2018 Annual Report
Expanding from our core
Expanding from our core
UGI Corporation (NYSE: UGI) is a holding company that, through subsidiaries,
distributes and markets energy products and related services. UGI Corporation
common stock is a balanced growth and income investment. The Company has
paid common dividends for 134 consecutive years and increased its dividend
in each of the last 31 years.
North
Belgium, Denmark, Finland,
Netherlands, Norway, Sweden,
Luxembourg, United Kingdom
East
Austria, the Czech Republic,
Hungary, Italy, Poland, Romania,,,
Slovakia, Switzerland
West
France
AmeriGas Partners, L.P. (NYSE: APU) is the nation’s largest
retail propane marketer, serving over 1.7 million customers in all
50 states from approximately 1,900 locations. UGI Corporation,
through subsidiaries, is the sole General Partner and owns 26%
of the Partnership; the public owns the remaining 74%.
UGI International distributes approximately 1 billion gallons
of liquefied petroleum gases (LPG) in 17 countries in Europe.
It also operates an energy marketing business in four of those
countries. Our businesses, for the most part, are among the
market leaders in their respective countries.
G
■ Gas Utility
■ Electric Utility
UGI Utilities, Inc.
operates a regulated
natural gas distribution
business that serves
over 642,000 customers in portions of 44 eastern and central
Pennsylvania counties and more than 500 customers in portions
of one Maryland county through its distribution system of
approximately 12,300 miles of gas mains. UGI Utilities, Inc. also
provides regulated electric utility service to approximately 62,000
customers in portions of Luzerne and Wyoming counties in
northeastern Pennsylvania.
UGI Energy Services sells natural
gas, electricity and liquid fuels to over
12,500 residential, commercial and
industrial customers in 11 eastern
states and the District of Columbia
and conducts UGI’s midstream natural
gas business through its ownership
of underground natural gas storage,
gas peaking plants, and pipeline
assets in Pennsylvania. UGI Energy
Services also owns all or a portion of
electric generation assets, principally in
Pennsylvania.
Expanding from our core
UGI Corporation remains focused on growth and expansion
in sectors that align with our core position as a distributor
and marketer of energy products and services.
Capabilities – We are expanding our capabilities to include energy
marketing in Europe and enhancing our LNG footprint and LPG fleets.
Marcellus Shale – We are expanding our participation in
a broad range of critical infrastructure projects in the Marcellus
Shale region.
Geography – We are expanding our reach. UGI International
is now in 17 countries in Europe, while Energy Services has
extended its marketing reach from the Marcellus down to the
Carolinas.
Customer Service – Customer service is at the core of
everything we do. Our reach has expanded recently as we have
incorporated more technology into ensuring our customers
have a stress-free engagement. AmeriGas now has over
470,000 customers registered for online capabilities.
To Our Shareholders
We are pleased to report record earnings for the third
consecutive year. Periods of extreme weather domestically,
and warm weather abroad, challenged our teams and they
responded by delivering adjusted earnings per share that
outpaced Fiscal 2017’s record results by 20%. The outstanding
results were enabled by UGI’s strong foundation for growth and
commitment to day-to-day execution. This foundation is built
on our commitment to identify and develop investments that
align with our fundamental business strategies while expanding
from our core. That expansion was evident this year as we
made progress on primary strategic initiatives such as the
continued build out of our Marcellus asset network, geographic
expansion in Europe, and increased gas and power marketing
activities in Europe. We also deployed record levels of capital at
our Utilities business and grew our ACE and National Accounts
programs at AmeriGas. As you can see below, this strategy has
delivered excellent returns for our shareholders over the last 20
years and we are well-positioned to build on this performance.
UGI was recognized by a number of respected publications
and institutions this year. Most notably, for the 14th time, UGI
was listed among the Fortune 500, which comprises the 500
largest companies in the United States as compiled by Fortune.
Of particular note, we were very pleased that among the eight
companies listed by Fortune in the Energy sector, UGI was
ranked #1 in the categories of Biggest Employer and Profits
Percent Change, and #2 in the Most Profitable Company
category. Barron’s again ranked UGI among the Barron’s 500
list of top performing companies and Platts named UGI as one
of the “Top 250 Global Energy Companies.”
The company delivered adjusted diluted earnings per share
of $2.74, a 36% increase over 2015 which was our last year
with near-normal weather conditions. Our strong earnings per
share growth trajectory is directly linked to the contributions
from our recent strategic investment and organic growth
across our businesses, all further amplified by beneficial
changes in tax laws.
• The Midstream & Marketing team had another outstanding
year, as we strengthened our position as a major midstream
operator in the central and eastern Marcellus with access
to capacity-constrained markets in the Mid-Atlantic and
New England. We completed the Steelton, PA LNG storage
facility and announced another new LNG storage facility for
Bethlehem, PA. These investments add critical storage and
delivery capacity to our LNG network as we strive to meet
the rapidly increasing demand for LNG peaking services. We
acquired the Texas Creek gathering system in north-central PA
and we are expanding that network as drilling activity increases
in that area. The PennEast pipeline project received the FERC
certificate of public convenience and necessity in January 2018
and is moving through the state-level permitting process.
• Our Utilities team had a very productive year. The Utility
deployed a record $340 million of capital, as we added
new customers, replaced gas distribution infrastructure and
upgraded our critical accounting systems. We added over
14,000 new residential and commercial heating customers and
continued to execute our extensive infrastructure replacement
and upgrade program. We merged our three gas utilities and
successfully concluded the first rate case filing for our Electric
Utility in over 20 years.
• AmeriGas made impressive progress with its ACE and
National Accounts programs. Both of these programs leverage
AmeriGas’ unparalleled national distribution network and our
ability to meet our customer commitments under challenging
circumstances. Fiscal 2018 was another very strong year, as
our National Accounts volumes rose over 11% and our ACE
volumes increased by 4%.
• UGI International was our only business that faced the
challenge of warmer weather than the prior year, but
still delivered a record level of operating income. Key
20-Year Cumulative Total Shareholder Return
(cid:81) UGI Corporation
Comparison between UGI Corporation and S&P 500 Index.
Assuming $100 invested at September 30, 1998
(cid:81) S&P 500
20-Year compound annual growth rate:
UGI Corporation – 16.8%; S&P 500 – 7.4%
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
A rich history of growing our business
1998
Began Cylinder
Exchange
1999
Entered
Europe
2001
Entered France
Columbia Propane
acquisition
2003
Acquired TXU Corp’s NE
gas marketing operation
2006
Acquired utility
operations of PG Energy
2008
Acquired gas utility
operations of PPL
We start Fiscal Year 2019 with the cash flow and balance
sheet capacity to fund our full range of active projects
with significant spare capacity to support additional new
investments. In addition to funding our growth projects, we
also remain very committed to growing our dividend. We are
proud to report that Fiscal 2018 marks 31 consecutive years
of increasing our dividend, and 134 consecutive years that
UGI has paid a dividend.
We can say with confidence that we are in an outstanding
position to deliver on our commitments for future earnings
growth. We thank you for your investment and look forward
to keeping you updated on our progress throughout the year.
Marvin O. Schlanger
Chairman of the Board
John L. Walsh
President and
Chief Executive Officer
accomplishments in the year included the successful integration
of the Preem and UniverGas acquisitions in Sweden and Italy,
which strengthened our position as one of the market leaders in
European LPG. We also had a very successful first year at DVEP,
our newly acquired natural gas and power marketing business in
the Netherlands. One final key achievement was the successful
conclusion of our three-year integration program for the Finagaz
acquisition. Our team in France did an outstanding job on this
crucial project, with a sustained focus over the past three years.
We have met or exceeded all the investment targets for Finagaz
and the positive impact of this strategic investment is evident
by the performance of our International business over the past
three years.
This year was another truly memorable year for UGI. We
continued to expand from our core base of operations
while once again delivering record EPS. We developed and
executed a range of attractive new investments that enhance
our foundation for future growth. We also made several key
executive appointments with an eye to the future. We were
delighted to have Ted Jastrzebski join us as CFO in the late
spring. He has been a great addition to our senior leadership
team. We were also pleased to appoint Roger Perreault
and Bob Beard to their roles as Executive VPs with overall
responsibility for our Global LPG and Natural Gas businesses,
respectively. Finally, Hugh Gallagher was named President and
CEO of AmeriGas in Q4 and we are delighted to have Hugh
in that crucial role. These appointments will enable continued
growth as we strive to leverage the common ground that exists
in many areas of our businesses, while maintaining our sharp
focus on local markets that has been the hallmark of UGI’s
success.
2,500
2,000
1,500
1,000
500
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n
e
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e
P
n
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e
R
l
a
t
o
T
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2012
Heritage acquisition
1 BCF expansion of
Temple LNG
Auburn I Project
2013
Auburn II Project
2014
PennEast Pipeline
announced
2015
Union Dale
Pipeline Project
2015
Finagaz acquisition
nearly doubles volume
in France
2017
Manning LNG Project
Sunbury Pipeline
Project
Financial Highlights
Adjusted Earnings Per Share (EPS)1
$3.00
$2.50
$2.29
$2.00
$2.05
$2.74
Natural Gas Marketing and
Utility Throughput
(billions of cubic feet)
435
402
346
2016
2017
2018
450
400
350
300
250
$1.50
$1.00
2.5
2.0
1.5
1.0
2016
2017
2018
Total Gallons – Global LPG
(billions of gallons)
Contribution2 by Business Segment
2.2
2.0
2.0
AmeriGas
Propane
15%
UGI
International
31%
Midstream &
Marketing
26%
UGI Utilities
28%
2016
2017
2018
2Adjusted Earnings Per Share
excludes $(0.08) from Corporate and Other
(1) Adjusted earnings per share (EPS) is not a measure of
performance of financial condition under accounting
principles generally accepted in the United State of America
(“GAAP”). For a more complete description of this non-
GAAP measure, why management believes this non-GAAP
measure is meaningful to investors, and a reconciliation to
earnings per share, see item 7, “Management’s Discussion
and Analysis of Financial Condition and Results of
Operations” included in UGI Corporation’s Annual Report on
Form 10-K for the fiscal year ended September 30, 2018.
Sustainability Efforts Across UGI
UGI is committed to delivering competitively priced energy projects and services to our customers in a safe, energy efficient and reliable
manner while providing superior shareholder value. We will meet these commitments in a sustainable and socially responsible way to
minimize our impact on the environment and be a good steward of our planet. We recognize that climate change is a challenge that we must
address today in order to create a more sustainable future for our customers, employees, shareholders and the communities we serve.
Utility Conversions
Energy Efficiency
90,000 households over last 10 years
$108MM in annual energy cost savings
Reduction in GHG emissions equivalent
to removing 103,000 passenger vehicles
from the road for a year
$5.5MM in rebates paid to participants;
added Gas Energy Efficiency and
Conservation in 2017
26 Combined Heating and
Power customers totaling 170 MW;
6 new projects underway
Solar Facilities
Landfill Gas Recovery
17,000 MWh generated per year
Electricity to power 1,700 homes
Reduction in GHG emissions equivalent
to removing 2,700 passenger vehicles from
the road for a year
Methane and landfill gas consumption at
Broad Mountain generation facility is about
1MM Dths per year
Enough Dths to heat 10,000 homes
Reduction in GHG emissions equivalent
to removing 14,000 passenger vehicles
from the road for a year
Additional activities
Pipeline replacement and betterment –
Improving system integrity and reducing leaks;
reduced leaks approximately 25% over the
past 5 years
Project ROAD – Using technology to optimize route
efficiency; eliminating an estimated 5.4 million miles
driven over the past two years
DVEP – Marketed 2.4 TWh from renewable energy
sources; enough to power 240,000 homes
Fleet Conversions – AmeriGas converting diesel
fleets to low carbon/low emission LPG; Natural
Gas businesses constructing CNG facilities and
converting fleets
UNITED STATES
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, 2018
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)
Pennsylvania
(State or Other Jurisdiction of
Incorporation or Organization)
23-2668356
(I.R.S. Employer Identification No.)
460 North Gulph Road, King of Prussia, PA 19406
(Address of Principal Executive Offices) (Zip Code)
(610) 337-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, without par value
Name of each Exchange
on Which Registered
New York Stock Exchange, Inc.
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
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
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
No
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 such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company,
or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging
growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Smaller reporting company
Accelerated filer
Emerging growth company
Non-accelerated filer
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with
any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
No
The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant on March 31, 2018 was $7,648,020,563.
At November 13, 2018, there were 173,846,575 shares of UGI Corporation Common Stock issued and outstanding.
Portions of the Proxy Statement for the Annual Meeting of Shareholders to be held on January 30, 2019 are incorporated by reference into Part III
of this Form 10-K.
TABLE OF CONTENTS
Forward-Looking Information
PART I:
Items 1. and 2. Business and Properties
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
PART II:
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III:
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions and Director Independence
Item 14. Principal Accounting Fees and Services
PART IV:
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Signatures
Index to Financial Statements and Financial Statement Schedules
Page
2
2
20
28
28
28
29
31
34
67
67
67
67
67
68
68
68
68
68
71
81
83
F-2
1
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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange
Act”). Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,”
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
our Risk Factors included in Item 1A herein and the following important factors that could affect our future results and could cause
those results to differ materially from those expressed in our forward-looking statements: (1) weather conditions resulting in
reduced demand; (2) cost volatility and availability of propane and other liquefied petroleum gases (“LPG”), electricity, and natural
gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including
safety, tax, consumer protection, environmental, 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) failure to acquire new customers or retain current customers thereby reducing or limiting any increase in
revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and
improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) customer,
counterparty, supplier, or vendor defaults; (12) liability for uninsured claims and for claims in excess of insurance coverage,
including those for personal injury and property damage arising from explosions, terrorism, natural disasters and other catastrophic
events that may result from operating hazards and risks incidental to generating and distributing electricity and transporting, storing
and distributing natural gas and LPG; (13) transmission or distribution system service interruptions; (14) political, regulatory and
economic conditions in the United States, Europe and other foreign countries, including the current conflicts in the Middle East,
and foreign currency exchange rate fluctuations, particularly the euro; (15) capital market conditions, including reduced access
to capital markets and interest rate fluctuations; (16) changes in commodity market prices resulting in significantly higher cash
collateral requirements; (17) reduced distributions from subsidiaries impacting the ability to pay dividends; (18) changes in
Marcellus Shale gas production; (19) the availability, timing and success of our acquisitions, commercial initiatives and investments
to grow our businesses; (20) our ability to successfully integrate acquired businesses and achieve anticipated synergies; (21) the
interruption, disruption, failure or malfunction of our information technology systems, including due to cyber attack; and (22)
continued analysis of recent tax legislation.
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
CORPORATE OVERVIEW
UGI Corporation (the “Company”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports
and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner
interests in a retail propane marketing and distribution business, (2) own and operate natural gas and electric distribution utilities,
and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production,
electricity generation and energy services business. Internationally, we distribute LPG and market other energy products and
services in Europe. Our subsidiaries and affiliates operate principally in the following four business segments:
• AmeriGas Propane
• UGI International
• Midstream & Marketing
• UGI Utilities
2
The AmeriGas Propane segment consists of the propane distribution business of AmeriGas Partners, L.P. (“AmeriGas Partners”
or the “Partnership”). In addition to distributing propane, the Partnership also sells, installs, and services propane appliances,
including heating systems. The Partnership conducts its propane distribution business through its principal operating subsidiary,
AmeriGas Propane, L.P., and is the nation’s largest retail propane distributor. The Partnership’s sole general partner is our subsidiary,
AmeriGas Propane, Inc. (“AmeriGas Propane” or the “General Partner”). The common units of AmeriGas Partners represent
limited partner interests in a Delaware limited partnership and trade on the New York Stock Exchange under the symbol “APU.”
We have an effective 26% ownership interest in the Partnership and the remaining interest is publicly held. See Note 1 to
Consolidated Financial Statements.
The UGI International segment consists of LPG distribution businesses conducted by our subsidiaries and affiliates in France,
Poland, Austria, Hungary, the Czech Republic, Slovakia, Switzerland, Romania, Belgium, the Netherlands, Luxembourg, the
United Kingdom, Italy, Finland, Denmark, Norway and Sweden. In addition, UGI International conducts an energy marketing
business in France, Belgium, the Netherlands and the United Kingdom. Based on volumes distributed, UGI International believes
that it is the largest distributor of LPG in France, Austria, Belgium, Denmark, Luxembourg and Hungary and one of the largest
distributors of LPG in Poland, the Czech Republic, Slovakia, Norway, the Netherlands and Sweden. These businesses are conducted
principally through our subsidiaries, UGI France SAS, Flaga GmbH, AvantiGas Limited, UniverGas Italia S.r.l. (“UniverGas”)
and DVEP Investeringen B.V. (“DVEP”).
The Midstream & Marketing segment consists of energy-related businesses conducted by our wholly-owned subsidiary, UGI
Energy Services, LLC (“Energy Services”), a subsidiary of UGI Enterprises, LLC (“Enterprises”). These businesses (i) conduct
energy marketing in the Mid-Atlantic region of the United States, (ii) operate and own natural gas liquefaction, storage and
vaporization facilities and propane-air mixing assets, (iii) manage natural gas pipeline and storage contracts, and (iv) develop,
own and operate pipelines, gathering infrastructure and gas storage facilities primarily in the Marcellus Shale region of Pennsylvania
and own all or portions of electricity generation facilities. The Midstream & Marketing segment also includes a subsidiary of
Enterprises that conducts a heating, ventilation, air conditioning, refrigeration, mechanical and electrical contracting, and project
management service business in portions of eastern and central Pennsylvania.
The UGI Utilities segment consists of the regulated natural gas distribution businesses (“Gas Utility”) of our subsidiary, UGI
Utilities, Inc. (“UGI Utilities”), and prior to their merger with and into UGI Utilities effective October 1, 2018 (the “Utilities
Merger”), UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). The UGI Utilities segment also consists
of UGI Utilities’ regulated electric distribution business in Pennsylvania (“Electric Utility”). Gas Utility serves more than 642,000
customers in eastern and central Pennsylvania and more than 500 customers in portions of one Maryland county. UGI Utilities’
natural gas distribution utility is referred to as “UGI Gas.” Electric Utility serves approximately 62,000 customers in portions of
Luzerne and Wyoming counties in northeastern Pennsylvania. Gas Utility is regulated by the Pennsylvania Public Utility
Commission (“PAPUC”) and, with respect to its several hundred customers in Maryland, the Maryland Public Service Commission
(“MDPSC”). Electric Utility is regulated by the PAPUC.
Business Strategy
Our business strategy is to grow the Company by focusing on our core competencies of distributing, storing, transporting and
marketing energy products and services. We are utilizing our core competencies from our existing businesses and our national
scope, international experience, extensive asset base and access to customers to accelerate both internal growth and growth through
acquisitions in our existing businesses, as well as in related and complementary businesses. During Fiscal 2018, we completed a
number of transactions in pursuit of this strategy and made progress on larger internally generated capital projects, including
infrastructure projects to further support the development of natural gas in the Marcellus Shale region of Pennsylvania. A few of
these transactions and projects are described below.
In October 2017, our Midstream & Marketing business enhanced its natural gas infrastructure assets with the acquisition of
approximately 60 miles of natural gas gathering lines in northern Pennsylvania, and in March 2018, it acquired an additional 3.6
miles of natural gas gathering lines in Clinton County, Pennsylvania. Also, in Fiscal 2018, Energy Services placed the Steelton
LNG peak shaving facility into service, which is designed to provide 65,000 dekatherms per day of peaking capacity and two
million gallons of LNG storage.
In addition, Energy Services made progress on the PennEast Pipeline project, the development of an approximately 120-mile
pipeline from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey. Energy Services owns a
20% interest in the PennEast Pipeline project and serves as the project manager. When completed, the PennEast Pipeline will
transport approximately 1 billion cubic feet of low cost natural gas to residential and commercial customers each day. In January
2018, the Federal Energy Regulatory Commission (“FERC”) issued a Certificate of Public Convenience and Necessity for the
PennEast Pipeline project.
3
In Fiscal 2018, UGI International expanded its LPG distribution business into Italy through the acquisition of Totalgaz Italia S.r.l.
(now known as UniverGas). UniverGas serves customers in the northern and central regions of Italy. In addition, UGI International
completed the integration of Finagaz, a May 2015 acquisition that nearly doubled our LPG distribution business in France.
UGI Utilities continued to execute on its infrastructure replacement and system betterment program, with record capital
expenditures in Fiscal 2018. For example, UGI Utilities made progress toward its goal of replacing the cast iron portions of its
gas mains by March 2027 and the bare steel portion of its gas mains by September 2041. Effective October 20, 2017, new base
rates went into effect for PNG resulting in an approximate $11.3 million increase in annual base rate revenues. In addition, in
January 2018, Electric Utility filed a request with the PAPUC to increase its base operating revenues for residential, commercial,
and industrial customers and, on October 25, 2018, the PAPUC issued a final order permitting Electric Utility to make a tariff
filing to increase its annual base distribution rates by $3.2 million, effective October 27, 2018.
Corporate Information
UGI Corporation was incorporated in Pennsylvania in 1991. The Company is not subject to regulation by the PAPUC and it is a
“holding company” under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing
regulations of the FERC give FERC access to certain holding company books and records and impose certain accounting, record-
keeping, and reporting requirements on holding companies. PUHCA 2005 also provides state utility regulatory commissions with
access to holding company books and records in certain circumstances. Pursuant to a waiver granted in accordance with FERC’s
regulations on the basis of UGI Corporation’s status as a single-state holding company system, UGI Corporation is not subject to
certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations.
Our executive offices are located at 460 North Gulph Road, King of Prussia, Pennsylvania 19406, and our telephone number is
(610) 337-1000. In this report, the terms “Company” and “UGI,” as well as the terms “our,” “we,” “us,” and “its,” are sometimes
used as abbreviated references to UGI Corporation or, collectively, UGI Corporation and its consolidated subsidiaries. Similarly,
the terms “AmeriGas Partners” and the “Partnership” are sometimes used as abbreviated references to AmeriGas Partners, L.P.
or, collectively, AmeriGas Partners, L.P. and its subsidiaries, and the term “UGI Utilities” is sometimes used as an abbreviated
reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries. The terms “Fiscal 2019,” “Fiscal 2018,”
“Fiscal 2017” and “Fiscal 2016” refer to the fiscal years ended September 30, 2019, September 30, 2018, September 30, 2017,
and September 30, 2016, respectively.
The Company’s corporate website can be found at www.ugicorp.com. Information on our website is not intended to be incorporated
into this report. The Company makes available free of charge at this website (under the “Investor Relations - Financial Reports
- SEC Filings and Proxy” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act,
including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q and its Current Reports on Form 8-K. The
Company’s Principles of Corporate Governance, Code of Ethics for the Chief Executive Officer and Senior Financial Officers
and Code of Business Conduct and Ethics for Directors, Officers and Employees are available on the Company’s website under
the caption “Investor Relations - Corporate Governance.” The Company’s charters of the Corporate Governance, Audit,
Compensation and Management Development, and Safety, Environmental and Regulatory Compliance Committees of the Board
of Directors are available on the Company’s website under the caption “Investor Relations - Corporate Governance - Committees.”
All of these documents are also available free of charge by writing to Treasurer, UGI Corporation, P.O. Box 858, Valley Forge,
PA 19482.
4
Products, Services and Marketing
AMERIGAS PROPANE
Our domestic propane distribution business is conducted through AmeriGas Partners. AmeriGas Propane is responsible for
managing the Partnership. The Partnership serves over 1.7 million customers in all 50 states from approximately 1,900 propane
distribution locations. In addition to distributing propane, the Partnership also sells, installs and services propane appliances,
including heating systems and propane-powered generators. Typically, the Partnership’s propane distribution locations are in
suburban and rural areas where natural gas is not readily available. Our local offices generally consist of a business office and
propane storage. As part of its overall transportation and distribution infrastructure, the Partnership operates as an interstate carrier
in all states throughout the continental U.S.
The Partnership sells propane primarily to residential, commercial/industrial, motor fuel, agricultural and wholesale customers.
The Partnership distributed over 1.1 billion gallons of propane in Fiscal 2018. Approximately 95% of the Partnership’s Fiscal
2018 sales (based on gallons sold) were to retail accounts and approximately 5% were to wholesale and supply customers. Sales
to residential customers in Fiscal 2018 represented approximately 36% of retail gallons sold; commercial/industrial customers
38%; motor fuel customers 18%; and agricultural customers 4%. Transport gallons, which are large-scale deliveries to retail
customers other than residential, accounted for 4% of Fiscal 2018 retail gallons. No single customer represents, or is anticipated
to represent, more than 5% of the Partnership’s consolidated revenues.
The Partnership continues to expand its AmeriGas Cylinder Exchange (“ACE”) program. At September 30, 2018, ACE cylinders
were available at over 59,000 retail locations throughout the U.S. Sales of our ACE cylinders to retailers are included in commercial/
industrial sales. The ACE program enables consumers to purchase or exchange propane cylinders at various retail locations such
as home centers, gas stations, mass merchandisers and grocery and convenience stores. In addition, in Fiscal 2018, the ACE
program continued to roll-out its 24/7 automated self-serve vending machines, enabling customers to purchase and exchange ACE
cylinders at various retail locations at any time of day. We also supply retailers with large propane tanks to enable retailers to
replenish customers’ propane cylinders directly at the retailer’s location.
Residential and commercial customers use propane primarily for home heating, water heating and cooking purposes. Commercial
users include hotels, restaurants, churches, warehouses, and retail stores. Industrial customers use propane to fire furnaces, as a
cutting gas and in other process applications. Other industrial customers are large-scale heating accounts and local gas utility
customers who use propane as a supplemental fuel to meet peak load deliverability requirements. As a motor fuel, propane is
burned in internal combustion engines that power school buses and other over-the-road vehicles, forklifts, and stationary engines.
Agricultural uses include tobacco curing, chicken brooding, crop drying, and orchard heating. In its wholesale operations, the
Partnership principally sells propane to large industrial end-users and other propane distributors.
Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the
bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer’s premises.
The Partnership owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from
approximately 120 gallons to approximately 1,200 gallons. The Partnership also delivers propane in portable cylinders, including
ACE and motor fuel cylinders. Some of these deliveries are made to the customer’s location, where cylinders are either picked
up or replenished in place.
During Fiscal 2018, we continued to make significant investments in technology to reduce operational costs while improving our
customers’ experience. For example, (i) following the successful implementation of the AmeriMobile distribution platform to all
district locations to more efficiently deploy our drivers in making deliveries to customers, we began to roll out the platform to our
service technicians for service scheduling, job routing, and billing, and (ii) we continue to promote a customer service culture
through enhancements to our on-line customer experience, enabling customers to transact with us after hours, to sign up as a new
customer and to seek customer support through live on-line chat.
Propane Supply and Storage
The United States propane market has over 250 domestic and international sources of supply, including the spot market. Supplies
of propane from the Partnership’s sources historically have been readily available. Volatility in the U.S. propane market stabilized
in Fiscal 2017, following record high levels reached in Fiscal 2016 and the fiscal year ended September 30, 2015, and the propane
industry continued to experience normal inventory levels in Fiscal 2018. The availability and pricing of propane supply is dependent
upon, among other things, the severity of winter weather, the price and availability of competing fuels such as natural gas and
crude oil, and the amount and availability of exported supply and, to a much lesser extent, imported supply. In recent years, there
has been an increase in overseas demand for U.S. propane exports as the U.S. continues to have low cost reliable sources of
5
propane. We utilized our extensive distribution and logistics channels to minimize disruption to our customers due to supply chain
interruptions resulting from severe cold weather events in January 2018 as well as the delay of critical supply imports into the
New England area.
During Fiscal 2018, approximately 98% of the Partnership’s propane supply was purchased under supply agreements with terms
of one to three years. Although no assurance can be given that supplies of propane will be readily available in the future, management
currently expects to be able to secure adequate supplies during Fiscal 2019. If supply from major sources were interrupted,
however, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially
higher and, at least on a short-term basis, margins could be adversely affected. Plains Marketing, L.P. supplied approximately
18% of the Partnership’s Fiscal 2018 propane supply. No other single supplier provided more than 10% of the Partnership’s total
propane supply in Fiscal 2018. In certain geographic areas, however, a single supplier provides more than 50% of the Partnership’s
requirements. Disruptions in supply in these areas could also have an adverse impact on the Partnership’s margins.
The Partnership’s supply contracts typically provide for pricing based upon (i) index formulas using the current prices established
at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas, or (ii) posted prices at the time of delivery. In addition,
some agreements provide maximum and minimum seasonal purchase volume guidelines. The percentage of contract purchases,
and the amount of supply contracted for at fixed prices, will vary from year to year as determined by the General Partner. The
Partnership uses a number of interstate pipelines, as well as railroad tank cars, delivery trucks and barges, to transport propane
from suppliers to storage and distribution facilities. The Partnership stores propane at various storage facilities and terminals
located in strategic areas across the U.S.
Because the Partnership’s profitability is sensitive to changes in wholesale propane costs, the Partnership generally seeks to pass
on increases in the cost of propane to customers. There is no assurance, however, that the Partnership will always be able to pass
on product cost increases fully, or keep pace with such increases, particularly when product costs rise rapidly. Product cost increases
can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude
oil and natural gas, or other unforeseen events. The General Partner has adopted supply acquisition and product cost risk
management practices to reduce the effect of volatility on selling prices. These practices currently include the use of summer
storage, forward purchases and derivative commodity instruments, such as propane price swaps. See “Management’s Discussion
and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures.”
The following graph shows the average prices of propane on the propane spot market during the last five fiscal years at Mont
Belvieu, Texas, and Conway, Kansas, both major storage areas.
Average Propane Spot Market Prices
General Industry Information
Propane is separated from crude oil during the refining process and also extracted from natural gas or oil wellhead gas at processing
plants. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for economy and ease
of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable
gas. Propane is colorless and odorless; an odorant is added to allow for its detection. Propane is considered a clean alternative
6
fuel under the Clean Air Act Amendments of 1990, producing negligible amounts of pollutants when properly consumed.
Competition
Propane competes with other sources of energy, some of which are less costly for equivalent energy value. Propane distributors
compete for customers with suppliers of electricity, fuel oil and natural gas, principally on the basis of price, service, availability
and portability. Electricity is generally more expensive than propane on a British thermal unit (“Btu”) equivalent basis, but the
convenience and efficiency of electricity make it an attractive energy source for consumers and developers of new homes. Fuel
oil is also a major competitor of propane but is currently more expensive than propane as well as a less environmentally attractive
energy source. Historically, however, fuel oil has been less expensive than propane. Furnaces and appliances that burn propane
will not operate on fuel oil, and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new
equipment. Propane serves as an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability
of product is required. Natural gas is generally a significantly less expensive source of energy than propane, although in areas
where natural gas is available, propane is used for certain industrial and commercial applications and as a standby fuel during
interruptions in natural gas service. The gradual expansion of the nation’s natural gas distribution systems has resulted in the
availability of natural gas in some areas that previously depended upon propane. However, natural gas pipelines are not present
in many areas of the country where propane is sold for heating and cooking purposes.
For motor fuel customers, propane competes with gasoline, diesel fuel, electric batteries, fuel cells and, in certain applications,
LNG and compressed natural gas. Wholesale propane distribution is a highly competitive, low margin business. Propane sales
to other retail distributors and large-volume, direct-shipment industrial end-users are price sensitive and frequently involve a
competitive bidding process.
Retail propane industry volumes have been declining for several years and no or modest growth in total demand is foreseen in the
next several years. Therefore, the Partnership’s ability to grow within the industry is dependent on its ability to acquire other retail
distributors and to achieve internal growth, which includes expansion of the ACE program and the National Accounts program
(through which the Partnership encourages multi-location propane users to enter into a single AmeriGas Propane supply agreement
rather than agreements with multiple suppliers), as well as the success of its sales and marketing programs designed to attract and
retain customers. The failure of the Partnership to retain and grow its customer base would have an adverse effect on its long-
term results.
The domestic propane retail distribution business is highly competitive. The Partnership competes in this business with other
large propane marketers, including other full-service marketers, and thousands of small independent operators. Some farm
cooperatives, rural electric cooperatives and fuel oil distributors include propane distribution in their businesses and the Partnership
competes with them as well. The ability to compete effectively depends on providing high quality customer service, maintaining
competitive retail prices and controlling operating expenses. The Partnership also offers customers various payment and service
options, including guaranteed price programs, fixed price arrangements and pricing arrangements based on published propane
prices at specified terminals.
In Fiscal 2018, the Partnership’s retail propane sales totaled more than 1.0 billion gallons. Based on the most recent annual survey
by the American Petroleum Institute, 2016 domestic retail propane sales (annual sales for other than chemical uses) in the U.S.
totaled approximately 8.2 billion gallons. Based on LP-GAS magazine rankings, 2016 sales volume of the ten largest propane
distribution companies (including AmeriGas Partners) represented approximately 36% of domestic retail sales.
Properties
As of September 30, 2018, the Partnership owned approximately 80% of its nearly 640 local offices throughout the country. The
transportation of propane requires specialized equipment. The trucks and railroad tank cars utilized for this purpose carry specialized
steel tanks that maintain the propane in a liquefied state. As of September 30, 2018, the Partnership operated a transportation fleet
with the following assets:
920
350
510
3,000
400
3,700
Approximate Quantity & Equipment Type
Trailers
Tractors
Railroad tank cars
Bobtail trucks
Rack trucks
Service and delivery trucks
7
% Owned
75%
4%
0%
26%
29%
35%
% Leased
25%
96%
100%
74%
71%
65%
Other assets owned at September 30, 2018 included approximately 1 million stationary storage tanks with typical capacities of
more than 120 gallons, approximately 4.2 million portable propane cylinders with typical capacities of 1 to 120 gallons, 22 terminals
and 12 transflow units.
Trade Names, Trade and Service Marks
The Partnership markets propane and other services principally under the “AmeriGas®,” “America’s Propane Company®,”
“Driving Every DaySM” “Heritage Propane®,” and “Relationships Matter®,” trade names and related service marks. The
Partnership also markets propane under various other trade names throughout the United States. UGI owns, directly or indirectly,
all the right, title and interest in the “AmeriGas” name and related trade and service marks. The General Partner owns all right,
title and interest in the “America’s Propane Company” trade name and related service marks. The Partnership has an exclusive
(except for use by UGI, AmeriGas, Inc., AmeriGas Polska Sp. z.o.o. and the General Partner), royalty-free license to use these
trade names and related service marks. UGI and the General Partner each have the option to terminate its respective license
agreement (except its licenses with permitted transferees and on 12 months prior notice in the case of UGI), without penalty, if
the General Partner is removed as general partner of the Partnership for cause. If the General Partner ceases to serve as the general
partner of the Partnership other than for cause, the General Partner has the option to terminate its license agreement upon payment
of a fee to AmeriGas Propane, L.P. equal to the fair market value of the licensed trade names. UGI has a similar termination option;
however, UGI must provide 12 months’ prior notice in addition to paying the fee to AmeriGas Propane, L.P. UGI and the General
Partner each also have the right to terminate its respective license agreement in order to settle any claim of infringement, unfair
competition or similar claim or if the agreement has been materially breached without appropriate cure.
Seasonality
Because many customers use propane for heating purposes, the Partnership’s retail sales volume is seasonal. During Fiscal 2018,
approximately 65% of the Partnership’s retail sales volume occurred, and substantially all of the Partnership’s operating income
was earned, during the peak heating season from October through March. As a result of this seasonality, sales are typically higher
in the Partnership’s first and second fiscal quarters (October 1 through March 31). Cash receipts are generally greatest during the
second and third fiscal quarters when customers pay for propane purchased during the winter heating season.
Sales volume for the Partnership traditionally fluctuates from year-to-year in response to variations in weather, prices, competition,
customer mix and other factors, such as conservation efforts and general economic conditions. For information on national weather
statistics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
The Partnership is subject to various federal, state and local environmental, health, safety and transportation laws and regulations
governing the storage, distribution and transportation of propane and the operation of bulk storage propane terminals.
Environmental
Generally, the applicable environmental laws impose limitations on the discharge of pollutants, establish standards for the handling
of solid and hazardous substances, and require the investigation and cleanup of environmental contamination. These laws include,
among others, the federal Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation
and Liability Act (“CERCLA” or the “Superfund Law”), the Clean Air Act, the Clean Water Act, the Homeland Security Act of
2002, the Emergency Planning and Community Right-to-Know Act, comparable state statutes and any applicable amendments.
The Partnership incurs expenses associated with compliance with its obligations under federal and state environmental laws and
regulations, and we believe that the Partnership is in material compliance with all of its obligations. The Partnership maintains
various permits that are necessary to operate its facilities, some of which may be material to its operations. The Partnership
continually monitors its operations with respect to potential environmental issues, including changes in legal requirements.
The Partnership is investigating and remediating contamination at a number of present and former operating sites in the United
States, including sites where its, predecessor entities operated manufactured gas plants. CERCLA and similar state laws impose
joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a
“hazardous substance” into the environment without regard to fault or the legality of the original conduct. Propane is not a hazardous
substance within the meaning of CERCLA.
8
Health and Safety
The Partnership is subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and
safety of our workers. These laws require the Partnership, among other things, to maintain information about materials, some of
which may be hazardous or toxic, that are used, released, or produced in the course of our operations. Certain portions of this
information must be provided to employees, federal and state and local governmental authorities and responders, commercial and
industrial customers and local citizens in accordance with applicable federal and state Emergency Planning and Community Right-
to-Know Act requirements. The Partnership’s operations are also subject to the safety hazard communication requirements and
reporting obligations set forth in federal workplace standards.
All states in which the Partnership operates have adopted fire safety codes that regulate the storage, distribution, and use of propane.
In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. The
Partnership conducts training programs to help ensure that its operations are in compliance with applicable governmental
regulations. With respect to general operations, the Partnership is subject in all jurisdictions in which it operates to rules and
procedures governing the safe handling of propane, including those established by National Fire Protection Association Pamphlets
No. 54 and No. 58, various state, local and international codes (including international fire, building and fuel gas codes), and
OSHA fall protection standards. Management believes that the policies and procedures currently in effect at all of its facilities
for the handling, storage, distribution and use of propane, as well as its fall protection standards, are consistent with industry
standards and are in compliance, in all material respects, with applicable laws and regulations.
