurement in its
entirety determines the applicable level in the fair value hierarchy. Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or liability. The adoption
of the new fair value guidance effective October 1, 2008 did not have a material impact
on the financial statements. See Note 14 for additional information on fair value
measurements.
Derivative Instruments
We account for derivative instruments and hedging activities in accordance with
guidance provided by the FASB which 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.
In the case of natural gas derivative financial instruments used by Gas Utility,
changes in fair value are included in deferred fuel costs in accordance with FASB
guidance regarding accounting for rate-regulated entities. For cash flow hedges, changes
in the fair value of the derivative financial instruments are recorded in accumulated
other comprehensive income (AOCI), to the extent effective at offsetting changes in
the hedged item, until earnings are affected by the hedged item. We discontinue cash
flow hedge accounting if the occurrence of the forecasted transaction is determined to
be no longer probable. Certain of our derivative financial instruments, although
generally effective as hedges, do not qualify for hedge accounting treatment. Changes in
the fair values of these derivative instruments are reflected in net income. Cash flows
from derivative financial instruments are included in cash flows from operating
activities.
For a more detailed description of the derivative instruments we use, our
accounting for derivatives, our objectives for using them and related supplemental
information required by GAAP, see Note 15.
F-9
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Revenue Recognition
UGI Utilities regulated revenues are recognized as natural gas and electricity are
delivered and include estimated amounts for distribution service and commodities rendered
but not billed at the end of each month. 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.
We present revenue-related taxes collected from customers and remitted to taxing
authorities, principally sales and use taxes, on a net basis. Electric Utility gross
receipts taxes are included in total revenues in accordance with regulatory practice.
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. Utilities reduce 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. We record interest on
tax deficiencies and income tax penalties in income taxes on the Consolidated Statements
of Income.
Comprehensive Income
The components of AOCI at September 30, 2009 and 2008 follow:
Derivative | ||||||||||||
Postretirement | Instruments Net | |||||||||||
Benefit Plans | Losses | Total | ||||||||||
Balance, September 30, 2009 |
$ | (79,142 | ) | $ | (3,944 | ) | $ | (83,086 | ) | |||
Balance, September 30, 2008 |
$ | (39,152 | ) | $ | (4,626 | ) | $ | (43,778 | ) |
Comprehensive income comprises net income and other comprehensive income
(loss). Other comprehensive loss of $39,308, $28,461 and $1,536 for Fiscal 2009, Fiscal
2008 and Fiscal 2007, respectively, reflects changes in actuarial gains and losses on
postretirement benefit plans, gains or losses on interest rate protection agreements
(IRPAs) and, through the date of its expiration in December 2007, changes in the fair
value of an electric price swap agreement, net of reclassifications to net income. Fiscal
2007 AOCI also includes an after-tax charge of $9,987 associated with the initial
adoption of FASB guidance for employers accounting for defined benefit pension and other
postretirement plans effective September 30, 2007 (see Accounting Changes below).
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are
classified as cash equivalents.
F-10
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Restricted Cash
Restricted cash represents those cash balances in our commodity futures brokerage
accounts which are restricted from withdrawal.
Inventories
Our inventories are stated at the lower of cost or market. Substantially all of our
inventory is determined on an average cost method.
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. The amounts assigned to
property, plant and equipment of acquired businesses are based upon estimated fair value
at date of acquisition.
We record depreciation expense for Utilities plant and equipment on a
straight-line method over the estimated average remaining lives of the various classes
of its depreciable property. Depreciation expense as a percentage of the related average
depreciable base for Gas Utility was 2.4% in Fiscal 2009 and Fiscal 2008, and 2.7% in
Fiscal 2007. Depreciation expense as a percentage of the related average depreciable
base for Electric Utility was 2.9% in Fiscal 2009, 2.6% in Fiscal 2008 and 2.7% in
Fiscal 2007. When Utilities retires 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 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.
No depreciation expense is included in cost of sales in the Consolidated Statements of
Income.
Goodwill
Our goodwill is the result of business acquisitions. Goodwill is subject to tests
for impairment at least annually. We perform goodwill impairment tests more frequently
than annually if events or circumstances indicate that the value of goodwill might be
impaired. When performing our impairment tests, we use discounted estimates of future
cash flows. No provisions for goodwill impairments were recorded during Fiscal 2009,
Fiscal 2008 or Fiscal 2007.
Impairment of Long-Lived Assets
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. No provisions for impairments were recorded during Fiscal
2009, Fiscal 2008 or Fiscal 2007.
Employee Retirement Plans
We use a market-related value of plan assets and an expected long-term rate of
return to determine the expected return on assets of our pension and other postretirement
plans. The market-related value of plan assets, other than equity investments, is based
upon market prices. The market-related value of equity investments is calculated by
rolling forward the prior-years market-related value with contributions, disbursements
and the expected return on plan assets. One third of the difference between the expected
and the actual value is then added to or subtracted from the expected value to determine
the new market-related value (see Note 10).
Equity-Based Compensation
All of our equity-based compensation principally comprising UGI stock options and
grants of UGI stock-based equity instruments (Units) is measured at fair value on the
grant date, date of modification or end of the period, as applicable. Compensation
expense is recognized on a straight-line basis over the requisite service period.
Depending upon the settlement terms of the awards, all or a portion of the fair value of
equity-based awards may be presented as a liability or as equity in our Consolidated
Balance Sheets. Equity-based compensation costs associated with the portion of Unit
awards classified as equity are measured based upon their estimated fair value on the
date of grant or modification. Equity-based compensation costs associated with the
portion of Unit awards classified as liabilities are measured based upon their estimated
fair value at the grant date and remeasured as of the end of each period.
For additional information on our equity-based compensation plans and related disclosures,
see Note 12.
F-11
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove
the effect of past operations and improve or maintain the quality of the environment.
These laws and regulations require the removal or remedy of the effect on the
environment of the disposal or release of certain specified hazardous substances at
current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable
that a liability has been incurred and an amount can reasonably be estimated. Amounts
recorded as environmental liabilities on the balance sheets represent our best estimate
of costs expected to be incurred or, if no best estimate can be made, the minimum
liability associated with a range of expected environmental investigation and
remediation 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 incurred costs through all appropriate means, including
regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific
environmental investigation and remediation costs, net of related third-party payments,
associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates,
through future base rate proceedings, a five-year average of such prudently incurred
remediation costs. CPG Gas and PNG Gas base rate revenues provide for the recovery of
environmental investigation and remediation costs associated with Pennsylvania sites.
For further information, see Note 13.
Subsequent Events
Management has evaluated the impact of subsequent events through November 20, 2009,
the date the financial statements were filed with the U.S. Securities and Exchange
Commission, and the effects of such evaluation have been reflected in the financial
statements and related disclosures.
3. ACCOUNTING CHANGES
Adoption of New Accounting Standards
FASB Accounting Standards Codification. In June 2009, the FASB issued guidance
identifying the sources of accounting principles and the framework for selecting
principles used in the preparation of financial statements by nongovernmental entities in
accordance with GAAP. The guidance has established the FASB Accounting Standards
Codification (Codification) as the source of such authoritative accounting principles.
The identification of the Codification as the source of authoritative accounting
principles does not change existing GAAP. The Codification is effective for all financial
statements issued after September 15, 2009.
Subsequent Events. On June 30, 2009, we adopted accounting guidance issued by
the FASB in May 2009 on accounting and disclosure of subsequent events. The adoption of
this guidance did not change our prior accounting practice other than to disclose the
date through which subsequent events were evaluated and the basis for that date. Other
than this new disclosure, adoption of this guidance did not have a significant impact on
our consolidated financial statements.
Disclosures about Derivative Instruments and Hedging Activities. Effective with our
disclosures for the quarter ended March 31, 2009, we adopted accounting guidance issued
by the FASB in March 2008 on enhanced disclosures about derivative instruments and
hedging activities. The enhanced disclosures provide greater transparency by requiring
entities to provide qualitative disclosures about their objectives and strategies for
using derivative instruments and quantitative disclosures that detail
the fair value amounts of, and gains and losses on, derivative instruments. Disclosures
about credit risk-related contingent features of derivative instruments are also required
See Note 15 for disclosures required by the new guidance.
Fair Value Measurements. On October 1, 2008, we adopted new guidance issued by the
FASB in September 2006 on fair value measurements. The new guidance defines fair value,
establishes a framework for measuring fair value in generally accepted accounting
principles, and expands disclosures about fair value measurements. In February 2008, two
amendments to this guidance were issued to exclude leases from the new fair value
guidance and to delay the effective date of the new fair value guidance until fiscal
years beginning after November 15, 2008 (Fiscal 2010) for non-financial assets and
liabilities that are recognized or disclosed at fair value in the financial statements on
a non-recurring basis. The adoption of the initial phase of the fair value guidance did
not have a material effect on our financial statements and we do not anticipate that the
adoption of the remainder of the fair value guidance will have a material effect on our
consolidated financial statements. In October 2008, two additional amendments to the
fair value guidance were issued which clarify the application of the fair value
measurement guidance to financial assets in a market that is not active and when the
volume and level of activity for the asset or liability have significantly decreased.