With respect to the transportation of propane by truck, the Partnership is subject to regulations promulgated under federal legislation,
including the Federal Motor Carrier Safety Act, the Hazardous Materials & Transportation Act and the Homeland Security Act of
2002. Regulations under these statutes cover the security and transportation of hazardous materials, including propane for purposes
of these regulations, and are administered by the Pipeline and Hazardous Materials Safety Administration of the U.S. Department
of Transportation (“DOT”). The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety
regulations for the transportation of gases by pipeline. The DOT's pipeline safety regulations apply, among other things, to a
propane gas system that supplies 10 or more residential customers or two or more commercial customers from a single source and
to a propane gas system any portion of which is located in a public place. The DOT’s pipeline safety regulations require operators
of all gas systems to provide operator qualification standards and training and written instructions for employees and third party
contractors working on covered pipelines and facilities, establish written procedures to minimize the hazards resulting from gas
pipeline emergencies, and conduct and keep records of inspections and testing. Operators are subject to the Pipeline Safety
Improvement Act of 2002. Management believes that the procedures currently in effect at all of the Partnership’s facilities for the
handling, storage, transportation and distribution of propane are consistent with industry standards and are in compliance, in all
material respects, with applicable laws and regulations.
Climate Change
There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas
(“GHG”) emissions, most notably carbon dioxide, to global warming. Because propane is considered a clean alternative fuel under
the federal Clean Air Act Amendments of 1990, the Partnership anticipates that this will provide it with a competitive advantage
over other sources of energy, such as fuel oil and coal, to the extent new climate change regulations become effective. At the same
time, increased regulation of GHG emissions, especially in the transportation sector, could impose significant additional costs on
the Partnership, its suppliers and its customers. In recent years, there has been an increase in state initiatives aimed at regulating
GHG emissions. For example, the California Environmental Protection Agency established a Cap & Trade program that requires
certain covered entities, including propane distribution companies, to purchase allowances to compensate for the GHG emissions
created by their business operations. Compliance with these types of regulations may increase our operating costs if we are unable
to pass these costs to our customers.
Employees
The Partnership does not directly employ any persons responsible for managing or operating the Partnership. The General Partner
provides these services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit
costs. At September 30, 2018, the General Partner had approximately 7,700 employees, including over 250 part-time, seasonal
and temporary employees, working on behalf of the Partnership. UGI also performs certain financial and administrative services
for the General Partner on behalf of the Partnership and is reimbursed by the Partnership.
9
UGI INTERNATIONAL
UGI International, through subsidiaries and affiliates, conducts (i) an LPG distribution business in 17 countries throughout Europe
(France, Poland, Austria, Hungary, the Czech Republic, Slovakia, Switzerland, Romania, Belgium, the Netherlands, Luxembourg,
the United Kingdom, Italy, Finland, Denmark, Norway and Sweden), and (ii) an energy marketing business in France, Belgium,
the Netherlands and the United Kingdom. Based on Fiscal 2018 volumes, UGI International believes that it is the largest distributor
of LPG in France, Austria, Belgium, Denmark, Luxembourg and Hungary and one of the largest distributors of LPG in Poland,
the Czech Republic, Slovakia, Norway, the Netherlands and Sweden.
Products, Services and Marketing
LPG Distribution Business
During Fiscal 2018, UGI International sold approximately 1 billion gallons of LPG throughout Europe. UGI International operates
under seven distinct LPG brands, and its customer base primarily consists of residential, commercial, industrial, agricultural,
wholesale and automobile fuel (‘‘autogas’’) customers that use LPG for space heating, cooking, water heating, motor fuel, leisure
activities, crop drying, irrigation, construction, power generation, manufacturing and as an aerosol propellant. For Fiscal 2018,
approximately 38% of UGI International’s LPG volume was sold to commercial and industrial customers, approximately 24%
was sold to residential, approximately 8% was sold to agricultural and approximately 30% was sold to wholesale and other
customers (including autogas). UGI International supplies LPG to its customers in small, medium and large bulk tanks at their
locations. In addition to bulk sales, UGI International sells LPG in cylinders through retail outlets, such as supermarkets, individually
owned stores and gas stations. Sales of LPG are also made to service stations to fuel vehicles that run on LPG. Approximately
62% of Fiscal 2018 LPG sales (based on volumes) were attributed to bulk, 17% to cylinder, 13% to wholesale and 8% to autogas.
For Fiscal 2018, no single customer represented more than 5% of UGI International’s revenues.
Bulk
UGI International classifies its bulk customers as small, medium or large bulk, depending on tank size at the customer locations.
Small bulk customers are primarily residential and small business users such as restaurants that use LPG mainly for heating and
cooking. Medium bulk customers consist mainly of large residential housing developments, hospitals, hotels, municipalities,
medium-sized industrial enterprises and poultry brooders. Large bulk customers include agricultural customers (including crop
drying) and companies that use LPG in their industrial processes. At September 30, 2018, UGI International had over 550,000
bulk LPG customers and sold approximately 627 million gallons of bulk LPG during Fiscal 2018.
Cylinder
UGI International sells LPG in both steel and composite cylinders and typically owns the cylinders in which the LPG is sold. The
principal end-users of cylinders are residential customers who use LPG for domestic applications, such as cooking and heating.
Non-residential uses include fuel for forklift trucks, road construction and welding. At September 30, 2018, UGI International had
approximately 19 million cylinders in circulation and sold approximately 170 million gallons of LPG in cylinders during Fiscal
2018. UGI International also delivers LPG to wholesale and retail customers in cylinders, including through the use of vending
machines.
Wholesale, Autogas and Other Services
Approximately 13% of UGI International’s Fiscal 2018 LPG sales were to wholesale customers (including small competitors,
large industrial customers and aerosol customers), and approximately 8% of Fiscal 2018 LPG sales were to autogas customers.
UGI International also provides logistics, storage and other services to third-party LPG distributors.
Energy Marketing Business
UGI International markets and supplies natural gas and electricity to small and medium enterprises, schools and municipalities
through third party distribution systems. UGI International started developing its energy marketing business organically in 2012
and completed the acquisition of DVEP in the Netherlands in August 2017. UGI International sold approximately 28 billion cubic
feet of natural gas and 3,850 gigawatt hours of electricity during Fiscal 2018.
LPG Supply, Storage and Transportation
In Fiscal 2017, UGI International centralized its European supply function. UGI International is typically party to term contracts,
with approximately 50 different suppliers, including producers and international oil and gas trading companies, to meet LPG
supply requirements throughout Europe. LPG supply is transported via rail and sea, and by road for shorter distances. Agreements
are generally one- to two-year term agreements with pricing based on internationally quoted market prices. Additionally, LPG is
10
purchased on the domestic spot markets to manage supply needs. In certain geographic areas (the United Kingdom and Italy), a
single supplier may provide approximately 50% or more of UGI International’s requirements. Because UGI International’s
profitability is sensitive to changes in wholesale LPG costs, UGI International generally seeks to pass on increases in the cost of
LPG to its customers. There can be no assurance, however, that UGI International will always be able to pass on product cost
increases fully, or keep pace with such increases, particularly when product costs rise rapidly. Product cost increases can be
triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil
and natural gas, or other unforeseen events.
UGI International stores LPG at various storage facilities and terminals located across Europe and has interests in 10 primary
storage facilities and over 70 secondary storage facilities. LPG stored in primary storage facilities is transported to smaller storage
facilities by rail and road. At secondary storage facilities, LPG is loaded into cylinders or trucks equipped with tanks and then
delivered to customers. UGI International also manages an extensive logistics and transportation network and has access to
seaborne import facilities.
UGI International transports LPG to customers primarily through outsourced transportation providers to serve both bulk and
cylinder markets. UGI International has long-term relationships with many providers of logistics and transportation services in
most of its markets and is not dependent on the services of any single transportation provider.
Competition and Seasonality
The LPG markets in western and northern Europe are mature, with modest declines in total demand due to competition with other
fossil fuels and other energy sources, conservation and macroeconomic conditions. In the Eastern European countries in which
UGI International operates, the demand for LPG is expected to grow in certain segments. Sales volumes are affected principally
by the severity of the weather and customer migration to alternative energy forms, including natural gas, electricity, heating oil
and wood. High LPG prices also may result in slower than expected growth due to customer conservation and customers seeking
less expensive alternative energy sources. In addition, government policies and incentives that favor alternative energy sources,
such as wind and solar, can result in customers migrating to energy sources other than LPG. In addition to price, UGI International
competes for customers in its various markets based on contract terms. UGI International competes locally as well as regionally
in many of its service territories. Additionally, particularly in France, although UGI International supplies certain supermarket
chains, it also competes with some of these supermarket chains that affiliate with LPG distributors to offer their own brands of
cylinders. UGI International seeks to increase demand for its LPG cylinders through marketing and product innovations.
In its energy marketing business, UGI International competes against small- and medium-sized enterprise providers of natural gas
and electricity in four countries in Europe where the markets have been deregulated for at least ten years. The markets are generally
stable, developed and growing and competition can be local, regional or pan-European.
Because many of UGI International’s customers use LPG for heating, sales volume is affected principally by the severity of the
temperatures during the heating season months and traditionally fluctuates from year-to-year in response to variations in weather,
prices and other factors, such as conservation efforts and the economic environment. Demand for LPG is higher during the colder
months of the year. For historical information on weather statistics for UGI International, see ‘‘Management’s Discussion and
Analysis of Financial Condition and Results of Operations.’’
Government Regulation
UGI International’s business is subject to various laws and regulations at the country and local levels, as well as at the European
Union (‘‘EU’’) level, with respect to matters such as protection of the environment, the storage, transportation and handling of
hazardous materials and flammable substances (including the Seveso II Directive), regulations specific to bulk tanks, cylinders
and pipe networks, competition, pricing, regulation of contract terms, anti-corruption (including the U.S. Foreign Corrupt Practices
Act, Sapin II and the U.K. Bribery Act), data privacy and protection, and the safety of persons and property.
Environmental
Environmental laws and regulations may require expenditures over a long timeframe to control environmental effects. Estimates
of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect
their ultimate level. These factors include, but are not limited to, the following: (i) the complexity of the site; (ii) changes in
environmental laws and regulations; (iii) the number of regulatory agencies or other parties involved; (iv) new technology that
renders previous technology obsolete or experience with existing technology that proves ineffective; (v) the level of remediation
required; and (vi) variation between the estimated and actual period of time required to respond to an environmentally-contaminated
site.
11
Data Privacy
The EU adopted the General Data Protection Regulation (‘‘GDPR’’), which became effective in May of 2018. The GDPR expands
the current EU data protection laws to all companies processing data of EU residents. It primarily focuses on unifying and
strengthening the regulations dealing with the collection, processing, use and security of personal and sensitive data.
Properties
In addition to regional headquarter locations and sales offices throughout its service territory, UGI International has interests in
10 primary storage facilities and over 70 secondary storage facilities.
Employees
At September 30, 2018, UGI International had approximately 2,900 employees.
MIDSTREAM & MARKETING
Retail Energy Marketing
Our retail energy marketing business is conducted through Energy Services and sells natural gas, liquid fuels and electricity to
over 12,500 residential, commercial and industrial customers at approximately 35,500 locations. Energy Services serves customers
in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio, Maryland, Massachusetts, Virginia, North Carolina,
South Carolina, Rhode Island and the District of Columbia. Energy Services distributes natural gas through the use of the distribution
systems of 41 local gas utilities. It supplies power to customers through the use of the transmission lines of 20 utility systems.
Historically, a majority of Energy Services’ commodity sales have been made under fixed-price agreements, which typically
contain a take-or-pay arrangement that permits customers to purchase a fixed amount of product for a fixed price during a specified
period, and requires payment even if the customer does not take delivery of the product. However, a growing number of Energy
Services’ commodity sales are currently being made under requirements contracts, under which Energy Services is typically an
exclusive supplier and will supply as much product at a fixed price as the customer requires. Energy Services manages supply
cost volatility related to these agreements by (i) entering into fixed-price supply arrangements with a diverse group of suppliers,
(ii) holding its own interstate pipeline transportation and storage contracts to efficiently utilize gas supplies, (iii) entering into
exchange-traded futures contracts on the New York Mercantile Exchange (“NYMEX”) and Intercontinental Exchange (“ICE”),
(iv) entering into over-the-counter derivative arrangements with major international banks and major suppliers, (v) utilizing supply
assets that it owns or manages, and (vi) utilizing financial transmission rights to hedge price risk against certain transmission costs.
Energy Services also bears the risk for balancing and delivering natural gas and power to its customers under various gas pipeline
and utility company tariffs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations -
Market Risk Disclosures.”
Midstream Assets
Our Midstream assets, which are owned by Energy Services and its subsidiaries, comprise a natural gas liquefaction, storage and
vaporization facility in Temple, Pennsylvania, a liquefaction and storage facility in Mehoopany, Pennsylvania, and propane storage
and propane-air mixing stations in Bethlehem, Reading, Hunlock Creek, and White Deer, Pennsylvania. Energy Services and its
subsidiaries also operate propane storage, rail transshipment terminals and propane-air mixing stations in Steelton and Williamsport,
Pennsylvania. These assets are used in Midstream & Marketing’s energy peaking business that provides supplemental energy,
primarily LNG and propane-air mixtures, to gas utilities at times of high demand (generally during periods of coldest winter
weather). In addition, Energy Services sells LNG to customers for use by trucks, drilling rigs, other motor vehicles and facilities
located off the gas grid. Our Midstream & Marketing segment also manages natural gas pipeline and storage contracts for UGI
Utilities and Frontier Natural Gas.
In Fiscal 2018, our Midstream & Marketing segment continued making investments to expand its energy peaking and LNG fuels
business. Energy Services placed the Steelton LNG peak shaving facility into service in Fiscal 2018, which is designed to provide
65,000 dekatherms per day of peaking capacity and two million gallons of LNG storage. Energy Services also purchased portable
LNG peak shaving equipment, which includes skid mounted LNG vaporizers, storage and LNG transport trailers, designed to
provide up to 15,000 dekatherms per day of peaking. These units were deployed to sites near Mt. Carmel and Reading, Pennsylvania.
A wholly-owned subsidiary of Energy Services owns and operates underground natural gas storage and related high pressure
pipeline facilities, which have FERC approval to sell storage services at market-based rates. The storage facilities are located in
the Marcellus Shale region of north-central Pennsylvania and have a total storage capacity of 15 million dekatherms and a maximum
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daily withdrawal quantity of 224,000 dekatherms. In Fiscal 2018, Energy Services leased more than 85% of the firm capacity at
its underground natural gas facilities to third parties.
Energy Services also operates a gathering system in the Marcellus Shale region of northeastern Pennsylvania with a total system
capacity of 470,000 dekatherms per day, which will be expanded to a total system capacity of 620,000 dekatherms per day in late
2019. The gathering system delivers into both the Tennessee Gas and Transcontinental Gas pipelines. In Fiscal 2018, Energy
Services completed the acquisition of 60 miles of natural gas gathering lines, dehydration and compression facilities located in
Bradford, Tioga and Lycoming Counties, Pennsylvania, as well as 3.6 miles of natural gas gathering lines located in Clinton
County, Pennsylvania.
In Fiscal 2018, our Midstream & Marketing segment also made progress on its participation in the PennEast Pipeline project to
develop an approximately 120-mile pipeline from Luzerne County, Pennsylvania to the Transco pipeline interconnection in Mercer
County, New Jersey. When completed, the pipeline will transport approximately 1 billion cubic feet of low cost natural gas to
residential and commercial customers each day. In January 2018, FERC issued a Certificate of Public Convenience and Necessity
for the PennEast Pipeline project and we expect to commence construction on the project in late 2019.
Future planned investments are expected to cover a range of midstream asset opportunities, including interstate pipelines, local
gathering systems and gas storage facilities and complementary and related investments.
Electricity Generation Assets
Midstream & Marketing’s electricity generation assets consist of electric generation facilities conducted by Energy Services’
wholly-owned subsidiary, UGI Development Company (“UGID”). UGID has an approximate 5.97% (approximately 102
megawatt) ownership interest in the Conemaugh generation station (“Conemaugh”), a 1,711-megawatt, coal-fired electricity
generation station located near Johnstown, Pennsylvania. Conemaugh is owned by a consortium of energy companies and operated
by a unit of NRG Energy. UGID also owns and operates the Hunlock Station located near Wilkes-Barre, Pennsylvania, a 130-
megawatt natural gas-fueled electricity generating station, and owns and operates a landfill gas-fueled generation plant near Hegins,
Pennsylvania, with gross generating capacity of 11 megawatts. The plant qualifies for renewable energy credits. In Fiscal 2018,
UGID completed the acquisition of Hunlock Energy, LLC, a 44 megawatt natural gas-fired peaking turbine in Luzerne County,
Pennsylvania. This turbine is adjacent to UGID’s existing Hunlock generation facility and, accordingly, the operation, fuel supply
and dispatch activities for the turbine will be conducted by UGID. Additionally, UGID owns and operates 13.5 megawatts of solar-
powered generation capacity in Pennsylvania, Maryland and New Jersey.
HVAC Business
Our Midstream & Marketing segment also conducts a heating, ventilation, air conditioning, mechanical & electrical contracting,
and project management service business through its HVAC business unit, which serves portions of eastern and central
Pennsylvania. This business serves customers in residential, commercial, industrial and new construction markets.
Competition
Our Midstream & Marketing segment competes with other midstream operators to sell gathering, compression, storage and pipeline
transportation services. Our Midstream & Marketing segment competes in both the regulated and non-regulated environment
against interstate and intrastate pipelines that gather, compress, process, transport and market natural gas. Our Midstream &
Marketing segment sells midstream services primarily to producers, marketers and utilities on the basis of price, customer service,
flexibility, reliability and operational experience. The competition in the midstream segment is significant and has grown recently
in the northeast U.S. as more competitors seek opportunities offered by the development of the Marcellus and Utica Shales.
Our Midstream & Marketing segment also competes with other marketers, consultants and local utilities to sell natural gas, liquid
fuels, electric power and related services to customers in its service area principally on the basis of price, customer service and
reliability. Midstream & Marketing’s midstream asset business has faced an increase in competition in recent years with the
consolidation of companies that have resulted in large, national competitors that can offer a suite of services across all customer
segments.
Our electricity generation assets compete with other generation stations on the interface of PJM Interconnection, LLC (“PJM”),
a regional transmission organization that coordinates the movement of wholesale electricity in certain states, including the states
in which we operate, and bases sales on bid pricing. Generally, each power generator has a small share of the total market on
PJM.
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Government Regulation
FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy, as
well as the sales for resale of natural gas and related storage and transportation services. Energy Services has a tariff on file with
FERC pursuant to which it may make power sales to wholesale customers at market-based rates. Energy Services also has market-
based rate authority for power sales to wholesale customers, to the extent that Energy Services purchases power in excess of its
retail customer needs. Two subsidiaries of Energy Services currently operate natural gas storage facilities under FERC certificate
approvals and offer services to wholesale customers at FERC-approved market-based rates. Two other Energy Services subsidiaries
operate natural gas pipelines that are subject to FERC regulation. UGI Mt. Bethel Pipeline Company, LLC operates a 12.5-mile,
12-inch pipeline located in Northampton County, Pennsylvania, and UGI Sunbury, LLC operates the Sunbury Pipeline, a 35-mile,
20-inch diameter pipeline located in central Pennsylvania that was placed into service on January 1, 2017. Energy Services and
its subsidiaries undertake various activities to maintain compliance with the FERC Standards of Conduct with respect to pipeline
operations. Energy Services is also subject to FERC reporting requirements, market manipulation rules and other FERC enforcement
and regulatory powers with respect to its wholesale commodity business.
Midstream & Marketing’s midstream assets include natural gas gathering pipelines and compression in northeastern Pennsylvania
that are regulated under the Pipeline Safety Improvement Act of 2002 and subject to operational oversight by both the Pipeline
and Hazardous Materials Safety Administration and the PAPUC.
Certain of our Midstream & Marketing businesses are subject to various federal, state and local environmental, safety and
transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk
storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, CERCLA, the Clean
Air Act, OSHA, the Homeland Security Act of 2002, the Emergency Planning and Community Right-to-Know Act, the Clean
Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to
have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or
the legality of the original conduct. With respect to the operation of natural gas gathering and transportation pipelines, Energy
Services also is required to comply with the provisions of the Pipeline Safety Improvement Act of 2002 and the regulations of the
U.S. DOT.
Our Midstream & Marketing’s electricity generation assets own electric generation facilities that are within the control area of
PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM.
UGID receives certain revenues collected by PJM, determined under an approved rate schedule. Like Energy Services, UGID
has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates, and FERC
recently extended UGID’s market-based rate authority through 2019. UGID is also subject to FERC reporting requirements,
market manipulation rules and other FERC enforcement and regulatory powers.
Employees
At September 30, 2018, Midstream & Marketing had over 600 employees, including nearly 300 employees in its HVAC business
and approximately 20 employees at UGID.
GAS UTILITY
UGI UTILITIES
Gas Utility consists of the regulated natural gas distribution businesses of our subsidiary, UGI Utilities, which prior to October 1,
2018, was comprised of UGI Utilities and two separate, wholly owned natural gas distribution utility subsidiaries, PNG and CPG.
UGI Utilities, PNG and CPG have been consolidated by merger effective October 1, 2018, with UGI Utilities as the surviving
entity. Gas Utility serves more than 642,000 customers in eastern and central Pennsylvania and more than 500 customers in
portions of one Maryland county. Gas Utility is regulated by the PAPUC and, with respect to its customers in Maryland, the
MDPSC.
Service Area; Revenue Analysis
Gas Utility provides natural gas distribution services to more than 642,000 customers in certificated portions of 44 eastern and
central Pennsylvania counties through its distribution system. Contemporary materials, such as plastic or coated steel, comprise
approximately 90% of Gas Utility’s 12,300 miles of gas mains, with bare steel pipe comprising approximately 8% and cast iron
pipe comprising approximately 2% of Gas Utility’s gas mains. In accordance with Gas Utility’s agreement with the PAPUC, Gas
Utility will replace the cast iron portion of its gas mains by March 2027 and the bare steel portion of its gas mains by September
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2041. 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 Utility’s service area are major production centers for basic industries such as specialty
metals, aluminum, glass, paper product manufacturing, and several power generation facilities. Gas Utility also distributes natural
gas to more than 500 customers in portions of one Maryland county.
System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal
2018 was approximately 264 billion cubic feet (“bcf”). System sales of gas accounted for approximately 23% of system throughput,
while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for
approximately 77% of system throughput.
Sources of Supply and Pipeline Capacity
Gas Utility is permitted to recover prudently incurred costs of natural gas it sells to its customers. See “Management’s Discussion
and Analysis of Financial Condition and Results of Operations - Market Risk Disclosures” and Note 8 to Consolidated Financial
Statements. 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 Marcellus, Gulf Coast, Mid-Continent, and Appalachian sources. For its transportation and storage functions, Gas Utility
has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission, LP, Columbia Gas
Transmission, LLC, Transcontinental Gas Pipeline Company, LLC, Dominion Transmission, Inc., ANR Pipeline Company and
Tennessee Gas Pipeline Company, L.L.C.
Gas Supply Contracts
During Fiscal 2018, Gas Utility purchased approximately 92.8 bcf of natural gas for sale to retail core-market customers (principally
comprised of firm- residential, commercial and industrial customers that purchase their gas from Gas Utility (“retail core-market”))
and off-system sales customers. Nearly 94% of the volumes purchased were supplied under agreements with 10 suppliers. The
remaining 6% of gas purchased by Gas Utility was supplied by 10 producers and marketers. Gas supply contracts for Gas Utility
are generally no longer than 12 months. 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’s sales are seasonal. For Fiscal 2018, approximately 59%
of Gas Utility’s sales volume was supplied, and approximately 96% of Gas Utility’s operating income was earned, during the peak
heating season from October through March.
Competition
Natural gas is a fuel that competes with electricity and oil and, to a lesser extent, with propane and coal. Competition among these
fuels is primarily a function of their comparative price and the relative cost and efficiency of the equipment. Natural gas generally
benefits from a competitive price advantage over oil, electricity and propane, although the price gap between natural gas and oil
narrowed in recent years. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility
responds to this competition with marketing and sales efforts designed to retain, expand, 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 PAPUC or by law, to provide gas distribution services. All of Gas Utility’s customers, including core-market customers, have
the right to purchase gas supplies from entities other than natural gas distribution utility companies.
A number of Gas Utility’s commercial and industrial customers have the ability to switch to an alternate fuel at any time and,
therefore, are served on an interruptible basis under rates that 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, the frequency and duration of interruptions, and alternative firm service options.
See “Gas Utility Regulation and Rates - Pennsylvania Public Utility Commission Jurisdiction and Gas Utility Rates.”
Approximately 42% of Gas Utility’s annual throughput volume for commercial and industrial customers includes non-interruptible
customers with firm rates with locations that afford them the opportunity of seeking transportation service directly from interstate
pipelines, thereby bypassing Gas Utility. In addition, nearly 17% of Gas Utility’s annual throughput volume for commercial and
industrial customers is from customers who are served under interruptible rates and are also in a location near an interstate pipeline.
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Gas Utility has 38 such customers, 35 of which have transportation contracts extending beyond Fiscal 2019. The majority of these
customers are served under transportation contracts having 3- to 20-year terms and all are among the largest customers for Gas
Utility in terms of annual volumes. No single customer represents, or is anticipated to represent, more than 5% of Gas Utility’s
total revenues.
Outlook for Gas Service and Supply
Gas Utility anticipates having adequate pipeline capacity, peaking services and other sources of supply available to it to meet the
full requirements of all firm customers on its system through Fiscal 2019. Supply mix is diversified, market priced and delivered
pursuant to a number of long-term and short-term primary firm transportation and storage arrangements, including transportation
contracts held by some of Gas Utility’s larger customers.
During Fiscal 2018, Gas Utility supplied transportation service to 10 electric generation facilities and installed new service to
three co-generation facilities. Gas Utility continues to seek new residential, commercial, and industrial customers for both firm
and interruptible service. In Fiscal 2018, Gas Utility connected approximately 1,900 new commercial and industrial customers.
In the residential market sector, Gas Utility added over 12,000 residential heating customers during Fiscal 2018. Approximately
54% of these customers converted to natural gas heating from other energy sources, mainly oil and electricity. New home
construction and existing non-heating gas customers who added gas heating systems to replace other energy sources primarily
accounted for the other residential heating connections in Fiscal 2018.
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 that relate to (i) the pricing of pipeline
services in a competitive energy marketplace, (ii) the flexibility of the terms and conditions of pipeline service tariffs and contracts,
and (iii) pipelines’ requests to increase their base rates, or change the terms and conditions of their storage and transportation
services.
UGI Utilities’ objective in negotiations with providers of gas supply resources, and in proceedings before regulatory agencies, is
to ensure availability of supply, transportation and storage alternatives to serve market requirements at the lowest cost possible,
taking into account the need for security with guaranteed deliverability and reliability 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.
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Gas Utility Regulation and Rates
UGI Gas Merger
On March 8, 2018, UGI Utilities and its wholly owned subsidiaries, PNG and CPG, filed an application with the PAPUC for
permission (i) to merge PNG and CPG with and into UGI Gas and (ii) for UGI Utilities to adopt the preexisting PNG and CPG
tariffs, rates and terms and conditions of service for inclusion in the UGI Gas tariff, and (iii) thereafter operate as the UGI South
(encompassing the former service territory of UGI Gas), UGI North rate district (formerly PNG) and UGI Central rate district
(formerly CPG) rate districts of UGI Utilities, respectively. The authority to merge was granted in a September 20, 2018 PAPUC
Opinion and Order, and the merger became effective October 1, 2018. The merger was also separately approved by the MDPSC.
Pennsylvania Public Utility Commission Jurisdiction and Gas Utility Rates
Gas Utility is subject to regulation by the PAPUC as to rates, terms and conditions of service, accounting matters, issuance of
securities, contracts and other arrangements with affiliated entities, gas safety and various other matters. Rates that Gas Utility
may charge for gas service come in two forms: (i) rates designed to recover purchased gas costs (“PGCs”); and (ii) rates designed
to recover costs other than PGCs. Rates designed to recover PGCs are reviewed in PGC proceedings. Rates designed to recover
costs other than PGCs are primarily established in general base rate proceedings.
In January 2016, UGI Utilities filed a request with the PAPUC for its first base rate increase in over 21 years. On October 14,
2016, the PAPUC approved a settlement that was effective October 19, 2016 and resulted in a $27.0 million increase in annual
base rate revenues. The settlement permitted UGI Gas to establish new reconcilable surcharges to permit the timely recovery of
the costs of universal service programs designed to assist low income customers, and costs associated with a new energy efficiency
and conservation program. UGI Gas was also permitted to implement a new Technology and Economic Development Rider to
provide additional flexibility in establishing the rates of smaller volume commercial and industrial customers to encourage cost-
effective load growth.
On January 19, 2017, PNG (now known as the UGI North rate district) filed a rate request with the PAPUC to increase PNG’s
base operating revenues for residential, commercial, and industrial customers by $21.7 million annually. On August 31, 2017,
the PAPUC approved a settlement that permitted PNG to increase its annual base distribution rates by $11.3 million, effective
October 20, 2017. The settlement also permitted PNG to recover costs associated with a new energy efficiency and conservation
program and, similar to UGI Gas, also permitted PNG to implement a new Technology and Economic Development Rider to
provide additional flexibility in establishing the rates of smaller volume commercial and industrial customers to encourage cost-
effective load growth.
On February 20, 2014, the PAPUC entered an order approving a Growth Extension Tariff (“GET Gas”) program under which UGI
Gas, PNG, and CPG may invest up to $5 million per year for five years, or $75 million in the aggregate for all three utilities, to
extend natural gas utility pipelines to provide service to unserved and underserved areas within their respective territories. Under
the GET Gas program, customers utilizing the extended pipeline to receive natural gas will pay a monthly surcharge over a 10-
year period to cover the cost of the extension. Gas Utility began connecting customers under the GET Gas program in October
2014.
In February 2012, Act 11 of 2012 (“Act 11”) became effective. Among other things, Act 11 authorized the PAPUC to permit
electric and gas distribution companies, between base rate cases and subject to certain conditions, to recover reasonable and prudent
costs incurred to repair, improve or replace eligible property through a Distribution System Improvement Charge (“DSIC”) assessed
to customers. DSICs are subject to quarterly adjustment, are capped at five percent of total customer charges absent a PAPUC-
granted exception, may only be sought if a base rate case has been filed within the last five years, and are subject to certain earnings
tests. In addition, Act 11 requires affected utilities to obtain approval of long-term infrastructure improvement plans (“LTIIP”)
from the PAPUC. Act 11 also authorized electric and gas distribution companies to utilize a fully forecasted future test year when
establishing rates in base rate cases before the PAPUC.
Prior to the merger effective October 1, 2018, the PAPUC approved LTIIPs for UGI Gas, PNG, and CPG in 2014, and on June
30, 2016, approved a revised LTIIP for these entities that increased the projected spend on DSIC-eligible property for the 2016-2018
period from approximately $266.3 million to $402.8 million. On August 2, 2018, the PAPUC approved one year extensions
through December 31, 2019 to the existing UGI Gas, PNG and CPG LTIIPs. The modified LTIIPs provide for approximately
$185.0 million of projected spend on DSIC-eligible property during calendar year 2019. The PAPUC also approved DSIC
mechanisms for PNG and CPG in September 2014 and July 2015, respectively. On March 31, 2016, PNG and CPG filed petitions
with the PAPUC seeking to increase the cap on their DSIC rate mechanisms from five percent to ten percent of billed distribution
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revenues. On May 10, 2017, the PAPUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5%
of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration of each company’s LTIIP filing.
On November 9, 2016, UGI Gas received PAPUC approval to establish a DSIC tariff mechanism effective January 1, 2017, subject
to refund and recoupment based on the PAPUC’s final resolution of certain matters set aside for hearing before an Administrative
Law Judge. Those matters were subsequently resolved in a PAPUC Order entered on July 13, 2017, and UGI Gas commenced
collections under its natural gas DSIC on July 1, 2018.
Currently, UGI South and UGI Central are collecting DSIC revenues, while UGI North will resume DSIC revenue collection once
the UGI North rate district places into service a threshold level of DSIC eligible plant agreed upon in the settlement of its more
recent base rate case.
The tariffs of UGI Gas’ rate districts include PGC rates applicable to firm retail rate schedules for customers who do not obtain
natural gas supply service from an alternative supplier. These PGC rates permit recovery of substantially all of the prudently
incurred costs of natural gas that UGI Gas sells to its customers. PGC rates are reviewed and approved annually by the PAPUC.
UGI Gas’ rate districts may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas.
Quarterly adjustments become effective on one day’s notice to the PAPUC and are subject to review during the next annual PGC
filing. Each proposed annual PGC rate is required to be filed with the PAPUC six months prior to its effective date. During this
period, the PAPUC 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 PAPUC issues an order
permitting the collection of gas costs at levels that meet such standard. The PGC mechanism also provides for an annual
reconciliation and for the payment or collection of interest on over and under collections. UGI Gas’ rate districts may release or
sell to and recover from alternative natural gas suppliers the costs of gas supply contracts and transportation capacity acquired to
serve the needs of smaller volume customers who elect to receive their natural gas supply service from an alternative supplier.
On April 28, 2017, UGI Gas, PNG and CPG filed the Gas Delivery Enhancement Rider (“GDE”) with the PAPUC. The GDE
provides a tariff mechanism to recover from certain non-choice transportation customers a portion of the costs associated with
temporary mobile sources of gas supply and interstate pipeline demand charge enhancements (collectively, “GDE Charges”) that
are incurred to achieve least-cost timely solutions to system reinforcement needs or for pipeline integrity management activities.
GDE Charges exclude costs that are recovered through existing PGC rate mechanisms as established in each company’s annual
66 Pa.C.S. § 1307(f) PGC proceeding. On August 31, 2017, the PAPUC entered an order approving the GDE Rider for all three
companies.
On June 23, 2016, Act 47 of 2016 was enacted. Act 47 revised the interest rates that are applied to PGC over and under collections,
removed the requirement that over and under collections be assessed to customers who leave default service to obtain natural gas
from an alternative supplier by way of a so-called migration rider, provided additional assurance of cost recovery for PGC costs,
and granted natural gas distribution companies the right to recover the reasonable costs incurred to implement customer choice
on a full and current basis through a reconcilable rate mechanism. Gas Utility implemented the interest rate revision and migration
rider provisions of Act 47 in December 2016.
FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers
UGI Utilities is subject to Section 4A of the Natural Gas Act, which prohibits the use or employment of any manipulative or
deceptive devices or contrivances in connection with the purchase or sale of natural gas or natural gas transportation subject to
the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity of gas
markets. UGI Utilities is also subject to Section 222 of the Federal Power Act, which prohibits the use or employment of any
manipulative or deceptive devices or contrivances in connection with the purchase or sale of electric energy or transmission service
subject to the jurisdiction of FERC, and FERC regulations that are designed to promote the transparency, efficiency, and integrity
of electric markets.
State Tax Surcharge Clauses
UGI Utilities’ gas 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.
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Utility Franchises
UGI Utilities, PNG and CPG each hold certificates of public convenience issued by the PAPUC 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 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 PAPUC and FERC, Gas Utility is subject to various federal, state and local laws governing
environmental matters, occupational health and safety, pipeline safety and other matters. Gas Utility is subject to the requirements
of the Resource Conservation and Recovery Act, CERCLA, and comparable state statutes with respect to the release of hazardous
substances. See Note 15 to Consolidated Financial Statements.
Employees
At September 30, 2018, Gas Utility had approximately 1,600 employees.
ELECTRIC UTILITY
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 over 2,200 miles of transmission and distribution lines and 13 substations.
At September 30, 2018, UGI Utilities’ electric utility operations had 70 employees.
Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’
energy requirements, pursuant to a supply plan filed and approved by the PAPUC. On January 26, 2018, Electric Utility filed a
request with the PAPUC for its first base rate increase in over 22 years. On October 25, 2018, the PAPUC entered an Opinion and
Order authorizing a $3.2 million increase in annual base distribution rates effective October 27, 2018. The PAPUC also authorized
Electric Utility to establish a new reconcilable surcharge to permit the timely recovery of the costs of universal service programs
designed to assist low income customers and required Electric Utility to refund approximately $0.21 million of tax benefits and
associated interest relating to the Tax Cuts and Jobs Act (the “TCJA”) through a one-time bill credit.
Electric Utility’s tariff includes rates, applicable to so-called “default service” customers who do not obtain electric generation
service from an alternative supplier, incurred pursuant to a PAPUC-approved supply plan. These default service rates are
reconcilable, may be adjusted quarterly, and are designed to permit Electric Utility to recover the full costs of providing default
service in a full and timely manner. Electric Utility has received PAPUC approval of its current default service rules and supply
plan through May 31, 2021. Electric Utility’s default service rates include recovery of costs associated with compliance with 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. On August 16, 2017, Electric Utility filed a Petition for
Approval of its initial LTIIP with the PAPUC for the 2018-2022 time period, which was approved by a PAPUC Opinion and Order
entered on December 21, 2017. Electric Utility’s projected annual investment in distribution infrastructure replacement was
approximately $7.6 million in Fiscal 2018, and will increase to $8.3 million by the fiscal year ending September 30, 2022. With
the completion of its base rate case, Electric Utility is now eligible to file for permission to implement a DSIC.
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 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 Utility’s 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.
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.
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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 FERC’s authority over certain utility or holding company
mergers or acquisitions of electric utilities or electric transmitting utility property valued at $10 million or more.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income and identifiable assets attributable to each of UGI’s reportable business
segments, and to the geographic areas in which we operate, for Fiscal 2018, Fiscal 2017 and Fiscal 2016 appears in Note 21 to
Consolidated Financial Statements included in Item 15 of this Report and is incorporated herein by reference.
At September 30, 2018, UGI and its subsidiaries had approximately 13,000 employees.
EMPLOYEES
ITEM 1A. RISK FACTORS
There are many factors that may affect our business and results of operations. Additional discussion regarding factors that may
affect our business and operating results is included elsewhere in this Report.
Our holding company structure could limit our ability to pay dividends or debt service.
We are a holding company whose material assets are the stock of our subsidiaries. Our ability to pay dividends on our common
stock and to pay principal and accrued interest on our debt, if any, depends on the payment of dividends to us by our principal
subsidiaries, AmeriGas, Inc., UGI Utilities, and Enterprises (including UGI International). Payments to us by those subsidiaries,
in turn, depend upon their consolidated results of operations and cash flows. The operations of our subsidiaries are affected by
conditions beyond our control, including weather, local regulations, competition in national and international markets we serve,
the costs and availability of propane, butane, natural gas, electricity, and other energy sources and capital market conditions. The
ability of our subsidiaries to make payments to us is also affected by the level of indebtedness of our subsidiaries, which is
substantial, and the restrictions on payments to us imposed under the terms of such indebtedness.
Supplier defaults may have a negative effect on our operating results.
When the Company’s subsidiaries enter into fixed-price sales contracts with customers, they typically enter into fixed-price
purchase contracts with suppliers. Depending on changes in the market prices of products compared to the prices secured in our
contracts with suppliers of LPG, natural gas and electricity, a default of one or more of our suppliers under such contracts could
cause us to purchase those commodities at higher prices, which would have a negative impact on our operating results.
We are dependent on our principal propane and LPG suppliers, which increases the risks from an interruption in supply and
transportation.
During Fiscal 2018, AmeriGas Propane purchased approximately 87% of its propane needs from twenty suppliers. If supplies
from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative
locations might be materially higher and, at least on a short-term basis, our earnings could be affected. Additionally, in certain
geographic areas, a single supplier may provide more than 50% of AmeriGas Propane’s propane requirements. Disruptions in
supply in these geographic areas could also have an adverse impact on our earnings. Our international businesses are similarly
dependent upon their LPG suppliers. For example, during Fiscal 2018, UGI International’s business in the United Kingdom
purchased over 90% of its LPG needs from two suppliers and, in Italy, over 50% of UGI International’s supply was sourced from
a single supplier. If supplies from UGI International’s principal LPG sources are interrupted, then the cost of procuring replacement
supplies and transporting those supplies from alternative locations might be materially higher and our earnings could be adversely
affected. There is no assurance that our international businesses will be able to continue to acquire sufficient supplies of LPG to
meet demand at prices or within time periods that would allow them to remain competitive.
Our ability to grow our businesses will be adversely affected if we are not successful in making acquisitions or integrating the
acquisitions we have made.
One of our strategies is to grow through acquisitions in the U.S. and in international markets. We may choose to finance future
acquisitions with debt, equity, cash or a combination of the three. We can give no assurances that we will find attractive acquisition
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candidates in the future, that we will be able to acquire such candidates on economically acceptable terms, that we will be able to
finance acquisitions on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional
debt incurred to finance an acquisition will not affect our ability to pay dividends. Moreover, acquisitions may require antitrust
and other regulatory clearances. We may have to offer commitments (such as agreements not to compete for certain businesses)
or divest assets to obtain clearance, which may adversely affect the overall economics of the transaction.
In addition, the restructuring of the energy markets in the U.S. and internationally, including the privatization of government-
owned utilities and the sale of utility-owned assets, is creating opportunities for, and competition from, well-capitalized competitors,
which may affect our ability to achieve our business strategy.
To the extent we are successful in making acquisitions, such acquisitions involve a number of risks. These risks include, but are
not limited to, the assumption of material liabilities, environmental liabilities, the diversion of management’s attention from the
management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and
difficulties in the assimilation of different cultures and practices and internal controls, as well as in the assimilation of broad and
geographically dispersed personnel and operations. The failure to successfully integrate acquisitions could have an adverse effect
on our business, financial condition and results of operations.
Regulators may not approve the rates we request and existing rates may be challenged, which may adversely affect our results
of operations.
In our UGI Utilities segment, our distribution operations are subject to regulation by the PAPUC. The PAPUC, among other
things, approves the rates that UGI Utilities may charge its utility customers, thus impacting the returns that UGI Utilities may
earn on the assets that are dedicated to its operations. We expect that UGI Utilities will periodically file requests with the PAPUC
to increase base rates charged to customers. If UGI Utilities is required in a rate proceeding to reduce the rates it charges its utility
customers, or is unable to obtain approval for timely rate increases from the PAPUC, particularly when necessary to cover increased
costs, UGI Utilities’ revenue growth will be limited and earnings may decrease.
We are subject to operating and litigation risks that may not be covered by insurance.
Our business operations in the U.S. and other countries are subject to all of the operating hazards and risks normally incidental to
the handling, storage and distribution of combustible products, such as LPG, propane and natural gas, and the generation of
electricity. These risks could result in substantial losses due to personal injury and/or loss of life, and severe damage to and
destruction of property and equipment arising from explosions and other catastrophic events, including acts of terrorism. As a
result of these and other incidents, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course
of business, including regulatory investigations, claims, lawsuits and other proceedings. Additionally, environmental
contamination could result in future legal proceedings. There can be no assurance that our insurance coverage will be adequate
to protect us from all material expenses related to pending and future claims or that such levels of insurance would be available
in the future at economical prices. Moreover, defense and settlement costs may be substantial, even with respect to claims and
investigations that have no merit. If we cannot resolve these matters favorably, our business, financial condition, results of
operations and future prospects may be materially adversely affected.
Our operations, capital expenditures and financial results may be affected by regulatory changes and/or market responses to
global climate change.
Increased regulation of GHG emissions, such as propane and methane, could impose significant additional costs on us, our suppliers
and our customers. Some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors.
For example, the California Environmental Protection Agency established a Cap & Trade program that requires certain covered
entities, including propane companies, to purchase allowances to compensate for the GHG emissions created by their business
operations. In September 2009, the EPA issued a final rule establishing a system for mandatory reporting of GHG emissions. In
November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries,
which include certain facilities of our natural gas distribution business. These subject facilities have been required to monitor
emissions since January 2011 and to submit detailed annual reports beginning in March 2012. In October 2015, the EPA promulgated
the Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (the “Clean Power
Plan”), which provides standards and guidelines for reducing existing power plants’ GHG emissions and related pollutants by
2030. However, in October 2017, the EPA announced its proposal to repeal the Clean Power Plan in its entirety on the grounds
that it exceeds the EPA’s delegated authority under the Clean Air Act.
At the international level, many nations have agreed to limit emissions of GHGs pursuant to the United National Framework
Convention on Climate Change, also known as the ‘‘Kyoto Protocol.’’ Further, as a result of commitments made at the UN
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climate conference in Durban, South Africa in December 2011, certain members of the international community negotiated a
treaty at the December 2015 Conference of Parties in Paris. The Paris Agreement, which entered into force in November 2016,
requires developed countries to set targets for emissions reductions once the Paris Agreement is adopted by those countries
within their respective national or federal law.
In the EU, there is a commitment to cut CO2 emissions by at least 40% by 2030 and EU member states have implemented a
range of subsidies and incentives to achieve the EU’s climate change goals. Further, emissions are regulated via a number of
means, including the European Union Emissions Trading System (‘‘EU ETS’’). The EU ETS is a trading system across the EU
for industrial emissions. The EU ETS is expected to become progressively more stringent over time, including by reducing the
number of allowances to emit GHGs. Further, in the EU, legislative proposals were made in 2017 to further reduce emissions
from new cars. The proposed target is a 30% reduction by 2030.
In recent years, a number of jurisdictions have also imposed or discussed imposing bans on internal combustion engines in
motor vehicles for the purpose of reducing GHG emissions, and these bans could expand to additional jurisdictions in the
future. In the EU, legislative proposals were made in 2017 to further reduce emissions from new cars. The proposed target is a
30% reduction by 2030. The proposed scheme would also provide incentives for accelerating the uptake of zero- and low-
emission vehicles. Manufacturers achieving a share of zero- and low-emission vehicles, exceeding the proposed benchmark
level of 15% in 2025 and 30% in 2030, would be rewarded. Such proposals and the general push for electrification could
reduce demand for LPG powered vehicles, although they have lower emissions than vehicles powered by gasoline and diesel.
Significant increases in cost of compliance for environmental certifications could materially impact our financial condition and
results of operations.
At this time, we cannot predict the effect that climate change regulation may have on our business, financial condition or operations
in the future.
Our international operations could be subject to increased risks, which may negatively affect our business results.
We currently operate LPG distribution and energy marketing businesses in Europe through our subsidiaries and we continue to
explore the expansion of our international businesses. As a result, we face risks in doing business abroad that we do not face
domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results,
including:
• costs and difficulties in staffing and managing international operations;
• potentially adverse tax consequences, including restrictions on repatriating earnings, potential increases to corporate
income taxes and the threat of “double taxation”;
• fluctuations in currency exchange rates, which can affect demand for our products, increase our costs and adversely
affect our profitability and reported results;
• regulatory requirements and changes in regulatory requirements, including European competition laws that may
adversely affect the terms of contracts with customers, including with respect to exclusive supply rights, and stricter
regulations applicable to the storage and handling of LPG;
• new and inconsistently enforced industry regulatory requirements, which can have an adverse effect on our competitive
position;
• tariffs and other trade barriers;
• difficulties in enforcing contractual rights;
• longer payment cycles;
• local political and economic conditions;
• internal control and risk management practices and policies; and
• potential violations of federal regulatory requirements, including anti-bribery, anti-corruption, and anti-money
laundering law, economic sanctions, the Foreign Corrupt Practices Act of 1977, as amended, and EU regulatory
requirements, including the GDPR and Sapin II.
In particular, certain legal and regulatory risks are associated with international business operations. We are subject to various
anti-corruption, economic sanctions and trade compliance laws, rules and regulations. For example, the U.S. government imposes
restrictions and prohibitions on transactions in certain foreign countries, including restrictions directed at oil and gas activities in
Russia, imposed in 2014 and amended in 2017. U.S. laws also prohibit the improper offer, payment, promise to pay, or authorization
of the payment of money or anything of value to any foreign official or political party, or to any person, knowing that all or a
portion of it will be used to influence a foreign official in his or her official duties or to secure an improper advantage. Ensuring
compliance with all relevant laws, rules and regulations is a complex task. Violation of one or more of these laws, rules or
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regulations could lead to loss of import or export privileges, civil or criminal penalties for us or our employees, or potential
reputational harm, which could have a material adverse effect on earnings, cash flows and financial condition.
Changes in data privacy and data protection laws and regulations, particularly in Europe, or any failure to comply with
such laws and regulations, could adversely affect our business and financial results.
There has been increased public attention regarding the use of personal information and data transfer, accompanied by legislation
and regulations intended to strengthen data protection, information security and consumer and personal privacy. The law in these
areas continues to develop and the changing nature of privacy laws in the U.S., the EU and elsewhere could impact our processing
of personal and sensitive information of our employees, vendors and customers. The EU adopted the GDPR, which became
effective in May of 2018. The GDPR expands the current EU data protections laws to all companies processing data of EU residents.
The GDPR requires companies to satisfy strict new requirements regarding the handling of personal and sensitive data, including
its use, protection and the ability of persons whose data is stored to correct or require deletion of data about themselves. Although
there is a consistency mechanism in the GDPR, data protection authorities from different EU member states may interpret and
apply the GDPR somewhat differently, and the GDPR also permits EU member states to create supplemental national laws, which
increases the complexity of compliance. Failure to comply with GDPR requirements could result in penalties of up to €20 million
or 4% of worldwide revenue, whichever is greater, for serious breaches. While we have invested significant time and resources
in preparing for and complying with the GDPR, the GDPR and other similar laws and regulations (including potential new data
privacy laws and regulations in the U.S.), as well as any associated inquiries or investigations or any other government actions,
may be costly to comply with, result in negative publicity, increase our operating costs, require significant management time and
attention, and subject us to remedies that may harm our business, including fines, demands or orders that we modify or cease
existing business practices.
Expanding our midstream asset business by constructing new facilities subjects us to risks.
We seek to grow our midstream asset business by constructing new pipelines and gathering systems. These construction projects
involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of
significant amounts of capital. These projects may not be completed on schedule, or at all, or at the anticipated costs. Moreover,
our revenues may not increase immediately upon the expenditure of funds on a particular project. We may construct facilities to
capture anticipated future growth in production and demand in an area in which anticipated growth and demand does not materialize.
As a result, there is the risk that new and expanded facilities may not be able to attract enough customers to achieve our expected
investment returns, which could have a material adverse effect on our business, financial condition and results of operations.
Decreases in the demand for our energy products and services because of warmer-than-normal heating season weather or
unfavorable weather conditions may adversely affect our results of operations.
Because many of our customers rely on our energy products and services to heat their homes and businesses, and for agricultural
purposes such as crop drying, our results of operations are adversely affected by warmer-than-normal heating season weather.
Weather conditions have a significant impact on the demand for our energy products and services for both heating and agricultural
purposes. Accordingly, the volume of our energy products sold is at its highest during the peak heating season of October through
March and is directly affected by the severity of the winter weather. For example, historically, approximately 60% to 70% of
AmeriGas Partners’ annual retail propane volume, 60% to 70% of the annual retail LPG volume of UGI International’s operations
in France, and 60% to 70% of Gas Utility’s natural gas throughput (the total volume of gas sold to or transported for customers
within our distribution system) has typically been sold during these months. There can be no assurance that normal winter weather
in our market areas will occur in the future.
In addition, our agricultural customers use LPG for purposes other than heating, including for crop drying, and unfavorable weather
conditions, such as lack of precipitation, may impact the demand for LPG. Moreover, harsh weather conditions may at times
impede the transportation and delivery of LPG, or restrict our ability to obtain LPG from suppliers. Spikes in demand caused by
weather or other factors can stress the supply chain and limit our ability to obtain additional quantities of LPG. Changes in LPG
supply costs are normally passed through to customers, but time lags (between when we purchase the LPG and when the customer
purchases the LPG) may result in significant gross margin fluctuations that could adversely affect our results of operations.
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 LPG
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and 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 and attrition. 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. Additionally,
EU and local laws and regulations may require mandatory conservation measures, which would reduce the demand for our energy
products. The EU is in the process of revising a directive on energy performance of buildings, with the goal to create a clear path
towards a low and zero-emission building stock in the EU by 2050, which is underpinned by national roadmaps to decarbonize
buildings. The EU is also adopting further measures to decarbonize electricity generation in order to reduce dependence on fossil
fuel imports and achieve its climate change objectives. Over time, these various measures will impact fossil fuel consumption in
Europe. 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.
Changes in commodity market prices may have a significant negative effect on our liquidity.
Depending on the terms of our contracts with suppliers as well as our use of financial instruments to reduce volatility in the cost
of LPG and natural gas, changes in the market price of LPG and natural gas can create margin payment obligations for us and
expose us to an increased liquidity risk. In addition, increased demand for domestically produced LPG and natural gas overseas
may, depending on production volumes in the U.S., result in higher domestic LPG prices and expose us to additional liquidity
risks.
Our potential to increase revenues may be affected by the decline in retail volumes of LPG and our ability to retain and
grow our customer base.
The retail LPG distribution industry in the U.S. and many of the European countries in which we operate is mature and has been
declining over the past several years, with no or modest growth (or decline) in total demand foreseen in the next several years.
Accordingly, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability
to grow within the LPG industry is dependent on our ability to acquire other retail distributors and to achieve internal growth,
which includes expansion of the domestic ACE and National Accounts programs in the U.S. and expansion in Europe, as well as
the success of our sales and marketing programs designed to attract and retain customers. A failure to retain and grow our customer
base would have an adverse effect on our results. Acquisitions in the U.S. and Europe may require merger control filings with
the Federal Trade Commission and the European Commission, as applicable, and commitments or divestments of assets may be
required to obtain clearance. Such commitments or divestments may influence the overall economics of the transaction.
UGI Utilities’ transmission and distribution systems may not operate as planned, which may increase expenses or decrease
UGI Utilities’ revenues and, thus, have an adverse effect on our financial results.
Our ability to manage operational risk with respect to UGI Utilities’ transmission and distribution systems is critical to our financial
results. The 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, including as a result of overpressurization of or damage
to natural gas pipelines. Operation of UGI Utilities’ transmission and distribution systems below our expectations may result in
lost revenues or increased expenses, including higher maintenance costs, civil litigation and the risk of regulatory penalties.
The risk of natural disasters and catastrophic events, including terrorism, may adversely affect the economy and the price
and availability of LPG, other refined fuels and natural gas.
Natural disasters and catastrophic events, such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, terrorist attacks,
political unrest and other similar occurrences, may adversely impact the price and availability of LPG (including propane), other
refined fuels and natural gas, which could adversely impact our financial condition and results of operations, our ability to raise
capital and our future growth. The impact that the foregoing may have on our industries in general, and on us in particular, is not
known at this time. A natural disaster or an act of terror could result in disruptions of crude oil or natural gas supplies and markets
(the sources of LPG), cause price volatility in the cost of LPG, fuel oil and natural gas, and our infrastructure facilities could be
direct or indirect targets. A natural disaster or terrorist activity may also hinder our ability to transport LPG and other refined fuels
if our means of supply transportation, such as rail or pipeline, become damaged as a result of an attack. A lower level of economic
activity could result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth.
Instability in the financial markets as a result of a natural disaster or terrorism could also affect our ability to raise capital. We
have opted to purchase insurance coverage for natural disasters and terrorist acts within our property and casualty insurance
programs, but we can give no assurance that our insurance coverage would be adequate to fully compensate us for any losses to
our business or property resulting from natural disasters or terrorist acts.
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If we are unable to protect our information technology systems against service interruption, misappropriation of data, or
breaches of security resulting from cyber security attacks or other events, or we encounter other unforeseen difficulties in the
operation of our information technology systems, our operations could be disrupted, our business and reputation may suffer,
and our internal controls could be adversely affected.
In the ordinary course of business, we rely on information technology systems, including the Internet and third-party hosted
services, to support a variety of business processes and activities and to store sensitive data, including (i) intellectual property, (ii)
our proprietary business information and that of our suppliers and business partners, (iii) personally identifiable information of
our customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement,
and supply chain activities. In addition, we rely on our information technology systems to process financial information and
results of operations for internal reporting purposes and to comply with financial reporting, legal, and tax requirements. Despite
our security measures, our information technology systems may be vulnerable to attacks by hackers or breached due to employee
error, malfeasance, sabotage, or other disruptions. A loss of our information technology systems, or temporary interruptions in
the operation of our information technology systems, misappropriation of data, or breaches of security could have a material
adverse effect on our business, financial condition, results of operations, and reputation. In addition, a cyber security attack could
provide a cyber intruder with the ability to control or alter our pipeline operations. Such an act could result in critical pipeline
failures.
Moreover, the efficient execution of the Company’s businesses is dependent upon the proper functioning of its internal systems,
such as the information technology systems that support the Company’s underlying business processes. Any significant failure
or malfunction of such information technology systems may result in disruptions of our operations. In addition, the effectiveness
of our internal controls could be adversely affected if we encounter unforeseen problems with respect to the operation of our
information technology systems. While we have purchased cyber security insurance, there are no assurances that the coverage
would be adequate in relation to any incurred losses.
Our operations may be adversely affected by competition from other energy sources.
Our energy products and services face competition from other energy sources, some of which are less costly for equivalent energy
value. In addition, we cannot predict the effect that the development of alternative energy sources might have on our operations.
Our LPG distribution businesses compete for customers against suppliers of electricity, fuel oil and natural gas. Electricity is a
major competitor of LPG but, except in France, is generally more expensive than LPG on a Btu equivalent basis for space heating,
water heating and cooking. However, in Europe and elsewhere, climate change policies favoring electricity from renewable energy
sources (“RES”) may cause changes in current relative price relationships. Moreover, notwithstanding cost, the convenience and
efficiency of electricity make it an attractive energy source for consumers and developers of new homes. In addition, due to the
prevalence of nuclear electric generation in France, the cost of electricity is generally less expensive than that of LPG, particularly
when the cost to install new equipment to convert to LPG is considered. Fuel oil is also a major competitor of LPG but is currently
more expensive than LPG as well as a less environmentally attractive energy source. Historically, however, fuel oil has been less
expensive than LPG. Furnaces and appliances that burn LPG will not operate on fuel oil and vice versa, and, therefore, a conversion
from one fuel to the other requires the installation of new equipment. Our customers generally have an incentive to switch to fuel
oil only if fuel oil becomes significantly less expensive than LPG. Except for certain industrial and commercial applications, LPG
is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is generally a
significantly less expensive source of energy than LPG. The gradual expansion of natural gas distribution systems in our service
areas has resulted, and may continue to result, in the availability of natural gas in some areas that previously depended upon LPG.
As long as natural gas remains a less expensive energy source than LPG, our LPG business will lose customers in each region
into which natural gas distribution systems are expanded.
Our natural gas businesses compete primarily with electricity and fuel 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.
There can be no assurance that our natural gas revenues will not be adversely affected by this competition.
Our need to comply with, and respond to industry-wide changes resulting from, comprehensive, complex, and sometimes
unpredictable governmental regulations, including regulatory initiatives aimed at increasing competition within our industry,
may increase our costs and limit our revenue growth, which may adversely affect our operating results.
While we generally refer to our UGI Utilities segment as our “regulated segment,” there are many governmental regulations that
have an impact on all of our businesses. Currently, we are subject to extensive and changing international, federal, state, and local
safety, health, transportation, tax, and environmental laws and regulations governing the marketing, storage, distribution, and
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transportation of our energy products. Moreover, existing statutes and regulations may be revised or reinterpreted and new laws
and regulations may be adopted or become applicable to the Company that may affect our businesses in ways that we cannot
predict.
New regulations, or a change in the interpretation of existing regulations, could result in increased expenditures. In addition, for
many of our operations, we are required to obtain permits from regulatory authorities and, in some cases, such regulatory permits
could subject our operations to additional regulations and standards of conduct. Failure to obtain or comply with these permits
or applicable regulations and standards of conduct could result in civil and criminal fines or the cessation of the operations in
violation. Governmental regulations and policies in the U.S. and Europe may provide for subsidies or incentives to customers
who use alternative fuels instead of carbon fuels. The EU has committed to cut CO2 emissions by at least 40% by 2030 and EU
member states have implemented a range of subsidies and incentives to achieve the EU’s climate change goals. These subsidies
and incentives may result in reduced demand for our energy products and services.
We are investigating and remediating contamination at a number of present and former operating sites in the U.S., including former
sites where we or our former subsidiaries operated manufactured gas plants. We have also received claims from third parties that
allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas
plant or conducted other operations. Costs we incur to remediate sites outside of Pennsylvania cannot currently be recovered in
PAPUC rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs to clean up these sites may
exceed our current estimates due to factors beyond our control, such as:
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•
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the discovery of presently unknown conditions;
changes in environmental laws and regulations;
judicial rejection of our legal defenses to third-party claims; or
the insolvency of other responsible parties at the sites at which we are involved.
Moreover, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net
income.
We also may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives
to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors
to grow their business or enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our
current business strategy.
Our profitability is subject to LPG pricing and inventory risk.
The retail LPG business is a “margin-based” business in which gross profits are dependent upon the excess of the sales price over
LPG supply costs. LPG is a commodity, and, as such, its unit price is subject to fluctuations in response to changes in supply or
other market conditions. We have no control over supplies, commodity prices or market conditions. Consequently, the unit price
of the LPG that our subsidiaries and other distributors and marketers purchase can change rapidly over a short period of time.
Most of our domestic LPG product supply contracts permit suppliers to charge posted prices at the time of delivery or the current
prices established at major U.S. storage points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international LPG
supply contracts are based on internationally quoted market prices. We also purchase a portion of our supplies in the spot market.
Because our subsidiaries’ profitability is sensitive to changes in wholesale LPG supply costs, it will be adversely affected if we
cannot pass on increases in the cost of LPG to our customers, or if there is a delay in passing on such cost increases. Due to
competitive pricing in the industry, our subsidiaries may not fully be able to pass on product cost increases to our customers when
product costs rise, or when our competitors do not raise their product prices in a timely manner. Finally, market volatility may
cause our subsidiaries to sell LPG at less than the price at which they purchased it, which would adversely affect our operating
results.
We offer our customers various fixed-price LPG programs, and a significant number of our customers utilize our fixed-price
programs. In order to manage the price risk from offering these services, we utilize our physical inventory position, supplemented
by forward commodity transactions with various third parties having terms and volumes substantially the same as our customer’s
contracts, but there can be no assurance that such measures will be effective. In periods of high LPG price volatility, the fixed-
price programs create exposure to over or under-supply positions as the demand from customers may significantly exceed or fall
short of supply procured. In addition, if LPG prices decline significantly subsequent to customers signing up for a fixed-price
program, there is a risk that customers will default on their commitments, adversely affecting our results of operations.
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Economic recession, volatility in the stock market and the low interest rate environment may negatively impact our pension
liability.
Economic recession, volatility in the stock market and the low interest rate environment have had a significant impact on our
pension liability and funded status. Declines in the stock or bond market and valuation of stocks or bonds, combined with continued
low interest rates, could further impact our pension liability and funded status and increase the amount of required contributions
to our pension plans.
The adoption of financial reform legislation by the United States Congress and related regulations may have an adverse effect
on our ability to use derivative instruments to hedge risks associated with our business.
Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Act”) in 2010, which contains comprehensive
financial reform legislation. Our derivative hedging activities are subject to Title VII of the Act, which regulates the over-the-
counter derivatives market and entities that participate in that market. The Act requires the Commodity Futures Trading Commission
(“CFTC”) and other regulators to implement the Act’s provisions, including rules regarding mandatory clearing, trade execution
and margin requirements. We expect to qualify for and rely upon an end-user exception from mandatory clearing and trade execution
requirements for swaps entered into to hedge our commercial risks. Separately, unclear swap margin requirements do not apply
to entities benefiting from the end-user exception. While most rules and regulations required to be issued by the CFTC under the
Act have been finalized, there are some additional rules and regulations that have yet to be adopted. It is possible that the rules
and regulations under the Act may increase our cost of using derivative instruments to hedge risks associated with our business
or may reduce the availability of such instruments to protect against risks we encounter. While costs imposed directly on us due
to regulatory requirements for derivatives under the Act, such as reporting recordkeeping and electing the end-user exception from
mandatory clearing, are relatively minor, costs imposed upon our counterparties may increase the cost of our doing business in
the derivatives markets to the extent such costs are passed on to us.
Position limits also may be imposed that could further limit our ability to hedge risks and may impose compliance and reporting
obligations on us. The CFTC has re-proposed position limits for certain futures and option contracts in the major energy markets
and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these
position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires
market participants to aggregate their positions with certain other persons under common ownership and control, unless an
exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position
limit rule and its finalized companion rule on aggregation may have an impact on our ability to hedge exposure to price fluctuation
of certain commodities. In addition to the CFTC federal position limit regime, designated contract markets also have established
position limit and accountability regimes. We may have to modify trading decisions or liquidate positions to avoid exceeding such
limits or at the direction of the exchange to comply with accountability levels. Further, any such position limit regime, whether
imposed at the federal level or at the DCM level may impose added operating costs to monitor compliance with such position
limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
Accordingly, our business and operating results may be adversely affected if, as a result of the Act and the rules and regulations
promulgated under the Act, we are forced to reduce or modify our current use of derivatives.
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.
Volatility in credit and capital markets may create additional risks to our businesses 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. Developments in the credit markets during the past few years increase our possible exposure to the liquidity,
default and credit risks of our suppliers and vendors, counterparties associated with derivative financial instruments and our
customers. Although we believe that current 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, less favorable market conditions could restrict our
ability to grow through acquisitions, limit the scope of major capital projects if access to credit and capital markets is limited, or
adversely affect our operating results.
We may not be able to collect on the accounts of our customers.
We depend on the viability of our customers for collections of accounts receivable and notes receivable. Moreover, our businesses
sell LPG to numerous retail customers, and as we grow our businesses through acquisitions, our retail customer base is expected
to significantly expand. There can be no assurance that our customers will not experience financial difficulties in the future or that
we will be able to collect all of our outstanding accounts receivable or notes receivable and any such nonpayment by our customers
27
could adversely affect our business.
We depend on our intellectual property and failure to protect that intellectual property could have an adverse effect on us.
We seek trademark protection for our brands in each of our businesses, and we invest significant resources in developing our
business brands. Failure to maintain our trademarks and brands could adversely affect our customer-facing businesses and our
operational results.
Our ability to obtain sufficient quantities of LPG is dependent on transportation facilities and providers.
Spikes in demand caused by weather or other factors can limit our access to port terminals and other transportation and storage
facilities, disrupt transportation and limit our ability to obtain sufficient quantities of LPG. A significant increase in port and similar
fees and fuel prices may also adversely affect our transportation costs and business. Transportation providers (rail and truck) in
some circumstances have limited ability to provide additional resources in times of peak demand. Moreover, our transportation
providers maintaining a staff of qualified truck drivers is critical to the success of our business. Regulatory requirements and an
improvement in the economy could reduce the number of eligible drivers or require us to pay higher transportation fees as our
transportation providers seek to pass on additional labor costs associated with attracting and retaining drivers.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
With the exception of those matters set forth in Note 15 to Consolidated Financial Statements included in Item 15 of this Report,
no material legal proceedings are pending involving the Company, any of its subsidiaries, or any of their properties, and no such
proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of business.
ITEM 4. MINE SAFETY DISCLOSURES
None.
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference.
28
PART II:
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our Common Stock is traded on the New York Stock Exchange under the symbol “UGI.” The following table sets forth the high
and low sales prices for the Common Stock on the New York Stock Exchange Composite Transactions tape as reported in The
Wall Street Journal for each full quarterly period within the two most recent fiscal years.
2018 Fiscal Year
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2017 Fiscal Year
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
Dividends
High
Low
$
$
$
$
$
$
$
$
55.94
52.49
48.04
49.77
High
51.11
52.00
50.38
46.66
$
$
$
$
$
$
$
$
50.31
43.60
42.51
46.43
Low
46.59
45.91
45.03
41.79
Quarterly dividends per common share on our Common Stock were paid in Fiscal 2018 and Fiscal 2017 as follows:
Amount
0.2600
0.2500
0.2500
0.2500
Amount
0.2500
0.2375
0.2375
0.2375
$
$
$
$
$
$
$
$
2018 Fiscal Year
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2017 Fiscal Year
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
Record Holders
On November 13, 2018, UGI had 6,165 holders of record of Common Stock.
29
Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth information with respect to the Company’s repurchases of its Common Stock during the quarter
ended September 30, 2018.
(a) Total
Number of
Shares
Purchased
0
135,000
165,000
300,000
(b) Average
Price Paid
per Share
(or Unit)
-
$54.00
$54.42
$54.23
(c) Total Number of
Shares (or Units)
Purchased as Part
of Publicly
Announced Plans
or Programs (1)
0
135,000
165000
300,000
(d) Maximum
Number (or
Approximate
Dollar Value) of
Shares (or Units)
that May Yet Be
Purchased Under
the Plans or
Programs
7,400,000
7,265,000
7,100,000
Period
July 1, 2018 to July 31, 2018
August 1, 2018 to August 31, 2018
September 1, 2018 to September 30, 2018
Total
(1) Shares of UGI Corporation Common Stock are repurchased through an extension of a previous share repurchase program
announced by the Company on January 25, 2018. The UGI Board of Directors authorized the repurchase of up to 8 million shares
of UGI Corporation Common Stock over a four-year period expiring in January 2022.
30
ITEM 6. SELECTED FINANCIAL DATA
(Millions of dollars, except per share amounts)
FOR THE PERIOD:
2018 (a)
Year Ended September 30,
2016
2015
2017
Income statement data:
Revenues
Net income including noncontrolling interests
Deduct net income attributable to
noncontrolling interests, principally in
AmeriGas Partners
Net income attributable to UGI Corporation
Earnings per common share attributable to UGI
stockholders:
Basic
Diluted
Cash dividends declared per common share
$
$
$
$
$
$
7,651.2
822.4
(103.7)
718.7
4.13
4.06
1.020
$
$
$
$
$
$
6,120.7
523.8
(87.2)
436.6
2.51
2.46
0.975
$
$
$
$
$
$
5,685.7
488.8
(124.1)
364.7
2.11
2.08
0.930
$
$
$
$
$
$
6,691.1
414.0
(133.0)
281.0
1.62
1.60
0.890
$
$
$
$
$
$
2014
8,277.3
532.6
(195.4)
337.2
1.95
1.92
0.791
AT PERIOD END:
Balance sheet data:
Total assets
Capitalization:
Debt:
Short-term debt:
AmeriGas Propane
UGI International
Midstream & Marketing
UGI Utilities
Long-term debt (including current
maturities):
AmeriGas Propane
UGI International
UGI Utilities
Other
Total debt
UGI Corporation stockholders’ equity
Noncontrolling interests, principally in
AmeriGas Partners
Total capitalization
Ratio of capitalization:
Total debt
UGI Corporation stockholders’ equity
Noncontrolling interests, principally in
AmeriGas Partners
$ 11,980.9
$ 11,582.2
$ 10,847.2
$ 10,514.2
$ 10,062.7
$
232.0
$
140.0
$
153.2
$
1.4
2.0
189.5
17.9
39.0
170.0
0.5
25.5
112.5
68.1
0.6
49.5
71.7
$
109.0
8.0
7.5
86.3
2,569.6
2,572.3
2,333.6
2,261.9
2,266.1
748.5
838.0
9.2
4,590.2
3,681.4
838.8
751.1
9.9
4,539.0
3,163.3
779.6
671.5
10.8
4,087.2
2,844.1
774.2
619.8
11.5
3,857.3
2,685.2
562.8
639.5
12.1
3,691.3
2,659.1
418.6
577.6
750.9
880.4
1,004.1
$
8,690.2
$
8,279.9
$
7,682.2
$
7,422.9
$
7,354.5
52.8%
42.4%
4.8%
100.0%
54.8%
38.2%
7.0%
100.0%
53.2%
37.0%
9.8%
100.0%
52.0%
36.2%
11.8%
100.0%
50.2%
36.2%
13.6%
100.0%
(a) Fiscal 2018 results include impacts from the Tax Cuts and Jobs Act (“TCJA”) in the U.S. See Notes 6 and 8 to Consolidated
Financial Statements for additional information.
31
(Millions of dollars, except per share amounts)
Non-GAAP Reconciliation:
Adjusted net income attributable to UGI
Corporation:
2018
Year Ended September 30,
2016
2015
2017
2014
Net income attributable to UGI Corporation
Net (gains) losses on commodity derivative
instruments not associated with current-period
transactions (net of tax of $26.7, $31.9, $13.5,
$(30.9) and $(4.5), respectively) (a) (b)
Unrealized (gains) losses on foreign currency
derivative instruments (net of tax of $9.3,
$(9.9), $0, $0 and $0) (a)
Loss on extinguishments of debt (net of tax of
$0, $(6.1), $(5.0), $0 and $0, respectively) (a)
Integration and acquisition expenses associated
with Finagaz acquired on May 29, 2015 (net of
tax of $(12.0), $(13.7), $(10.6), $(7.7) and
$(2.2), respectively) (a)
Impairment of Partnership tradenames and
trademarks (net of tax of $(5.8), $0, $0, $0 and
$0, respectively) (a)
Impact from change in French tax rate
Remeasurement impact from TCJA
Costs associated with extinguishment of debt
(net of tax of $0, $0, $0, $(5.7) and $0,
respectively) (a) (c)
Impact of retroactive change in French tax law
Adjusted net income attributable to UGI
Corporation (d)
Adjusted diluted earnings per share:
UGI Corporation earnings per share - diluted
Net (gains) losses on commodity derivative
instruments not associated with current-period
transactions (b)
Unrealized (gains) losses on foreign currency
derivative instruments
Loss on extinguishments of debt
Integration and acquisition expenses associated
with Finagaz acquired on May 29, 2015
Impairment of Partnership tradenames and
trademarks
Impact from change in French tax rate
Remeasurement impact from TCJA
Costs associated with extinguishment of debt
Impact of retroactive change in French tax law
Adjusted diluted earnings per share (d)
$
718.7
$
436.6
$
364.7
$
281.0
$
337.2
(68.1)
(51.2)
(29.9)
53.3
(19.6)
—
13.9
9.6
—
7.9
—
—
18.5
26.2
17.3
14.9
14.5
(12.1)
(166.3)
—
—
—
(29.0)
—
—
—
—
—
—
—
—
—
—
—
4.6
—
$
$
485.6
4.06
$
$
406.1
2.46
$
$
360.0
2.08
$
$
353.8
1.60
$
$
(0.39)
(0.11)
—
0.10
0.08
(0.07)
(0.93)
—
—
2.74
$
(0.29)
(0.17)
0.30
0.08
0.05
0.15
—
(0.16)
—
—
—
2.29
$
—
0.04
0.10
—
—
—
—
—
2.05
$
—
—
0.08
—
—
—
0.03
—
2.01
$
$
6.6
—
—
4.3
—
—
—
—
5.7
353.8
1.92
0.04
—
—
0.03
—
—
—
—
0.03
2.02
(a) Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.
(b) Includes the effects of rounding.
(c) Costs associated with extinguishment of debt in Fiscal 2015 are included in “Interest expense” on the Consolidated Statements
of Income.
(d) Management uses "adjusted net income attributable to UGI" and "adjusted diluted earnings per share," both of which are non-
GAAP financial measures, when evaluating UGI's overall performance. Adjusted net income attributable to UGI is net income
attributable to UGI after excluding (1) net after-tax gains and losses on commodity and certain foreign currency derivative
instruments not associated with current-period transactions (principally comprising changes in unrealized gains and losses
32
on such derivative instruments); (2) Finagaz integration and acquisition expenses; (3) losses on extinguishments of debt; (4)
impairment of Partnership tradenames and trademarks; and (5) remeasurement impacts on deferred income tax balances
resulting from the TCJA in the U.S. and changes in French tax rates and tax law.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition
to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide
meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on
commodity and certain foreign currency derivative instruments not associated with current-period transactions and other
significant discrete items that can affect the comparison of period-over-period results.
33
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) discusses our results of
operations for Fiscal 2018, Fiscal 2017 and Fiscal 2016, 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 21 to Consolidated Financial Statements.
Because most of our businesses sell or distribute energy products used in large part for heating purposes, our results are significantly
influenced by temperatures in our service territories, particularly during the peak heating-season months of October through March.
Accordingly, our results of operations, after adjusting for the effects of gains and losses on derivative instruments not associated
with current period transactions as further discussed below under “Non-GAAP Financial Measures - Adjusted Net Income
Attributable to UGI and Adjusted Diluted Earnings Per Share,” are significantly higher in our first and second fiscal quarters.
UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted earnings per share,” both of
which are financial measures not in accordance with accounting principles generally accepted in the United States of America
(“GAAP”), when evaluating UGI’s overall performance. Management believes that these non-GAAP measures provide meaningful
information to investors. Adjusted net income attributable to UGI Corporation excludes (1) net after-tax gains and losses on
commodity and certain foreign currency derivative instruments not associated with current-period transactions and (2) other
significant discrete items that management believes affect the comparison of period-over-period results (as such items are further
described below). UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under
GAAP. Volatility in net income attributable to UGI Corporation as determined in accordance with GAAP can occur as a result of
gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions.
These gains and losses result principally from recording changes in unrealized gains and losses on these derivative instruments.
However, because these derivative instruments economically hedge anticipated future purchases or sales of energy commodities
or, in the case of certain foreign currency derivatives, reduce volatility in anticipated future earnings associated with our foreign
operations, we expect that such gains and losses will be largely offset by gains or losses on anticipated future energy commodity
transactions or mitigate the volatility in anticipated future earnings associated with our European operations. For further
information, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per
Share” below and Note 21 to Consolidated Financial Statements.
Executive Overview
Net Income Attributable to UGI Corporation by Business Unit (GAAP)
(Dollars in millions)
AmeriGas Propane
UGI International
Midstream & Marketing
UGI Utilities
Corporate & Other (b)
2018 (a)
2017
2016
Amount
% of
Total
Amount
% of
Total
Amount
% of
Total
$
174.7
138.6
196.8
148.9
59.7
24.3% $
19.3%
27.4%
20.7%
8.3%
44.6
158.6
86.9
116.0
30.5
10.2% $
36.3%
19.9%
26.6%
7.0%
43.2
111.6
97.4
87.1
25.4
11.8%
30.6%
26.7%
23.9%
7.0%
Net income attributable to UGI Corporation
$
718.7
100.0% $
436.6
100.0% $
364.7
100.0%
(a) Fiscal 2018 net income attributable to UGI Corporation by business unit reflects the impacts of the TCJA in the U.S., and
UGI International’s Fiscal 2018 and Fiscal 2017 net income also reflects the impacts of tax legislation in France. See “Impact
of Tax Reform” below and Note 6 to Consolidated Financial Statements.
(b) Corporate & Other includes net after-tax gains on commodity derivative instruments not associated with current-period
transactions of $68.1 million, $51.2 million and $29.9 million in Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively.
Corporate & Other also includes after-tax unrealized gains (losses) on certain foreign currency derivative instruments of $19.6
million and $(13.9) million in Fiscal 2018 and Fiscal 2017, respectively. See Note 21 to Consolidated Financial Statements
for a discussion of amounts included in Corporate & Other.
Fiscal 2018 Financial Review
Our Fiscal 2018 operating results reflect temperatures based upon heating degree days that were normal, or slightly warmer than
normal, in each of our business units’ service territories. Compared to Fiscal 2017, average temperatures in our domestic business
units were significantly colder, while temperatures in our UGI International business in Europe were slightly warmer. After two
34
consecutive years of significantly warmer-than-normal weather in the U.S., the return of more normal weather in Fiscal 2018
enabled us to demonstrate the earnings potential of our existing businesses and our recent acquisitions and investments. Our Fiscal
2018 net income attributable to UGI also reflects the enactment of the TCJA.
Our net income attributable to UGI as determined in accordance with GAAP was $718.7 million, equal to $4.06 per diluted share,
compared with $436.6 million, equal to $2.46 per diluted share, in Fiscal 2017. The significantly higher GAAP net income
attributable to UGI and diluted earnings per share reflects, among other things, the remeasurement impacts on our deferred income
tax assets and liabilities from the TCJA and changes in French income tax rates enacted in early Fiscal 2018. The higher Fiscal
2018 GAAP net income attributable to UGI and diluted earnings per share also reflect higher net gains on certain derivative
instruments not associated with current-period transactions. Our adjusted net income attributable to UGI for Fiscal 2018 was
$485.6 million, equal to $2.74 per diluted share, a 20% increase over Fiscal 2017’s adjusted net income and adjusted diluted
earnings per share. Our Fiscal 2018 GAAP and adjusted net income attributable to UGI and GAAP and adjusted diluted earnings
per share were records for the Company. For further information on our non-GAAP financial measures “adjusted net income
attributable to UGI Corporation” and “adjusted diluted earnings per share,” including reconciliations of these measures to the most
directly comparable GAAP measures, see “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted
Diluted Earnings Per Share” below. While the 20% increase in our adjusted results reflects the beneficial effects of the more
favorable weather and the current-year benefits of the lower U.S. federal tax rate, it also reflects contributions from recent natural
gas infrastructure investments relating to our growing network in the Marcellus Shale in Pennsylvania, growth initiatives at each
of our business units and a base rate increase at UGI Utilities.
While average weather at each of our business units in Fiscal 2018 was normal, or slightly warmer than normal, each of our
businesses responded well to significant variability in weather patterns during the Fiscal 2018 heating season. In our domestic
operations, cold weather arrived later than normal with temperatures in October and November averaging nearly 10% warmer
than normal. Extremely cold weather arrived in late December and early January in the U.S. This cold weather resulted in record
peak day sendout at our Gas Utility for several consecutive days during the first week in January. In addition, our Midstream &
Marketing business saw the return of price volatility and cold weather opportunities which favorably impacted capacity management
and peaking margin. February temperatures in the U.S. were significantly warmer than normal but turned colder in mid-March
through April, with April 2018 being the coldest in more than 20 years. At our UGI International business in Europe, retail LPG
volumes early in Fiscal 2018 were reduced by an unfavorable fall crop drying season and temperatures that were warmer than
normal. Our UGI International volumes benefited later in the heating season as a result of extremely cold weather in February
and March, as many parts of Europe experienced cold and snow not experienced in decades.
As previously mentioned, our Fiscal 2018 results also include incremental earnings from recent investments, business acquisitions
and organic growth. These incremental earnings include the full-year operation of the Sunbury Pipeline, incremental earnings
from our Texas Creek natural gas gathering system, increases in peaking contracts and higher electricity generation volumes and
unit margins at Midstream & Marketing; customer growth and the PNG rate case at UGI Utilities; continued growth in our ACE
and National Accounts programs at AmeriGas Propane; and the DVEP and UniverGas acquisitions at UGI International.
Impact of Tax Reform
Our Fiscal 2018 results reflect the impacts of two significant tax law changes: the TCJA in the U.S. and December 2017 tax
legislation in France (the “December 2017 French Finance Bills”). Among other things, the TCJA reduces the U.S. federal income
tax rate from 35% to 21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on
previously un-repatriated foreign earnings, and allows for immediate capital expensing of certain qualified property, which for
UGI Utilities and certain FERC-regulated assets will be eliminated beginning in Fiscal 2019. The December 2017 French Finance
Bills increased the Fiscal 2018 corporate income tax rate in France to 39.4% from 34.4%, but includes measures to reduce the
corporate income tax rate, over time, to 25.8% effective for fiscal years starting after January 1, 2022 (Fiscal 2023).
As a result of the TCJA and the December 2017 French Finance Bills, during Fiscal 2018 we adjusted our deferred income tax
assets and liabilities to remeasure our existing U.S. and French deferred income tax assets and liabilities at the new tax rates in
the U.S. and France. The net adjustment to our deferred income tax assets and liabilities resulting from the TCJA reduced our
Fiscal 2018 income tax expense by $166.3 million equal to $0.93 per diluted share. Due to the effects of utility ratemaking, most
of the reduction in UGI Utilities’ deferred income tax assets and liabilities was not recognized immediately in income tax expense
but has been reflected in regulatory assets and liabilities in accordance with utility ratemaking. The net adjustment to our deferred
income tax assets and liabilities in France resulting from the December 2017 French Finance Bills reduced our Fiscal 2018 income
tax expense by $12.1 million equal to $0.07 per diluted share. On a combined basis, these remeasurement adjustments to our
deferred income tax assets and liabilities reduced our Fiscal 2018 income taxes, and increased our net income attributable to UGI,
by $178.4 million or $1.01 per diluted share. Although these remeasurement adjustments decreased our income tax expense and
increased our GAAP net income, we have eliminated these remeasurement adjustments from our non-GAAP adjusted results.
35
In addition to the remeasurement adjustments related to our U.S. and French income tax assets and liabilities, our income tax
expense for Fiscal 2018 was further reduced by approximately $52.1 million (equal to $0.30 per diluted share) principally as a
result of our lower Fiscal 2018 blended U.S. income tax rate of 24.5% compared to 35% previously. However, the impact of this
decrease in income taxes was partially offset by the after-tax reduction in UGI Utilities’ revenues resulting from a May 2018
PAPUC Order. In accordance with this Order, UGI Utilities reduced its revenues by $24.1 million, and established an associated
regulatory liability, related to $17.1 million (equal to $0.10 per diluted share) of tax benefits resulting from the change in the
federal tax rate from 35% to 21% for the period January 1, 2018 through June 30, 2018. After adjusting for this reduction in UGI
Utilities’ revenues, the impact of the TCJA increased Fiscal 2018 earnings (excluding the remeasurement effects previously
mentioned) by $35.0 million (equal to $0.20 per diluted share). This Fiscal 2018 current-period benefit from the TCJA in the U.S.
was reduced by a modest $0.6 million increase in Fiscal 2018 current-period income taxes in France resulting from the higher
Fiscal 2018 French income tax rate.
In addition to the requirement to establish a regulatory liability for the tax benefits resulting from the TCJA for the period January
1, 2018 to June 30, 2018, the PAPUC also ordered each regulated utility currently not in a general base rate case proceeding to
reduce their rates through a reconcilable negative surcharge applied to bills rendered on or after July 1, 2018. The negative surcharge
will remain in place until the effective date of new rates established in the utility’s next general base rate proceeding. This negative
surcharge effectively offsets the effects of the TCJA on income taxes at UGI Utilities until such effects are considered in future
rate proceedings. The impact of the negative surcharge on net income for the period July 1, 2018 to September 30, 2018, was not
material.
For further information on the TCJA, the December 2017 French Finance Bills, the regulatory impacts on UGI Utilities resulting
from the TCJA and the actions of the PAPUC, see Notes 6 and 8 to Consolidated Financial Statements.
Strategic Initiatives
During Fiscal 2018, we continued to make significant strategic and operational progress in support of our long-term goals. AmeriGas
Propane continued to drive costs out of the business through operating efficiencies, the application of technology solutions, and
organizational management initiatives. Through continued expansion and enhancement of technology initiatives, AmeriGas
Propane continued to reduce distribution costs and optimize delivery routing to increase the efficiency of its distribution model.
AmeriGas Propane experienced a significant increase in the number of customer accounts registered for online capabilities and
has developed and deployed other technology-enabled methods to communicate with customers. Volumes from the ACE cylinder
program in Fiscal 2018 were the highest on record reflecting an increase in the number of retail locations including locations
offering 24/7 automated self-service vending machines, and the National Account program’s performance in Fiscal 2018 benefited
from double-digit volume growth due in large part to more normal winter weather and customer growth.
During Fiscal 2018, UGI International completed the integration of Finagaz acquired in May 2015 on time, achieving higher-than-
expected synergies. In addition, UGI International integrated three smaller businesses acquired in late Fiscal 2017 and early Fiscal
2018, including LPG distribution businesses in Sweden and Italy as well as DVEP, a leading energy marketer in the Netherlands.
In addition, UGI International centralized its European supply and commodity hedging functions in France, continued to build-
out its cylinder distribution model including vending machines and expansion of retail chain customers, and executed the start-
up of a natural gas marketing business in the United Kingdom. We also made significant progress on the implementation of the
newly enacted European data privacy regulation, the Global Data Protection Regulation, across our European operations.
During Fiscal 2018, Midstream & Marketing acquired a midstream gas gathering system, Texas Creek, which included 60 miles
of natural gas gathering lines, and acquired the Endless Mountain natural gas gathering system. Both of these gathering systems
operate in the Marcellus Shale in northern Pennsylvania. Midstream & Marketing also acquired a 44 megawatt natural gas turbine
adding capacity to the Hunlock site. In addition to these and other strategic asset acquisitions, Midstream & Marketing completed
the Steelton LNG storage and vaporization unit, which is an important component of satisfying growing peak-day demand, and
achieved several important milestones on the PennEast pipeline project including receipt of the FERC certificate of public
convenience and necessity in January 2018.
UGI Utilities added over 14,000 new residential and commercial heating customers during Fiscal 2018 with conversions accounting
for the majority of the additions. In January, UGI Utilities filed a base rate request for the Electric Division. New rates for Electric
Utility went into effect in late October 2018. UGI Utilities continued to invest in its distribution system deploying nearly $340
million in capital, including approximately $185 million for replacement and betterment, and received regulatory approval for the
merger of UGI Utilities’ three utility companies effective October 1, 2018. During Fiscal 2018, UGI Utilities also completed the
design of UNITE Phase 2, its Enterprise Resource Planning (“ERP”) system, and made substantial progress on the build phases
of the project. UGI Utilities also made significant progress toward the completion of its new corporate headquarters building,
which is expected to be completed in the spring of Fiscal 2019.
36
At the UGI Corporation level, we implemented the first phase of a global human resource management tool for our domestic
entities, made significant progress on a new enterprise performance management and reporting tool; and developed a global IT
security framework.
Financing Transactions and Liquidity
In October 2017, UGI Utilities entered into a $125 million unsecured variable-rate term loan due through October 2022 with a
group of banks. Proceeds from the Utilities Term Loan were used by UGI Utilities to repay revolving credit agreement borrowings
and for general corporate purposes. We have entered into an interest rate swap that will fix the underlying interest rate on this debt
at approximately 3% beginning September 30, 2019. In December 2017, AmeriGas Propane, L.P. (“AmeriGas OLP”) entered into
the Second Amended and Restated Credit Agreement that provides for borrowings up to $600 million (including a $150 million
sublimit for letters of credit) and expires in December 2022. Also in December 2017, UGI International, LLC entered into a secured
multicurrency revolving facility with a group of banks providing for borrowings up to €300 million through 2020. As further
described below, this revolving facility was replaced with a new revolving credit facility in October 2018 as part of the UGI
International refinancing transaction.
On October 25, 2018, UGI International, LLC, a wholly owned second-tier indirect subsidiary of UGI Corporation, completed a
significant refinancing transaction and (i) issued €350 million of 3.25% bonds due November 2025 through an underwritten private
placement, (ii) borrowed €300 million under its 2018 UGI International Credit Facilities Agreement term loan facility, and (iii)
entered into a €300 million multicurrency revolving credit facility. The €300 million term loan is due, and the new multicurrency
revolving facility expires, in October 2023. The proceeds from the term loan and the 3.25% bonds plus cash on hand were used
to repay UGI France’s and Flaga’s term loans ahead of schedule. For additional information on this refinancing, see “Financial
Condition and Liquidity” below and Note 5 to Consolidated Financial Statements.
We believe each of our business units has sufficient liquidity to fund business operations during Fiscal 2019 (see “Financial
Condition and Liquidity” below).
Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share
Adjusted Net Income Attributable to UGI Corporation by Business Unit (Non-GAAP)
(Dollars in millions)
AmeriGas Propane
UGI International
Midstream & Marketing
UGI Utilities
Corporate & Other
2018
2017
2016
Amount
% of
Total
Amount
% of
Total
Amount
$
76.3
153.1
126.7
140.9
(11.4)
15.7 % $
31.5 %
26.1 %
29.0 %
(2.3)%
54.2
155.8
86.9
116.0
(6.8)
406.1
13.3 % $
38.4 %
21.4 %
28.6 %
(1.7)%
100.0 % $
51.1
128.9
87.1
97.4
(4.5)
360.0
% of
Total
14.2 %
35.8 %
24.2 %
27.1 %
(1.3)%
100.0 %
Net income attributable to UGI Corporation
$
485.6
100.0 % $
As previously mentioned, UGI management uses “adjusted net income attributable to UGI Corporation” and “adjusted diluted
earnings per share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Adjusted net
income attributable to UGI Corporation is net income attributable to UGI after excluding (1) net after-tax gains and losses on
commodity and certain foreign currency derivative instruments not associated with current-period transactions (principally
comprising changes in unrealized gains and losses on such derivative instruments); (2) Finagaz integration expenses; (3) losses
on extinguishments of debt; (4) impairments of Partnership tradenames and trademarks; and (5) remeasurement impacts on income
tax balances resulting from the enactments of the TCJA and French Finance Bills.
UGI does not designate its commodity and certain foreign currency derivative instruments as hedges under GAAP. Volatility in
net income attributable to UGI Corporation as determined in accordance with GAAP can occur as a result of gains and losses on
commodity and certain foreign currency derivative instruments not associated with current-period transactions. These gains and
losses result principally from recording changes in unrealized gains and losses on unsettled commodity and certain foreign currency
derivative instruments and, to a much lesser extent, certain realized gains and losses on settled commodity derivative instruments
that are not associated with current-period transactions. However, because these derivative instruments economically hedge
anticipated future purchases or sales of energy commodities, or in the case of certain foreign currency derivatives reduce volatility
37
in anticipated future earnings associated with our foreign operations, we expect that such gains or losses will be largely offset by
gains or losses on anticipated future energy commodity transactions or mitigate volatility in anticipated future earnings. For further
information on the Company’s accounting for commodity and certain foreign currency derivative instruments, see Notes 2 and
17 to Consolidated Financial Statements.
Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to,
and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide
meaningful information to investors about UGI’s performance because they eliminate the impact of gains and losses on commodity
and certain foreign currency derivative instruments not associated with current-period transactions and other significant discrete
items that can affect the comparison of period-over-period results.
The following tables reconcile net income attributable to UGI Corporation, the most directly comparable GAAP measure, to
adjusted net income attributable to UGI Corporation and reconcile diluted earnings per share, the most comparable GAAP measure,
to adjusted diluted earnings per share, to reflect the adjustments referred to above for Fiscal 2018, Fiscal 2017 and Fiscal 2016.
38
Year Ended September 30, 2018
Adjusted net income
attributable to UGI
Corporation (millions):
Net income attributable to UGI
Corporation
Net gains on commodity
derivative instruments not
associated with current-period
transactions (net of tax of $26.7)
(a)
Unrealized gains on foreign
currency derivative instruments
(net of tax of $9.3) (a)
Integration expenses associated
with Finagaz (net of tax of
$(12.0)) (a)
Impairment of Partnership
tradenames and trademarks (net
of tax of $(5.8)) (a)
Impact from December 2017
French Finance Bills
Remeasurement impact from
TCJA
Adjusted net income (loss)
attributable to UGI Corporation
Adjusted diluted earnings per
share:
UGI Corporation earnings per
share - diluted
Net gains on commodity
derivative instruments not
associated with current-period
transactions (b)
Unrealized gains on foreign
currency derivative instruments
Integration expenses associated
with Finagaz
Impairment of Partnership
tradenames and trademarks
Impact from December 2017
French Finance Bills
Remeasurement impact from
TCJA (b)
Adjusted diluted earnings (loss)
per share
Total
AmeriGas
Propane
UGI
International
Midstream
& Marketing UGI Utilities
Corporate &
Other
$ 718.7
$
174.7
$
138.6
$
196.8
$
148.9
$
59.7
(68.1)
(19.6)
18.5
14.5
(12.1)
—
—
—
14.5
—
—
—
18.5
—
(12.1)
—
—
—
—
—
—
—
—
—
—
(68.1)
(19.6)
—
—
—
(166.3)
(112.9)
8.1
(70.1)
(8.0)
16.6
$ 485.6
$
76.3
$
153.1
$
126.7
$
140.9
$
(11.4)
$
4.06
$
0.99
$
0.78
$
1.11
$
0.84
$
0.34
(0.39)
(0.11)
0.10
0.08
(0.07)
(0.93)
—
—
—
0.08
—
(0.64)
—
—
0.10
—
(0.07)
0.06
—
—
—
—
—
—
—
—
—
—
(0.39)
(0.11)
—
—
—
(0.39)
(0.04)
0.08
$
2.74
$
0.43
$
0.87
$
0.72
$
0.80
$
(0.08)
39
Year Ended September 30,
2017
Adjusted net income
attributable to UGI
Corporation (millions):
Net income attributable to UGI
Corporation
Net gains on commodity
derivative instruments not
associated with current-period
transactions (net of tax of
$31.9) (a)
Unrealized losses on foreign
currency derivative instruments
(net of tax of $(9.9)) (a)
Loss on extinguishments of
debt (net of tax of $(6.1)) (a)
Integration expenses associated
with Finagaz (net of tax of
$(13.7)) (a)
Impact from December 2016
French Finance Bills
Adjusted net income (loss)
attributable to UGI Corporation
Adjusted diluted earnings per
share:
UGI Corporation earnings per
share – diluted
Net gains on commodity
derivative instruments not
associated with current-period
transactions
Unrealized losses on foreign
currency derivative instruments
Loss on extinguishments of
debt
Integration expenses associated
with Finagaz
Impact from December 2016
French Finance Bills
Total
AmeriGas
Propane
UGI
International
Midstream
& Marketing UGI Utilities
Corporate &
Other
$
436.6
$
44.6
$
158.6
$
86.9
$
116.0
$
30.5
$
$
(51.2)
13.9
9.6
26.2
(29.0)
—
—
9.6
—
—
—
—
—
26.2
(29.0)
—
—
—
—
—
—
—
—
—
—
(51.2)
13.9
—
—
—
406.1
$
54.2
$
155.8
$
86.9
$
116.0
$
(6.8)
2.46
$
0.25
$
0.89
$
0.49
$
0.66
$
0.17
(0.29)
0.08
0.05
0.15
(0.16)
—
—
0.05
—
—
—
—
—
0.15
(0.16)
—
—
—
—
—
—
—
—
—
—
(0.29)
0.08
—
—
—
Adjusted diluted earnings (loss)
per share
$
2.29
$
0.30
$
0.88
$
0.49
$
0.66
$
(0.04)
40
Year Ended September 30,
2016
Adjusted net income
attributable to UGI
Corporation (millions):
Net income attributable to UGI
Corporation
Net gains on commodity
derivative instruments not
associated with current-period
transactions (net of tax of
$13.5) (a)
Loss on extinguishments of
debt (net of tax of $(5.0)) (a)
Integration expenses associated
with Finagaz (net of tax of
$(10.6)) (a)
Adjusted net income (loss)
attributable to UGI Corporation
Adjusted diluted earnings per
share:
UGI Corporation earnings per
share - diluted
Net gains on commodity
derivative instruments not
associated with current-period
transactions (b)
Loss on extinguishments of
debt
Integration expenses associated
with Finagaz
Adjusted diluted earnings per
share
Total
AmeriGas
Propane
UGI
International
Midstream
& Marketing UGI Utilities
Corporate &
Other
$
364.7
$
43.2
$
111.6
$
87.1
$
97.4
$
25.4
(29.9)
7.9
17.3
—
7.9
—
—
—
17.3
—
—
—
—
—
—
(29.9)
—
—
360.0
$
51.1
$
128.9
$
87.1
$
97.4
$
(4.5)
2.08
$
0.25
$
0.64
$
0.50
$
0.55
$
0.14
$
$
(0.17)
0.04
0.10
—
0.04
—
—
—
0.10
—
—
—
—
—
—
(0.17)
—
—
$
2.05
$
0.29
$
0.74
$
0.50
$
0.55
$
(0.03)
(a) Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.
(b) Includes the effects of rounding.
41
Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2018 with Fiscal 2017 and (2) Fiscal 2017
with Fiscal 2016.
Fiscal 2018 Compared with Fiscal 2017
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
(Dollars in millions)
AmeriGas Propane (b)(c)
UGI International (d)(e)
Midstream & Marketing
UGI Utilities (f)
Corporate & Other (g)(h)
2018
2017
Variance - Favorable
(Unfavorable)
Amount
(a)
% of
Total
Amount
% of
Total
Amount
% Change
$
174.7
138.6
196.8
148.9
59.7
24.3% $
19.3%
27.4%
20.7%
8.3%
44.6
158.6
86.9
116.0
30.5
10.2% $
36.3%
19.9%
26.6%
7.0%
130.1
(20.0)
109.9
32.9
29.2
291.7 %
(12.6)%
126.5 %
28.4 %
N.M.
64.6 %
Net income attributable to UGI Corporation
$
718.7
100.0% $
436.6
100.0% $
282.1
(a) Fiscal 2018 net income attributable to UGI Corporation includes income (loss) from remeasurement adjustments to tax-related
accounts as a result of the enactment of the TCJA as follows:
AmeriGas Propane
UGI International
Midstream & Marketing
UGI Utilities
Corporate & Other
Net income attributable to UGI Corporation
$
$
112.9
(8.1)
70.1
8.0
(16.6)
166.3
In addition to the remeasurement adjustments above, Fiscal 2018 income tax expense was reduced by an additional $52.1
million principally due to a lower federal income tax rate in Fiscal 2018 as a result of the TCJA.
(b) Fiscal 2018 includes after-tax impairment charge of $14.5 million as a result of the plan to discontinue use of certain Partnership
tradenames and trademarks.
(c) Fiscal 2017 includes net after-tax loss of $9.6 million from extinguishments of debt.
(d) Fiscal 2018 includes beneficial impact of a $12.1 million remeasurement adjustment to net deferred income tax liabilities
associated with the enactment of the December 2017 French Finance Bills. Fiscal 2017 includes beneficial impact of a $29.0
million remeasurement adjustment to net deferred income tax liabilities associated with a change in French income tax rate
and an income tax settlement refund of $6.7 million, plus interest, in France. In addition to these remeasurement adjustments,
Fiscal 2018 also reflects the current-year negative impact of the December 2017 French Finance Bills which decreased Fiscal
2018 net income attributable to UGI by approximately $0.6 million.
(e) Includes after-tax integration expenses associated with Finagaz of $18.5 million and $26.2 million for Fiscal 2018 and Fiscal
2017, respectively.
(f) Fiscal 2018 includes reduction in net income of $17.1 million to reflect the establishment of a regulatory liability and associated
deferred income taxes from tax savings incurred during the period January 1, 2018 to June 30, 2018 as a result of the TCJA.
(g) Includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $68.1
million and $51.2 million for Fiscal 2018 and Fiscal 2017, respectively. Also includes after-tax unrealized gains (losses) on
certain foreign currency derivative instruments of $19.6 million and $(13.9) million for Fiscal 2018 and Fiscal 2017,
respectively.
(h) Fiscal 2017 includes a $7.1 million after-tax loss associated with the impairment of a cost basis investment.
N.M. — Variance is not meaningful.
42
AmeriGas Propane
(Dollars in millions)
Revenues
Total margin (a)
Partnership operating and administrative expenses (b)
Impairment of Partnership tradenames and trademarks (c)
Partnership Adjusted EBITDA (d)(e)
Operating income (e)(f)(g)
Retail gallons sold (millions)
Degree days – % colder (warmer) than normal (h)
2018
2017
Increase (Decrease)
$
$
$
$
$
$
2,823.0
1,508.3
923.1
75.0
605.5
347.2
$
$
$
$
$
$
2,453.5
1,450.6
915.1
$
$
$
— $
551.3
355.3
$
$
1,081.3
1,046.9
0.3%
(11.3)%
369.5
57.7
8.0
75.0
54.2
(8.1)
34.4
—
15.1 %
4.0 %
0.9 %
N.M.
9.8 %
(2.3)%
3.3 %
—
(a) Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2018 and Fiscal 2017 excludes net pre-
tax gains of $12.5 million and $31.1 million, respectively, on commodity derivative instruments not associated with current-
period transactions.
(b) Operating and administrative expenses in Fiscal 2017 include a $7.5 million environmental accrual associated with the site
of a former manufactured gas plant (“MGP”) obtained in a prior-year acquisition (see Note 15 to Consolidated Financial
Statements).
(c) Fiscal 2018 reflects $75.0 million impairment charge associated with a plan to discontinue the use of certain Partnership
tradenames and trademarks (see Note 11 to Consolidated Financial Statements).
(d) Partnership Adjusted EBITDA should not be considered as an alternative to net income (loss) (as an indicator of operating
performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted
EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated
Financial Statements).
(e) Fiscal 2017 reflects adjustments to correct previously recorded gains on sales of fixed assets ($8.8 million) and decreased
depreciation expense ($1.1 million) relating to certain assets acquired with the Heritage Propane acquisition in 2012, which
reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income by $7.7 million.
(f) Amounts for Fiscal 2017 reflect an adjustment to correct depreciation expense associated with prior periods which reduced
operating income by $7.5 million.
(g) Operating income reflects certain operating and administrative expenses of the General Partner.
(h) Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided
by the National Oceanic and Atmospheric Administration (“NOAA”) for 344 Geo Regions in the United States, excluding
Alaska and Hawaii.
N.M. - Variance is not meaningful.
AmeriGas Propane’s retail gallons sold during Fiscal 2018 were 3.3% higher than in Fiscal 2017. Average temperatures based
upon heating degree days during Fiscal 2018 were 0.3% colder than normal and 13.0% colder than Fiscal 2017.
AmeriGas Propane retail propane revenues increased $337.9 million during Fiscal 2018 reflecting the effects of higher average
retail selling prices ($267.5 million) and higher retail volumes sold ($70.4 million). Wholesale propane revenues increased $24.4
million reflecting the effects of higher average wholesale selling prices ($13.5 million) and higher wholesale volumes sold ($10.9
million). Average daily wholesale propane commodity prices during Fiscal 2018 at Mont Belvieu, Texas, one of the major supply
points in the U.S., were approximately 36% higher than such prices during Fiscal 2017. Other revenues in Fiscal 2018 were slightly
higher than in the prior year principally reflecting higher service and ancillary revenues. AmeriGas Propane cost of sales increased
$311.8 million principally reflecting the effects on propane cost of sales of higher average propane product costs ($266.1 million)
and, to a much lesser extent, the effects of the higher retail and wholesale propane volumes sold ($39.6 million).
AmeriGas Propane total margin increased $57.7 million principally reflecting slightly higher retail propane total margin ($56.6
million) and slightly higher non-propane total margin ($1.1 million). The increase in retail propane total margin reflects the higher
retail volumes sold and, to a much lesser extent, slightly higher average retail propane unit margins.
Partnership Adjusted EBITDA increased $54.2 million in Fiscal 2018 principally reflecting the effects of the higher total margin
($57.7 million) and higher other operating income ($12.5 million) partially offset by a $15.5 million increase in Partnership
operating and administrative expenses (excluding the effects of the $7.5 million MGP accrual in the prior year). The increase in
other operating income largely reflects the absence of an $8.8 million adjustment recorded in Fiscal 2017 to correct previously
recorded gains on sales of fixed assets acquired with the Heritage Propane acquisition in 2012. The increase in Partnership operating
and administrative expenses reflects, among other things, higher total compensation and benefits cost ($20.4 million), principally
43
higher labor, overtime and incentive compensation costs associated with the increased activity and improved performance; higher
vehicle expenses ($10.6 million); and higher outside services expense ($6.3 million). These increases in operating expenses were
partially offset by lower general insurance and self-insured casualty and liability expense and, to a lesser extent, lower provisions
for uncollectible accounts and travel and entertainment expenses.
AmeriGas Propane operating income decreased $8.1 million in Fiscal 2018 as the $57.7 million increase in Partnership total
margin, the higher other operating income ($12.5 million) and a decrease in depreciation and amortization expense ($4.8 million)
were more than offset by the $75.0 million impairment of Partnership tradenames and trademarks and an $8.0 million increase in
operating and administrative costs (including the effects of the $7.5 million MGP accrual in the prior year).
During Fiscal 2017, AmeriGas Partners recognized a pre-tax loss of $59.7 million ($9.6 million after-tax loss attributable to UGI)
associated with early extinguishments of debt. For further information, see Note 5 to Consolidated Financial Statements.
UGI International
(Dollars in millions)
Revenues
Total margin (a)
Operating and administrative expenses (b)
Operating income
Income before income taxes (c)
LPG retail gallons sold (millions)
2018
2017
Increase
$
$
$
$
$
2,683.8
1,063.7
703.2
223.1
188.8
886.3
$
$
$
$
$
1,877.5
942.2
626.2
195.7
175.0
827.9
$
$
$
$
$
806.3
121.5
77.0
27.4
13.8
58.4
—
42.9%
12.9%
12.3%
14.0%
7.9%
7.1%
—
UGI International degree days – % (warmer) colder than
normal (d)
(5.3)%
0.7%
(a) Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2018 and Fiscal 2017 excludes net pre-
tax gains of $92.8 million and $19.0 million, respectively, on commodity derivative instruments not associated with current-
period transactions.
(b) Reflects impacts of Finagaz integration expenses for Fiscal 2018 and Fiscal 2017 of $30.5 million and $39.9 million,
respectively.
(c) Income before income taxes for Fiscal 2018 and Fiscal 2017 excludes net pre-tax unrealized gains (losses) on certain foreign
currency derivative contracts of $28.9 million and $(23.8) million, respectively.
(d) Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service
territories.
Average temperatures during Fiscal 2018 were approximately 5.3% warmer than normal and 5.9% warmer than Fiscal 2017. Total
retail gallons sold during Fiscal 2018 were higher reflecting incremental LPG retail gallons sold from our October 2017 acquisition
of UniverGas. Our existing businesses’ retail volumes were slightly lower than the prior year as slightly higher bulk sales late in
the heating season were offset by the effects of warmer weather and lower crop-drying volumes early in Fiscal 2018. During Fiscal
2018, average wholesale prices for propane and butane in northwest Europe were approximately 23% and 19% higher than in
Fiscal 2017, respectively.
UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting
periods. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent,
the British pound sterling. During Fiscal 2018 and Fiscal 2017, the average unweighted euro-to-dollar translation rates were
approximately $1.19 and $1.11, respectively, and the average unweighted British pound sterling-to-dollar translation rates were
approximately $1.35 and $1.27, respectively. Although the euro and British pound sterling were stronger during Fiscal 2018 and
affect the comparison of line item amounts presented in the table above, the beneficial impact of the stronger currencies on net
income was substantially offset by net losses on foreign currency exchange contracts.
UGI International revenues increased $806.3 million during Fiscal 2018 reflecting approximately $439 million of combined
incremental revenues from UniverGas and DVEP, higher LPG selling prices and the translation effects on our existing businesses’
revenues of the stronger euro and British pound sterling. The higher LPG selling prices reflect in large part the effects of higher
LPG product costs. UGI International cost of sales increased $684.8 million during Fiscal 2018 reflecting approximately $381
million of incremental cost of sales associated with UniverGas and DVEP, the effects on cost of sales from the higher average
LPG commodity costs, and the translation effects of the stronger euro and British pound sterling.
44
The increase in total margin principally reflects the translation effects of the stronger euro and British pound sterling on margin
(approximately $80 million), incremental margin from UniverGas and DVEP ($58 million), and slightly higher natural gas margin
from our existing energy marketing business. These increases in margin were partially offset by slightly lower total margin from
our existing retail LPG business reflecting in large part lower Fiscal 2018 income on foreign currency exchange contracts. Total
margin from our existing natural gas business increased approximately $4.9 million reflecting higher subscription fee margin
partially offset by lower average unit margins during Fiscal 2018.
The $27.4 million increase in UGI International operating income principally reflects the previously mentioned $121.5 million
increase in total margin partially offset by a $77.0 million increase in operating and administrative expenses and a $23.2 million
increase in depreciation and amortization expense. The increase in operating and administrative expenses principally reflects the
translation effects of the stronger euro and British pound sterling on local currency expenses (approximately $45.0 million) and
approximately $39 million of incremental expenses from UniverGas and DVEP. Our existing businesses’ local currency operating
and administrative expenses, excluding Finagaz integration costs, were slightly lower than the prior year as lower compensation
and benefits expense and lower tank and cylinder repair costs were largely offset by higher compliance costs associated with
energy conservation and operational safety requirements and slightly higher distribution costs. Operating and administrative
expenses in Fiscal 2018 and Fiscal 2017 include $30.5 million and $39.9 million of Finagaz integration costs, respectively. The
increase in depreciation and amortization principally reflects incremental amounts associated with UniverGas and DVEP ($9.9
million) and the translation effects of the stronger currencies. UGI International income before income taxes increased $13.8
million principally reflecting the previously mentioned $27.4 million increase in UGI International operating income reduced by
higher realized losses on foreign currency exchange contracts ($12.7 million) and slightly higher interest expense due to the effects
of the stronger euro.
Midstream & Marketing
(Dollars in millions)
Revenues
Total margin (a)
Operating and administrative expenses
Operating income
Income before income taxes
2018
2017
Increase
$
$
$
$
$
1,421.7
330.9
114.0
173.9
176.3
$
$
$
$
$
1,121.2
264.5
95.6
139.2
141.4
$
$
$
$
$
300.5
66.4
18.4
34.7
34.9
26.8%
25.1%
19.2%
24.9%
24.7%
(a) Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2018 and Fiscal 2017 excludes net pre-
tax (losses) gains of $(1.4) million and $55.7 million, respectively, on commodity derivative instruments not associated with
current-period transactions.
Temperatures across Midstream & Marketing’s energy marketing territory were approximately 1.5% warmer than normal during
Fiscal 2018 but approximately 12.0% colder than Fiscal 2017. Midstream & Marketing’s Fiscal 2018 revenues were $300.5 million
higher reflecting higher natural gas ($210.6 million) and retail power marketing ($15.0 million) revenues; higher revenues from
midstream assets ($62.4 million), principally higher natural gas gathering, peaking, and capacity management revenues; and higher
electric generation revenues ($13.1 million). The increase in natural gas revenues principally reflects the effects of higher natural
gas volumes from colder Fiscal 2018 temperatures, customer growth and slightly higher average natural gas prices. The increase
in capacity management and peaking revenues reflects the effects of colder weather in late December and January, higher capacity
values, and with respect to peaking revenues, an increase in the number of peaking contracts. The higher natural gas gathering
revenues principally reflects incremental revenues from the Sunbury Pipeline and from the Texas Creek natural gas gathering
assets acquired on October 31, 2017. Electric generation revenues reflect higher volumes generated principally from the Hunlock
natural-gas fired generation station and higher average selling prices. Midstream & Marketing cost of sales was $1,090.8 million
in Fiscal 2018 compared to $856.7 million in Fiscal 2017, an increase of $234.1 million, principally reflecting higher natural gas
and retail power cost of sales primarily a result of the higher natural gas and retail power volumes and higher average natural gas
costs.