These further amendments did not have an impact on our results of operations or financial
condition. See Notes 2 and 14 for further information on fair value measurements in
accordance with the new guidance.
F-12
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Offsetting
of Amounts Related to Certain Contracts. On October 1,
2008, we adopted accounting
guidance issued by the FASB in April 2007 which permits companies to offset fair value
amounts recognized for the right to reclaim cash collateral (a receivable) or the
obligation to return cash collateral (a payable) against fair value amounts recognized
for derivative instruments executed with the same counterparty under a master netting
agreement. In addition, upon the adoption, companies are permitted to change their
accounting policy to offset or not offset fair value amounts recognized for derivative
instruments under master netting arrangements. The new guidance requires retrospective
application for all periods presented. We have elected to continue our policy of
reflecting derivative asset or liability positions, as well as cash collateral, on a
gross basis in our Consolidated Balance Sheets. Accordingly, the adoption of the new
guidance did not impact our financial statements.
Fair Value Option for Financial Assets and Liabilities. On October 1, 2008, we
adopted accounting guidance issued by the FASB in February 2007 by which we may elect
to report individual financial instruments and certain items at fair value with changes
in fair value reported in earnings. Once made, this election is irrevocable for those
items. The adoption of this guidance did not impact our financial statements.
Uncertainty in Income Taxes. Effective October 1, 2007, we adopted new interpretive
guidance issued by the FASB on accounting for uncertainty related to income taxes. The
new guidance provides a comprehensive model for the recognition, measurement and
disclosure in financial statements of uncertain income tax positions that a company has
taken or expects to take on a tax return. The cumulative effect from the adoption of the
new guidance was recorded as a $230 decrease to the October 1, 2007 retained earnings
balance.
Pension and Postretirement Plans. Effective September 30, 2007, we adopted new
accounting guidance issued by the FASB relating to employers accounting for pension and
postretirement benefit plans. The new guidance requires recognition of an asset or
liability in the statement of financial position reflecting the funded status of pension
and postretirement benefit plans, such as retiree health and life, with current year
changes recognized in shareholders equity. The new guidance did not change the existing
criteria for measurement of periodic benefit costs, plan assets or benefit obligations.
The incremental effect of the initial adoption of the new guidance reduced stockholders
equity at September 30, 2007 by $9,987.
New Accounting Standards Not Yet Implemented
Enhanced Disclosures of Postretirement Plan Assets. In December 2008, the FASB
issued new guidance requiring more detailed disclosures about employers postretirement
plan assets, including employers investment strategies, major categories of plan assets,
concentrations of risk within plan assets, and valuation techniques used to measure the
fair value of plan assets. The provisions of this guidance are effective for fiscal years
ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to
disclosure only, it will not impact the financial statements.
Intangible Asset Useful Lives. In April 2008, the FASB issued new guidance which
amends the factors that should be considered in developing renewal or extension
assumptions used to determine the useful life of a recognized intangible asset under
GAAP. The intent of the new guidance is to improve the consistency between the useful
life of a recognized intangible asset under GAAP relating to intangible asset accounting
and the period of expected cash flows used to measure the fair value of the asset under
GAAP relating to business combinations and other applicable accounting literature. The
new guidance is effective for financial statements issued for fiscal years beginning
after December 15, 2008 (Fiscal 2010) and must be applied
prospectively to intangible assets acquired after the effective date. We do not
believe the new guidance will have a significant impact on our financial statements.
Business Combinations. In December 2007, the FASB issued new guidance on the
accounting for business combinations. The new guidance applies to all transactions or
other events in which an entity obtains control of one or more businesses. The new
guidance establishes, among other things, principles and requirements for how the
acquirer (1) recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2)
recognizes and measures the goodwill acquired in a business combination or gain from a
bargain purchase; and (3) determines what information with respect to a business
combination should be disclosed. The new guidance applies prospectively to business
combinations for which the acquisition date is on or after the first annual reporting
period beginning on or after December 15, 2008 (Fiscal 2010). Among the more significant
changes in accounting for acquisitions are (1) transaction costs will generally be
expensed (rather than being included as costs of the acquisition); (2) contingencies,
including contingent consideration, will generally be recorded at fair value with
subsequent adjustments recognized in operations (rather than as adjustments to the
purchase price); and (3) decreases in valuation allowances on acquired deferred tax
assets will be recognized in operations (rather than decreases in goodwill). Generally,
the effects of the new guidance will depend on future acquisitions.
F-13
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
4. ACQUISITION OF PPL GAS UTILITIES CORPORATION
On October 1, 2008, UGI Utilities acquired all of the outstanding stock of PPL Gas
Utilities Corporation (now CPG), the natural gas distribution utility of PPL Corporation
(PPL), for cash consideration of $267,600 plus estimated working capital of $35,370
(the CPG Acquisition). Immediately after the closing of the CPG Acquisition, CPGs
wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC,
CPP), its retail propane distributor, sold its assets to AmeriGas Propane, L.P.
(AmeriGas OLP), an affiliate of UGI, for cash consideration of $32,000 plus estimated
working capital of $1,621. CPG distributes natural gas to approximately 76,000 customers
in eastern and central Pennsylvania, and also distributes natural gas to several hundred
customers in portions of one Maryland county. CPP sold propane to customers principally
in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition at closing with a
combination of $120,000 cash contributed by UGI on September 25, 2008, proceeds from the
issuance on October 1, 2008 of $108,000 principal amount of 6.375% Senior Notes due 2013
and approximately $75,000 of borrowings under UGI Utilities Revolving Credit Agreement.
UGI Utilities used the $33,621 of cash proceeds from the sale of the assets of CPP to
AmeriGas OLP to reduce its revolving credit agreement borrowings.
The assets and liabilities resulting from the CPG Acquisition which reflect the
final purchase price allocation are included in our Consolidated Balance Sheet at
September 30, 2009. Pursuant to the CPG Acquisition purchase agreement, the purchase
price was subject to adjustment for the difference between the estimated working capital
of $35,370 and the actual working capital as of the closing date agreed to by both UGI
Utilities and PPL. During Fiscal 2009, UGI Utilities and PPL reached an agreement on the
working capital adjustment pursuant to which PPL paid UGI Utilities $9,738 in cash,
including interest. Also during Fiscal 2009, UGI Utilities and AmeriGas OLP reached an
agreement on the working capital adjustment associated with UGI Utilities sale of the
assets of CPP to AmeriGas OLP pursuant to which UGI Utilities reimbursed AmeriGas OLP
$1,352.
The purchase price of the CPG Acquisition, including transaction fees and expenses
and incurred liabilities totaling approximately $2,300, has been allocated to the assets
acquired and liabilities assumed as follows:
Current assets less current liabilities |
$ | 22,065 | ||
Property, plant and equipment |
227,301 | |||
Goodwill |
18,419 | |||
Utility regulatory assets |
22,466 | |||
Other assets |
7,412 | |||
Noncurrent liabilities |
(34,383 | ) | ||
Total |
$ | 263,280 | ||
The primary item that results in goodwill are the synergies between CPG Gas and our
existing utility businesses. Substantially all of the goodwill is deductible for income
tax purposes over a fifteen-year period.
The operating results of CPG are included in our consolidated results beginning
October 1, 2008. The following table presents pro forma income statement data for Fiscal
2008 as if the CPG Acquisition had occurred as of October 1, 2007:
2008 | ||||
(pro forma) | ||||
Revenues |
$ | 1,475,113 | ||
Net income |
$ | 82,927 | ||
The pro forma results of operations reflect CPGs historical operating results
after giving effect to adjustments directly attributable to the transaction that are
expected to have a continuing effect. The pro forma amounts are not necessarily
indicative of the operating results that would have occurred had the CPG Acquisition
been completed as of the date indicated, nor are they necessarily indicative of future
operating results.
Also during Fiscal 2007, UGI Utilities received a $23,670 working capital
adjustment payment associated with its Fiscal 2006 acquisition of Southern Union
Companys PG Energy Division, a natural gas distribution utility located in northeastern
Pennsylvania (now PNG Gas).
F-14
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
5. REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS
The following regulatory assets and liabilities associated with Utilities are included in
our accompanying balance sheets at September 30:
2009 | 2008 | |||||||
Regulatory assets: |
||||||||
Income taxes recoverable |
$ | 79,492 | $ | 73,695 | ||||
Postretirement benefits |
2,473 | 4,321 | ||||||
CPG Gas pension and postretirement plans |
8,572 | | ||||||
Environmental costs |
26,877 | 9,009 | ||||||
Deferred fuel costs |
19,584 | 15,987 | ||||||
Other |
4,546 | 4,371 | ||||||
Total regulatory assets |
$ | 141,544 | $ | 107,383 | ||||
Regulatory liabilities: |
||||||||
Postretirement benefits |
$ | 9,310 | $ | 8,886 | ||||
Environmental overcollections |
8,720 | | ||||||
Deferred fuel refunds |
30,846 | | ||||||
Total regulatory liabilities |
$ | 48,876 | $ | 8,886 | ||||
Income taxes recoverable. This regulatory asset is the result of recording deferred
tax liabilities pertaining to temporary tax differences principally as a result of the
pass through to ratepayers of accelerated tax depreciation for state income tax purposes,
and the flow through of accelerated tax depreciation for federal income tax purposes for
certain years prior to 1981. These deferred taxes have been reduced by deferred tax
assets pertaining to utility deferred investment tax credits. Utilities has recorded
regulatory income tax assets related to these deferred tax liabilities representing
future revenues recoverable through the ratemaking process over the average remaining
depreciable lives of the associated property ranging from 1 to approximately 50 years.
Postretirement benefits. The PUC has authorized UGI Utilities to recover certain early
retirement benefit costs as well as other postretirement benefit costs incurred prior to
such amounts being reflected in tariff rates. These costs are reflected as regulatory
assets in the table above. At September 30, 2009, UGI Utilities expects to recover these
costs over periods ranging from 1 to approximately 10 years.
Gas Utility and Electric Utility are also recovering ongoing postretirement benefit
costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI
Gas and Electric Utility, the difference between the amounts recovered through rates and
the actual costs incurred in accordance with accounting for postretirement benefits are
being deferred for future refund to or recovery from ratepayers. Such amounts are
reflected in regulatory liabilities in the table above. In addition, in accordance with
GAAP relating to pension and postretirement plans, UGI Utilities postretirement
regulatory liability is adjusted annually to reflect changes in the funded status of UGI
Gas and Electric Utilitys postretirement benefit plan.
CPG Gas pension and postretirement plans. This regulatory asset represents the
portion of prior service cost and net actuarial losses associated with CPG Gas pension
and postretirement plans that will be recovered through future rates based upon
established regulatory practices. These regulatory assets are adjusted annually or more
frequently under certain circumstances when the funded status of the plans is recorded in
accordance with GAAP relating to pension and postretirement plans. These costs are
amortized over the average remaining life expectancy of the plan participants. These
regulatory assets are reflected net of associated deferred income taxes.
Environmental costs. Environmental costs represents amounts actually spent by UGI Gas to
clean up sites in Pennsylvania as well as the portion of estimated probable future
environmental remediation and investigation costs that CPG Gas and PNG Gas expect to
incur in conjunction with remediation consent orders and agreements with the Pennsylvania
Department of Environmental Protection (see Note 13). UGI Gas is currently permitted to
include in rates, through future base rate proceedings, a five-year average of such
prudently incurred remediation costs. PNG Gas and CPG Gas are currently recovering and
expect to continue to recover these costs in base rate revenues. At September 30, 2009,
the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon
future remediation activity.
F-15
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Deferred fuel costs and refunds. Gas Utilitys 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 GAAP relating to rate-regulated
entities, we defer the difference between amounts recognized in revenues and the
applicable gas costs incurred until they are subsequently billed or refunded to
customers. Net undercollected gas costs are classified as a regulatory asset
and net overcollections are classified as a regulatory liability. Gas Utility uses
derivative financial instruments to reduce volatility in the cost of gas it purchases for
firm- residential, commercial and industrial (retail core-market) customers. Realized
and unrealized gains or losses on natural gas derivative financial instruments are
included in deferred fuel refunds or costs. Unrealized losses on such contracts at
September 30, 2008 were $23,321. There were no such gains or losses at September 30, 2009. UGI
Utilities expects to recover or refund deferred fuel costs generally over a period of 1
to 2 years.
Environmental overcollections. This regulatory liability represents the difference
between amounts recovered in rates and actual costs incurred (net of insurance proceeds)
associated with the terms of a consent order agreement between CPG and the Pennsylvania
Department of Environmental Protection to remediate certain gas plant sites.
Other. Other regulatory assets comprise a number of items including, among others,
deferred asset retirement costs, deferred rate case expenses, customer choice
implementation costs and deferred software development costs. At September 30, 2009, UGI
Utilities expects to recover these costs over periods of approximately 1 to 5 years.
UGI
Utilities regulatory liabilities relating to postretirement
benefits and environmental overcollections are
included in Other noncurrent liabilities on the Consolidated Balance Sheets. UGI
Utilities does not recover a rate of return on its regulatory assets.
Other Regulatory Matters
PNG and CPG Base Rate Filings. On January 28, 2009, PNG and CPG filed separate requests
with the PUC to increase base operating revenues by $38,118 annually for PNG and $19,635
annually for CPG to fund system improvements and operations necessary to maintain safe
and reliable natural gas service and energy assistance for low income customers as well
as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each
filed joint settlement petitions with the PUC based on agreements with the opposing
parties regarding the requested base operating revenue increases. On August 27, 2009, the
PUC approved the settlement agreements which resulted in a $19,800 base operating revenue
increase for PNG Gas and a $10,000 base
operating revenue increase for CPG Gas. The increases became effective August 28, 2009
and did not have a material effect on Fiscal 2009 results.
Electric Utility. As a result of Pennsylvanias Electricity Generation Customer Choice
and Competition Act that became effective January 1, 1997, all of Electric Utilitys
customers are permitted 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 through December 31, 2009, were established in
a series of PUC approved settlements (collectively, the POLR Settlement), the latest of
which became effective June 23, 2006.
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates
up to certain limits through December 31, 2009. Consistent with the terms of the POLR
Settlement, Electric Utility increased its POLR rates effective January 1, 2009, which
increased the average cost to a residential heating customer by approximately 1.5% over
such costs in effect during calendar year 2008. Effective January 1, 2008, Electric
Utility increased its POLR rates which increased the average cost to a residential
heating customer by approximately 5.5% over such costs in effect during calendar year
2007. Effective January 1, 2007, Electric Utility increased the average cost to a
residential heating customer by approximately 35% over such costs in effect during
calendar year 2006.
On July 17, 2008, the PUC approved Electric Utilitys default service procurement,
implementation and contingency plans, as modified by the terms of a May 2, 2008
settlement, filed in accordance with the PUCs default service regulations. These plans
do not affect Electric Utilitys existing POLR settlement effective through December 31,
2009. The approved plans specify how Electric Utility will solicit and acquire default
service supplies for residential customers for the period January 1, 2010 through May 31,
2014, and for commercial and industrial customers for the period January 1, 2010 through
May 31, 2011 (collectively, the Settlement Term). UGI Utilities filed a rate plan on
August 29, 2008 for the Settlement Term. On January 22, 2009, the PUC approved a
settlement of the rate filing that provides for Electric Utility to fully recover its
default service costs. On October 1, 2009, UGI Utilities filed a default service plan to
establish procurement rules applicable to the period after May 31, 2011 for its
commercial and industrial customers.
F-16
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
6. INVENTORIES
Inventories comprise the following at September 30:
2009 | 2008 | |||||||
Gas Utility natural gas |
$ | 189,747 | $ | 155,843 | ||||
Materials, supplies and other |
6,851 | 5,429 | ||||||
Total inventories |
$ | 196,598 | $ | 161,272 | ||||
At September 30, 2009 and 2008, UGI Utilities was a party to one-year storage
contract administrative agreements (SCAAs) expiring on October 1, 2009 and 2008,
respectively. Pursuant to the SCAAs, UGI Utilities has, among other things, released
certain storage and transportation contracts for the terms of the SCAAs. UGI
Utilities also transferred certain associated storage inventories upon commencement of
the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and
makes payments associated with refilling storage inventories during the term of the
SCAAs. Included among these contract administrative agreements is an agreement with UGI
Energy Services, Inc., a second-tier, wholly owned subsidiary of UGI (see Note 18). The
historical cost of natural gas storage inventories released under the SCAAs, which
represents a portion of Gas Utilitys total natural gas storage inventories, and any
exchange receivable (representing amounts of natural gas inventories used by the other
parties to the agreements but not yet replenished), are included in the caption Gas
Utility natural gas in the table above. The carrying value of gas storage inventories
released under the SCAAs at September 30, 2009 and 2008 comprising 9.0 billion cubic feet
(bcf) and 9.8 bcf of natural gas was $77,948 and $81,182, respectively. Effective
November 1, 2009, UGI Utilities entered into three new SCAAs with terms ranging from one
to three years.
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment comprise the following categories at September 30:
2009 | 2008 | |||||||
Distribution |
$ | 1,813,201 | $ | 1,520,346 | ||||
Transmission |
76,826 | 28,547 | ||||||
General and other |
166,850 | 120,163 | ||||||
Total property, plant and equipment |
$ | 2,056,877 | $ | 1,669,056 | ||||
F-17
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
8. DEBT
Long-term debt comprises the following at September 30:
2009 | 2008 | |||||||
Senior Notes: |
||||||||
6.375% Notes, due September 2013 |
$ | 108,000 | $ | | ||||
5.75% Notes, due October 2016 |
175,000 | 175,000 | ||||||
6.21% Notes, due October 2036 |
100,000 | 100,000 | ||||||
Medium-Term Notes: |
||||||||
5.53% Notes, due September 2012 |
40,000 | 40,000 | ||||||
5.37% Notes, due August 2013 |
25,000 | 25,000 | ||||||
5.16% Notes, due May 2015 |
20,000 | 20,000 | ||||||
7.37% Notes, due October 2015 |
22,000 | 22,000 | ||||||
5.64% Notes, due December 2015 |
50,000 | 50,000 | ||||||
6.17% Notes, due June 2017 |
20,000 | 20,000 | ||||||
7.25% Notes, due November 2017 |
20,000 | 20,000 | ||||||
5.67% Notes, due January 2018 |
20,000 | 20,000 | ||||||
6.50% Notes, due August 2033 |
20,000 | 20,000 | ||||||
6.13% Notes, due October 2034 |
20,000 | 20,000 | ||||||
Total long-term debt |
$ | 640,000 | $ | 532,000 | ||||
There are no principal payments of long-term debt due through Fiscal 2011;
$40,000 is due in Fiscal 2012; $133,000 is due in Fiscal 2013; and no amounts are due in
Fiscal 2014.