Midstream & Marketing total margin increased $66.4 million in Fiscal 2018 reflecting higher total margin from our midstream
assets ($57.1 million), principally the result of higher natural gas gathering, capacity management and peaking total margin, and
higher electricity generation total margin ($6.9 million). Fiscal 2018 total margin from natural gas marketing was about equal to
Fiscal 2017 as slightly higher natural gas marketing volumes sold was offset by slightly lower average unit margins. The higher
natural gas gathering total margin reflects incremental margin from the Sunbury Pipeline and, to a much lesser extent, higher
margin from the recent expansion of our natural gas gathering assets including the Texas Creek natural gas gathering assets. The
increase in capacity management and peaking total margin reflects in large part the effects of extremely cold weather primarily
in late December and in January, higher capacity values and, with respect to peaking margin, a year-over-year increase in the
45
number of peaking contracts. The higher electricity generation total margin reflects higher electric generation volumes principally
at our Hunlock Station generating facility and higher electricity unit margins.
The increase in Midstream & Marketing operating income principally reflects the previously mentioned increase in total margin
($66.4 million) partially offset by higher operating and administrative expenses ($18.4 million), higher depreciation expense ($8.1
million), and a decrease in other operating income primarily reflecting the absence of AFUDC income associated with the Sunbury
Pipeline project recorded in Fiscal 2017 ($5.2 million). The $18.4 million increase in operating and administrative expenses reflects
higher compensation and benefits expense and higher expenses associated with greater peaking, LNG and natural gas gathering
activities, while the increase in depreciation expense principally reflects incremental depreciation from the expansion of our natural
gas pipeline, natural gas gathering, LNG and peaking assets. The $34.9 million increase in income before income taxes in Fiscal
2018 principally reflects the higher operating income ($34.7 million) and slightly higher AFUDC income associated with our
PennEast pipeline equity investment partially offset by slightly higher interest expense.
2018
2017
Increase
UGI Utilities
(Dollars in millions)
Revenues (a)
Total margin (a)(b)
Operating and administrative expenses
Operating income (a)
Income before income taxes (a)
Adjusted net income attributable to UGI Corporation (a)(c)
Gas Utility system throughput – billions of cubic feet (“bcf”)
Core market
Total
$
$
$
$
$
$
$
$
$
$
$
$
1,092.4
564.5
244.6
237.5
194.6
140.9
80.2
264.0
$
$
$
$
$
$
887.6
515.6
223.2
228.3
188.1
116.0
70.4
243.1
Electric Utility distribution sales - millions of kilowatt hours
(“gwh”)
Gas Utility degree days – % (warmer) than normal (d)
1,005.9
(2.1)%
950.6
(11.1)%
204.8
48.9
21.4
9.2
6.5
24.9
9.8
20.9
55.3
—
23.1%
9.5%
9.6%
4.0%
3.5%
21.5%
13.9%
8.6%
5.8%
—
(a) Gas Utility’s Fiscal 2018 revenues, total margin, operating income and income before income taxes were reduced by $24.1
million to record the effects of income tax savings that accrued during the period January 1, 2018 to June 30, 2018, in accordance
with a PAPUC Order issued May 17, 2018, related to the TCJA (see Notes 6 and 8 to Consolidated Financial Statements).
Although UGI Utilities’ income before income taxes for Fiscal 2018 was negatively impacted by this $24.1 million reduction
in revenues, the impact on UGI Utilities’ net income was offset by a reduction in Fiscal 2018 income tax expense principally
as a result of the lower federal income tax rate. The impact of the PAPUC Order on revenues for the period July 1, 2018 to
September 30, 2018 was not material.
(b) Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e., Electric Utility gross receipts
taxes, of $5.0 million and $4.7 million during Fiscal 2018 and Fiscal 2017, respectively. For financial statement purposes,
Electric Utility gross receipts taxes are included in “Operating and administrative expenses” on the Consolidated Statements
of Income (but are excluded from operating and administrative expenses presented above).
(c) Adjusted net income attributable to UGI Corporation is a non-GAAP measure. See “Non-GAAP Financial Measures - Adjusted
Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share” above for a reconciliation of UGI Utilities’ adjusted
net income attributable to UGI Corporation to the most comparable GAAP measure.
(d) Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by
NOAA for airports located within Gas Utility’s service territory.
Temperatures in Gas Utility’s service territory during Fiscal 2018 were 2.1% warmer than normal but 10.1% colder than Fiscal
2017. Gas Utility core market volumes increased 9.8 bcf (13.9%) reflecting, among other things, the effects of the colder weather
and growth in the number of core market customers. Total Gas Utility distribution system throughput increased 20.9 bcf principally
reflecting higher large firm delivery service volumes and the higher core market volumes. Gas Utility’s core market customers
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 others. These increases
were partially offset by lower interruptible delivery service volumes. Electric Utility kilowatt-hour sales were 5.8% higher than
Fiscal 2017, principally reflecting the effects of colder heating-season weather on heating-related sales, and the effects of warmer
summer weather on air-conditioning sales.
46
UGI Utilities revenues increased $204.8 million reflecting a $195.7 million increase in Gas Utility revenues and a $9.1 million
increase in Electric Utility revenues. In accordance with a PAPUC Order issued May 17, 2018, during Fiscal 2018 Gas Utility’s
revenues were reduced by $24.1 million, and an associated regulatory liability was established, to record the effects of tax savings
that accrued during the period January 1, 2018 to June 30, 2018 as a result of the TCJA. Excluding the impact on revenues from
the PAPUC Order, Gas Utility revenues increased $218.8 million principally reflecting an increase in core market revenues ($143.0
million), higher off-system sales revenues ($54.6 million), and higher large firm delivery service revenues ($21.2 million).
The $143.0 million increase in Gas Utility core market revenues principally reflects the effects of the higher core market throughput
($70.7 million), higher average retail core market PGC rates ($61.4 million) and the increase in PNG base rates effective October
20, 2017 ($10.9 million). The increase in Electric Utility revenues principally reflects higher Electric Utility distribution system
sales ($6.1 million) and higher average default service (“DS”) rates ($2.6 million). Because Gas Utility and Electric Utility are
subject to reconcilable PGC and DS recovery mechanisms, increases or decreases in the actual cost of gas or electricity associated
with customers who purchase their gas or electricity from UGI Utilities impact revenues and cost of sales but have no direct effect
on retail core-market margin (see Note 8 to Consolidated Financial Statements for a discussion of these recovery mechanisms).
UGI Utilities cost of sales was $522.9 million in Fiscal 2018 compared with $367.3 million in Fiscal 2017 principally reflecting
higher Gas Utility cost of sales ($149.3 million) and higher Electric Utility cost of sales ($6.3 million). The higher Gas Utility cost
of sales principally reflects higher average retail core market PGC rates ($61.4 million), higher cost of sales associated with Gas
Utility off-system sales ($54.6 million), and higher retail core-market volumes ($26.8 million). The higher Electric Utility cost of
sales reflects the higher electricity sales.
UGI Utilities total margin increased $48.9 million principally reflecting higher total margin from Gas Utility core market customers
($53.9 million) and higher large firm delivery service total margin ($15.8 million) partially offset by the reduction in margin
resulting from the PAPUC’s May 17, 2018 Order regarding the effects of the TCJA. The increase in Gas Utility core market margin
principally reflects the higher core market throughput ($44.6 million) and the increase in PNG base rates effective October 20,
2017 ($9.3 million). Electric Utility total margin increased $2.4 million principally reflecting the higher distribution system sales.
UGI Utilities operating income increased $9.2 million principally reflecting the increase in total margin ($48.9 million) partially
offset by higher operating and administrative expenses ($21.4 million), greater depreciation expense ($12.3 million) associated
with increased distribution system and IT capital expenditure activity, and lower other operating income ($6.1 million). The increase
in UGI Utilities operating and administrative expenses principally reflects higher uncollectible accounts expense ($9.9 million),
higher contractor and outside services expenses ($5.0 million), higher IT maintenance and consulting expenses ($4.0 million) and
higher compensation and benefits expenses ($2.6 million). The decrease in other operating income principally reflects the absence
of $5.8 million of income from an environmental insurance settlement recorded in Fiscal 2017. UGI Utilities income before income
taxes increased $6.5 million reflecting the increase in UGI Utilities operating income ($9.2 million) partially offset by higher
interest expense.
Although UGI Utilities pre-tax income increased a modest $6.5 million (3.5%) in Fiscal 2018 due to the impact on revenues from
the PAPUC Order regarding income tax savings for the period January 1, 2018 to June 30, 2018, UGI Utilities adjusted net income
attributable to UGI increased $24.9 million (21.5%). UGI Utilities Fiscal 2018 adjusted net income reflects the benefits of a $23.4
million decrease in current-year income taxes principally as a result of the lower federal income tax rate in Fiscal 2018.
Interest Expense and Income Taxes
Our consolidated interest expense during Fiscal 2018 was $230.1 million, $6.6 million higher than the $223.5 million of interest
expense recorded during Fiscal 2017. The higher interest expense principally reflects the effects of higher long-term debt
outstanding at UGI Utilities, higher average short-term borrowings and higher short-term interest rates, and the effects of the
stronger euro on UGI International interest expense. These increases were partially offset by lower average interest rates on long-
term debt at AmeriGas Propane and lower average debt outstanding at UGI International.
As previously mentioned, our consolidated income taxes for Fiscal 2018 were significantly impacted by the enactment of the TCJA
in the U.S. and the December 2017 French Finance Bills. Our effective tax rate for Fiscal 2018 reflects the effects of deferred
income tax asset and liability remeasurement adjustments resulting from the TCJA and the December 2017 French Finance Bills,
which adjustments reduced Fiscal 2018 income tax expense by $178.4 million, and the lower blended U.S. federal income tax rate
of 24.5% compared with 35% in Fiscal 2017. The effective income tax rate in Fiscal 2017 reflects the impact of a December 2016
change in the French corporate income tax rate for future years which reduced consolidated income tax expense by $29.0 million
and, to a much lesser extent, the effects of an income tax settlement refund of $6.7 million, plus interest, in France.
47
Fiscal 2017 Compared with Fiscal 2016
Consolidated Results
Net Income Attributable to UGI Corporation by Business Unit:
(Dollars in millions)
AmeriGas Propane (a)
UGI International (b)(c)
UGI Utilities
Midstream & Marketing
Corporate & Other (d)(e)
2017
2016
Variance - Favorable
(Unfavorable)
Amount
% of
Total
Amount
% of
Total
Amount
% Change
$
44.6
158.6
86.9
116.0
30.5
10.2% $
36.3%
19.9%
26.6%
7.0%
43.2
111.6
87.1
97.4
25.4
11.8% $
30.6%
23.9%
26.7%
7.0%
1.4
47.0
(0.2)
18.6
5.1
71.9
3.2 %
42.1 %
(0.2)%
19.1 %
N.M.
19.7 %
Net income attributable to UGI Corporation
$
436.6
100.0% $
364.7
100.0% $
(a) Includes net after-tax losses of $9.6 million and $7.9 million from extinguishments of debt in Fiscal 2017 and Fiscal 2016,
respectively.
(b) Fiscal 2017 includes beneficial impact of a $29.0 million adjustment to net deferred income tax liabilities associated with a
change in French income tax rate, the release of a $7.6 million valuation allowance against future uses of foreign tax credit
carryforwards and an income tax settlement refund of $6.7 million, plus interest, in France.
(c) Includes after-tax integration expenses associated with Finagaz of $26.2 million and $17.3 million in Fiscal 2017 and Fiscal
2016, respectively.
(d) Includes net after-tax gains on commodity derivative instruments not associated with current-period transactions of $51.2
million and $29.9 million in Fiscal 2017 and Fiscal 2016, respectively. Fiscal 2017 also includes $13.9 million of after-tax
unrealized losses on certain foreign currency derivative instruments.
(e) Fiscal 2017 includes a $7.1 million after-tax loss from the impairment of a cost basis investment.
N.M. — Variance is not meaningful.
AmeriGas Propane
(Dollars in millions)
Revenues
Total margin (a)
Partnership operating and administrative expenses (b)
Partnership Adjusted EBITDA (c)(d)
Operating income (d)(e)(f)
Retail gallons sold (millions)
Degree days – % (warmer) than normal (g)
2017
2016
Increase (Decrease)
$
$
$
$
$
2,453.5
1,450.6
915.1
551.3
355.3
$
$
$
$
$
2,311.8
1,447.0
928.8
543.0
356.3
$
$
$
$
$
1,046.9
1,065.5
(11.3)%
(12.4)%
141.7
3.6
(13.7)
8.3
(1.0)
(18.6)
—
6.1 %
0.2 %
(1.5)%
1.5 %
(0.3)%
(1.7)%
—
(a) Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2017 and Fiscal 2016 excludes net pre-
tax gains of $31.1 million and $66.1 million, respectively, on commodity derivative instruments not associated with current-
period transactions.
(b) Partnership operating and administrative expenses in Fiscal 2017 include a $7.5 million environmental accrual associated
with the site of a former MGP obtained in a prior-year acquisition (see Note 15 to Consolidated Financial Statements).
(c) Partnership Adjusted EBITDA should not be considered as an alternative to net income (as an indicator of operating
performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership Adjusted
EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated
Financial Statements).
(d) Fiscal 2017 includes adjustments to correct previously recorded gains on sales of fixed assets ($8.8 million) and decreased
depreciation expense ($1.1 million) relating to certain assets acquired with the Heritage Propane acquisition in 2012, which
reduced Partnership Adjusted EBITDA by $8.8 million and reduced operating income by $7.7 million.
(e) Fiscal 2017 reflects an adjustment to correct depreciation expense associated with prior periods which reduced operating
income by $7.5 million.
(f) Operating income reflects operating and administrative expenses of the General Partner.
48
(g) Deviation from average heating degree days for the 15-year period 2002-2016 based upon national weather statistics provided
by NOAA for 344 Geo regions in the United States, excluding Alaska and Hawaii.
AmeriGas Propane’s retail gallons sold during Fiscal 2017 decreased 1.7% compared with Fiscal 2016. Average temperatures
based upon heating degree days during Fiscal 2017 were significantly warmer than normal but slightly colder than Fiscal 2016.
Although average temperatures during Fiscal 2017 were slightly colder than the prior year, the critical heating season months of
January and February were approximately 9% warmer than during the same period of Fiscal 2016.
AmeriGas Propane’s retail propane revenues increased $119.0 million during Fiscal 2017 reflecting the effects of higher average
retail selling prices ($154.3 million) partially offset by the lower retail volumes sold ($35.3 million). Wholesale propane revenues
increased $11.4 million during Fiscal 2017 reflecting the effects of higher average wholesale selling prices ($11.8 million) partially
offset by lower wholesale volumes sold ($0.4 million). Average daily wholesale propane commodity prices during Fiscal 2017 at
Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 50% higher than such prices during Fiscal
2016 when commodity propane prices were at recent historic lows. Other revenues in Fiscal 2017 were slightly higher than in
Fiscal 2016. AmeriGas Propane total cost of sales increased $138.1 million principally reflecting the effects on propane cost of
sales of higher average propane product costs ($150.1 million) reduced by the effects of the lower propane volumes sold ($13.6
million).
AmeriGas Propane total margin increased $3.6 million in Fiscal 2017 as slightly lower retail propane total margin ($5.7 million)
was more than offset by higher non-propane total margin. The slight decrease in retail propane total margin principally reflects
the decrease in retail gallons sold partially offset by slightly higher average retail unit margin.
AmeriGas Propane operating income in Fiscal 2017 was approximately equal to the prior year as lower Partnership operating and
administrative expenses ($13.7 million) and the slightly higher total margin ($3.6 million) were offset by a decrease in other
operating income ($16.4 million). Partnership operating and administrative expenses in Fiscal 2017 were $13.7 million lower than
in Fiscal 2016 reflecting lower uninsured litigation and general insurance expenses ($26.8 million), resulting in large part from
the absence of a $15.0 million accrual for a class action lawsuit recorded during the fourth quarter of Fiscal 2016, and lower group
medical insurance expenses ($9.8 million). These decreases in Partnership operating and administrative expenses were partially
offset by higher vehicle expenses ($7.8 million), higher bad debt expense ($6.5 million), and a $7.5 million environmental accrual
associated with a former MGP site obtained in a prior-year acquisition. The lower other operating income in Fiscal 2017 reflects,
among other things, lower gains on asset sales ($10.3 million), primarily resulting from an $8.8 million adjustment recorded during
the first quarter of Fiscal 2017 to correct previously recorded gains on sales of fixed assets, and lower fuel tax credits ($2.8 million).
Partnership Adjusted EBITDA increased $8.3 million in Fiscal 2017 principally reflecting lower Fiscal 2017 Partnership operating
and administrative costs which, for the calculation of Partnership Adjusted EBITDA exclude the $7.5 million environmental accrual
($21.2 million), and the slightly higher total margin ($3.6 million) offset in part by the previously mentioned lower other operating
income ($16.4 million).
During Fiscal 2017, AmeriGas Partners recognized a pre-tax loss of $59.7 million ($9.6 million after-tax loss attributable to UGI)
associated with early extinguishments of debt. During Fiscal 2016, AmeriGas Partners recognized a pre-tax loss of $48.9 million
($7.9 million after-tax loss attributable to UGI) associated with early extinguishments of debt. For further information on these
transactions, see Note 5 to Consolidated Financial Statements.
UGI International
(Dollars in millions)
Revenues
Total margin (a)
Operating and administrative expenses (b)
Operating income
Income before income taxes (c)
LPG retail gallons sold (millions) (d)
2017
2016
Increase (Decrease)
$
$
$
$
$
1,877.5
942.2
626.2
195.7
175.0
827.9
$
$
$
$
$
1,868.8
965.0
639.7
206.6
182.0
820.5
$
$
$
$
$
8.7
(22.8)
(13.5)
(10.9)
(7.0)
7.4
0.5 %
(2.4)%
(2.1)%
(5.3)%
(3.8)%
0.9 %
UGI International degree days - % colder (warmer) than
normal (e)
0.7%
(7.9)%
—
—
(a) Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2017 and Fiscal 2016 excludes net pre-
tax gains of $19.0 million and $31.8 million, respectively, on UGI International commodity derivative instruments not
associated with current-period transactions.
(b) Includes Finagaz integration expenses in Fiscal 2017 and Fiscal 2016 of $39.9 million and $27.9 million, respectively.
49
(c) Fiscal 2017 excludes net pre-tax unrealized losses on certain foreign currency derivative contracts of $23.8 million.
(d) LPG retail gallons sold in Fiscal 2017 reflect a 30.7 million decline in autogas volumes principally as a result of exiting the
low-margin autogas business in Poland during Fiscal 2016. LPG retail gallons sold in Fiscal 2016 exclude retail gallons from
operations in China, which were sold in March 2016.
(e) Deviation from average heating degree days for the 15-year period 2002-2016 at locations in our UGI International service
territories.
Average temperatures during Fiscal 2017 at UGI International were 0.7% colder than normal and 9.7% colder than Fiscal 2016.
Total LPG retail gallons sold during Fiscal 2017 were slightly higher as the beneficial volume effects of the colder weather were
substantially offset by a 30.7 million gallon decline in autogas volumes, principally as a result of exiting the low-margin, high-
volume autogas business in Poland during Fiscal 2016, and lower crop-drying volumes as a result of a dry Fiscal 2017 crop season
in France. During Fiscal 2017, average wholesale commodity prices for propane and butane in northwest Europe were approximately
34% and 29%, respectively, higher than in Fiscal 2016.
UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting
periods. The functional currency of a significant portion of our UGI International results is the euro and, to a much lesser extent,
the British pound sterling. Although the British pound sterling and the euro during much of Fiscal 2017 were slightly weaker than
during Fiscal 2016, the translation effects of these currencies did not negatively impact UGI International net income due to gains
on foreign currency exchange contracts used to hedge a portion of U.S. dollar purchases of LPG.
UGI International revenues increased $8.7 million during Fiscal 2017 as higher average bulk and cylinder LPG selling prices and
the effects of the colder weather on bulk sales were substantially offset by the translation impact on revenues of the weaker British
pound sterling and euro, the effects of exiting the low-margin autogas business in Poland and lower Fiscal 2017 wholesale sales.
UGI International cost of sales increased $31.5 million during Fiscal 2017 as the effects on cost of sales from the higher average
LPG commodity costs and increase in bulk sales were partially offset by the translation impact from the weaker British pound
sterling and the euro, the effects of the lower volumes associated with exiting the autogas business in Poland, and the effects of
the lower wholesale sales.
UGI International total margin decreased $22.8 million primarily reflecting (1) the translation effects of the weaker British pound
sterling and euro; (2) slightly lower average retail bulk and cylinder LPG unit margins; and (3) the absence of margin from the
autogas business in Poland. The slightly lower average retail bulk and cylinder LPG unit margins principally reflect the negative
effects on current-year period unit margins of higher LPG commodity costs and the beneficial effects on prior-year unit margins
of declining LPG wholesale commodity costs. These decreases in unit margin were partially offset by the increase in bulk sales
resulting from the colder weather.
The $10.9 million decrease in Fiscal 2017 UGI International operating income principally reflects the previously mentioned $22.8
million decrease in total margin and a $5.0 million increase in depreciation and amortization partially offset by a $13.5 million
decrease in operating and administrative expenses and a decrease in other operating expense. The decrease in operating and
administrative expenses principally reflects lower operating and administrative costs in France resulting from expense synergies
associated with the Finagaz integration and, to a much lesser extent, the translation effects of the weaker euro and British pound
sterling offset, in part, by higher incremental Finagaz integration expenses. Operating and administrative expenses include $39.9
million and $27.9 million of Finagaz integration expenses in Fiscal 2017 and Fiscal 2016, respectively. The decrease in other
operating expense reflects, in large part, the absence of a $5.5 million loss recorded during Fiscal 2016 associated with interest
rate hedge ineffectiveness. UGI International income before income taxes decreased $7.0 million principally reflecting the
previously mentioned $10.9 million decrease in UGI International operating income offset by slightly lower interest expense due
in large part to a lower Fiscal 2017 average interest rate on UGI France SAS’s €600 million Senior Facilities Agreement term loan.
Midstream & Marketing
(Dollars in millions)
Revenues
Total margin (a)
Operating and administrative expenses
Operating income
Income before income taxes
2017
2016
Increase (Decrease)
$
$
$
$
$
1,121.2
264.5
95.6
139.2
141.4
$
$
$
$
$
866.6
264.4
90.9
146.7
144.6
$
$
$
$
$
254.6
0.1
4.7
(7.5)
(3.2)
29.4 %
— %
5.2 %
(5.1)%
(2.2)%
50
(a) Total margin represents total revenues less total cost of sales. Total margin for Fiscal 2017 and Fiscal 2016 excludes net pre-
tax gains (losses) of $55.7 and $(6.3) million, respectively, on commodity derivative instruments not associated with current-
period transactions.
Temperatures across Midstream & Marketing’s energy marketing territory were 12.1% warmer than normal but 2.2% colder than
in the prior year. Midstream & Marketing’s Fiscal 2017 revenues were $254.6 million higher than in Fiscal 2016 principally
reflecting higher natural gas revenues ($262.9 million) and, to a much lesser extent, higher peaking revenues ($15.5 million). The
increase in natural gas revenues principally reflects higher average natural gas prices, higher natural gas volumes associated with
customer growth, and the effects of the slightly colder weather, while the increase in peaking revenues reflects an increase in the
number of peaking contracts. These increases in revenues were partially offset principally by lower capacity management and
electric generation revenues. Midstream & Marketing cost of sales was $856.7 million in Fiscal 2017 compared to $602.2 million
in Fiscal 2016, an increase of $254.5 million, principally reflecting higher natural gas cost of sales primarily a result of the higher
natural gas volumes and prices.
Midstream & Marketing total margin in Fiscal 2017 was about equal to the prior year as higher peaking total margin ($15.0 million),
higher natural gas gathering total margin ($4.1 million), and higher natural gas total margin ($3.3 million) were offset primarily
by a decrease in total margin from capacity management ($10.6 million), electricity generation ($6.3 million), and storage services
($3.0 million). The increase in peaking total margin reflects an increase in the number of contracts while the higher natural gas
gathering and natural gas total margin reflects higher activity. The decline in capacity management margin reflects higher fixed
demand charges associated with higher capacity contract commitments partially offset by slightly higher prices for pipeline capacity
during the Fiscal 2017 heating season. The lower electricity generation margin reflects lower electricity price spreads, slightly
lower electricity generation volumes, and lower capacity revenue.
Midstream & Marketing operating income and income before income taxes during Fiscal 2017 decreased $7.5 million and $3.2
million, respectively. The decrease in operating income principally reflects higher depreciation expense ($4.8 million) and an
increase in operating and administrative expenses ($4.7 million). These decreases were partially offset by a $1.9 million increase
in other operating income, primarily higher AFUDC associated with pipeline capital expenditures. The $4.7 million increase in
operating and administrative expenses reflects higher wage and benefits expense partially offset by lower Conemaugh and Hunlock
electricity generating station operating and maintenance expenses, while the $4.8 million increase in depreciation expense
principally reflects incremental depreciation from the expansion of our natural gas pipeline and peaking assets. The decrease in
income before income taxes in Fiscal 2017 reflects the lower operating income partially offset by $4.3 million from our PennEast
pipeline equity investment reflecting AFUDC income.
2017
2016
Increase (Decrease)
UGI Utilities
(Dollars in millions)
Revenues
Total margin (a)
Operating and administrative expenses
Operating income
Income before income taxes
Gas Utility system throughput – billions of cubic feet (“bcf”)
Core market
Total
$
$
$
$
$
$
$
$
$
$
887.6
515.6
223.2
228.3
188.1
70.4
243.1
$
$
$
$
$
768.5
473.9
203.6
200.9
163.3
66.2
212.4
Electric Utility distribution sales - millions of kilowatt hours
(“gwh”)
Gas Utility degree days – % (warmer) colder than normal (b)
950.6
(11.1)%
961.6
(13.6)%
119.1
41.7
19.6
27.4
24.8
4.2
30.7
(11.0)
—
15.5 %
8.8 %
9.6 %
13.6 %
15.2 %
6.3 %
14.5 %
(1.1)%
—
(a) Total margin represents total revenues less total cost of sales and Electric Utility gross receipts taxes, of $4.7 million and $4.8
million during Fiscal 2017 and Fiscal 2016, respectively. Electric Utility gross receipt taxes are included in “Operating and
administrative expenses” on the Consolidated Statements of Income (but are excluded from operating and administrative
expenses presented above).
(b) Deviation from average heating degree days for the 15-year period 2000-2014 based upon weather statistics provided by
NOAA for airports located within Gas Utility’s service territory.
51
Temperatures in Gas Utility’s service territory during Fiscal 2017 were 11.1% warmer than normal but 2.6% colder than during
Fiscal 2016. Gas Utility core market volumes increased 4.2 bcf (6.3%) principally reflecting the effects of the slightly colder
Fiscal 2017 weather and growth in the number of core market customers. Total Gas Utility distribution system throughput increased
30.7 bcf reflecting significantly higher large firm delivery service volumes principally associated with service to a new natural
gas-fired generation facility and the higher core market volumes. These increases were partially offset by lower interruptible
delivery service volumes. Electric Utility kilowatt-hour sales were 1.1% lower than in the prior year, principally reflecting the
impact on air-conditioning sales from cooler summer temperatures.
UGI Utilities Fiscal 2017 revenues increased $119.1 million reflecting a $121.7 million increase in Gas Utility revenues partially
offset by slightly lower Electric Utility revenues. The higher Gas Utility revenues principally reflect an increase in core market
revenues ($85.1 million), higher large firm delivery service revenues ($14.3 million) and higher off-system sales revenues ($25.0
million). The $85.1 million increase in Gas Utility core market revenues reflects higher average retail core market PGC rates
($37.0 million), the effects of the higher core market throughput ($28.0 million) and the increase in UGI Gas base rates effective
October 19, 2016 ($20.1 million). The decrease in Electric Utility revenues principally reflects the lower Electric Utility volumes
($1.8 million), slightly lower average DS rates ($0.5 million) and lower transmission revenue ($0.4 million). UGI Utilities cost
of sales was $367.3 million in Fiscal 2017 compared with $289.8 million in Fiscal 2016, principally reflecting higher average
retail core market PGC rates ($37.0 million), the higher Gas Utility retail core-market volumes ($14.0 million) and higher cost of
sales associated with Gas Utility off-system sales ($25.0 million). The higher Gas Utility cost of sales is partially offset by a
decrease in Electric Utility cost of sales of $1.5 million reflecting the lower volumes sold and the slightly lower DS rates.
UGI Utilities total margin increased $41.7 million principally reflecting higher total margin from Gas Utility core market customers
($32.7 million) and higher large firm delivery service total margin ($11.4 million) partially offset by lower other margin. The
increase in Gas Utility core market margin principally reflects the increase in UGI Gas base rates effective October 19, 2016 ($20.1
million) and the higher core market throughput ($12.6 million). Electric Utility total margin decreased $0.8 million principally
reflecting the lower volume sales and lower transmission revenue.
UGI Utilities Fiscal 2017 operating income increased $27.4 million, principally reflecting the increase in total margin ($41.7
million) and higher other operating income, net ($10.3 million). These increases in operating income were reduced by higher
operating and administrative expenses ($19.6 million) and higher depreciation expense ($5.0 million) associated with increased
capital expenditure activity. The higher other operating income, net, reflects a $5.8 million environmental insurance settlement,
the absence of a charge recorded in the prior year related to environmental matters ($2.5 million), and lower interest on PGC
overcollections ($1.6 million). The increase in UGI Utilities operating and administrative expenses in the current year reflects
higher pension and employee benefits expenses ($7.0 million), higher customer accounts expense ($4.2 million) and higher
regulatory asset amortization expense related to environmental remediation expenses ($1.9 million). The increase in Fiscal 2017
operating and administrative expenses also reflects the fact that Fiscal 2016 expenses were reduced by the capitalization of $5.4
million of development stage IT project costs that had been expensed in prior periods but qualified for capitalization during Fiscal
2016. UGI Utilities income before income taxes increased $24.8 million reflecting the increase in UGI Utilities operating income
($27.4 million) partially offset by higher interest expense.
Interest Expense. Our consolidated interest expense during Fiscal 2017 was $223.5 million, $5.4 million lower than the $228.9
million of interest expense recorded during Fiscal 2016. The lower interest expense principally reflects lower average interest
rates on long-term debt at UGI International and AmeriGas Propane. These decreases were partially offset by the effects of higher
long-term debt outstanding at AmeriGas Propane and UGI Utilities.
Income Taxes. Our effective income tax rate was lower in Fiscal 2017 compared with Fiscal 2016. The lower effective tax rate
in Fiscal 2017 principally reflects (1) the remeasurement of our net deferred income tax liabilities in France as a result of the
reduction in the French statutory rate from 34.43% to 28.92% effective in Fiscal 2021, which reduced Fiscal 2017 income taxes
by $29.0 million; (2) the impact of excess tax benefits of $10.3 million resulting from the adoption of new accounting guidance
on share-based payments effective October 1, 2016 (see Note 2 to Consolidated Financial Statements); (3) the release of a $7.6
million valuation allowance against future uses of foreign tax credit carryforwards; and (4) an income tax settlement refund of
$6.7 million, plus interest, in France.
52
Financial Condition and Liquidity
We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements.
Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities
and, in the case of Midstream & Marketing, from a receivables purchase facility (“Receivables Facility”). Long-term cash
requirements are generally met through issuance of long-term debt or equity securities. We believe that each of our business units
has sufficient liquidity in the forms of cash and cash equivalents on hand; cash expected to be generated from operations; credit
facility and Receivables Facility borrowings; and the ability to obtain long-term financing to meet anticipated contractual and
projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not,
however, be available to us on acceptable terms.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its subsidiaries
by its principal business units. Our cash and cash equivalents totaled $452.6 million at September 30, 2018, compared with $558.4
million at September 30, 2017. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30,
2018 and 2017, UGI had cash and cash equivalents of $194.3 million and $291.1 million, respectively, a substantial portion of
which is located in the U.S. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.
AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives from AmeriGas Partners. At
September 30, 2018, our 27% effective ownership interest in the Partnership consisted of approximately 24.7 million Common
Units and an aggregate 2% general partner interest. Approximately 45 days after the end of each fiscal quarter, the Partnership
distributes all of its Available Cash (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas
Partners, as amended (the “Partnership Agreement”)) relating to such fiscal quarter. AmeriGas Propane, as general partner of
AmeriGas Partners, is entitled to receive incentive distributions when AmeriGas Partners’ quarterly distribution exceeds $0.605
per limited partner unit. During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the total amount of distributions received by the General
Partner with respect to its aggregate 2% general partner interest in the Partnership totaled $54.9 million, $52.7 million and $47.4
million, respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2018,
Fiscal 2017 and Fiscal 2016 of $45.3 million, $43.5 million and $38.2 million, respectively (see Note 14 to Consolidated Financial
Statements).
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, our principal business units paid cash dividends and made other cash payments
to UGI and its subsidiaries as follows:
Year Ended September 30,
2018
2017
2016
(Millions of dollars)
AmeriGas Propane
UGI Utilities
UGI International
Total
$
$
128.0
$
123.0
$
50.0
19.0
57.7
118.3
197.0
$
299.0
$
107.0
47.0
98.4
252.4
Cash dividends and other cash payments received from UGI International were lower in Fiscal 2018 due to the use of cash for
the acquisition of UniverGas.
Dividends and Distributions
On April 24, 2018, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.26
per Common Share, equal to $1.04 on an annualized basis. The dividend rate reflects an approximately 4% increase from the
previous quarterly rate of $0.25. The new quarterly dividend rate was effective with the dividend payable on July 1, 2018, to
shareholders of record on June 15, 2018.
During Fiscal 2018, the General Partner’s Board of Directors approved, and AmeriGas Partners paid, quarterly distributions on
AmeriGas Partners Common Units at a rate of $0.95 per Common Unit, equal to $3.80 per Common Unit for Fiscal 2018.
Repurchases of Common Stock
In January 2014, the UGI Board of Directors authorized a share repurchase program for up to 15 million shares of UGI Corporation
Common Stock. The authorization permitted the execution of the share repurchase program over a four-year period, which expired
in January 2018. On January 25, 2018, UGI’s Board of Directors authorized an extension of the share repurchase program for up
to 8 million shares of UGI Corporation Common Stock for an additional four-year period expiring in January 2022. Pursuant to
53
such authorizations, during Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company purchased on the open market 1.2 million, 0.9
million and 1.25 million shares at a total purchase price of $59.8 million, $43.3 million and $47.6 million, respectively.
Long-term Debt and Credit Facilities
The Company’s debt outstanding at September 30, 2018 and 2017, comprises the following:
(millions of dollars)
Short-term borrowings
Long-term debt (including current
maturities):
Senior notes
Term loans
Other long-term debt
Unamortized debt issuance costs
(27.5)
Total long-term debt
Total debt
$ 2,569.6
$ 2,801.6
$
$
Long-term Debt
AmeriGas
Propane
232.0
$
UGI
International
1.4
$
2018
Midstream
& Marketing
2.0
$
UGI
Utilities
189.5
$
Other
Total
2017
Total
$ — $ 424.9
$
366.9
$ 2,575.0
$
— $
— $
675.0
$ — $ 3,250.0
$ 3,250.0
—
22.1
730.1
20.9
(2.5)
748.5
749.9
$
$
—
0.4
—
0.4
2.4
160.3
6.8
(4.1)
838.0
$
$ 1,027.5
$
$
—
8.8
—
8.8
8.8
890.4
902.1
59.0
(34.1)
$ 4,165.3
$ 4,590.2
59.8
(39.8)
$ 4,172.1
$ 4,539.0
UGI International. In December 2017, Flaga repaid $9.2 million principal amount of its then-existing $59.1 million U.S. dollar
denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned
term loan, which amended the previous agreement to extend the maturity of the term loan to April 2020 (“Flaga U.S. Dollar Term
Loan”). Prior to its repayment in October 2018 (see “Subsequent Event - UGI International Refinancing” below), borrowings
under the Flaga U.S. Dollar Term Loan bore interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga effectively
fixed the LIBOR component of the interest rate, and effectively fixed the U.S. dollar value of the interest and principal payments
payable under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank.
UGI Utilities. In October 2017, UGI Utilities entered into a $125 million unsecured variable-rate term loan agreement (the “Utilities
Term Loan”) with a group of banks. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement
borrowings and for general corporate purposes. The Utilities Term Loan is payable in equal quarterly installments of $1.6 million,
commencing in March 2018, with the balance of the principal being due and payable in full on October 30, 2022. Under the
Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime
rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain
indebtedness of UGI Utilities. In July 2018, UGI Utilities entered into a forward-starting pay-fixed, receive-variable interest rate
swap that generally fixes the underlying prevailing market interest rates on Utilities Term Loan borrowings at approximately
3.00% through July 2022. This forward-starting interest rate swap commences September 30, 2019.
Subsequent Event - UGI International Refinancing
On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, entered into a five-year unsecured
Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 million variable-rate term loan which was drawn
on October 25, 2018, and (2) a €300 million senior unsecured multicurrency revolving facility agreement (together, the “2018
UGI International Credit Facilities Agreement”). The 2018 UGI International Credit Facilities Agreement matures on October 18,
2023. Term loan borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated
euribor rate, which euribor rate has a floor of zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20%, is
dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan
borrowings is 1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18,
2022, to fix the underlying euribor rate on term loan borrowings at 0.34%. Under the multicurrency revolving credit facility
agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated
euribor rate plus a margin ranging from 1.20% to 2.85%. Loans made in U.S. dollars will bear interest at the associated LIBOR
rate plus a margin ranging from 1.45% to 3.10%. The margin on revolving facility borrowings is dependent upon a ratio of net
consolidated indebtedness to consolidated EBITDA, as defined.
54
On October 25, 2018, UGI International, LLC issued in an underwritten private placement €350 million principal amount of 3.25%
senior unsecured notes due November 1, 2025 (the “UGI International 3.25% Senior Notes”). The UGI International 3.25% Senior
Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the UGI International Credit Facilities Agreement variable-
rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 million outstanding principal of UGI France
SAS’s variable-rate term loan under its 2015 Senior Facilities Agreement due April 2020; €45.8 million of outstanding principal
of Flaga’s variable-rate term loan due October 2020; and $49.9 million of outstanding principal of Flaga’s U.S. dollar variable-
rate term loan due April 2020, plus accrued and unpaid interest, and (2) for general corporate purposes.
For further information on these transactions and the Company’s other long-term borrowings, see Note 5 to Consolidated Financial
Statements.
Short-term Debt
Due to the seasonal nature of the Company’s businesses, cash provided by operating activities is generally strongest during the
second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services
consumed during the peak heating season months. Conversely, cash from operating activities is generally at its lowest levels during
the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts
receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use their credit facilities to satisfy their seasonal
operating cash flow needs. UGI International principally uses borrowings under credit agreements and cash on hand to satisfy its
operating cash flow needs. Energy Services, LLC has historically used its Receivables Facility to satisfy much of its seasonal
operating cash flow needs. Energy Services, LLC also has a $240 million credit facility, which it can use for general corporate
purposes. Borrowings under the credit facilities and the Energy Services, LLC Receivables Facility are classified as “Short-term
borrowings” on the Consolidated Balance Sheets.
AmeriGas Partners. In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement
(“AmeriGas Credit Agreement”) with a group of banks. The AmeriGas Credit Agreement amends and restates a previous credit
agreement. The AmeriGas Credit Agreement provides for borrowings up to $600 million (including a $150 million sublimit for
letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest
rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a
one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. The
applicable margin on base rate borrowings ranges from 0.50% to 1.75%, and the applicable margin on Eurodollar Rate borrowings
ranges from 1.50% to 2.75%.
UGI International. In December 2017, UGI International, LLC entered into a secured multicurrency revolving facility agreement
(the "2017 UGI International Credit Agreement") with a group of banks providing for borrowings up to €300 million through
April 2020. Under the 2017 UGI International Credit Agreement, UGI International, LLC could borrow in euros or U.S. dollars.
During Fiscal 2018, there were no borrowings made under this facility. Upon entering into the 2018 UGI International Credit
Facilities Agreement, we terminated (1) the 2017 UGI International Credit Agreement; (2) UGI France SAS’s revolving credit
facility under its 2015 Senior Facilities Agreement; and (3) Flaga’s credit facility agreement.
UGI Utilities. In September 2018, UGI Utilities entered into an Increasing Lender Commitment and Acceptance (the “Commitment
and Acceptance”) under UGI Utilities’ revolving credit agreement. The Commitment and Acceptance increased the amount of
loan commitments under this revolving credit agreement to $450 million, from $300 million previously (including a $100 million
sublimit for letters of credit), expiring in March 2020. All other terms of UGI Utilities’ revolving credit agreement remained
unchanged.
Information about the Company’s principal credit agreements (excluding Energy Services, LLC’s Receivables Facility, which is
discussed below) as of September 30, 2018 and 2017, is presented in the tables below.
55
Expiration Date
Total
Capacity
Borrowings
Outstanding
Letters of
Credit and
Guarantees
Outstanding
Available
Borrowing
Capacity
Weighted
Average
Interest Rate
- End of Year
(Millions of dollars or euros)
September 30, 2018
AmeriGas OLP
December 2022
UGI International, LLC (a)
UGI France SAS (a)
Flaga (a)(b)
Energy Services, LLC
UGI Utilities (c)
September 30, 2017
AmeriGas OLP
UGI France SAS (a)
Flaga (a)(b)
Energy Services, LLC
UGI Utilities
April 2020
April 2020
October 2020
March 2021
March 2020
June 2019
April 2020
October 2020
March 2021
March 2020
$
€
€
€
$
$
$
€
€
$
$
600.0
$
232.0
$
63.5
$
300.0
60.0
55.0
240.0
450.0
525.0
60.0
55.0
240.0
300.0
$
$
$
$
—
—
— €
—
189.5
140.0
—
$
$
— €
—
170.0
$
— €
— €
0.5
€
— $
2.0
67.2
$
$
— €
6.5
€
— $
2.0
$
304.5
300.0
60.0
54.5
240.0
258.5
317.8
60.0
48.5
240.0
128.0
4.58%
N.A.
N.A.
N.A.
N.A.
3.03%
3.74%
N.A.
N.A.
N.A.
2.11%
(a) Facility terminated on October 25, 2018, concurrent with entering into the 2018 UGI International Credit Facilities Agreement.
(b) Total capacity comprises a €25 million multi-currency revolving credit facility, a €5 million overdraft facility and a €25 million
guarantee facility. Guarantees outstanding reduce the available capacity on the €25 million guarantee facility.
(c) On September 21, 2018, UGI Utilities entered into the Commitment and Acceptance, which increased the total capacity under
this facility to $450 million.
The average daily and peak short-term borrowings under the Company’s principal credit agreements during Fiscal 2018 and Fiscal
2017 are as follows:
(Millions of dollars or euros)
Average
Peak
Average
Peak
2018
2017
AmeriGas OLP
UGI International, LLC
UGI France SAS
Flaga
Energy Services, LLC
UGI Utilities
$
€
€
€
$
$
191.2
$
349.0
$
89.3
$
292.5
— €
— €
— €
— €
— €
— €
15.5
150.4
$
$
79.0
215.0
$
$
— €
— €
— €
8.0
80.7
$
$
—
—
—
28.0
178.0
Energy Services, LLC also has a Receivables Facility with an issuer of receivables-backed commercial paper. On October 26,
2018, the expiration date of the Receivables Facility was extended to October 25, 2019. The Receivables Facility, as amended,
provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November through
April, and up to $75 million of eligible receivables during the period May through October. Energy Services, LLC uses the
Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and
for general corporate purposes.
At September 30, 2018, the outstanding balance of trade receivables was $65.0 million of which $2.0 million was sold to the bank.
At September 30, 2017, the outstanding balance of trade receivables was $44.8 million of which $39.0 million was sold to the
bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the Consolidated Balance Sheet. During Fiscal 2018
and Fiscal 2017, peak sales of receivables were $68.0 million and $49.0 million, respectively, and average daily amounts sold
were $11.3 million and $14.0 million, respectively.
For detailed information on the Company’s short-term borrowings, see Note 5 to Consolidated Financial Statements.
56
Cash Flows
Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the
second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products and services
consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the
fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable,
is generally greatest.
Operating Activities:
Year-to-year variations in our cash flows from operating activities can be significantly affected by changes in operating working
capital especially during periods with significant changes in energy commodity prices. Cash flows from operating activities in
Fiscal 2018, Fiscal 2017 and Fiscal 2016 were $1,085.3 million, $964.4 million and $969.7 million, respectively. Cash flows from
operating activities before changes in operating working capital were $1,219.7 million in Fiscal 2018, $1,133.0 million in Fiscal
2017 and $926.6 million in Fiscal 2016. The higher cash flow from operating activities before changes in operating working capital
principally reflects improved year-over-year operating results. Changes in operating working capital (used) provided operating
cash flow of $(134.4) million in Fiscal 2018, $(168.6) million in Fiscal 2017 and $43.1 million in Fiscal 2016. Cash flow from
changes in operating working capital principally reflect the impact of energy commodity prices on changes in accounts receivable,
inventories and accounts payable. The higher cash used to fund changes in operating working capital in Fiscal 2018 and Fiscal
2017 reflects, in large part, the net impact of increases in LPG and natural gas prices on accounts receivable, inventories and
accounts payable. The higher cash used to fund changes in operating working capital in Fiscal 2018 also reflects federal income
tax overpayments resulting from TCJA regulations released late in Fiscal 2018 regarding bonus depreciation for utility assets. In
addition, cash flow from changes in operating working capital in Fiscal 2018 include net overcollections of UGI Utilities purchased
gas and electricity costs of $31.0 million in Fiscal 2018, compared with net refunds of such costs of $15.4 million and $22.7
million in Fiscal 2017 and Fiscal 2016, respectively.
Investing Activities:
Investing activity cash flow is principally affected by cash expenditures for property, plant and equipment; cash paid for acquisitions
of businesses and assets; changes in restricted cash balances; and net cash proceeds from sales and retirements of property, plant
and equipment. Cash expenditures for property, plant and equipment totaled $574.4 million in Fiscal 2018, $638.9 million in Fiscal
2017 and $563.8 million in Fiscal 2016. Cash payments for property, plant and equipment were higher in Fiscal 2017 compared
with Fiscal 2018 and Fiscal 2016 reflecting in large part higher Midstream & Marketing capital expenditures associated with the
Sunbury Pipeline project. Net cash used for acquisitions of businesses and assets in Fiscal 2018 principally reflects the October
2017 acquisition of UniverGas at UGI International, and the acquisition of the Texas Creek natural gas gathering assets, a smaller
natural gas gathering system and a power generation asset at Midstream & Marketing. Fiscal 2017 reflects net cash paid for
acquisitions at AmeriGas Propane and UGI International including the acquisition of DVEP in August 2017. Net cash paid for
acquisitions of businesses in Fiscal 2016 includes business acquisitions at AmeriGas Propane and UGI International. Changes in
restricted cash, primarily cash in futures brokerage accounts, provided cash from investing activities of $0.7 million in Fiscal
2018, $6.1 million in Fiscal 2017 and $53.7 million in Fiscal 2016. The amount of restricted cash required in such accounts is
generally the result of changes in underlying commodity prices.
Financing Activities:
Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; short-term
borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances or
repurchases of equity instruments.
In October 2017, UGI Utilities issued $125 million of unsecured notes and used the proceeds to reduce short-term borrowings
and for general corporate purposes. Repayments of debt during Fiscal 2018 include UGI International’s repayments of
approximately $82 million of term-loan debt at UGI France SAS and Flaga, and UGI Utilities’ repayments of $40 million of
maturing Medium-Term Notes. During Fiscal 2017, UGI Utilities issued $100 million of Senior Notes and used the net proceeds
principally to fund infrastructure replacement and betterment capital expenditures, IT initiatives and for general corporate purposes.
During Fiscal 2017, AmeriGas Partners and AmeriGas Finance Corp. issued $700.0 million of Senior Notes the net proceeds of
which were used in large part for the early repayment of a portion of AmeriGas Partners’ 7.00% Senior Notes having an aggregate
principal balance of $500.0 million plus accrued and unpaid interest and early redemption premiums. Also during Fiscal 2017,
AmeriGas Partners and AmeriGas Finance Corp. issued $525 million of Senior Notes, the net proceeds of which were used primarily
for the early repayments in February and May of the remaining outstanding AmeriGas Partners’ 7.00% Senior Notes having an
aggregate principal balance of $480.8 million.
57
In Fiscal 2016, AmeriGas Partners issued $1.35 billion face value of AmeriGas Partners Senior Notes and used substantially all
of the net proceeds from the issuance to repay $1.27 billion principal amount of existing AmeriGas Partners Senior Notes subject
to tender offers and notices of redemptions. In addition, during Fiscal 2016 UGI Utilities issued $300 million of Senior Notes and
used the net proceeds principally to repay maturing long-term debt and short-term borrowings. The increases in dividends on UGI
Common Stock and distributions on AmeriGas Partners’ publicly held Common Units during the three-year period principally
reflect the effects of increases in quarterly dividend and distribution rates.
For further information on debt transactions, see Note 5 to Consolidated Financial Statements.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions) for Fiscal 2018, Fiscal 2017 and Fiscal 2016.
We also provide amounts we expect to spend in Fiscal 2019. We expect to finance a substantial portion of our Fiscal 2019 capital
expenditures from cash generated by operations, borrowings under credit facilities and cash on hand.
Year Ended September 30,
(Millions of dollars)
AmeriGas Propane
UGI International
Midstream & Marketing
UGI Utilities
Total
2019
(estimate)
2018
2017
2016
$
$
117.0
$
101.3
$
122.0
129.0
375.0
111.4
43.1
338.5
$
98.1
90.3
117.5
317.7
743.0
$
594.3
$
623.6
$
101.7
99.9
140.4
262.5
604.5
The higher levels of UGI Utilities capital expenditures in Fiscal 2018 and Fiscal 2017, as well as those estimated for Fiscal 2019,
reflect greater main replacement and system improvement capital expenditures, increases in new business capital expenditures
and expected investments in new IT projects. The higher level of Midstream & Marketing capital expenditures estimated for Fiscal
2019 primarily reflect expected investments in new midstream assets and new IT projects.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2018. Such obligations include scheduled repayments
of long-term debt, interest on long-term fixed-rate debt, operating lease payments, unconditional purchase obligations for pipeline
capacity, pipeline transportation and natural gas storage services and commitments to purchase natural gas, LPG and electricity,
capital expenditures and derivative instruments. The following table presents contractual cash obligations with non-affiliates under
agreements existing as of September 30, 2018:
(Millions of dollars)
Long-term debt (a)
Interest on long-term-fixed rate debt (a)(b)
Operating leases
AmeriGas Propane supply contracts
UGI International supply contracts
Midstream & Marketing supply contracts
UGI Utilities supply, storage and
transportation contracts
Derivative instruments (c)
Payments Due by Period
Total
Fiscal
2019
Fiscal
2020 - 2021
Fiscal
2022 - 2023
Thereafter
$
4,199.4
$
88.5
$
690.2
$
130.7
$
3,290.0
1,850.3
452.7
14.0
88.2
348.0
314.7
23.5
196.1
88.0
14.0
88.2
248.5
85.4
10.9
372.9
144.0
—
—
88.0
92.9
11.5
364.9
108.1
—
—
11.5
68.6
1.1
916.4
112.6
—
—
—
67.8
—
Total
$
7,290.8
$
819.6
$
1,399.5
$
684.9
$
4,386.8
(a) Based upon stated maturity dates for debt outstanding at September 30, 2018. Principal repayments relating to the UGI France
Senior Facilities term loan due through April 2020; the Flaga variable-rate term loan due October 2020; and the Flaga U.S.
dollar variable-rate term loan due April 2020, are included in the table above. These term loans were repaid on October 25,
2018 with net proceeds from the issuance of the UGI International 3.25% Senior Notes due November 2025 and the UGI
International Credit Facilities Agreement due October 2023 (see “Subsequent Event - UGI International Refinancing” above
and Note 5 to Consolidated Financial Statements).
58
(b) Based upon stated interest rates adjusted for the effects of interest rate swaps.
(c) Represents the sum of amounts due if derivative instrument liabilities were settled at the September 30, 2018 amounts reflected
in the Consolidated Balance Sheet (but excluding amounts associated with interest rate and cross-currency swaps).
“Other noncurrent liabilities” included in our Consolidated Balance Sheet at September 30, 2018, principally comprise regulatory
liabilities (see Note 8 to Consolidated Financial Statements); refundable tank and cylinder deposits (as further described in Note
2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and
casualty liabilities and obligations under environmental remediation agreements (see Note 15 to Consolidated Financial
Statements); pension and other postretirement benefit liabilities recorded in accordance with accounting guidance relating to
employee retirement plans (see Note 7 to Consolidated Financial Statements); and liabilities associated with executive
compensation plans (see Note 13 to Consolidated Financial Statements). These liabilities are not included in the table of Contractual
Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or
amount. Required minimum contributions to UGI Utilities’ pension plan (as further described below under “U.S. Pension Plan”)
in Fiscal 2019 are not expected to be material. Required minimum contributions to the U.S. Pension Plan in years beyond Fiscal
2019 will depend, in large part, on the impacts of future returns on pension plan assets and interest rates on pension plan liabilities.
Certain of our operating lease arrangements, primarily vehicle leases with remaining lease terms of one to ten years, have residual
value guarantees. Although such fair values at the end of the leases have historically exceeded the guaranteed amount, at
September 30, 2018, the maximum potential amount of future payments under lease guarantees assuming the leased equipment
was deemed worthless was approximately $55 million.
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into the Standby Equity Commitment Agreement (the “Commitment Agreement”) with
AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up
to $225 million of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital
contributions may be made from time to time during the Commitment Period upon request of the Partnership. There have been
no capital contributions made to the Partnership under the Commitment Agreement.
In consideration for any capital contributions made pursuant to the Commitment Agreement, the Partnership will issue to UGI or
a wholly owned subsidiary new Class B Common Units representing limited partner interests in the Partnership (“Class B Units”)
at a price equal to the 20-day volume-weighted average price of the Partnership’s Common Units prior to the date of the Partnership’s
capital call. The Class B Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit
yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash
or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions
from the Partnership.
Generally, at any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion
of the Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance
of the Class B Units, subject to certain conditions, the Partnership may elect to convert all or any portion of the Class B Units into
Common Units. For additional information, see Note 15 to Consolidated Financial Statements.
U.S. Pension Plan
In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG,
CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). The fair values of the U.S. Pension
Plan’s assets totaled $531.7 million and $498.0 million at September 30, 2018 and 2017, respectively. At September 30, 2018 and
2017, the underfunded positions of the U.S. Pension Plan, defined as the excess of the projected benefit obligation (“PBO”) over
the U.S. Pension Plan’s assets, were $79.5 million and $141.2 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans, including the Employee Retirement
Income Security Act of 1974 (“ERISA”) rules and regulations. Required minimum contributions to the U.S. Pension Plan in Fiscal
2018 are not expected to be material. Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2018 was $13.0 million.
Pre-tax pension cost associated with the U.S. Pension Plan in Fiscal 2019 is expected to be approximately $6.0 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. At September 30, 2018, we
have recorded after-tax charges to UGI Corporation’s stockholders’ equity of $11.0 million and recorded regulatory assets totaling
$87.1 million in order to reflect the funded status of our pension and other postretirement benefit plans. For a more detailed
discussion of the U.S. Pension Plan and our other postretirement benefit plans, see Note 7 to Consolidated Financial Statements.
59
Related Party Transactions
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, we did not enter into any related-party transactions that had a material effect on
our financial condition, results of operations or cash flows.
Off-Balance-Sheet Arrangements
UGI primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject
to the recognition and measurement guidance relating to guarantees under GAAP.
We do not have any off-balance-sheet arrangements that are expected to have a material effect on our financial condition, change
in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Utility Regulatory Matters
Utilities Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and
MDPSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. After receiving
all necessary Federal Energy Regulatory Commission (“FERC”), MDPSC, and PAPUC approvals, CPG and PNG were merged
into UGI Utilities effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued
September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI
North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI
Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities
to maintain separate accounting-type schedules for limited future ratemaking purposes.
Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution
revenues by $9.2 million, which was later reduced by Electric Utility to $7.7 million to reflect the impact of the TCJA and other
adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and
reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 million annual base distribution
rate increase for Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility is required to provide
customers with a one-time $0.2 million billing credit associated with 2018 TCJA tax benefits.
On August 31, 2017, the PAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for
an $11.3 million base distribution rate increase for PNG (now the UGI North rate district of Gas Utility). The increase became
effective October 20, 2017.
On October 14, 2016, the PAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for
a $27.0 million base distribution rate increase for UGI Gas (now the UGI South rate district of Gas Utility). The increase became
effective on October 19, 2016.
Distribution System Improvement Charge. State legislation permits gas and electric utilities in Pennsylvania to recover a
distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism
providing for a more timely cost recovery of qualifying capital expenditures between base rate cases.
PNG and CPG received PAPUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC
at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PAPUC issued a final Order
to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG
and CPG, pending reconsideration at each company’s Long-Term Infrastructure Improvement Plan filing. PNG’s DSIC has been
reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume under the UGI North rate district
upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its most recent base rate
case.
In November 2016, UGI Gas received PAPUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges
billed to customers, effective January 1, 2017. UGI Gas began recovering revenue under the mechanism effective July 1, 2018,
as it exceeded, during the third quarter of Fiscal 2018, the threshold amount of DSIC-eligible plant agreed upon in the settlement
of its recent base rate case.
Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017 explosion in Manor Township,
Lancaster County, PA, that resulted in the death of one UGI Utilities’ employee and injuries to two other UGI Utilities’ employees
60
and one sewer authority employee, and destroyed two residences and damaged several other homes, the PAPUC Bureau of
Investigation and Enforcement (“BIE”) filed a formal complaint at the PAPUC in which BIE alleges that UGI Utilities committed
multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the
explosion, and requested that the PAPUC order UGI Utilities to pay approximately $2.1 million in civil penalties, which is the
maximum allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint.
Manufactured Gas Plants
From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number
of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other
residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present
on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania
and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested
all of its utility operations other than certain Pennsylvania operations, including those now constituting UGI Gas and Electric
Utility. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG) with similar
histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG were merged into UGI Utilities effective
October 1, 2018.
Prior to the Utilities Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to a consent order and agreement
(“COA”) with the Pennsylvania Department of Environmental Protection (“PADEP”) to address the remediation of specified
former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the merger, UGI Utilities, as the
successor to CPG and PNG, is required to either obtain a certain number of points per calendar year based on defined eligible
environmental investigatory and/or remedial activities at the MGPs and in the case of one COA, an additional obligation to plug
specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap. The
cost cap of the three COAs, in the aggregate, is $5.4 million. The three COAs are currently scheduled to terminate at the end of
2031, 2020 and 2020. At September 30, 2018 and 2017, our aggregate estimated accrued liabilities for environmental investigation
and remediation costs related to the COAs totaled $51.0 million and $54.3 million, respectively. UGI Utilities has recorded
associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8 to the
Consolidated Financial Statements).
We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material
to UGI Utilities’ results of operations because UGI Utilities receives ratemaking recovery of actual environmental investigation
and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated
difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly
owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of
environmental contamination or perform environmental remediation. 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 a former subsidiary of UGI Utilities if a court were to conclude that (1) the
subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator
because of its conduct with respect to its subsidiary’s MGP. At September 30, 2018 and 2017, neither the undiscounted nor the
accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material.
Market Risk Disclosures
Our primary market risk exposures are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk.
Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions,
we do not use derivative financial and commodity instruments for speculative or trading purposes.
Commodity Price Risk
The risk associated with fluctuations in the prices the Partnership and our UGI International operations pay for LPG is principally
a result of market forces reflecting changes in supply and demand for LPG and other energy commodities. Their profitability is
sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and
UGI International may not, however, always be able to pass through product cost increases fully, or keep pace with such increases,
particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts
for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity
61
instruments including price swap contracts. Our UGI International operations use over-the-counter derivative commodity
instruments and may from time to time enter into other derivative contracts, similar to those used by the Partnership, to reduce
market risk associated with a portion of their LPG purchases. Over-the-counter derivative commodity instruments used to
economically hedge forecasted purchases of LPG are generally settled at expiration of the contract. In addition, certain of our UGI
International businesses hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases through the use of
forward foreign currency exchange contracts as further described below.
Gas Utility's tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its retail
core-market customers, including the cost of financial instruments used to hedge purchased gas costs. 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 and option 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. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's
PGC recovery mechanism.
Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of
financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism,
there is limited power cost risk, including the cost of forward electricity purchase contracts, associated with our Electric Utility
operations.
In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures contracts for a portion
of gasoline volumes expected to be used in their operations. These gasoline futures contracts are recorded at fair value with changes
in fair value reflected in “Operating and administrative expenses” on the Consolidated Statements of Income.
In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sales contracts for natural
gas and electricity, Midstream & Marketing enters into NYMEX, Intercontinental Exchange (“ICE”) and over-the-counter natural
gas and electricity futures and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream &
Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge a portion of its anticipated
sales of electricity from its electricity generation facilities. Although Midstream & Marketing’s fixed-price supply arrangements
mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to
perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s
results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a
number of suppliers. UGI International’s natural gas and electricity marketing businesses also use natural gas and electricity futures
and forward contracts to economically hedge market risk associated with fixed-price sales and purchase contracts.
From time to time, Midstream & Marketing purchases financial transmission rights (“FTRs”) to economically hedge certain
transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to
time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the
locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also uses NYMEX
futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of
natural gas or propane.
Midstream & Marketing has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by
its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to
supply electricity under these agreements, Midstream & Marketing would be required to purchase electricity on the spot market
or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact
Midstream & Marketing’s results.
Interest Rate Risk
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally
do not impact fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash
flows.
Our variable-rate debt includes short-term borrowings, the Utilities Term Loan and, prior to their repayment on October 25, 2018,
UGI France SAS’s and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to
short-term market interest rates. UGI Utilities has entered into a forward-starting, amortizing, pay-fixed, receive-variable interest
rate swap agreement commencing September 30, 2019. Prior to their repayment on October 25, 2018, UGI France SAS and Flaga,
through the use of pay-fixed, receive-variable interest rate swaps, had fixed the underlying euribor interest rates on their euro-
62
denominated term loans through all, or a substantial portion of, the periods such debt was outstanding. In addition, prior to its
repayment on October 25, 2018, Flaga’s U.S. dollar-denominated loan had been swapped from a floating-rate U.S. dollar-
denominated interest rate to a fixed-rate euro-denominated interest rate through a cross-currency swap, removing interest rate risk
(and foreign currency exchange risk as further described below under Foreign Currency Exchange Rate Risk) associated with the
underlying interest payments. At September 30, 2018, combined borrowings outstanding under variable-rate debt agreements,
excluding UGI France SAS’s and Flaga’s effectively fixed-rate term loan and Flaga’s U.S. dollar-denominated loan, totaled $545.2
million. Based upon average borrowings outstanding under variable-rate borrowings (excluding UGI France SAS’s and Flaga’s
effectively fixed-rate term loan debt and Flaga’s U.S. dollar-denominated loan), an increase in short-term interest rates of 100
basis points (1%) would have increased our Fiscal 2018 interest expense by approximately $5 million. The remainder of our debt
outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the
fair value of this fixed-rate debt of approximately $228 million at September 30, 2018. A 100 basis point decrease in market
interest rates would result in increases in the fair value of this fixed-rate debt of approximately $254 million at September 30,
2018.
As previously mentioned, in October 2018, UGI International entered into the 2018 UGI International Credit Facilities Agreement,
which includes a $300 million variable-rate term loan maturing in October 2023. In November 2018, UGI International, LLC
entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on 2018
UGI International Credit Facilities Agreement term loan borrowings at 0.34%. We have designated these forward-starting interest
rate swaps as cash flow hedges.
As previously mentioned, in October 2017, UGI Utilities entered into a $125 million variable-rate Term Loan. In July 2018, UGI
Utilities entered into a forward-starting, pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing
market interest rates on UGI Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-starting
interest rate swap commences September 30, 2019. We have designated this forward-starting interest rate swap as a cash flow
hedge.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for
debt with similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having
interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term
forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”).
Foreign Currency Exchange Rate Risk
Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro and, to a lesser extent, the U.S. dollar
versus the British pound sterling. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate
with changes in the associated foreign currency exchange rates. From time to time, we use derivative instruments to hedge portions
of our net investments in foreign subsidiaries (“net investment hedges”). Gains or losses on net investment hedges remain in
accumulated other comprehensive income until such foreign operations are sold or liquidated. At September 30, 2018, there were
no unsettled net investment hedges outstanding. With respect to our net investments in our UGI International operations, a 10%
decline in the value of the associated foreign currencies versus the U.S. dollar would reduce their aggregate net book value at
September 30, 2018, by approximately $140 million, which amount would be reflected in other comprehensive income. In October
2018, concurrent with entering into the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25%
Senior Notes, we designated borrowings under these agreements as net investment hedges.
In addition, in order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September
30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated
LPG product purchases primarily during the heating-season months of October through March.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as
a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward
foreign currency exchange contracts.
As previously mentioned and prior to its related loan repayment on October 25, 2018, Flaga entered into cross-currency swaps to
hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of its
U.S. dollar denominated variable-rate term loan. These cross-currency hedges included initial and final exchanges of principal
from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was
determined by the market spot rate on the date of issuance. These cross-currency swaps also included interest rate swaps of a
floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate.
Derivative Instrument Credit Risk
63
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument
counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain
credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and
monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties
that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances
for certain financial transactions as deemed appropriate.
Certain of these derivative instrument agreements call for the posting of collateral by the counterparty or by the Company in the
forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally
require cash deposits in margin accounts. At September 30, 2018, restricted cash in brokerage accounts totaled $9.6 million.
Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon
the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms
of their contracts was not material at September 30, 2018. Certain of the Partnership’s derivative contracts have credit-risk-related
contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating.
At September 30, 2018, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted
would not be material.
The following table summarizes the fair values of unsettled market risk sensitive derivative instrument assets (liabilities) held at
September 30, 2018. The table also includes the changes in fair values of derivative instruments that would result if there were
(1) a 10% adverse change in the market prices of LPG, gasoline, natural gas, electricity and electricity transmission congestion
charges; (2) a 50 basis point adverse change in prevailing market interest rates; and (3) a 10% change in the value of the euro and
the British pound sterling versus the U.S. dollar. Gas Utility’s and Electric Utility’s commodity derivative instruments other than
gasoline futures contracts are excluded from the table below because any associated net gains or losses are refundable to or
recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.
(Millions of dollars)
September 30, 2018:
Commodity price risk
Interest rate risk
Foreign currency exchange rate risk
Critical Accounting Policies and Estimates
Asset (Liability)
Fair Value
Change in
Fair Value
$
$
$
164.7
$
(1.0) $
$
7.1
(98.3)
(2.5)
(55.6)
Accounting policies and estimates discussed in this section are those that we consider to be the most critical to an understanding
of our financial statements because they involve significant judgments and uncertainties. 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 management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which
could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the
estimates and assumptions associated with them, with the Company’s Audit Committee. Also, see Note 2 to Consolidated Financial
Statements which discusses the significant accounting policies that we have selected from acceptable alternatives.
Goodwill Impairment Evaluation. Our goodwill is the result of business acquisitions. We do not amortize goodwill, but test it
at least annually for impairment at the reporting unit level. A reporting unit is the operating segment, or a business one level below
the operating segment (a component), if discrete financial information is prepared and regularly reviewed by segment management.
Components are aggregated as a single reporting unit if they have similar economic characteristics. A reporting unit with goodwill
is required to perform an impairment test annually or whenever events or circumstances indicate that the value of goodwill may
be impaired.
For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that
the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the
qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their
carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches.
For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated
future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate
risk-adjusted rates. We use our internal forecasts to estimate future cash flows, which may include estimates of long-term future
growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to
64
establish fair values under our income approach involve management judgments based on a broad range of information and
historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of
the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires
judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an
impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting
unit. As of September 30, 2018, our goodwill totaled $3,160.4 million. We did not record any impairments of goodwill in Fiscal
2018, Fiscal 2017 or Fiscal 2016.
Impairment of Long-Lived Assets. Impairment testing for individual long-lived assets, or groups of long-lived assets, is required
when circumstances indicate that such assets may be impaired. If it is determined that a triggering event has occurred, we prepare
a quantitative evaluation based upon undiscounted cash flow projections expected to be realized over the remaining useful life of
the asset or the primary asset of an asset group. A long-lived asset or group of assets is considered impaired when the carrying
amount of such assets exceeds the associated undiscounted estimated future cash flows. When determining whether an asset or
group of assets has been impaired, management groups assets at the lowest level that has identifiable cash flows. Performing an
impairment test on long-lived assets involves judgment in areas such as identifying when a triggering event requiring evaluation
occurs; identifying and grouping assets; and, if the asset or group of assets is determined to be impaired based upon an excess of
carrying amount over estimated undiscounted future cash flows, determining the fair value of the asset or asset group. Although
cash flow estimates are based upon relevant information at the time the estimates are made, estimates of future cash flows are by
nature highly uncertain and contemplate factors that change over time such as the expected use of the asset including future
production and sales volumes, expected fluctuations in prices of commodities and expected proceeds from disposition. No material
provisions for impairments of long-lived assets were recorded during Fiscal 2018, Fiscal 2017 or Fiscal 2016.
Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation that arises in the normal course
of business. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and
elsewhere, and PNG and CPG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances
may be present. In accordance with GAAP, we record a reserve when it is probable that a liability exists and the amount or range
of amounts related to such liability can be reasonably estimated. When no amount within a range of possible loss is a better estimate
than any other amount within the range, liabilities recorded are based upon the low end of the range. The likelihood of a loss with
respect to a particular contingency is often difficult to predict and determining a reasonable estimate of the loss or a range of
possible loss may not be practicable based upon the information available and the potential effects of future events and decisions
by third parties that will determine the ultimate resolution of the contingency. Reasonable estimates involve management judgments
based on a broad range of information and prior experience and include an evaluation of the nature of the claim, the procedural
status of the matter, the probability or likelihood of success of prosecuting or defending the claim, the information available with
respect to the claim, the opinions and views of outside counsel and other advisors, and past experience in similar matters. These
judgments are reviewed quarterly as more information is received, and the amounts reserved are updated as necessary. Our estimated
reserves may differ materially from the ultimate liability and such reserves may change materially as more information becomes
available and estimated reserves are adjusted.
Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PAPUC. 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 PAPUC, 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, 2018, our regulatory assets and regulatory
liabilities totaled $301.0 million and $390.2 million, respectively. For additional information on regulatory assets and liabilities,
see Notes 2 and 8 to Consolidated Financial Statements.
Accounting For Derivative Instruments at Fair Value. The Company enters into derivative instruments to economically hedge
the risks associated with changes in commodity prices, interest rates and foreign currency rates. Accounting requirements for
derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. These
derivatives are recognized as assets and liabilities at fair value on the Consolidated Balance Sheets. Derivative assets and liabilities
are presented net by counterparty on our Consolidated Balance Sheets if the right of offset exists. 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.
Changes in the fair values of certain derivative instruments that qualify and are designated as cash flow hedges are recorded in
accumulated other comprehensive income (“AOCI”) or noncontrolling interests, both of which are components of equity, to the
extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. Changes in the fair values
of derivative instruments that we do not designate as, or that do not qualify for, hedge accounting under GAAP, which currently
comprises all of our commodity and certain of our foreign currency derivative instruments, are recognized in earnings on the
Consolidated Statements of Income. The fair values of our derivative instruments are determined based upon actively-quoted
65
market prices for identical assets and liabilities, indicative price quotations available through brokers, industry price publications
or recent market transactions and related market indicators. We maximize the use of observable inputs and minimize the use of
unobservable inputs when measuring fair value. Gains and losses associated with derivatives utilized by UGI Utilities to manage
the price risk inherent in its natural gas and electricity purchasing activities are recoverable through Gas Utility PGC or Electric
Utility DS mechanisms, subject to PAPUC approval. Accordingly, the offset to the changes in fair values of these derivatives for
which the normal purchases and normal sales exception under GAAP does not apply are recorded as either a regulatory asset or
liability on the Consolidated Balance Sheets. At September 30, 2018, the net fair value of our derivative assets totaled $186.0
million and the net fair value of our derivative liabilities totaled $24.5 million.
Income Taxes. We use the asset and liability method of accounting for income taxes. Under this method, income tax expense is
recognized for the amount of taxes payable or refundable for the current year and for deferred tax liabilities and assets for the
future tax consequences of events that have been recognized in our financial statements or tax returns. Positions taken by an entity
in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the positions will be examined by tax authorities
with full knowledge of relevant information. We use assumptions, judgments and estimates to determine our current provision for
income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any
valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current
provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of
current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation thereof and
the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated
financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account
estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our
current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above
could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2018, our net deferred
tax liabilities totaled $980.9 million.
Recently Issued Accounting Pronouncements
See Note 3 to the Consolidated Financial Statements for a discussion of the effects of recently issued accounting guidance.
66
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis
of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Annual Report on Internal Control Over Financial Reporting and the financial statements and financial statement
schedules referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) The Company's disclosure controls and procedures are designed to provide reasonable assurance that the information required
to be disclosed by the Company in reports filed or submitted under the Securities Exchange Act of 1934, as amended (the
“Exchange Act”), is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules
and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief
Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company's management, with
the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the
Company's disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation,
the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures,
as of September 30, 2018, were effective at the reasonable assurance level.
(b) For “Management’s Annual Report on Internal Control Over Financial Reporting” see Item 8 of this Report (which information
is incorporated herein by reference).
(c) During the most recent fiscal quarter, no change in the Company’s internal control over financial reporting occurred that has
materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
67
PART III:
ITEMS 10 THROUGH 14.
In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12, 13 and
14 is incorporated in this Report by reference to the following portions of UGI’s Proxy Statement, which will be filed with the
SEC by December 31, 2018.
Information
Captions of Proxy Statement
Incorporated by Reference
Item 10.
Directors, Executive Officers and Corporate Governance Election of Directors
- Nominees; Corporate
Governance; Director Independence; Board Leadership
Structure and Role in Risk Management; Board Meetings
and Attendance; Board and Committee Structure;
Communications with the Board; Securities Ownership
of Certain Beneficial Owners - Security Ownership of
Directors and Executive Officers; Securities Ownership
of Certain Beneficial Owners - Section 16(a) Beneficial
Ownership Reporting Compliance; Report of the Audit
Committee of the Board of Directors
The Code of Ethics for the Chief Executive Officer and
Senior Financial Officers of UGI Corporation is available
without
the Company’s website,
www.ugicorp.com, or by writing to Treasurer, UGI
Corporation, P. O. Box 858, Valley Forge, PA 19482.
charge
on
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters
Compensation of Directors; Report of the Compensation
and Management Development Committee of the Board
of Directors; Compensation Discussion and Analysis;
Compensation of Executive Officers; Compensation
Committee Interlocks and Insider Participation
Security Ownership of Directors and Executive Officers;
Securities Ownership of Certain Beneficial Owners;
Section 16(a)
Beneficial Ownership Reporting
Compliance.
Item 13.
Certain Relationships and Related Transactions, and
Director Independence
Election of Directors - Director Independence and Board
and Committee Structure; Policy for Approval of Related
Person Transactions
Item 14.
Principal Accounting Fees and Services
Our Independent Registered Public Accounting Firm
68
Equity Compensation Table
The following table sets forth information as of the end of Fiscal 2018 with respect to compensation plans under which our
equity securities are authorized for issuance.
Number of securities
to be
issued upon exercise of
outstanding options,
warrants and rights
(a)
Weighted average
exercise price of
outstanding options,
warrants and rights
(b)
Number of securities
remaining available for future
issuance under equity
compensation plans
(excluding securities reflected
in column (a)) (c)
8,197,069 (1) $
959,718 (3) $
33.93
0
9,047,383 (2)
0
Plan category
Equity compensation
plans approved by
security holders
Equity compensation
plans not approved by
security holders
Total
9,156,787
$
33.93 (4)
(1) Represents 8,197,069 stock options under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and
Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan.