UGI Utilities has a revolving credit agreement (Revolving Credit Agreement)
with banks providing for borrowings of up to $350,000 which expires in August 2011. Under
The Revolving Credit Agreement, UGI Utilities may borrow at various prevailing interest
rates, including LIBOR and the banks prime rate. UGI Utilities had borrowings
outstanding under the Revolving Credit Agreement, which we classify as bank loans,
totaling $154,000 at September 30, 2009 and $57,000 at September 30, 2008. The
weighted-average interest rates on Revolving Credit Agreement borrowings at September 30,
2009 and 2008 were 0.59% and 5.0%, respectively. In conjunction with
the October 1, 2008,
CPG Acquisition, UGI made a $120,000 cash contribution to
UGI Utilities on September 25, 2008. This cash contribution was used by UGI Utilities to
reduce borrowings under the Revolving Credit Agreement. On
October 1, 2008, UGI
Utilities borrowed under the Revolving Credit Agreement to fund a
portion of the CPG Acquisition (see Note 4).
The Revolving Credit Agreement requires UGI Utilities to maintain a maximum ratio of
Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
9. INCOME TAXES
The provisions for income taxes consist of the following:
2009 | 2008 | 2007 | ||||||||||
Current expense: |
||||||||||||
Federal |
$ | 19,302 | $ | 31,974 | $ | 24,727 | ||||||
State |
10,000 | 10,460 | 7,571 | |||||||||
Total current expense |
29,302 | 42,434 | 32,298 | |||||||||
Deferred expense |
17,898 | 7,894 | 16,667 | |||||||||
Investment tax credit amortization |
(368 | ) | (378 | ) | (386 | ) | ||||||
Total income tax expense |
$ | 46,832 | $ | 49,950 | $ | 48,579 | ||||||
F - 18
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
A reconciliation from the statutory federal tax rate to our effective tax rate is as
follows:
2009 | 2008 | 2007 | ||||||||||
Statutory federal tax rate |
35.0 | % | 35.0 | % | 35.0 | % | ||||||
Difference in tax rate due to: |
||||||||||||
State income taxes, net of federal |
3.6 | 4.7 | 4.8 | |||||||||
Other, net |
(1.3 | ) | 0.6 | (0.2 | ) | |||||||
Effective tax rate |
37.3 | % | 40.3 | % | 39.6 | % | ||||||
Deferred tax liabilities (assets) comprise the following at September 30:
2009 | 2008 | |||||||
Excess book basis over tax basis of property, plant and equipment |
$ | 199,213 | $ | 164,870 | ||||
Goodwill |
13,444 | 9,006 | ||||||
Regulatory assets |
51,576 | 34,030 | ||||||
Other |
1,883 | 1,954 | ||||||
Gross deferred tax liabilities |
266,116 | 209,860 | ||||||
Pension plan liabilities |
(60,350 | ) | (21,713 | ) | ||||
Allowance for doubtful accounts |
(4,723 | ) | (4,340 | ) | ||||
Deferred investment tax credits |
(2,352 | ) | (2,505 | ) | ||||
Employee-related expenses |
(8,832 | ) | (5,224 | ) | ||||
Regulatory liabilities |
(16,648 | ) | (3,687 | ) | ||||
Environmental liabilities |
(9,256 | ) | (6,041 | ) | ||||
Derivative financial instruments |
(2,781 | ) | (3,280 | ) | ||||
Other |
(17,249 | ) | (5,159 | ) | ||||
Gross deferred tax assets |
(122,191 | ) | (51,949 | ) | ||||
Net deferred tax liabilities |
$ | 143,925 | $ | 157,911 | ||||
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. UGIs federal income tax returns are settled
through the tax year 2006. UGIs federal income tax return for Fiscal 2007 is currently
under audit. Although it is not possible to predict with certainty the timing of the
conclusion of UGIs pending federal tax audit, we anticipate that the aforementioned
federal tax audit will likely be completed during Fiscal 2010.
We file separate company income tax returns in a number of states but are subject to
state income tax principally in Pennsylvania. Pennsylvania income tax returns are
generally subject to examination for a period of three years after the filing of the
respective returns.
During Fiscal 2009, $55 of interest income was recognized in income taxes in the
Consolidated Statement of Income. As of September 30, 2009, we have unrecognized income
tax benefits totaling $634 including related accrued interest of $71. If these
unrecognized tax benefits were subsequently recognized, $560 would be recorded as a
benefit to income taxes on the consolidated statement of income and, therefore, would
impact the effective tax rate. Generally, a net reduction in unrecognized tax benefits
could occur because of expiration of the statute of limitations in certain jurisdictions
or as a result of settlements with
tax authorities. The amount of reasonably possible changes in unrecognized tax
benefits and related interest in the next twelve months is a net reduction of
approximately $291.
F - 19
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is
as follows:
Balance at October 1, 2007 |
$ | 694 | ||
Additions for tax positions of the current year |
66 | |||
Additions for tax positions of prior years |
185 | |||
Balance at September 30, 2008 |
945 | |||
Additions for tax positions of the current year |
63 | |||
Additions for tax positions of prior years |
197 | |||
Settlements with tax authorities |
(571 | ) | ||
Balance at September 30, 2009 |
$ | 634 | ||
10. EMPLOYEE RETIREMENT PLANS
Defined Benefit Pension and Other Postretirement Plans
We sponsor two defined benefit pension plans (Pension Plans) for employees hired
prior to January 1, 2009 of UGI Utilities, PNG, CPG, UGI, and certain of UGIs other
wholly owned subsidiaries. In addition, we provide postretirement health care benefits to
certain retirees and postretirement life insurance benefits to nearly all active and
retired employees.
Effective December 31, 2008, we merged two of our domestic defined benefit pension
plans. The merged plan will maintain the separate benefit formulas and specific rights
and features of each predecessor plan. As a result of the merger, we were required under
GAAP to remeasure the combined plans assets and benefit obligations as of December 31,
2008 and recorded an after-tax charge to AOCI of $38,688. As a result of the
remeasurement, Fiscal 2009 pension expense increased approximately
$3,900 in the
nine-month period subsequent to the remeasurement principally as a result of the
amortization of actuarial losses.
The following table provides a reconciliation of the projected benefit obligations
(PBOs) of the Pension Plans, the accumulated benefit obligations (ABOs) of our other
postretirement benefit plans, plan assets and the funded status of the pension and other
postretirement plans as of September 30, 2009 and 2008. ABO is the present value of
benefits earned to date with benefits based upon current compensation levels. PBO is ABO
increased to reflect future compensation.
F - 20
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Pension | Other Postretirement | |||||||||||||||
Benefits | Benefits | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Change in benefit obligations: |
||||||||||||||||
Benefit obligations beginning of year |
$ | 300,578 | $ | 299,441 | $ | 9,713 | $ | 13,822 | ||||||||
Service cost |
6,831 | 5,660 | 139 | 277 | ||||||||||||
Interest cost |
22,904 | 19,064 | 843 | 802 | ||||||||||||
Actuarial loss (gain) |
64,709 | (9,261 | ) | 1,557 | (1,794 | ) | ||||||||||
Plan amendments |
42 | | 46 | (357 | ) | |||||||||||
Plan curtailment |
| | | (2,202 | ) | |||||||||||
Acquisitions |
44,465 | | 3,418 | | ||||||||||||
Benefits paid |
(17,488 | ) | (14,326 | ) | (1,106 | ) | (835 | ) | ||||||||
Benefit obligations end of year |
$ | 422,041 | $ | 300,578 | $ | 14,610 | $ | 9,713 | ||||||||
Change in plan assets: |
||||||||||||||||
Fair value of plan assets beginning of year |
$ | 240,997 | $ | 290,112 | $ | 10,002 | $ | 12,173 | ||||||||
Actual gain (loss) on assets |
14,527 | (34,789 | ) | 46 | (1,773 | ) | ||||||||||
Employer contributions |
| | 772 | 437 | ||||||||||||
Acquisitions |
38,402 | | | | ||||||||||||
Benefits paid |
(17,488 | ) | (14,326 | ) | (1,106 | ) | (835 | ) | ||||||||
Fair value of plan assets end of year |
$ | 276,438 | $ | 240,997 | $ | 9,714 | $ | 10,002 | ||||||||
Funded status of the plans end of year |
$ | (145,603 | ) | $ | (59,581 | ) | $ | (4,896 | ) | $ | 289 | |||||
Assets (liabilities) recorded in the balance sheet: |
||||||||||||||||
Prepaid assets (included in other assets) |
$ | | $ | | $ | | $ | 701 | ||||||||
Unfunded liabilities (included in other noncurrent liabilities) |
(145,603 | ) | (59,581 | ) | (4,896 | ) | (412 | ) | ||||||||
Net amount recognized |
$ | (145,603 | ) | $ | (59,581 | ) | $ | (4,896 | ) | $ | 289 | |||||
Amounts recorded in stockholders equity: |
||||||||||||||||
Prior service cost |
$ | 392 | $ | 321 | $ | 61 | $ | | ||||||||
Net actuarial loss (gain) |
134,878 | 66,645 | 93 | (142 | ) | |||||||||||
Total |
$ | 135,270 | $ | 66,966 | $ | 154 | $ | (142 | ) | |||||||
In Fiscal 2010, we estimate that we will amortize $5,900 of net actuarial
losses and $40 of prior service cost from stockholders equity.
Actuarial assumptions are described below. The discount rates at September 30 are
used to measure the year-end benefit obligations and the earnings effects for the
subsequent year. The discount rate is based upon market-observed yields for high quality
fixed income securities with maturities that correspond to the payment of benefits. The
expected rate of return on assets assumption is based on the current and expected asset
allocations as well as historical and expected returns on various categories of plan
assets.
Pension Plans | Other Postretirement Benefits | |||||||||||||||||||||||||||||||
Weighted-average assumptions: | 2009 | 2008 | 2007 | 2006 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||||||||||
Discount rate |
5.5 | % | 6.8 | % | 6.4 | % | 6.0 | % | 5.5 | % | 6.8 | % | 6.4 | % | 6.0 | % | ||||||||||||||||
Expected return on plan assets |
8.5 | % | 8.5 | % | 8.5 | % | 8.5 | % | 5.5 | % | 5.5 | % | 5.5 | % | 5.6 | % | ||||||||||||||||
Rate of increase in salary levels |
3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % |
The ABO for the Pension Plans was $374,213 and $267,798 as of September 30, 2009 and
2008, respectively. Included in the end of year Pension Plans PBOs above are $37,023 at
September 30, 2009 and $27,882 at September 30, 2008 relating to employees of UGI and
certain of its other subsidiaries. Included in the end of year other postretirement plans
ABOs above are $665 at September 30, 2009 and $562 at September 30, 2008 relating to
employees of UGI and certain of its other subsidiaries.
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Net periodic pension expense and other postretirement benefit costs relating to the
Companys employees include the following components:
Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
2009 | 2008 | 2007 | 2009 | 2008 | 2007 | |||||||||||||||||||
Service cost |
$ | 5,975 | $ | 5,053 | $ | 5,457 | $ | 131 | $ | 261 | $ | 273 | ||||||||||||
Interest cost |
21,326 | 17,757 | 17,144 | 820 | 775 | 842 | ||||||||||||||||||
Expected return on assets |
(23,794 | ) | (22,702 | ) | (21,838 | ) | (523 | ) | (640 | ) | (596 | ) | ||||||||||||
Curtailment gain |
| | | | (2,202 | ) | | |||||||||||||||||
Amortization of: |
||||||||||||||||||||||||
Prior service cost (benefit) |
29 | 26 | 242 | (410 | ) | (388 | ) | (350 | ) | |||||||||||||||
Actuarial loss |
3,588 | | 866 | 88 | | 115 | ||||||||||||||||||
Net benefit cost (income) |
7,124 | 134 | 1,871 | 106 | (2,194 | ) | 284 | |||||||||||||||||
Change in associated regulatory liabilities |
| | | 3,271 | 3,435 | 3,123 | ||||||||||||||||||
Benefit cost after change in regulatory liabilities |
$ | 7,124 | $ | 134 | $ | 1,871 | $ | 3,377 | $ | 1,241 | $ | 3,407 | ||||||||||||
Pension Plans assets are held in trust. It is our general policy to fund
amounts for pension benefits equal to at least the minimum contribution required by
ERISA. From time to time we may, at our discretion, contribute additional amounts. We did
not make any contributions to the Pension Plans in Fiscal 2009, Fiscal 2008 or Fiscal
2007. We believe that we will be required to make contributions during Fiscal 2010 of
approximately $3,400.
UGI Utilities has established a Voluntary Employees Beneficiary Association
(VEBA) trust to pay retiree health care and life insurance benefits by depositing into
the VEBA the annual amount of postretirement benefits costs determined under GAAP. The
difference between such amounts calculated under GAAP and the amounts included in UGI
Gas and Electric Utilitys rates is deferred for future recovery from, or refund to,
ratepayers. The required contribution to the VEBA during Fiscal 2010 is not expected to
be material.
Expected payments for pension benefits and other postretirement welfare benefits are
as follows:
Other | ||||||||
Pension | Postretirement | |||||||
Benefits | Benefits | |||||||
Fiscal 2010 |
$ | 18,551 | $ | 1,543 | ||||
Fiscal 2011 |
19,388 | 1,563 | ||||||
Fiscal 2012 |
20,425 | 1,525 | ||||||
Fiscal 2013 |
21,566 | 1,469 | ||||||
Fiscal 2014 |
22,783 | 1,472 | ||||||
Fiscal 2015 2019 |
133,527 | 7,259 |
In accordance with our investment strategy to obtain long-term growth, our target
asset allocations are to maintain a mix of 65% equities and the remainder in fixed income
funds or cash equivalents in the Pension Plans. The targets and actual allocations for
the Pension Plans and the VEBA trust assets at September 30 are as follows:
Target | Pension Plan | VEBA | ||||||||||||||||||||||
Pension Plan | VEBA | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Equities |
65 | % | 65 | % | 68 | % | 63 | % | 64 | % | 57 | % | ||||||||||||
Fixed income funds |
35 | % | 35 | % | 32 | % | 37 | % | 30 | % | 34 | % | ||||||||||||
Cash equivalents |
N/A | 0 | % | N/A | N/A | 6 | % | 9 | % |
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
UGI Common Stock comprised approximately 8% and 9% of Pension Plans assets at
September 30, 2009 and 2008, respectively.
The assumed health care cost trend rates are 8.0% for Fiscal 2010, decreasing to
5.0% in Fiscal 2016. A one percentage point change in the assumed health care cost trend
rate would increase (decrease) the Fiscal 2009 postretirement benefit cost and obligation
as follows:
1% Increase | 1% Decrease | |||||||
Service and interest costs in Fiscal 2009 |
$ | 13 | $ | (12 | ) | |||
ABO at September 30, 2009 |
$ | 219 | $ | (204 | ) |
We also sponsor an unfunded and non-qualified supplemental executive retirement
income plan. At September 30, 2009 and 2008, the projected benefit obligations of this
plan were $2,773 and $3,161, respectively. We recorded expense for this plan of $635 in
Fiscal 2009, $362 in Fiscal 2008 and $355 in Fiscal 2007.
Defined Contribution Plan
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. The Utilities Savings Plan provides for
employer matching contributions. The cost of benefits under the Utilities Savings Plan
totaled $1,758 in Fiscal 2009, $1,256 in Fiscal 2008 and $1,069 in Fiscal 2007.
11. SERIES PREFERRED STOCK
We have 2,000,000 shares of Series Preferred Stock authorized for issuance, including
both series subject to and series not subject to mandatory redemption. We had no shares
of Series Preferred Stock outstanding at September 30, 2009 or 2008.
12. EQUITY-BASED COMPENSATION
Under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated
as of December 5, 2006 (the UGI OECP), certain key employees of UGI Utilities may be
granted stock options to acquire shares of UGI Common Stock, stock appreciation rights
(SARS), UGI Units (comprising Stock Units or Performance Units) and other
equity-based amounts. Under the UGI OECP, the exercise price for options may not be less
than the fair market value on the grant date. Awards under the UGI OECP may vest
immediately or ratably over a period of years (generally three-year periods), and stock
options for UGI Common Stock can be exercised no later than ten years from the grant
date. In addition, the UGI OECP provides that the awards of UGI Units may also provide
for the crediting of UGI Common Stock dividend equivalents to participants accounts.
Except in the event of retirement, death or disability, each grant, unless paid, will
terminate when the participant ceases to be employed. There are certain change of control
and retirement eligibility conditions that, if met, generally result in accelerated
vesting or elimination of further service requirements.
UGI Stock and UGI Performance Unit awards entitle the grantee to shares of UGI
Common Stock or cash once the service condition is met and, with respect to UGI
Performance Unit awards, subject to UGI market performance conditions. With respect to
UGI Performance Unit awards, the actual number of shares (or their cash equivalent)
ultimately issued, and the actual amount of dividend equivalents paid, is generally
dependent upon the achievement of market performance and service conditions. UGI
Performance Unit grant recipients are awarded a target number of Performance Units. The
number of Performance Units
ultimately paid at the end of the performance period (generally three years) may
range from 0% to 200% of the target award based upon UGIs Total Shareholder Return
percentile rank relative to companies in the Standard & Poors Utilities Index.