(2) Represents 4,116 securities remaining for future issuance of stock options from the 2004 Omnibus Equity Compensation Plan
Amended and Restated as of December 5, 2006 and 9,043,267 of securities remaining for issuance from the UGI Corporation
2013 Omnibus Incentive Compensation Plan. The UGI Corporation 2013 Omnibus Incentive Compensation Plan was
approved by the shareholders on January 24, 2013.
(3) Represents 959,718 restricted stock units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended
and Restated as of December 5, 2006 and the UGI Corporation 2013 Omnibus Incentive Compensation Plan.
(4) Weighted-average exercise price of outstanding options; excludes restricted stock units.
The information concerning the Company’s executive officers required by Item 10 is set forth below.
Name
John L. Walsh
Ted J. Jastrzebski
Robert F. Beard
Roger Perreault
Hugh J. Gallagher
Joseph L. Hartz
Monica M. Gaudiosi
Ann P. Kelly
Age
63
57
53
54
55
55
55
48
EXECUTIVE OFFICERS
President and Chief Executive Officer
Position
Chief Financial Officer
Executive Vice President, Natural Gas and President and Chief Executive Officer, UGI
Utilities, Inc.
Executive Vice President, Global LPG and President, UGI International, LLC
President and Chief Executive Officer, AmeriGas Propane, Inc.
President, UGI Energy Services, LLC
Vice President, General Counsel and Secretary
Vice President - Chief Accounting Officer and Corporate Controller
All officers are elected for a one-year term at the organizational meetings of the respective Boards of Directors held each year.
There are no family relationships between any of the officers or between any of the officers and any of the directors.
69
John L. Walsh
Mr. Walsh is a Director and President (since 2005) and Chief Executive Officer (since 2013) of UGI Corporation. In addition,
Mr. Walsh serves as a Director (since 2005) and Chairman of the Board of AmeriGas Propane, Inc. (since 2016), where he had
served as a director and vice chairman since 2005. He also serves as a Director and Vice Chairman of UGI Utilities, Inc. (since
2005). Both AmeriGas Propane, Inc. and UGI Utilities, Inc. are subsidiaries of UGI Corporation. Mr. Walsh served as Chief
Operating Officer of UGI Corporation (2005 to 2013) and as President and Chief Executive Officer of UGI Utilities, Inc. (2009
to 2011). Previously, Mr. Walsh was the Chief Executive of the Industrial and Special Products division of the BOC Group plc,
an industrial gases company, a position he assumed in 2001. He was an Executive Director of BOC (2001 to 2005) having joined
BOC in 1986 as Vice President - Special Gases and having held various senior management positions in BOC, including President
of Process Gas Solutions, North America (2000 to 2001) and President of BOC Process Plants (1996 to 2000). Mr. Walsh also
serves as Director at Main Line Health, Inc., the United Way of Greater Philadelphia and Southern New Jersey, the World Affairs
Council of Philadelphia, the Greater Philadelphia Chamber of Commerce, the Satell Institute, and the Philadelphia Zoo, and as
Trustee at the Saint Columbkille Partnership School.
Ted J. Jastrzebski
Mr. Jastrzebski is Chief Financial Officer of UGI Corporation (since May 2018). Mr. Jastrzebski also serves as Principal Financial
Officer of AmeriGas Propane, Inc. (since September 18, 2018). From 2013 until 2018, Mr. Jastrzebski served as Executive Vice
President and Chief Financial Officer of Qurate Retail Group, which is comprised of QVC, HSN, Cornerstone Brands, and Zulily.
Previously, Mr. Jastrzebski held various positions at The Hershey Company, including Senior Vice President and President, Hershey
Americas (2011 to 2013), Senior Vice President and President, Hershey International (2007 to 2010) and Vice President, Finance,
Hershey International (2004 to 2007). Mr. Jastrzebski also served as Senior Vice President, Finance, IT and Administration and
Chief Financial Officer of CARE (2002 to 2004) and as Vice President and Chief Financial Officer of Project Hope (1999 to 2002).
Robert F. Beard
Mr. Beard is Executive Vice President, Natural Gas (since September 18, 2018) and President and Chief Executive Officer and a
Director of UGI Utilities, Inc. (since 2011). He previously served as Vice President - Marketing, Rates and Gas Supply (2010 to
2011) and Vice President - Southern Region (2008 to 2010) of UGI Utilities, Inc. From 2006 until 2008, Mr. Beard served as Vice
President - Operations and Engineering of PPL Gas Utilities Corporation and, from 2002 until 2006, he served as Director -
Operations and Engineering of PPL Gas Utilities Corporation.
Roger Perreault
Mr. Perreault is Executive Vice President, Global LPG of UGI Corporation (since September 2018), President - UGI International,
LLC (since December 2015), and a Director of AmeriGas Propane, Inc. (since October 1, 2018). Prior to joining UGI Corporation,
Mr. Perreault held various positions at Air Liquide, an industrial gases company he joined in 1994, and served in various leadership
positions from 2008 to 2014, including in a global role as President, Large Industries with international responsibilities and, prior
to that, in a role with responsibility for Air Liquide’s North American large industries business. Prior to joining Air Liquide, Mr.
Perreault was a chemical engineer and operations manager with I.C.I. in Quebec, Canada.
Hugh J. Gallagher
Mr. Gallagher is President and Chief Executive Officer (since September 2018) and a Director (since October 1, 2018) of AmeriGas
Propane, Inc. Previously he served as Vice President - Finance and Chief Financial Officer of the General Partner (2013 to 2018).
He has also served as Treasurer of both UGI Corporation and the General Partner (2011 to 2014), Director - Treasury Services
and Investor Relations of UGI Corporation (2009 to 2011) and Director - Treasury Services (2007 to 2009) of UGI Corporation.
He has also served as the General Partner’s Director - Business Development (2004 to 2007), Director of Financial Planning and
Analysis (2000 to 2004), Financial Manager - Operations (1999 to 2000), Manager of Financial Reporting (1996 to 1999), and
Team Leader - Financial Reporting (1995 to 1996). Mr. Gallagher joined UGI Corporation in 1990, serving in various finance
and accounting roles of increasing responsibility.
70
Joseph L. Hartz
Mr. Hartz is President of UGI Energy Services, LLC (since March 2017). He previously served as Chief Operating Officer (June
2014 to March 2017) and as Vice President - Supply and Operations (July 2010 to June 2014) of UGI Energy Services, LLC. He
joined UGI Utilities, Inc. in 1985 as an accountant and has held various positions of increasing responsibility at UGI Utilities and
UGI Energy Services, including Vice President - Assets and Supply and Chief Financial Officer.
Monica M. Gaudiosi
Ms. Gaudiosi is the Vice President, General Counsel and Secretary of UGI Corporation and UGI Utilities, Inc. (since 2012). She
is also Vice President (since 2012), General Counsel (since 2015) and Secretary (since 2012) of AmeriGas Propane, Inc. Prior to
joining UGI Corporation, Ms. Gaudiosi served as Senior Vice President and General Counsel (2007 to 2012) and Senior Vice
President and Associate General Counsel (2005 to 2007) of Southern Union Company. Prior to joining Southern Union Company
in 2005, Ms. Gaudiosi held various positions with General Electric Capital Corporation (1997 to 2005). Before joining General
Electric Capital Corporation, Ms. Gaudiosi was an associate at the law firms of Hunton & Williams (1994 to 1997) and Sutherland,
Asbill & Brennan (1988 to 1994).
Ann P. Kelly
Ms. Kelly is Vice President, Chief Accounting Officer and Corporate Controller of UGI Corporation (since March 2018). She
previously served as Assistant Treasurer of UGI Corporation (2016 to 2018) and Controller and Chief Accounting Officer of UGI
Utilities, Inc. (2014 to 2016). Prior to joining UGI Utilities, Inc., Ms. Kelly held the position of Chief Financial Officer of JGM,
Inc. (2013 to September 2014). She previously held roles of increasing responsibility in finance and accounting at Preferred Sands
(February 2012 to July 2012), Exelon Generation (2007 to 2009 and 2010 to 2012), PECO Energy Company (2009 to 2010),
Radnor Holdings Corporation (1997 to 2007), PricewaterhouseCoopers LLP (1994 to 1997) and Dean Witter Reynolds (1992 to
1994).
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:
Management’s Annual Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm (on Internal Control Over Financial Reporting)
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and
Schedules)
Consolidated Balance Sheets as of September 30, 2018 and 2017
Consolidated Statements of Income for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Comprehensive Income for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Changes in Equity for the years ended September 30, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
(2)
Financial Statement Schedules:
I — Condensed Financial Information of Registrant (Parent Company)
II — Valuation and Qualifying Accounts for the years ended September 30, 2018, 2017 and 2016
71
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 related notes.
(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):
Registrant
Filing
Exhibit
3.1
Form 10-Q
(6/30/05)
UGI
UGI
UGI
Form 8-K
(7/29/14)
3.1
Form 8-K
(7/31/17)
3.1
UGI
Form 8-B/A
(4/17/96)
3.(4)
AmeriGas
Partners, L.P.
Form 10-Q
(6/30/09)
3.1
AmeriGas
Partners, L.P.
Form 8-K
(3/14/12)
3.1
Incorporation by Reference
Exhibit No.
3.1
Exhibit
(Second) Amended and
Restated Articles of
Incorporation of the Company
as amended through June 6,
2005.
3.2
3.3
4.1
4.2
4.3
4.4
4.5
Articles of Amendment to the
Amended and Restated
Articles of Incorporation of
UGI Corporation.
Bylaws of UGI Corporation,
amended and restated as of
July 25, 2017.
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 long-term debt not required
to be filed pursuant to Item
601(b)(4) of Regulation S-K).
The description of the
Company’s Common Stock
contained in the Company’s
registration statement filed
under the Securities Exchange
Act of 1934, as amended.
UGI Corporation’s (Second)
Amended and Restated
Articles of Incorporation, as
amended, and Bylaws
referred to in 3.1, 3.2, and 3.3
above.
Fourth Amended and Restated
Agreement of Limited
Partnership of AmeriGas
Partners, L.P. dated as of July
27, 2009.
Amendment No. 1 to Fourth
Amended and Restated
Agreement of Limited
Partnership of AmeriGas
Partners, L.P. dated as of
March 13, 2012.
72
Incorporation by Reference
Exhibit No.
4.6
Exhibit
Amendment No. 2 to Fourth
Amended and Restated
Agreement of Limited
Partnership of AmeriGas
Partners, L.P. dated as of July
27, 2015.
Registrant
Filing
AmeriGas
Partners, L.P.
Form 8-K
(7/27/15)
Exhibit
3.1
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
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.
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.
Indenture, dated as of
January 12, 2012, among
AmeriGas Finance Corp.,
AmeriGas Finance LLC,
AmeriGas Partners, L.P., as
guarantor, and U.S. Bank
National Association, as
trustee.
First Supplemental Indenture,
dated as of January 12, 2012,
among AmeriGas Finance
Corp., AmeriGas Finance
LLC, AmeriGas Partners,
L.P., as guarantor, and U.S.
Bank National Association, as
trustee.
Form of Fixed Rate Medium-
Term Note.
Form of Fixed Rate Series B
Medium-Term Note.
Form of Floating Rate Series
B Medium-Term Note.
Officer’s Certificate
establishing Medium-Term
Notes Series.
Form of Officer’s Certificate
establishing Series B
Medium-Term Notes under
the Indenture.
Form of Officers’ Certificate
establishing Series C
Medium-Term Notes under
the Indenture.
Forms of Floating Rate and
Fixed Rate Series C Medium-
Term Notes.
Utilities
4(c)
Registration
Statement No.
33-77514
(4/8/94)
Utilities
Form 8-K
(9/12/06)
4.2
AmeriGas
Partners, L.P.
Form 8-K
(1/12/12)
4.1
AmeriGas
Partners, L.P.
Form 8-K
(1/12/12)
4.2
Form 8-K
(8/26/94)
Form 8-K
(8/1/96)
Form 8-K
(8/1/96)
Form 8-K
(8/26/94)
Form 8-K
(8/1/96)
Form 8-K
(5/21/02)
Form 8-K
(5/21/02)
4(i)
4(i)
4(ii)
4(iv)
4(iv)
4.2
4.1
Utilities
Utilities
Utilities
Utilities
Utilities
Utilities
Utilities
73
Incorporation by Reference
Exhibit No.
4.18
Exhibit
Form of Note Purchase
Agreement dated October 30,
2013 between the Company
and the purchasers listed as
signatories thereto.
4.19
4.20
4.21
4.22
4.23
4.24
10.1**
10.2**
Note Purchase Agreement
dated April 22, 2016 between
the Company and the
purchasers listed as
signatories thereto.
Indenture, dated as of June
27, 2016, among AmeriGas
Partners, L.P., AmeriGas
Finance Corp., and U.S. Bank
National Association, as
trustee.
First Supplemental Indenture,
dated as of June 27, 2016,
among AmeriGas Partners,
L.P., AmeriGas Finance
Corp., and U.S. Bank
National Association, as
trustee.
Second Supplemental
Indenture, dated as of
December 28, 2016, among
AmeriGas Partners, L.P.,
AmeriGas Finance Corp., and
U.S. Bank National
Association, as trustee
(including form of global
note).
Third Supplemental
Indenture, dated as of
February 13, 2017, among
AmeriGas Partners, L.P.,
AmeriGas Finance Corp., and
U.S. Bank National
Association, as trustee
(including form of global
note).
Indenture, dated as of October
25, 2018, by and among
International, the guarantors
named therein, U.S. Bank
National Association, as
trustee, Elavon Financial
Services DAC, as registrar
and transfer agent, and Elavon
Financial Services DAC, UK
Branch, as paying agent
(including the form of Note).
AmeriGas Propane, Inc. 2010
Long-Term Incentive Plan on
Behalf of AmeriGas Partners,
L.P. effective July 30, 2010.
AmeriGas Propane, Inc.
Executive Annual Bonus
Plan, effective as of October
1, 2006, as amended
November 15, 2012.
Registrant
Filing
Utilities
Utilities
Form 8-K
(10/30/13)
Form 8-K
(4/28/16)
AmeriGas
Partners, L.P.
Form 8-K
(6/27/16)
Exhibit
4.1
4.1
4.1
AmeriGas
Partners, L.P.
Form 8-K
(6/27/16)
4.2
AmeriGas
Partners, L.P.
Form 8-K
(12/28/16)
4.1
AmeriGas
Partners, L.P.
Form 8-K
(2/13/17)
4.1
UGI
Form 8-K
(10/25/18)
4.1
AmeriGas
Partners, L.P.
Form 8-K
(7/30/10)
10.2
AmeriGas
Partners, L.P.
Form 10-Q
(3/31/13)
10.9
74
Incorporation by Reference
Exhibit No.
10.3**
Exhibit
AmeriGas Propane, Inc.
Executive Employee
Severance Plan, as amended
and restated as of June 15,
2017.
Registrant
Filing
AmeriGas
Partners, L.P.
Form 10-K
(9/30/17)
Exhibit
10.9
10.4**
10.5**
10.6**
*10.7**
*10.8**
10.9**
10.10**
10.11**
10.12**
10.13
*10.14**
10.15**
AmeriGas Propane, Inc. Non-
Qualified Deferred
Compensation Plan, as
Amended and Restated
effective November 22, 2013.
Change in Control Agreement
for Monica M. Gaudiosi dated
as of April 23, 2012.
Change in Control Agreement
for Mr. Sheridan Amended
and Restated as of March 3,
2012.
Description of oral
compensation arrangement
for Messrs. Walsh, Perreault.
Beard and Jastrzebski and Ms.
Gaudiosi.
Description of oral
compensation arrangement
for Mr. Sheridan.
AmeriGas Propane, Inc.
Supplemental Executive
Retirement Plan, as Amended
and Restated effective June
15, 2017.
AmeriGas Propane, Inc.
Senior Executive Employee
Severance Plan, as amended
as of June 15, 2017.
Form of Change in Control
Agreement Amended and
Restated as of May 12, 2008
for Mr. Walsh.
Form of Change in Control
Agreement for Mr. Roger
Perreault dated December 7,
2015.
Form of Confidentiality and
Post Employment Activities
Agreement with AmeriGas
Propane, Inc. for Mr.
Sheirdan.
Summary of Director
Compensation dated October
1, 2018.
UGI Corporation 2004
Omnibus Equity
Compensation Plan Amended
and Restated as of September
5, 2014.
AmeriGas
Partners, L.P.
Form 10-Q
(3/31/14)
10.4
UGI
AmeriGas
Partners, L.P.
Form 10-Q
(6/30/12)
Form 10-Q
(3/31/12)
10.1
10.6
AmeriGas
Partners, L.P.
Form 10-Q
(6/30/17)
10.1
AmeriGas
Partners, L.P.
Form 10-Q
(6/30/17)
10.4
UGI
UGI
Form 10-Q
(6/30/08)
10.3
Form 10-K
(9/30/16)
10.15
AmeriGas
Partners L.P.
Form 10-K
(9/30/09)
10.29
UGI
Form 10-K
(9/30/16)
10.25
75
Registrant
Filing
Exhibit
10.26
Form 10-K
(9/30/16)
Incorporation by Reference
Exhibit No.
10.16**
Exhibit
UGI Corporation 2004
Omnibus Equity
Compensation Plan Amended
and Restated as of September
5, 2014 - Terms and
Conditions as effective
January 1, 2016.
10.17**
10.18**
10.19**
10.20**
10.21**
10.22**
10.23**
10.24**
10.25**
10.26**
UGI Corporation 2009
Deferral Plan, as Amended
and Restated effective June
15, 2017.
UGI Corporation
Supplemental Executive
Retirement Plan and
Supplemental Savings Plan,
as Amended and Restated
effective April 1, 2015.
UGI Corporation 2009
Supplemental Executive
Retirement Plan for New
Employees, as Amended and
Restated as of June 15, 2017.
UGI Corporation 2013
Omnibus Incentive
Compensation Plan, effective
as of September 5, 2014.
UGI Corporation 2013
Omnibus Incentive
Compensation Plan, effective
as of September 5, 2014 -
Terms and Conditions for
Non-Employee Directors
effective January 1, 2016.
UGI Corporation Executive
Annual Bonus Plan effective
as of October 1, 2006, as
amended November 16, 2012.
UGI Corporation Executive
Employee Severance Plan, as
amended and restated as of
June 15, 2017.
UGI Corporation Senior
Executive Employee
Severance Plan, as amended
as of June 15, 2017.
Form of UGI Corporation
2013 Omnibus Incentive
Compensation Plan
Nonqualified Stock Option
Grant Letter for UGI, Utilities
and AmeriGas Employees,
dated January 1, 2018.
Form of UGI Corporation
2013 Omnibus Incentive
Compensation Plan
Performance Unit Grant
Letter for UGI and Utilities
Employees, dated January 1,
2018.
UGI
UGI
UGI
UGI
UGI
UGI
UGI
UGI
UGI
UGI
UGI
76
Form 10-Q
(6/30/17)
10.6
Form 10-K
(9/30/17)
10.26
Form 10-Q
(6/30/17)
10.1
Form 10-K
(9/30/16)
10.30
Form 10-K
(9/30/16)
10.31
Form 10-Q
(3/31/13)
10.14
Form 10-K
(9/30/17)
10.31
Form 10-Q
(6/30/17)
10.7
Form 10-Q
(3/31/18)
10.1
Form 10-Q
(3/31/18)
10.2
Registrant
Filing
Exhibit
10.3
Form 10-Q
(3/31/18)
UGI
UGI
UGI
UGI
UGI
UGI
Utilities
Utilities
UGI
Incorporation by Reference
Exhibit No.
10.27**
Exhibit
Form of UGI Corporation
2013 Omnibus Incentive
Compensation Plan, Stock
Unit Grant Letter for Non
Employee Directors, dated
January 25, 2018.
10.28**
10.29**
10.30**
10.31**
10.32**
10.33**
10.34**
10.35
10.36
Form of UGI Corporation
2013 Omnibus Incentive
Compensation Plan,
Nonqualified Stock Option
Grant Letter for Non
Employee Directors, dated
January 25, 2018.
Form of AmeriGas Propane,
Inc. 2010 Long-Term
Incentive Plan on Behalf of
AmeriGas Partners, L.P.,
Phantom Unit Grant Letter for
Non Employee Directors,
dated January 24, 2018.
Form of AmeriGas Propane,
Inc. 2010 Long-Term
Incentive Plan on Behalf of
AmeriGas Partners, L.P.,
Performance Unit Grant
Letter for Employees dated
January 1, 2018.
AmeriGas Propane, Inc. 2010
Long-Term Incentive Plan on
Behalf of AmeriGas Partners,
L.P. effective January 1, 2018
- Terms and Conditions
Form of Confidentiality, Non-
Competition and Non-
Solicitation Agreement
between UGI Corporation and
Ted J. Jastrzebski.
UGI Utilities, Inc. Executive
Annual Bonus Plan, effective
as of October 1, 2006, as
amended as of November 16,
2012.
UGI Utilities, Inc. Senior
Executive Employee
Severance Plan, as amended
as of July 10, 2017.
Trademark License
Agreement dated April 19,
1995 among UGI
Corporation, AmeriGas, Inc.,
AmeriGas Propane, Inc.,
AmeriGas Partners, L.P. and
AmeriGas Propane, L.P.
First Amendment, dated as of
November 18, 2015, to
Trademark License
Agreement, dated April 19,
1995, by and among UGI
Corporation, AmeriGas, Inc.,
AmeriGas Propane, Inc.,
AmeriGas Partners, L.P., and
AmeriGas Propane, L.P.
Form 10-Q
(3/31/18)
10.4
Form 10-Q
(3/31/18)
10.5
Form 10-Q
(3/31/18)
10.6
Form 10-Q
(3/31/18)
10.7
Form 10-Q
(8/7/18)
10.1
Form 10-Q
(3/31/13)
10.2
Form 10-Q
(6/30/17)
10.1
Form 10-K
(9/30/10)
10.37
AmeriGas
Partners, L.P.
Form 10-K
(9/30/15)
10.40
77
Incorporation by Reference
Exhibit No.
10.37
Exhibit
Trademark License
Agreement, dated April 19,
1995 among AmeriGas
Propane, Inc., AmeriGas
Partners, L.P. and AmeriGas
Propane, L.P.
10.38
10.39
10.40
10.41
10.42
Form of Receivables Purchase
Agreement, dated as of
November 30, 2001, as
amended through and
including Amendment No. 18
thereto dated October 27,
2017, by and among UGI
Energy Services, LLC, as
servicer, Energy Services
Funding Corporation, as
seller, and PNC Bank,
National Association, as
issuer and administrator.
Amendment No. 19, dated as
of October 26, 2018, to
Receivables Purchase
Agreement, dated as of
November 30, 2001 (as
amended, supplemented or
modified from time to time),
by and among UGI Energy
Services, LLC, as servicer,
Energy Services Funding
Corporation, as seller, and
PNC Bank, National
Association, as issuer and
administrator.
Form of Purchase and Sale
Agreement, dated as of
November 30, 2001, as
amended through and
including Amendment No. 4
thereto dated October 1, 2013,
by and between UGI Energy
Services, LLC and Energy
Services Funding
Corporation.
FSS Service Agreement No.
79028 effective as of
December 1, 2014 by and
between Columbia Gas
Transmission, LLC and UGI
Utilities, Inc.
SST Service Agreement
No. 79133 effective as of
December 1, 2014 by and
between Columbia Gas
Transmission, LLC and UGI
Utilities, Inc.
Registrant
Filing
AmeriGas
Partners, L.P.
Form 10-Q
(12/31/10)
Exhibit
10.1
UGI
Form 10-K
(9/30/17)
10.38
UGI
Form 8-K
(10/26/18)
10.1
UGI
Form 10-K
(9/30/17)
10.39
Utilities
Form 10-K
(9/30/14)
10.16
Utilities
Form 10-K
(9/30/14)
10.19
78
Incorporation by Reference
Exhibit No.
10.43
Exhibit
Amended and Restated Credit
Agreement dated as of June
18, 2014 by and among
AmeriGas Propane, L.P., as
Borrower, AmeriGas Propane,
Inc., as Guarantor, Wells
Fargo Securities, LLC, as
Sole Lead Arranger and Sole
Book Manager, and the other
financial institutions from
time to time party thereto.
10.44
10.45
10.46
10.47
Amendment No. 1 dated as of
June 20, 2016 to Amended
and Restated Credit
Agreement dated June 18,
2014 by and among
AmeriGas Propane, L.P., as
Borrower, AmeriGas Propane,
Inc., as Guarantor, Wells
Fargo Bank, National
Association, as
Administrative Agent,
Swingline Lender, and Issuing
Lender, Wells Fargo
Securities, LLC, as Sole Lead
Arranger and Sole Book
Manager and the other
financial institutions from
time to time party thereto.
Credit Agreement, dated as of
March 27, 2015 among UGI
Utilities, Inc., as borrower,
PNC Bank, National
Association, as administrative
agent, Citizens Bank of
Pennsylvania, as syndication
agent, PNC Capital Markets
LLC and Citizens Bank, N.A.,
as joint lead arrangers and
joint bookrunners and the
other financial institutions
from time to time parties
thereto.
Second Amended and
Restated Credit Agreement,
dated February 29, 2016, by
and among UGI Energy
Services, LLC, as borrower,
and JP Morgan Chase Bank,
N.A., as administrative agent,
and PNC Bank, National
Association, as syndication
agent, and Wells Fargo Bank,
National Association, as
documentation agent.
Gas Supply and Delivery
Service Agreement between
UGI Utilities, Inc. and UGI
Energy Services, LLC,
effective November 1, 2015.
Registrant
Filing
AmeriGas
Partners, L.P.
Form 8-K
(6/18/14)
Exhibit
10.1
AmeriGas
Partners, L.P.
Form 8-K
(6/20/16)
10.2
Utilities
Form 8-K
(3/27/15)
10.1
UGI
Form 8-K
(2/29/16)
10.1
Utilities
Form 10-K
(9/30/16)
10.19
79
Incorporation by Reference
Exhibit No.
10.48
Exhibit
Credit Agreement, dated
October 31, 2017, by and
among UGI Utilities, Inc.,
PNC Bank National
Association, as administrative
agent, The Bank of New York
Mellon, as syndication agent,
and certain other lenders
named therein.
Registrant
Filing
Utilities
Form 8-K
(10/31/17)
Exhibit
10.1
AmeriGas
Partners, L.P.
Form 8-K
(11/7/17)
10.1
Utilities
Form 8-K
(9/21/18)
10.1
UGI
Form 8-K
(10/25/18)
4.2
UGI
Form 10-K
(9/30/03)
14
10.49
10.50
10.51
14
*21
*23
*31.1
Standby Equity Commitment
Agreement, dated November
7, 2017, by and among
AmeriGas Partners, L.P.,
AmeriGas Propane, Inc. and
UGI Corporation.
Increasing Lender
Commitment and Acceptance,
dated as of September 21,
2018, among UGI Utilities,
Inc., as borrower, PNC Bank,
National Association, as
administrative agent, and each
of the entities listed under the
caption “Increasing Lenders”
on the signature pages thereto.
Multicurrency Facilities
Agreement, effective October
25, 2018, among
International, as borrower,
Natixis, as agent, mandated
lead arranger, bookrunner and
coordinator, Barclays Bank
Plc, BNP Paribas, Credit
Agricole Corporate and
Investment Bank, HSBC
France, ING Bank N.V.,
French Branch, Mediobanca
International (Luxembourg)
S.A., Raiffeisen Bank
International AG and Societe
Generale Corporate and
Investment Banking, as
mandated lead arrangers, and
certain other lenders.
Code of Ethics for principal
executive, financial and
accounting officers.
Subsidiaries of the Registrant.
Consent of Ernst & Young
LLP
Certification by the Chief
Executive Officer relating to
the Registrant’s Report on
Form 10-K for the fiscal year
ended September 30, 2018
pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
80
Registrant
Filing
Exhibit
Incorporation by Reference
Exhibit No.
*31.2
Exhibit
Certification by the Chief
Financial Officer relating to
the Registrant’s Report on
Form 10-K for the fiscal year
ended September 30, 2018
pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
*32
*101.INS
*101.SCH
*101.CAL
*101.DEF
*101.LAB
*101.PRE
Certification by the Chief
Executive Officer and the
Chief Financial Officer
relating to the Registrant’s
Report on Form 10-K for the
fiscal year ended September
30, 2018, pursuant to Section
906 of the Sarbanes-Oxley
Act of 2002.
XBRL Instance
XBRL Taxonomy Extension
Schema
XBRL Taxonomy Extension
Calculation Linkbase
XBRL Taxonomy Extension
Definition Linkbase
XBRL Taxonomy Extension
Labels Linkbase
XBRL Taxonomy Extension
Presentation Linkbase
Filed herewith.
*
** As required by Item 15(a)(3), this exhibit is identified as a compensatory plan or arrangement.
ITEM 16. FORM 10-K SUMMARY
None.
81
Exhibit No. Description
EXHIBIT INDEX
10.7
10.8
10.14
21
23
31.1
31.2
32
Description of oral compensation arrangement for Messrs. Walsh, Perreault, Beard and Jastrzebski and Ms.
Gaudiosi.
Description of oral compensation arrangement for Mr. Sheridan.
Summary of Director Compensation as of October 1, 2018.
Subsidiaries of the Registrant.
Consent of Ernst & Young LLP.
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year
ended September 30, 2018 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year
ended September 30, 2018 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report
on Form 10-K for the fiscal year ended September 30, 2018, pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
101.INS
XBRL Instance
101.SCH
XBRL Taxonomy Extension Schema
101.CAL
XBRL Taxonomy Extension Calculation Linkbase
101.DEF
XBRL Taxonomy Extension Definition Linkbase
101.LAB
XBRL Taxonomy Extension Labels Linkbase
101.PRE
XBRL Taxonomy Extension Presentation Linkbase
82
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.
SIGNATURES
Date: November 20, 2018
UGI CORPORATION
By: /s/ Ted J. Jastrzebski
Ted J. Jastrzebski
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 20, 2018,
by the following persons on behalf of the Registrant in the capacities indicated.
Signature
/s/ John L. Walsh
John L. Walsh
/s/ Ted J. Jastrzebski
Ted J. Jastrzebski
/s/ Ann P. Kelly
Ann P. Kelly
/s/ Marvin O. Schlanger
Marvin O. Schlanger
/s/ M. Shawn Bort
M. Shawn Bort
/s/ Theodore A. Dosch
Theodore A. Dosch
/s/ Richard W. Gochnauer
Richard W. Gochnauer
/s/ Alan N. Harris
Alan N. Harris
/s/ Frank S. Hermance
Frank S. Hermance
/s/ Anne Pol
Anne Pol
/s/ James B. Stallings, Jr.
James B. Stallings, Jr.
Title
President and Chief Executive Officer
(Principal Executive Officer) and Director
Chief Financial Officer
(Principal Financial Officer)
Vice President, Chief Accounting Officer and Corporate
Controller (Principal Accounting Officer)
Chairman and Director
Director
Director
Director
Director
Director
Director
Director
83
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2018
F-1
UGI CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Management’s Annual Report on Internal Control over Financial Reporting
Financial Statements:
Report of Independent Registered Public Accounting Firm (on Internal Control Over Financial Reporting)
Report of Independent Registered Public Accounting Firm (on Consolidated Financial Statements and
Schedules)
Consolidated Balance Sheets as of September 30, 2018 and 2017
Consolidated Statements of Income for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Comprehensive Income for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended September 30, 2018, 2017 and 2016
Consolidated Statements of Changes in Equity for the years ended September 30, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
Financial Statement Schedules:
For the years ended September 30, 2018, 2017 and 2016:
I — Condensed Financial Information of Registrant (Parent Company)
II — Valuation and Qualifying Accounts
Pages
F-3
F-4
F-5
F-6
F-7
F-8
F-9
F-10
F-11
S-1
S-4
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
Reports of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in this Annual Report were prepared
by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related
information were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”)
and include amounts that are based on management’s best judgments and estimates.
The Audit Committee of the Board of Directors is composed of three members, each of whom is independent and a non-employee
director of the Company. The Committee is responsible for monitoring and overseeing the financial reporting process, the adequacy
of internal accounting controls, the independence and performance of the Company’s independent registered public accounting
firm and internal auditors. The Committee meets regularly, with and without management present, with the independent registered
public accounting firm and the internal auditors, both of which report directly to the Committee. In addition, the Committee
provides regular reports to the Board of Directors.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company,
as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. 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 Company’s internal control over financial reporting as of September 30, 2018,
based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the “COSO criteria”).
Internal control over financial reporting refers to the process, designed under the supervision and with the participation of
management, including our Chief Executive Officer and our Chief Financial Officer, and effected by the Company’s Board of
Directors, 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 GAAP and includes policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
Company; (2) 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 (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate 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’s internal control over financial reporting was effective
as of September 30, 2018, based on the COSO criteria. Ernst & Young LLP, our independent registered public accounting firm,
has audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2018, as stated in
their report, which appears herein.
/s/ John L. Walsh
Chief Executive Officer
/s/ Ted J. Jastrzebski
Chief Financial Officer
/s/ Ann P. Kelly
Chief Accounting Officer
F-3
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of UGI Corporation
Opinion on Internal Control over Financial Reporting
We have audited UGI Corporation and subsidiaries’ internal control over financial reporting as of September 30, 2018, based on
criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission 2013 framework (the COSO criteria). In our opinion, UGI Corporation and subsidiaries (the Company)
maintained, in all material respects, effective internal control over financial reporting as of September 30, 2018, based on the
COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of the Company as of September 30, 2018 and 2017, the related consolidated statements
of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended September
30, 2018, and the related notes and the financial statement schedules listed in the Index at Item 15(a) and our report dated November
20, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Annual Report on
Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent
with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for
our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) 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 (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
November 20, 2018
F-4
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of UGI Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of UGI Corporation and subsidiaries (the Company) as of September
30, 2018 and 2017, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for
each of the three years in the period ended September 30, 2018, and the related notes and the financial statement schedules listed
in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated
financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2018 and 2017,
and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2018, in conformity
with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company's internal control over financial reporting as of September 30, 2018, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013
framework and our report dated November 20, 2018, expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on
the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error
or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether
due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2014.
Philadelphia, Pennsylvania
November 20, 2018
F-5
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
ASSETS
Current assets
Cash and cash equivalents
Restricted cash
Accounts receivable (less allowances for doubtful accounts of $35.1 and $26.9, respectively)
Accrued utility revenues
Inventories
Utility regulatory assets
Derivative instruments
Prepaid expenses
Other current assets
Total current assets
Property, plant and equipment
Non-utility
Utility
Accumulated depreciation
Net property, plant, and equipment
Goodwill
Intangible assets, net
Utility regulatory assets
Derivative instruments
Other assets
Total assets
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt
Short-term borrowings
Accounts payable
Employee compensation and benefits accrued
Deposits and advances
Derivative instruments
Accrued interest
Other current liabilities
Total current liabilities
Debt and other liabilities
Long-term debt
Deferred income taxes
Derivative instruments
Other noncurrent liabilities
Total liabilities
Commitments and contingencies (Note 15)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized – 450,000,000 shares; issued –
174,142,997 and 173,987,691 shares, respectively)
Retained earnings
Accumulated other comprehensive loss
Treasury stock, at cost
Total UGI Corporation stockholders’ equity
Noncontrolling interests, principally in AmeriGas Partners
Total equity
Total liabilities and equity
See accompanying Notes to Consolidated Financial Statements.
F-6
September 30,
2018
2017
$
$
452.6
9.6
751.9
14.0
318.2
7.5
142.5
130.2
61.6
1,888.1
558.4
10.3
626.8
13.3
278.6
8.3
63.1
83.9
54.8
1,697.5
5,345.8
3,616.3
8,962.1
(3,153.9)
5,808.2
3,160.4
513.6
293.5
43.5
273.6
$ 11,980.9
5,564.6
3,285.3
8,849.9
(3,312.9)
5,537.0
3,107.2
611.7
360.6
9.2
259.0
$ 11,582.2
$
$
18.8
424.9
561.8
132.1
191.2
11.7
60.7
330.9
1,732.1
4,146.5
991.9
12.8
997.6
7,880.9
177.5
366.9
439.6
124.7
206.9
25.0
60.7
288.8
1,690.1
3,994.6
1,357.0
21.8
777.8
7,841.3
1,200.8
2,610.7
(110.4)
(19.7)
3,681.4
418.6
4,100.0
$ 11,980.9
1,188.6
2,106.7
(93.4)
(38.6)
3,163.3
577.6
3,740.9
$ 11,582.2
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Year Ended September 30,
2018
2017
2016
$
7,651.2
$
6,120.7
$
5,685.7
4,074.9
2,013.4
75.0
455.1
(31.3)
6,587.1
1,064.1
4.3
—
16.2
(230.1)
854.5
(32.1)
822.4
(103.7)
718.7
4.13
4.06
$
$
$
2,837.3
1,873.4
—
416.3
(10.5)
5,116.5
1,004.2
4.3
(59.7)
(23.9)
(223.5)
701.4
(177.6)
523.8
(87.2)
436.6
2.51
2.46
$
$
$
173,908
176,905
173,662
177,159
1.02
$
0.975
$
2,437.5
1,881.7
—
400.9
(22.4)
4,697.7
988.0
(0.2)
(48.9)
—
(228.9)
710.0
(221.2)
488.8
(124.1)
364.7
2.11
2.08
173,154
175,572
0.93
Revenues
Costs and Expenses
Cost of sales (excluding depreciation and amortization shown below)
Operating and administrative expenses
Impairment of Partnership tradenames and trademarks
Depreciation and amortization
Other operating income, net
Operating income
Income (loss) from equity investees
Loss on extinguishments of debt
Gain (loss) on foreign currency contracts, net
Interest expense
Income before income taxes
Income taxes
Net income including noncontrolling interests
Deduct net income attributable to noncontrolling interests, principally in
AmeriGas Partners
Net income attributable to UGI Corporation
Earnings per common share attributable to UGI Corporation stockholders:
Basic
Diluted
Weighted-average common shares outstanding (thousands):
Basic
Diluted
Dividends declared per common share
See accompanying Notes to Consolidated Financial Statements.