We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock
options. We use a Monte Carlo valuation approach to estimate the fair value of UGI
Performance Unit awards. We recorded total net pre-tax equity-based compensation expense
associated with both UGI Units and UGI stock options of $1,142 ($668 after-tax) during
Fiscal 2009; $842 ($492 after-tax) during Fiscal 2008; and $1,006 ($588 after-tax) during
Fiscal 2007.
As of September 30, 2009, there was $387 of unrecognized compensation cost related
to non-vested UGI stock options that is expected to be recognized over a weighted-average
period of 1.9 years. As of September 30, 2009, there was a total of $638 of unrecognized
compensation expense associated with 50,334 UGI Unit awards that is expected to be
recognized over a weighted average period of 1.8 years. At September 30, 2009 and 2008,
total liabilities of $560 and $357, respectively, associated with UGI Unit awards are
reflected in Other current liabilities and Other noncurrent liabilities in the
Consolidated Balance Sheets.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
The following table summarizes UGI Unit award activity for Fiscal 2009:
Total | Vested | Non-Vested | ||||||||||||||||||||||
Weighted | Weighted | Weighted | ||||||||||||||||||||||
Average | Average | Average | ||||||||||||||||||||||
Number of | Grant Date | Number of | Grant Date | Number of | Grant Date | |||||||||||||||||||
UGI | Fair Value | UGI | Fair Value | UGI | Fair Value | |||||||||||||||||||
Units | (per Unit) | Units | (per Unit) | Units | (per Unit) | |||||||||||||||||||
September 30, 2008 |
63,300 | $ | 26.68 | 18,333 | $ | 24.98 | 44,967 | $ | 27.37 | |||||||||||||||
Granted |
31,700 | $ | 28.00 | | $ | | 31,700 | $ | 28.00 | |||||||||||||||
Vested |
| $ | | 19,901 | $ | 24.77 | (19,901 | ) | $ | 24.77 | ||||||||||||||
Forfeited |
(25,666 | ) | $ | 28.67 | | $ | | (25,666 | ) | $ | 28.67 | |||||||||||||
Unit awards paid |
(19,000 | ) | $ | 21.08 | (19,000 | ) | $ | 21.08 | | $ | | |||||||||||||
September 30, 2009 |
50,334 | $ | 28.61 | 19,234 | $ | 28.62 | 31,100 | $ | 28.60 | |||||||||||||||
13. COMMITMENTS AND CONTINGENCIES
Commitments
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 $5,894 in Fiscal 2009, $4,858 in Fiscal 2008 and $4,519 in Fiscal 2007.
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: 2010 $5,047; 2011 $4,183; 2012 $3,496; 2013 $2,966; 2014 $2,074; after
September 30, 2014 $4,678.
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,
natural gas storage and peaking service which Gas Utility may terminate at various dates
through 2029. Gas Utilitys costs associated with transportation and storage service
agreements are included in its annual PGC filings 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 electric energy needs under contracts with various
suppliers and on the spot market. Contracts with producers for energy needs expire at
various dates through Fiscal 2014.
Future contractual cash obligations under Gas Utility and Electric Utility supply,
storage and service agreements existing at September 30, 2009 for fiscal years ending
September 30 are as follows: 2010 $240,831; 2011 $125,169; 2012 $108,188; 2013
$66,905; 2014 $54,531; after 2014 $108,513.
Contingencies
CPG is party to a Consent Order and Agreement (CPG-COA) with the Pennsylvania
Department of Environmental Protection (DEP) requiring CPG to perform a specified level
of activities associated with environmental investigation and remediation work at certain
properties in Pennsylvania on which manufactured gas plant (MGP) related facilities
were operated (CPG MGP Properties) and to plug a minimum number of non-producing
natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation
Consent Order and Agreement (PNG-COA) with the DEP. The PNG-COA requires PNG to perform
annually a specified level of activities associated with environmental investigation and
remediation work at certain properties on which MGP-related facilities were operated
(PNG MGP Properties). Under these agreements, environmental expenditures relating to
the CPG MGP Properties and the PNG MGP Properties are capped at $1,800 and $1,100,
respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP
Properties and at the end of 2013 for well plugging activities. The PNG-COA terminates in
2019 but may be terminated by either party effective at the end of any two-year period
beginning with the original effective date in March 2004. At September 30, 2009, our accrued
liabilities for environmental investigation and remediation costs related to the CPG-COA
and the PNG-COA totaled $25,042. In accordance with GAAP related to rate-regulated
entities, we have recorded associated regulatory assets totaling $25,042.
F - 24
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries
owned and operated a number of 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, by the early 1950s UGI Utilities divested all of its utility
operations other than certain Pennsylvania operations, including those which now
constitute UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of
hazardous substances at Pennsylvania MGP sites to be material to its results of operations
because UGI Gas is currently permitted to include in rates, through future base rate
proceedings, a five-year average of such prudently incurred remediation costs. At
September 30, 2009 and 2008, neither UGI Gas undiscounted nor its accrued liability for
environmental investigation and cleanup costs was material.
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.
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 subsidiarys 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 subsidiarys MGP.
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South
Carolina Electric & Gas Company (SCE&G), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated
from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant
UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for
approximately 25% of the costs associated with the site. SCE&G asserts that it has spent
approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating
to the site and estimates that future response costs, including a claim by the United
States Justice Department for natural resource damages, could be as high as $14,000. Trial
took place in March 2009 and the courts decision is pending.
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens
Communications Company, now known as Frontier Communications Company (Frontier), served
a complaint naming UGI Utilities as a third-party defendant in a civil action pending in
the United States District Court for the District of Maine. In that action, the City of
Bangor, Maine (City) sued Frontier to recover environmental response costs associated
with MGP wastes generated at a plant allegedly operated by Frontiers predecessors at a
site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other
third-party defendants alleging that the third-party defendants are responsible for an
equitable share of any costs Frontier would be required to pay to the City for cleaning up
tar deposits in the Penobscot River. Frontier alleged that through ownership and control
of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and
operated the plant from 1901 to 1928. Frontier made similar allegations of control against
another third-party defendant, CenterPoint Energy Resources Corporation (CenterPoint),
whose predecessor owned the Bangor subsidiary from 1928 to 1944. Frontiers third-party
claims were stayed pending a
resolution of the Citys suit against Frontier, which was tried in September 2005. On
June 27, 2006, the court issued an order finding Frontier responsible for 60% of the
cleanup costs, which were estimated at $18,000. On February 14, 2007, Frontier and the
City entered into a settlement agreement pursuant to which Frontier agreed to pay $7,600.
Frontier subsequently filed the current action against the original third-party
defendants, repeating its claims for contribution. On September 22, 2009, the court
granted summary judgment in favor of co-defendant CenterPoint. UGI Utilities believes
that it also has good defenses and has filed a motion for summary judgment with respect to
Frontiers claims.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Sag Harbor, New York Matter. 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. By
letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental
Conservation has approved a remedy for the site that is estimated to cost approximately
$10,000. KeySpan believes that the cost could be as high as $20,000. UGI Utilities is in
the process of reviewing the information provided by KeySpan and is investigating this
claim.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.
On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services
Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities
(together the Northeast Companies), in the United States District Court for the District
of Connecticut seeking 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 through control of former
subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs
for all of the sites could total approximately $215,000 and asserted that UGI Utilities is
responsible for approximately $103,000 of this amount. The Northeast Companies
subsequently withdrew their claims with respect to three of the sites and UGI Utilities
acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease.
In April 2009, the court conducted a trial to determine whether UGI Utilities operated any
of the nine remaining sites that were owned and operated by former subsidiaries. On May
22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine
sites. In a second phase of the trial scheduled for early 2010, the court will determine
what, if any, contamination at Waterbury North is related to UGI Utilities period of
operation. The Northeast Companies estimate that remediation costs at Waterbury North
could total $25,000.
We cannot predict with certainty the final results of any of the environmental claims
or legal actions described above. 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. In addition to the matters described above, there are other
pending claims and legal actions arising in the normal course of our businesses. While the
results of these other pending claims and legal actions cannot be predicted with
certainty, we believe, after consultation with counsel, the final outcome of such other
matters will not have a significant effect on our consolidated financial position, results
of operations or cash flows.
14. FAIR VALUE MEASUREMENTS
The following table presents our financial assets and financial liabilities that are
measured at fair value on a recurring basis for each of the fair value hierarchy levels,
including both current and noncurrent portions, as of September 30, 2009:
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Derivative financial instruments: |
||||||||||||||||
Assets |
$ | 102 | $ | 765 | $ | | $ | 867 | ||||||||
Liabilities |
$ | | $ | | $ | | $ | |
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
15. DISCLOSURES ABOUT DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND OTHER FINANCIAL
INSTRUMENTS
Derivative Instruments and Hedging Activities
We are exposed to certain market risks related to our ongoing business operations.
Management uses derivative financial and commodity instruments, among other things, to
manage these risks. The primary risks managed by derivative instruments are (1) commodity
price risk and (2) interest rate risk. Although we use derivative financial and commodity
instruments to reduce market risk associated with forecasted transactions, we do not use
derivative financial and commodity instruments for speculative or trading purposes. The
use of derivative instruments is controlled by our risk management and credit policies
which govern, among other things, the derivative instruments we can use, counterparty
credit limits and contract authorization limits. Because our derivative instruments,
other than FTRs and gasoline futures and swap contracts (as further described below),
generally qualify as hedges under GAAP or are recoverable or refundable pursuant to
current regulatory practice, we expect that changes in the fair value of derivative
instruments used to manage commodity or interest rate risk would
be substantially offset by gains or losses on the associated anticipated transactions.
Commodity Price Risk
Gas Utilitys tariffs contain clauses that permit recovery of all of the prudently
incurred costs of natural gas it sells to retail core-market customers. As permitted and
agreed to by the PUC pursuant to Gas Utilitys annual PGC filings, Gas Utility currently
uses New York Mercantile Exchange (NYMEX) natural gas futures contracts to reduce
commodity price volatility associated with a portion of the natural gas it purchases for
its retail core-market customers. At September 30, 2009, there were no unsettled NYMEX
natural gas futures contracts outstanding.
In order to reduce volatility associated with a substantial portion of its
electricity transmission congestion costs, Electric Utility obtains FTRs through an
annual PJM Interconnection (PJM) allocation process and by purchases of FTRs at
monthly PJM auctions. FTRs are derivative financial instruments that entitle the holder
to receive compensation for electricity transmission congestion charges that result when
there is insufficient electricity transmission capacity on the electric transmission
grid. PJM is a regional transmission organization that coordinates the movement of
wholesale electricity in all or parts of 14 eastern and midwestern states.
In order to reduce operating expense volatility, UGI Utilities from time to time
enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes
expected to be used in the operation of its vehicles and equipment. The volumes of
gasoline under these contracts and the effect on net income from changes in fair value
were not material for all periods presented.
Although we did not have any unsettled natural gas futures contracts outstanding at
September 30, 2009, we typically hedge anticipated purchases of natural gas over periods
of approximately 12 to 18 months. The volume of electricity congestion that is subject
to FTRs at September 30, 2009 totaled 1.0 million kilowatt-hours and the maximum period
over which we are currently hedging electricity congestion with FTRs is 20 months. At
September 30, 2009, the maximum period over which we are hedging gasoline is 12 months.
With respect to natural gas futures contracts associated with our Gas Utility,
gains and losses on unsettled natural gas futures contracts are recorded in deferred
fuel costs on the Consolidated Balance Sheet in accordance with the FASB guidance
related to rate-regulated entities and reflected in cost of sales through the PGC
mechanism. At September 30, 2008, Gas Utility had recorded current liabilities of
$23,321 representing the fair values of unsettled natural gas futures contracts as of
that date and associated regulatory assets of equal amount. There were no such amounts
at September 30, 2009. Because Electric Utility is entitled to fully recover its default
service costs commencing January 1, 2010 pursuant to the January 22, 2009 settlement of
its default service rate filing with the PUC (see Note 5), changes in the fair value of
Electric Utility FTRs associated with periods beginning January 1, 2010 will not affect
net income. Electric Utility FTRs associated with periods prior to January 2010 are
recorded at fair value with changes in fair value reflected in cost of sales.
Interest Rate Risk
Our long-term debt typically is issued at fixed rates of interest. As these
long-term debt issues mature, we typically refinance such debt with new debt having
interest rates reflecting then-current market conditions. In order to reduce market rate
risk on the underlying benchmark rate of interest associated with near- to medium-term
forecasted issuances of fixed-rate debt, from time to time we enter into interest rate
protection agreements (IRPAs). We account for IRPAs as cash flow hedges. Changes in
the fair values of IRPAs are recorded in AOCI, to the
extent effective in offsetting changes in the underlying interest rate risk, until
earnings are affected by the hedged interest expense. At September 30, 2009 there were
no unsettled IRPA contracts outstanding.
We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are
recorded in AOCI to the extent effective in offsetting changes in the underlying
interest rate risk, until earnings are affected by the hedged interest expense. At
such time, gains and losses are recorded in interest expense. At September 30,
2009, the amount of net losses associated with IRPAs expected to be reclassified into
earnings during the next twelve months is $1,164.
F - 27
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Derivative Financial Instrument Credit Risk
Our natural gas exchange-traded futures contracts are guaranteed by the NYMEX and
have limited credit risk. These contracts generally require cash deposits in margin
accounts. At September 30, 2008, Gas Utilitys restricted cash in brokerage accounts
totaled $34,037. There was no such restricted cash at September 30, 2009. We generally
do not have credit-risk-related contingent features in our derivative contracts.
The following table provides information regarding the balance sheet location and
fair values of derivative assets and liabilities existing as of September 30, 2009:
As of September 30, 2009 | Derivative Assets | Derivative (Liabilities) | ||||||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||||||
Location | Value | Location | Value | |||||||||||||
Derivatives Not Designated as
Hedging Instruments: |
||||||||||||||||
FTRs |
Derivative financial instruments | $ | 765 | $ | | |||||||||||
Gasoline futures contracts |
Derivative financial instruments | 102 | | |||||||||||||
Total Derivatives Not Designated
as Hedging Instruments |
$ | 867 | $ | | ||||||||||||
During the year ended September 30, 2009, the amount of IRPA net losses
included in AOCI that were reclassified into net income totaled $1,164. During the year
ended September 30, 2009, the impact of changes in the fair value of FTRs and gasoline
futures and swap contracts on our net income was not material.
We are also 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 qualify for normal purchase and normal sale exception accounting under GAAP
because they provide for the delivery of products or services in quantities that are
expected to be used in the normal course of operating our business and the price based
on the contract underlying is directly associated with the price or value of a service.
Financial Instruments
The carrying amounts of financial instruments included in current assets and
current liabilities (excluding unsettled derivative instruments and current maturities
of long-term debt) approximate their fair values because of their short-term nature. The
carrying amounts and estimated fair values of our remaining financial instruments assets
and (liabilities) at September 30 (including unsettled derivative instruments) are as
follows:
Asset (Liability) | ||||||||
Carrying | Estimated | |||||||
Amount | Fair Value | |||||||
2009: |
||||||||
Derivative financial instruments |
$ | 867 | $ | 867 | ||||
Long-term debt |
(640,000 | ) | (705,710 | ) | ||||
2008: |
||||||||
Derivative financial instruments |
$ | (22,982 | ) | $ | (22,982 | ) | ||
Long-term debt |
(532,000 | ) | (484,000 | ) |
We estimate the fair value of long-term debt by using current market rates and by
discounting future cash flows using rates available for similar type debt. Fair values
of derivative financial instruments are determined in accordance with the FASBs
guidance regarding fair value measurements.
F - 28
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Financial instruments other than derivative financial instruments, such as our
short-term investments and trade accounts receivable, could expose us to concentrations
of credit risk. We limit our credit risk from short-term investments by investing only
in investment-grade commercial paper, money market mutual funds and securities
guaranteed by the U.S. Government or its agencies. The credit risk from trade accounts
receivable is limited because we have a large customer base which extends across many
different markets.
16. SEGMENT INFORMATION
We have determined that we have two reportable segments: (1) Gas Utility and
(2) Electric Utility. Gas Utility revenues are derived principally from the sale and
distribution of natural gas to customers in eastern, northeastern and central
Pennsylvania. Electric Utility derives its revenues principally from the sale and
distribution of electricity in two northeastern Pennsylvania counties. The HVAC Business
does not meet the quantitative thresholds for separate segment reporting under GAAP
relating to business segment reporting and has been included in
Other for periods commencing
January 1, 2007, the date UGI Utilities contributed its heating,
ventilation and air-conditioning services business to UGI HVAC.
Periods prior to January 1, 2007 have not been restated.
The accounting policies of our reportable segments are the same as those described
in Note 2. We evaluate the performance of our Gas Utility and Electric Utility 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 - 29
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
Financial information by business segment follows:
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
2009 |
||||||||||||||||
Revenues |
$ | 1,381,260 | $ | 1,240,981 | $ | 138,495 | $ | 1,784 | ||||||||
Cost of sales |
944,793 | 853,163 | 91,630 | | ||||||||||||
Depreciation and amortization |
51,112 | 47,228 | 3,884 | | ||||||||||||
Operating income |
169,472 | 153,457 | 15,376 | 639 | ||||||||||||
Interest expense |
43,918 | 42,192 | 1,726 | | ||||||||||||
Income before income taxes |
125,554 | 111,265 | 13,650 | 639 | ||||||||||||
Total assets |
2,030,237 | 1,915,901 | 113,201 | 1,135 | ||||||||||||
Goodwill |
180,145 | 180,145 | | | ||||||||||||
Capital expenditures |
79,084 | 73,825 | 5,259 | | ||||||||||||
2008 |
||||||||||||||||
Revenues |
$ | 1,289,053 | $ | 1,138,346 | $ | 139,232 | $ | 11,475 | ||||||||
Cost of sales |
920,413 | 831,066 | 84,312 | 5,035 | ||||||||||||
Depreciation and amortization |
41,325 | 37,679 | 3,638 | 8 | ||||||||||||
Operating income |
163,042 | 137,556 | 24,449 | 1,037 | ||||||||||||
Interest expense |
39,065 | 37,068 | 1,997 | | ||||||||||||
Income before income taxes |
123,977 | 100,489 | 22,451 | 1,037 | ||||||||||||
Total assets |
1,694,466 | 1,582,371 | 112,095 | | ||||||||||||
Goodwill |
161,726 | 161,726 | | | ||||||||||||
Capital expenditures |
64,351 | 58,243 | 6,048 | 60 | ||||||||||||
2007 |
||||||||||||||||
Revenues |
$ | 1,183,247 | $ | 1,044,946 | $ | 121,935 | $ | 16,366 | ||||||||
Cost of sales |
816,451 | 741,468 | 67,770 | 7,213 | ||||||||||||
Depreciation and amortization |
40,934 | 37,396 | 3,532 | 6 | ||||||||||||
Operating income |
165,093 | 136,586 | 25,995 | 2,512 | ||||||||||||
Interest expense |
42,327 | 39,891 | 2,436 | | ||||||||||||
Income before income taxes |
122,766 | 96,695 | 23,559 | 2,512 | ||||||||||||
Total assets |
1,649,038 | 1,530,399 | 110,076 | 8,563 | ||||||||||||
Goodwill |
162,309 | 162,309 | | | ||||||||||||
Capital expenditures |
73,411 | 66,164 | 7,212 | 35 |
17. OTHER INCOME, NET
Other income, net, comprises the following:
2009 | 2008 | 2007 | ||||||||||
Non-tariff service income |
$ | 3,221 | $ | 6,191 | $ | 5,068 | ||||||
Interest income |
288 | 1,444 | 2,480 | |||||||||
Curtailment gain |
| 2,202 | | |||||||||
Other |
3,752 | 3,087 | 1,016 | |||||||||
Total other income, net |
$ | 7,261 | $ | 12,924 | $ | 8,564 | ||||||
18. RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI
bills UGI Utilities monthly for all direct expenses incurred by UGI on behalf of UGI
Utilities and an allocated share of indirect corporate expenses incurred or paid with
respect to services provided to UGI Utilities. The allocation of indirect UGI corporate
expenses to UGI Utilities utilizes a weighted, three-component formula based upon the
relative percentage of UGI Utilities revenues, operating expenses and net assets
employed to the total of such items for UGIs other operating subsidiaries for which
general and administrative services are provided. Management believes that this
allocation method is reasonable and equitable to UGI Utilities and this allocation method
has been accepted by the PUC in past rate case proceedings and management audits as a
reasonable method of allocating such expenses. 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 UGIs subsidiaries, principally payroll-related services. Amounts billed to
these entities by UGI Utilities for all periods presented were not material.
F - 30
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UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
At September 30, 2009, UGI Utilities was a party to a one-year storage contract
administrative agreement (SCAA) with Energy Services expiring on October 31, 2009. At
September 30, 2008, UGI Utilities was a party to a one-year SCAA with Energy Services
expiring on October 31, 2008. Pursuant to the SCAAs, UGI Utilities has, among other
things, released certain storage and transportation contracts for the terms of the
SCAAs. UGI Utilities also transferred certain associated storage inventories upon
commencement of the SCAAs, will receive a transfer of storage inventories at the end of
the SCAAs, and makes payments associated with refilling storage inventories during the
term of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes
certain payments to UGI Utilities for its various obligations under the SCAAs. UGI
Utilities incurred costs associated with the SCAAs totaling $55,760 in Fiscal 2009,
$111,764 in Fiscal 2008 and $92,683 in Fiscal 2007. In conjunction with the SCAA expiring
on October 31, 2009, UGI Utilities received $15,000 in security deposits from Energy
Services which amount is included in other current liabilities on the September 30,
2009 Consolidated Balance Sheet.
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, 2009,
comprising approximately 7.7 bcf of natural gas, was $67,436. The carrying value of these
gas storage inventories at September 30, 2008, comprising approximately 8.3 bcf feet of
natural gas, was $70,833. Effective November 1, 2009, UGI Utilities entered into a new
SCAA with Energy Services expiring on October 31, 2012.
UGI Utilities has gas supply and delivery service agreements with Energy Services
pursuant to which Energy Services provides certain gas supply and related delivery
service to UGI Utilities during the peak heating-season months of November to March. In
addition, from time to time, UGI Utilities purchases natural gas or pipeline capacity
from Energy Services. The
aggregate amount of these transactions (exclusive of SCAA transactions)
during Fiscal 2009, Fiscal 2008 and Fiscal 2007 totaled $24,444, $52,603 and $36,286,
respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy
Services. During Fiscal 2009, Fiscal 2008 and Fiscal 2007, revenues associated with sales
to Energy Services totaled $30,911, $66,126 and $39,564, respectively. Also from time to
time, the Company purchases natural gas or pipeline capacity from Energy Services (in
addition to those transactions already described above). During Fiscal 2009, Fiscal 2008
and Fiscal 2007, such purchases totaled $17,268, $29,454 and $2,008, respectively. These
transactions did not have a material effect on the Companys financial position, results
of operations or cash flows.
On October 1, 2008, in conjunction with the CPG Acquisition, CPGs wholly owned
subsidiary CPP sold its assets to AmeriGas OLP, an affiliate of UGI. See Note 4 for
additional information regarding this transaction.
19. 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 the Companys
businesses.
December 31, | March 31, | June 30, | September 30, | |||||||||||||||||||||||||||||
2008 | 2007 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||
Revenues |
$ | 446,692 | $ | 364,388 | $ | 581,260 | $ | 519,998 | $ | 208,300 | $ | 235,544 | $ | 145,008 | $ | 169,123 | ||||||||||||||||
Operating income |
$ | 62,012 | $ | 58,609 | $ | 85,673 | $ | 81,669 | $ | 16,443 | $ | 20,058 | $ | 5,344 | $ | 2,706 | ||||||||||||||||
Net income (loss) |
$ | 31,134 | $ | 28,633 | $ | 44,746 | $ | 43,086 | $ | 3,113 | $ | 6,248 | $ | (271 | ) | $ | (3,940 | ) |
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UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
(Thousands of dollars)
Balance at | Charged to | Balance at | ||||||||||||||
beginning | costs and | end of | ||||||||||||||
of year | expenses | Other | year | |||||||||||||
Year Ended September 30, 2009 |
||||||||||||||||
Reserves deducted from assets in the
consolidated balance sheet: |
||||||||||||||||
Allowance for
doubtful accounts |
$ | 10,369 | $ | 19,193 | $ | (22,735 | )(1) | $ | 11,384 | |||||||
$ | 4,557 | (2) | ||||||||||||||
Other reserves: |
||||||||||||||||
Other, principally
environmental |
$ | 16,011 | $ | 2,335 | $ | 18,495 | (2) | $ | 38,707 | |||||||
$ | (3,678 | )(3) | ||||||||||||||
$ | 5,544 | (5) | ||||||||||||||
Year Ended September 30, 2008 |
||||||||||||||||
Reserves deducted from assets in the
consolidated balance sheet: |
||||||||||||||||
Allowance for
doubtful accounts |
$ | 10,824 | $ | 18,210 | $ | (18,533 | )(1) | $ | 10,369 | |||||||
$ | (132 | )(4) | ||||||||||||||
Other reserves: |
||||||||||||||||
Other, principally
environmental |
$ | 18,562 | $ | 795 | $ | (4,101 | )(3) | $ | 16,011 | |||||||
$ | 755 | (5) | ||||||||||||||
Year Ended September 30, 2007 |
||||||||||||||||
Reserves deducted from assets in the
consolidated balance sheet: |
||||||||||||||||
Allowance for
doubtful accounts |
$ | 12,389 | $ | 14,353 | $ | (16,341 | )(1) | $ | 10,824 | |||||||
$ | 423 | (2) | ||||||||||||||
Other reserves: |
||||||||||||||||
Other, principally
environmental |
$ | 8,868 | $ | 2,363 | $ | (923 | )(3) | $ | 18,562 | |||||||
$ | 8,254 | (2) |
(1) | Uncollectible accounts written off, net of recoveries
|
|
(2) | Acquisition adjustments |
|
(3) | Payments, net |
|
(4) | Dividend of UGI HVAC |
|
(5) | Other adjustments |
S - 1
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EXHIBIT INDEX
Exhibit No. | Description | |||
10.10 | UGI Utilities, Inc. Senior Executive Employee Severance Plan as in
effect as of November 1, 2008 |
|||
10.18 | Form of Change in Control Agreement Amended and Restated as of May 12,
2008 for Messrs. Barney and Terranova and Ms. Ebner |
|||
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 the Chief Executive Officer and Chief Financial
Officer pursuant to Section 906 of the Sarbanes-Oxley Act |