$
$
$
$
F-7
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)
Year Ended September 30,
2018
2017
2016
Net income including noncontrolling interests
$
822.4
$
523.8
$
488.8
Net gains (losses) on derivative instruments (net of tax of $(0.8), $(0.5) and
$12.3, respectively)
Reclassifications of net losses (gains) on derivative instruments (net of tax
of $(2.6), $4.1 and $5.0, respectively)
Foreign currency translation adjustments (net of tax of $(0.5), $(0.6) and
$0.0, respectively)
Foreign currency (losses) gains on long-term intra-company transactions
Benefit plans, principally actuarial gains (losses) (net of tax of $(5.2),
$(3.8) and $7.1, respectively)
Reclassifications of benefit plans actuarial losses and net prior service
benefit (net of tax of $1.1, $(2.1) and $(0.4), respectively)
Other comprehensive (loss) income
Comprehensive income including noncontrolling interests
Deduct comprehensive income attributable to noncontrolling interests,
principally in AmeriGas Partners
Comprehensive income attributable to UGI Corporation
See accompanying Notes to Consolidated Financial Statements.
1.0
4.3
(21.4)
(9.1)
10.4
(2.2)
(17.0)
805.4
1.7
(9.7)
34.6
24.8
6.5
3.4
61.3
585.1
(16.5)
(8.1)
(4.9)
(1.9)
(10.9)
2.2
(40.1)
448.7
(103.7)
701.7
$
$
(87.2)
497.9
$
(124.1)
324.6
F-8
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests
Adjustments to reconcile net income including noncontrolling interests to
net cash provided by operating activities:
Depreciation and amortization
Deferred income tax (benefit) expense, net
Provision for uncollectible accounts
Changes in unrealized gains and losses on derivative instruments
Impairment of Partnership tradenames and trademarks
Equity-based compensation expense
Loss on extinguishments of debt
Settlement of UGI Utilities interest rate protection agreements
Loss on private equity partnership investment
Other, net
Net change in:
Accounts receivable and accrued utility revenues
Inventories
Utility deferred fuel costs, net of changes in unsettled derivatives
Accounts payable
Other current assets
Other current liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment
Acquisitions of businesses and assets, net of cash acquired
Decrease in restricted cash
Other, net
Net cash used by investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock
Distributions on AmeriGas Partners publicly held Common Units
Issuances of debt, net of issuance costs
Repayments of debt, including redemption premiums
Receivables Facility net (repayments) borrowings
Increase in short-term borrowings
Issuances of UGI Common Stock
Repurchases of UGI Common Stock
Other
Net cash used by financing activities
Effect of exchange rate changes on cash and cash equivalents
Cash and cash equivalents (decrease) increase
CASH AND CASH EQUIVALENTS
End of year
Beginning of year
(Decrease) increase
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for:
Interest
Income taxes
See accompanying Notes to Consolidated Financial Statements.
F-9
Year Ended September 30,
2018
2017
2016
$
822.4
$
523.8
$
488.8
455.1
(68.8)
35.6
(132.8)
75.0
22.5
—
—
—
10.7
(147.6)
(37.4)
31.1
65.1
(26.6)
(19.0)
1,085.3
(574.4)
(187.2)
0.7
13.0
(747.9)
(176.9)
(263.0)
124.4
(149.1)
(37.0)
93.5
34.9
(59.8)
(5.2)
(438.2)
(5.0)
(105.8) $
$
452.6
558.4
(105.8) $
416.3
110.1
30.7
(82.0)
—
19.3
59.7
—
11.0
44.1
(103.6)
(64.7)
(15.4)
49.9
(37.5)
2.7
964.4
(638.9)
(101.6)
6.1
(29.0)
(763.4)
(168.9)
(261.6)
1,307.1
(1,064.8)
13.5
61.2
11.0
(43.3)
(0.8)
(146.6)
1.2
55.6
558.4
502.8
55.6
221.7
118.0
$
$
202.1
98.0
$
$
$
$
$
400.9
77.4
21.7
(91.6)
—
23.8
48.9
(36.0)
—
(7.3)
37.3
29.4
(22.7)
(40.0)
(8.6)
47.7
969.7
(563.8)
(61.2)
53.7
12.7
(558.6)
(160.7)
(257.3)
1,629.5
(1,569.9)
6.0
95.7
13.7
(47.6)
15.5
(275.1)
(2.9)
133.1
502.8
369.7
133.1
228.9
134.5
$
$
$
$
$
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)
Year Ended September 30,
2017
2018
2016
Common stock, without par value
Balance, beginning of year
Common stock issued:
Employee and director plans (including losses on treasury stock
transactions), net of tax withheld
Excess tax benefits realized on equity-based compensation
Equity-based compensation expense
Gain on sale of treasury stock
Balance, end of year
Retained earnings
Balance, beginning of year
Cumulative effect of change in accounting for employee share-based payments
Losses on treasury stock transactions in connection with employee and
director plans
Net income attributable to UGI Corporation
Cash dividends on common stock ($1.02, $0.975, and $0.93 per share,
respectively)
Balance, end of year
Accumulated other comprehensive income (loss)
Balance, beginning of year
Net gains (losses) on derivative instruments
Reclassification of net losses (gains) on derivative instruments
Benefit plans, principally actuarial gains (losses)
Reclassification of benefit plans actuarial losses and net prior service benefits
Foreign currency (losses) gains on long-term intra-company transactions
Foreign currency translation adjustments
Balance, end of year
Treasury stock
Balance, beginning of year
Common stock issued:
Employee and director plans, net of tax withheld
Repurchases of common stock
Reacquired common stock – employee and director plans
Sale of treasury stock
Balance, end of year
Total UGI Corporation stockholders’ equity
Noncontrolling interests
Balance, beginning of year
Net income attributable to noncontrolling interests, principally in AmeriGas
Partners
Dividends and distributions
Other
Balance, end of year
Total equity
See accompanying Notes to Consolidated Financial Statements.
$
1,188.6
$
1,201.6
$
1,214.6
(1.5)
—
13.7
—
1,200.8
2,106.7
—
(37.8)
718.7
$
$
(28.2)
—
13.2
2.0
1,188.6
1,834.1
4.9
—
436.6
$
$
(39.7)
15.5
11.2
—
1,201.6
1,630.1
—
—
364.7
(176.9)
2,610.7
$
(168.9)
2,106.7
$
(160.7)
1,834.1
(93.4) $
1.0
4.3
10.4
(2.2)
(9.1)
(21.4)
(110.4) $
(154.7) $
1.7
(9.7)
6.5
3.4
24.8
34.6
(93.4) $
(114.6)
(16.5)
(8.1)
(10.9)
2.2
(1.9)
(4.9)
(154.7)
(38.6) $
(36.9) $
(44.9)
86.5
(59.8)
(7.8)
—
(19.7) $
$
3,681.4
49.6
(43.3)
(8.2)
0.2
(38.6) $
$
3,163.3
84.7
(47.6)
(29.1)
—
(36.9)
2,844.1
577.6
$
750.9
$
880.4
103.7
(263.3)
0.6
418.6
4,100.0
$
$
87.2
(261.6)
1.1
577.6
3,740.9
$
$
124.1
(257.3)
3.7
750.9
3,595.0
$
$
$
$
$
$
$
$
$
$
$
F-10
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Index to Notes
Note 1 — Nature of Operations
Note 2 — Summary of Significant Accounting Policies
Note 3 — Accounting Changes
Note 4 — Acquisitions of Businesses and Assets
Note 5 — Debt
Note 6 — Income Taxes
Note 7 — Employee Retirement Plans
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
Note 9 — Inventories
Note 10 — Property, Plant and Equipment
Note 11 — Goodwill and Intangible Assets
Note 12 — Series Preferred Stock
Note 13 — Common Stock and Equity-Based Compensation
Note 14 — Partnership Distributions
Note 15 — Commitments and Contingencies
Note 16 — Fair Value Measurements
Note 17 — Derivative Instruments and Hedging Activities
Note 18 — Accumulated Other Comprehensive Income (Loss)
Note 19 — Other Operating Income, Net
Note 20 — Quarterly Data (unaudited)
Note 21 — Segment Information
Note 1 — Nature of Operations
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets
energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a
retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; and (3) own
and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity
generation and energy services business. In Europe, we market and distribute propane and other liquefied petroleum gases (“LPG”)
and market energy products and services. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we”
or “us.”
We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”).
AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its
principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”). AmeriGas Partners and AmeriGas OLP are Delaware
limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the
general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the
“Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30,
2018, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held
an effective 27.0% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises AmeriGas
Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held
by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas
Partners in excess of its 1% general partner interest under certain circumstances (see Note 14).
Our wholly owned subsidiary, UGI Enterprises, LLC (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution
business throughout much of Europe and (2) an energy marketing business in France, Belgium, the Netherlands and the United
Kingdom. These businesses are conducted principally through our subsidiaries, UGI France SAS (“UGI France”), Flaga GmbH
(“Flaga”), AvantiGas Limited (“AvantiGas”), DVEP Investeringen B.V. (“DVEP”) and UniverGas Italia S.r.l. (“UniverGas”). We
refer to our foreign operations collectively as “UGI International.”
UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through
subsidiaries, energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas
production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. Energy Services,
F-11
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities
principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning,
refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania (“HVAC”). Energy Services,
LLC and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the
Federal Energy Regulatory Commission ("FERC"). We refer to the businesses of Energy Services, LLC and its subsidiaries and
HVAC as “Midstream & Marketing.”
UGI Utilities, Inc. (“UGI Utilities”) owns and operates a natural gas distribution utility business (“Gas Utility”) directly and, prior
to their merger with and into UGI Utilities effective October 1, 2018 (see Note 8), through its wholly owned subsidiaries, UGI
Penn Natural Gas, Inc. and UGI Central Penn Gas, Inc. The terms “PNG” and “CPG” are used herein as abbreviated references
to UGI Penn Natural Gas, Inc. and UGI Central Penn Gas, Inc., respectively, or to their associated natural gas utilities. 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.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission
(“PAPUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission
(“MDPSC”). Electric Utility is subject to regulation by the PAPUC and the Federal Energy Regulatory Commission (“FERC”).
UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.
Note 2 — Summary of 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, revenues, expenses and costs. These estimates are
based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be
reasonable under the circumstances. Accordingly, 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
The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the
Partnership, are majority owned. We report the public’s interests in the Partnership, and outside ownership interests in other
consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate intercompany accounts and
transactions when we consolidate.
Entities in which we do not have control, but have significant influence over operating and financial policies, are accounted for
by the equity method. Investments in business entities that are not publicly traded and in which we do not have significant influence
over operating and financial policies are accounted for using the cost method. Our equity and cost method investments totaled
$147.2 and $120.4 at September 30, 2018 and 2017, respectively, and are included in “Other assets” on the Consolidated Balance
Sheets.
A wholly owned subsidiary of UGI, UGI PennEast, LLC, and four other members comprising wholly owned subsidiaries of
Southern Company, New Jersey Resources, South Jersey Industries, and Enbridge, Inc., hold 20% membership interests each in
PennEast Pipeline Company, LLC (“PennEast”). PennEast is focused on constructing an approximate 120-mile natural gas pipeline
from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey. Affiliates of all members plan to be
customers of the pipeline under 15-year contracts. PennEast is considered to be an equity method investment as we have the ability
to exercise significant influence, but not control, over PennEast. We are obligated to provide capital contributions based upon our
ownership percentage. Our investment in PennEast at September 30, 2018 and 2017 totaled $72.6 and $51.0, respectively.
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s
(“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this
guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded
as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the
future. Similarly, 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. Regulatory assets and
F-12
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded
within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and
income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our
utility operations, see Note 8.
Fair Value Measurements
The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis.
Fair value in GAAP is defined 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. Fair value measurements performed on a recurring basis
principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts.
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three
levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1
measurements) and the lowest priority to unobservable inputs (Level 3 measurements). A level within the fair value hierarchy is
based on the lowest level of any input that is significant to the fair value measurement.
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.
• 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 markets that are not active, 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.
• Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for
the asset or liability.
Fair value is 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. We evaluate the
need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values
of our derivative instruments.
Derivative Instruments
Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the normal purchase and normal
sale (“NPNS”) exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument,
whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes.
Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair
values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“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 occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued
for derivatives that cease to be highly effective. We do not designate our commodity and certain foreign currency derivative
instruments as hedges under GAAP. Changes in the fair values of these derivative instruments are reflected in net income. Gains
and losses on substantially all of the commodity derivative instruments used by UGI Utilities are included in regulatory assets or
liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we
also enter into net investment hedges. Gains and losses on net investment hedges that relate to our foreign operations are included
in AOCI until such foreign net investment is sold or liquidated.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a
result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign
currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains
F-13
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
and losses on these contracts are recorded in “Gain (loss) on foreign currency contracts, net” on the Consolidated Statements of
Income.
Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included
in cash flows from operating activities on the Consolidated Statements of Cash Flows. Cash flows from the interest portion of our
cross-currency hedges, if any, are included in cash flows from operating activities while cash flows from the currency portion of
such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included
in cash flows from investing activities on the Consolidated Statements of Cash Flows.
For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them
and other information, see Note 17.
Foreign Currency Translation
Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income
statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period.
Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such
transactions arise with the impact of subsequent changes in such rates reflected in the income statement. The functional currency
of a significant portion of our international operations is the euro.
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing and our UGI International
energy marketing business record revenues when energy products are delivered or services are provided to customers. Revenues
from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance
services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for
distribution service rendered and commodities delivered 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.
We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use
taxes, on a net basis. Electric Utility gross receipts taxes are included in “Operating and administrative expenses” on the Consolidated
Statements of Income in accordance with regulatory practice.
Accounts Receivable
Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance
for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions
for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific
amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including
vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as
“Operating and administrative expenses” on the Consolidated Statements of Income. Depreciation expense associated with the
Partnership and UGI International delivery vehicles is classified in “Depreciation and amortization” on the Consolidated Statements
of Income.
Income Taxes
AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. Instead, their taxable income or loss is
allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss
and (2) the differences between the book and tax basis of our investment in the Partnership. AmeriGas OLP has subsidiaries which
operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation
of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.
F-14
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
UGI Utilities records deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax
depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also records a deferred income tax
liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, 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 UGI Utilities’ plant additions over the service lives of the related
property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when 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. At September 30, 2018 and 2017, such deferred
investment tax credits totaled $2.6 and $2.9, respectively.
We record interest on underpayments and overpayments of income taxes, and income tax penalties, in “Income taxes” on the
Consolidated Statements of Income. For Fiscal 2018, Fiscal 2017 and Fiscal 2016, interest income or expense recognized in
“Income taxes” on the Consolidated Statements of Income was not material.
The Tax Cuts and Jobs Act (“TCJA”) was enacted on December 22, 2017, and includes a broad range of tax reform provisions
affecting the Company, including, among other things, changes in the U.S. corporate income tax rate. The TCJA reduces the
corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. We are subject to a 24.5% blended
U.S. federal income tax rate for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to
21%. In accordance with GAAP, at the date of enactment of the TCJA our federal deferred income taxes, including deferred income
taxes related to items included in AOCI, were remeasured based upon the new corporate income tax rate. For our non-utility
businesses, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and
the adjustment recorded in the provision for income taxes. Our utility businesses are also required to adjust deferred income tax
assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in income tax rates
on deferred income tax balances will be recovered or refunded in future rates, our rate-regulated utility businesses record a regulatory
asset or liability associated with these deferred income tax assets and liabilities. For additional information regarding the impact
of the TCJA and associated regulatory effects, see Notes 6 and 8.
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares
outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common
stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2018,
Fiscal 2017 and Fiscal 2016:
(Thousands of shares)
Weighted-average common shares outstanding for basic computation
Incremental shares issuable for stock options and common stock awards (a)
Weighted-average common shares outstanding for diluted computation
2018
2017
2016
173,908
2,997
176,905
173,662
3,497
177,159
173,154
2,418
175,572
(a) For Fiscal 2018, Fiscal 2017 and Fiscal 2016, there were 0 shares, 146 shares and 38 shares, respectively, associated with
outstanding stock option awards that were not included in the computation of diluted earnings per share above because their
effect was antidilutive.
Cash and Cash Equivalents
For cash flow purposes, cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities
of three months or less when purchased.
Restricted Cash
Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from
withdrawal.
F-15
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Inventories
Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for non-
utility LPG and natural gas and Gas Utility natural gas; specific identification for appliances; and the first-in, first-out (“FIFO”)
method for all other inventories.
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at the lower of original cost or fair value, if impaired. Capitalized costs include labor,
materials and other direct and indirect costs, and for certain operations subject to cost-of-service rate regulation, allowance for
funds used during construction (“AFUDC”). We also include in property, plant and equipment costs associated with computer
software we develop or obtain for use in our business. The amounts assigned to property, plant and equipment of acquired businesses
are based upon estimated fair value at date of acquisition. When we retire or otherwise dispose of non-utility plant and equipment,
we eliminate the associated cost and accumulated depreciation and recognize any resulting gain or loss in "Other operating income,
net" on the Consolidated Statements of Income.
We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives.
At September 30, 2018, estimated useful lives by asset type were as follows:
Asset Type
Buildings and improvements
Equipment, primarily cylinders and tanks
Electricity generation facilities
Pipeline and related assets
Transportation equipment and office furniture and fixtures
Computer software
Minimum
Estimated Useful
Life
(in years)
Maximum
Estimated Useful
Life
(in years)
10
5
25
25
3
1
40
30
40
40
10
10
We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line basis based upon the projected service
lives of the various classes of its depreciable property. The average composite depreciation rates at our Gas Utility and Electric
Utility for Fiscal 2018, 2017 and 2016 were as follows:
Gas Utility
Electric Utility
2018
2017
2016
2.3%
2.2%
2.2%
2.4%
2.2%
2.5%
UGI Utilities’ information technology (“IT”) costs associated with major IT system installations, conversions and improvements,
such as software training, data conversion, business process reengineering costs, preliminary project stage costs and cloud
computing are deferred as a regulatory asset and included as a component of property, plant and equipment. As of September 30,
2018, approximately $6.3 of these costs have been deferred as a regulatory asset and have not yet been requested in a rate proceeding.
UGI Utilities amortizes computer software and related IT system installation costs on a straight-line basis over expected periods
of benefit not exceeding 15 years once the installed software is ready for its intended use.
We classify amortization of computer software and related IT system installation costs included in property, plant and equipment
as depreciation expense. Depreciation expense totaled $396.5, $365.5 and $346.6 for Fiscal 2018, Fiscal 2017 and Fiscal 2016,
respectively.
For property subject to cost of service rate regulation including substantially all of UGI Utilities depreciable utility plant and
equipment, upon retirement we charge the original cost to accumulated depreciation for financial accounting purposes. Costs
incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years,
consistent with prior ratemaking treatment.
No depreciation expense is included in cost of sales on the Consolidated Statements of Income.
F-16
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Goodwill and Intangible Assets
Intangible Assets. We amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite.
No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 11).
Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships, certain tradenames and
noncompete agreements, do not exceed 15 years. We review definite-lived intangible assets for impairment whenever events or
changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment
loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset.
Intangible assets with indefinite lives are not amortized but are tested for impairment annually (and more frequently if events or
changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to
fair value, if impaired.
In April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain tradenames and trademarks,
primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, over a period of approximately three
years. As a result, during the third quarter of Fiscal 2018, the Partnership determined that these tradenames and trademarks no
longer had indefinite lives and adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values.
During the third quarter of Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount
is reflected in “Impairment of Partnership tradenames and trademarks” on the Consolidated Statements of Income, and is amortizing
the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years. For
further information on these tradenames and trademarks, see Notes 11 and 16.
Goodwill. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is
an operating segment or one level below an operating segment (a component) if discrete financial information is prepared and
regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic
characteristics. Each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or
circumstances indicate that the value of goodwill may be impaired.
For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that
the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the
qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their
carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches.
For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated
future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate
risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future
growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to
establish fair values under our income approach involve management judgments based on a broad range of information and
historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of
the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires
judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an
impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting
unit.
There were no accumulated goodwill impairment losses at September 30, 2018 and 2017, and no provisions for goodwill
impairments were recorded during Fiscal 2018, Fiscal 2017 or Fiscal 2016. For further information on our goodwill and intangible
assets, see Note 11.
Impairment of Long-Lived Assets and Cost Basis Investments
We evaluate long-lived assets for impairment 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 material provisions for impairments were recorded during Fiscal 2018, Fiscal 2017 or Fiscal 2016.
We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary.
During Fiscal 2017, we recorded a pre-tax loss of $11.0 associated with an other-than-temporary impairment of our investment in
a private equity partnership that invests in renewable energy companies. This loss is reflected in “Other operating income, net”
on the Consolidated Statements of Income. No other-than-temporary impairment losses were recognized during Fiscal 2018 or
Fiscal 2016.
F-17
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Debt Issuance Costs
We defer and amortize debt issuance costs and debt premiums and discounts over the expected lives of the respective debt issues
considering maturity dates. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from
the carrying amount of such debt. Deferred debt issuance costs associated with revolving credit facilities are classified as “Other
assets” on our Consolidated Balance Sheets. Amortization of debt issuance costs is reported as interest expense. Unamortized costs
associated with redemptions of debt prior to their stated maturity are generally recognized and recorded in loss on extinguishment
of debt. As permitted by regulatory authorities, gains or losses resulting from refinancings of UGI Utilities’ debt are deferred and
amortized over the lives of the new issuances.
Refundable Tank and Cylinder Deposits
Included in “Other noncurrent liabilities” on our Consolidated Balance Sheets are customer paid deposits on tanks and cylinders
primarily owned by subsidiaries of UGI France of $272.0 and $279.9 at September 30, 2018 and 2017, respectively. Deposits are
refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effects 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 be reasonably 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. Under GAAP,
if the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable,
such liabilities are discounted to reflect the time value of money. We intend to pursue recovery of incurred costs through all
appropriate means, including regulatory relief. UGI Utilities receives ratemaking recognition of environmental investigation and
remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference
between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see
Note 15.
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 U.S. pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is
based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s 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 7).
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments
and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units” or “Unit awards”),
are 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 on 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.
We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount
of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences
between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax
F-18
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
return are recorded on the Consolidated Statements of Income. We account for forfeitures of share-based payments when they
occur.
Effective October 1, 2016, we adopted Accounting Standards Update (“ASU”) No. 2016-09, “Improvements to Employee Share-
Based Payments Accounting” (“ASU 2016-09”) which simplifies several aspects of accounting for employee share-based payment
transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as
classification in the statement of cash flows. As a result of the adoption of ASU 2016-09, beginning in Fiscal 2017 excess tax
benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax
benefit or expense in the reporting period in which they occur, and assumed proceeds under the treasury stock method used for
computing diluted shares outstanding no longer include windfall tax benefits in the diluted shares calculation. In addition, upon
the adoption of ASU 2016-09, we recorded a $4.9 increase to retained earnings and decrease to deferred income tax liabilities for
excess tax benefits related to prior period unrecognized state tax benefits. We elected to use the prospective method of transition
for classifying excess tax benefits as cash flow from operating activities on the Consolidated Statements of Cash Flows. In addition,
as provided by the new guidance, we elected to account for forfeitures of share-based payments when they occur.
For additional information on our equity-based compensation plans and related disclosures, see Note 13.
Note 3 — Accounting Changes
New Accounting Standards Adopted Effective October 1, 2018
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (“ASU
2014-09”). The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in ASC No.
605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 requires that an entity
recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration
to which the entity expects to be entitled in exchange for those goods or services. In addition, the new guidance requires enhanced
disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenues and cash
flows arising from contracts with customers and requires, among other things, the disaggregation of revenues into categories that
show how economic factors affect the nature, timing and uncertainty of revenues and cash flows. We adopted this ASU effective
October 1, 2018, using the modified retrospective transition method.
The Company has completed the process of analyzing the impact of the new guidance using an integrated approach which includes
evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance,
reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design
of internal controls. Although the impact of the adoption of the new revenue recognition guidance will not have a material impact
on our financial statements, certain performance obligations associated the release of capacity contracts at UGI Utilities will be
reflected on a gross, rather than net, basis beginning October 1, 2018 and revenues from certain other negotiated rate contracts
will be reflected on a straight-line basis.
Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for
Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a
customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement
was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the
service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense
related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments
for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and
to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees
are presented. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after
the date of adoption. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation
costs associated with cloud computing arrangements that are service contracts incurred after October 1, 2018.
Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02,
“Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded
tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to
the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted.
F-19
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
We adopted this ASU effective October 1, 2018. The amount of stranded tax benefits reclassified from AOCI to retained earnings
as of October 1, 2018 was not material.
Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation
of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service
cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees
in the income statement. The other components are required to be presented elsewhere in the income statement and outside of
income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization,
when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator
continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of
a regulatory asset or liability. Upon adoption, UGI Utilities will capitalize the non-service cost components of postretirement
benefit costs as a regulatory asset. The new guidance became effective for us on October 1, 2018 with a retrospective adoption
for income statement presentation and a prospective adoption for capitalization. Other than the presentation of the non-service
cost components on the statement of income, the adoption of this new guidance will not have a material impact on our consolidated
financial statements.
Statement of Cash flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows:
Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the
total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described
as restricted cash and restricted cash equivalents will be included with cash and cash equivalents when reconciling the beginning-
of-period and end-of-period total amounts on the statement of cash flows. The amendments in the ASU are required to be adopted
on a retrospective basis. We adopted this ASU effective October 1, 2018. Adoption of this new guidance will result in a change
in presentation of restricted cash on the Consolidated Statement of Cash Flows; otherwise this guidance will not have a significant
impact on our Consolidated Statement of Cash Flows and disclosures.
Other Accounting Principles Not Yet Adopted
Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to
the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor
defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments
in this ASU are effective for interim and annual periods ending after December 15, 2020 (Fiscal 2021). The guidance shall be
adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the
process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the
period in which the new guidance will be adopted.
Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure
Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by
removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning after
December 15, 2019 (Fiscal 2021). The guidance regarding removed and modified disclosures will be adopted on a retrospective
basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company
is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining
the period in which the new guidance will be adopted.
Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging
Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects
of risk management activities in the financial statements. The amendments in this ASU are effective for the Company for interim
and annual periods beginning October 1, 2019 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges
as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance
is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption
of the new guidance and determining the period in which the new guidance will be adopted.
Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing
guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those
leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of
cash flows from leases. The amendments in this ASU are effective for the Company for interim and annual periods beginning
October 1, 2019 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for
F-20
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements unless
an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides
entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the
opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1,
2019 and expect to elect the proposed transition option which would allow the Company to maintain historical presentation for
periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance
and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at
the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats
compatible with a new lease management system that will assist with the initial adoption of the standard.
Note 4 — Acquisitions of Businesses and Assets
Acquisitions of Businesses
During Fiscal 2018, UGI International acquired UniverGas, an LPG distribution business with operations in northern and central
regions of Italy, and AmeriGas Propane acquired two retail propane distribution businesses. During Fiscal 2017, UGI International
acquired DVEP, an energy marketing business with operations in the Netherlands, and an LPG distribution business with operations
in Sweden, and AmeriGas Propane acquired several retail propane distribution businesses. During Fiscal 2016, UGI International
acquired several LPG distribution businesses with operations in Austria, Norway and the United Kingdom, and AmeriGas Propane
acquired several retail propane distribution businesses. The operating results of these businesses have been included in our operating
results from their respective dates of acquisition.
Total cash paid and liabilities incurred in connection with these acquisitions were as follows:
2018
2017
2016
AmeriGas
Propane
UGI
International
AmeriGas
Propane
UGI
International
AmeriGas
Propane
UGI
International
Total cash paid
Liabilities incurred (a)
Total purchase price
$
$
10.1
2.7
12.8
$
$
121.9
—
121.9
$
$
36.8
10.8
47.6
$
$
99.7
20.6
120.3
$
$
37.6
11.8
49.4
$
$
24.1
—
24.1
(a) UGI International Fiscal 2017 amount includes note payable to seller. AmeriGas Propane amounts principally comprise
amounts payable under noncompete agreements.
Acquisitions of Assets
During Fiscal 2018, Midstream & Marketing acquired for cash 60 miles of natural gas gathering lines and related dehydration and
compression equipment, and a smaller natural gas gathering system, both located in northern Pennsylvania. In addition, during
Fiscal 2018, Midstream & Marketing acquired for cash a 44 megawatt natural gas-fired peaking turbine located on its Hunlock
Station site in northeast Pennsylvania. Total cash consideration for these asset acquisitions totaled $70.3.
Note 5 — Debt
Significant Financing Activities
AmeriGas Propane. In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement
(“AmeriGas OLP Credit Agreement”) with a group of banks. The AmeriGas OLP Credit Agreement amends and restates a previous
credit agreement. The AmeriGas OLP Credit Agreement provides for borrowings up to $600 (including a $150 sublimit for letters
of credit) and expires in December 2022. The AmeriGas OLP Credit Agreement permits AmeriGas to borrow at prevailing interest
rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a
one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas OLP Credit Agreement, plus a margin.
The applicable margin on base rate borrowings ranges from 0.50% to 1.75%, and the applicable margin on Eurodollar Rate
borrowings ranges from 1.50% to 2.75%. The aforementioned margins on borrowings are dependent upon AmeriGas Partners’
ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas
OLP Credit Agreement).
F-21
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
During Fiscal 2017, AmeriGas Partners issued, in underwritten offerings, $700 principal amount of 5.50% Senior Notes due May
2025 and $525 principal amount of 5.75% Senior Notes due May 2027 (collectively, the “AmeriGas 2017 Senior Notes”). The
AmeriGas 2017 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the
issuance of the AmeriGas 2017 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of
redemption, of all of AmeriGas Partners’ 7.00% Senior Notes, having an aggregate principal balance of $980.8 plus accrued and
unpaid interest and early redemption premiums, and (2) for general corporate purposes.
During Fiscal 2016, AmeriGas Partners issued in an underwritten offering $675 principal amount of 5.625% Senior Notes due
May 2024 and $675 principal amount of 5.875% Senior Notes due August 2026 (collectively, the “AmeriGas 2016 Senior Notes”).
The AmeriGas 2016 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from
the issuance of the AmeriGas 2016 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of
redemption, of all of AmeriGas Partners’ previously issued 6.50% Senior Notes, 6.75% Senior Notes and 6.25% Senior Notes,
having an aggregate principal balance of $1,270.0 plus accrued and unpaid interest and early redemption premiums and (2) for
general corporate purposes.
In connection with the early repayments of AmeriGas’ Senior Notes, during Fiscal 2017 and 2016, the Partnership recognized pre-
tax losses which are reflected in “Loss on extinguishments of debt” on the Consolidated Statements of Income and comprise the
following:
Early redemption premiums
Write-off of unamortized debt issuance costs
Loss on extinguishments of debt
2017
2016
51.3
8.4
59.7
$
$
39.6
9.3
48.9
$
$
UGI International. In December 2017, UGI International, LLC, a wholly owned subsidiary of UGI, entered into a secured
multicurrency revolving facility agreement (the "2017 UGI International Credit Agreement") due April 2020 with a group of banks
providing for borrowings up to €300. Upon entering into the 2018 UGI International Credit Facilities Agreement on October 25,
2018 (see “Subsequent Event - UGI International Refinancing” below), the 2017 UGI International Credit Agreement was
terminated. Under the 2017 UGI International Credit Agreement, UGI International, LLC could borrow in euros or U.S. dollars.
Loans made in euros bore interest at the associated euribor rate plus a margin ranging from 1.45% to 2.35%. Loans made in U.S.
dollars bore interest at LIBOR plus a margin ranging from 1.70% to 2.60%. The aforementioned margins are dependent upon
certain indebtedness at UGI International, LLC. There were no borrowings made under the 2017 UGI International Credit
Agreement.
Also, in December 2017, Flaga repaid $9.2 of the outstanding principal amount of its then-existing $59.1 U.S. dollar denominated
variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan,
which amended the previous agreement to extend the maturity of the term loan to April 2020 (“Flaga U.S. Dollar Term Loan”).
Prior to its repayment in October 2018 (see “Subsequent Event - UGI International Refinancing” below), borrowings under the
Flaga U.S. Dollar Term Loan bore interest at the one-month LIBOR rate plus a margin of 1.125%. Flaga effectively fixed the
LIBOR component of the interest rate, and effectively fixed the U.S. dollar value of the interest and principal payments payable
under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank.
UGI Utilities. In September 2018, UGI Utilities entered into an Increasing Lender Commitment and Acceptance (the “Commitment
and Acceptance”) under its existing unsecured, revolving credit agreement. The Commitment and Acceptance increases the amount
of loan commitments under UGI Utilities’ existing unsecured, revolving credit agreement to $450 from $300. All other terms of
UGI Utilities’ existing unsecured, revolving credit agreement remain unchanged.
In October 2017, UGI Utilities entered into a $125 unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with
a group of banks. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general
corporate purposes. The Utilities Term Loan is payable in equal quarterly installments of $1.6, commencing in March 2018, with
the balance of the principal being due and payable in full on October 30, 2022. Under the Utilities Term Loan, UGI Utilities may
borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such
borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Utilities
Term Loan requires that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined. In July
2018, UGI Utilities entered into a forward-starting pay-fixed, receive-variable interest rate swap that generally fixes the underlying
prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-
F-22
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
starting interest rate swap commences September 30, 2019. We have designated this forward-starting interest rate swap as a cash
flow hedge.
In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) with a consortium
of lenders. Pursuant to the 2016 Note Purchase Agreement, UGI Utilities issued $100 aggregate principal amount of 2.95% Senior
Notes due June 2026 and $200 aggregate principal amount of 4.12% Senior Notes due September 2046 in June 2016 and September
2016, respectively. In October 2016, UGI Utilities issued $100 aggregate principal amount of 4.12% Senior Notes due October
2046. The net proceeds of the issuance of these senior notes were used (1) to repay UGI Utilities’ maturing 5.75% Senior Notes,
7.37% Medium-term Notes and 5.64% Medium-term Notes; (2) to provide additional financing for UGI Utilities’ infrastructure
replacement and betterment capital program and the information technology initiatives; and (3) for general corporate purposes.
These senior notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt.
F-23
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Long-term Debt
Long-term debt comprises the following at September 30:
AmeriGas Propane:
AmeriGas Partners Senior Notes:
5.50% due May 2025
5.875% due August 2026
5.625% due May 2024
5.75% due May 2027
HOLP Senior Secured Notes, including unamortized premium of $0.2 and $0.4, respectively (a)
Other
Unamortized debt issuance costs
Total AmeriGas Propane
UGI International:
UGI France Senior Facilities term loan (b)
Flaga variable-rate term loan (c)
Flaga U.S. dollar variable-rate term loan (d)
Other
Unamortized debt issuance costs
Total UGI International
UGI Utilities:
Senior Notes:
4.12%, due September 2046
4.98%, due March 2044
4.12%, due October 2046
6.21%, due September 2036
2.95%, due June 2026
Medium-Term Notes:
6.13%, due October 2034
6.50%, due August 2033
5.67%, due January 2018
7.25%, due November 2017
Variable-rate term loan (e)
Other
Unamortized debt issuance costs
Total UGI Utilities
Other
Total long-term debt
Less: current maturities
Total long-term debt due after one year
2018
2017
$
700.0
675.0
675.0
525.0
7.5
14.6
(27.5)
2,569.6
627.0
53.2
49.9
20.9
(2.5)
748.5
200.0
175.0
100.0
100.0
100.0
20.0
20.0
—
—
120.3
6.8
(4.1)
838.0
9.2
4,165.3
(18.8)
4,146.5
$
700.0
675.0
675.0
525.0
11.3
17.3
(31.3)
2,572.3
708.9
54.1
59.1
21.3
(4.6)
838.8
200.0
175.0
100.0
100.0
100.0
20.0
20.0
20.0
20.0
—
—
(3.9)
751.1
9.9
4,172.1
(177.5)
3,994.6
$
$
(a) At September 30, 2018 and 2017, the effective interest rate on the HOLP Senior Secured Notes was 6.75%. These notes are
collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash.
(b) Borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor
rate, which euribor rate has a floor of 0.0%. The margin on term loan borrowings (which ranges from 1.60% to 2.70%) is
dependent upon the ratio of UGI France’s consolidated total net debt to EBITDA, each as defined. At September 30, 2018
and 2017, such margin was 1.75% and 1.90%, respectively. UGI France has entered into pay-fixed, receive-variable interest
rate swaps through April 30, 2019, to fix the underlying euribor rate on term loan borrowings at 0.18%. At September 30,
2018 and 2017, the effective interest rate on the term loan was approximately 1.93% and 2.08%, respectively. Principal
F-24
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
amounts outstanding under the term loan are due as follows: €60 due April 2019 and €480 due April 2020. This term loan
was repaid on October 25, 2018, in conjunction with the UGI International refinancing transaction (see “Subsequent Event -
UGI International Refinancing” below).
(c) Borrowings bear interest at three-month euribor rates, plus a margin and other fees. The margin and other fees range from
1.20% to 2.60% and are based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined, as
well as fees defined by the local jurisdiction. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally
fix the underlying market rate at 0.23%, effective October 2016. The effective interest rate on this term loan at September 30,
2018 and 2017, was 1.93% and 1.80%, respectively. This term loan was repaid on October 25, 2018, in conjunction with the
UGI International refinancing transaction (see “Subsequent Event - UGI International Refinancing” below).
(d) Borrowings bear interest at a one-month LIBOR rate plus a margin of 1.125%. Flaga has effectively fixed the LIBOR component
of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments by entering into a
cross-currency swap arrangement with a bank. At September 30, 2018 and 2017, the effective interest rate on this term loan
was 0.55% and 0.87%, respectively. This term loan was repaid on October 25, 2018, in conjunction with the UGI International
refinancing transaction (see “Subsequent Event - UGI International Refinancing” below).
(e) Borrowings bear interest at prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. UGI
Utilities has entered into a forward-starting, pay-fixed, receive-variable interest rate swap that generally fixes the underlying
prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022, commencing
September 30, 2019. The effective interest rate on this term loan at September 30, 2018, was 2.76%.
Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows:
AmeriGas Propane
UGI International (a)
UGI Utilities
Other
Total
2019
2020
2021
2022
2023
$
$
8.8
70.0
9.0
0.7
88.5
$
$
8.0
607.7
8.2
0.8
624.7
$
$
3.6
53.2
7.8
0.9
65.5
$
$
1.6
20.1
6.8
0.8
29.3
$
$
0.3
—
95.3
5.8
101.4
(a) Includes scheduled repayments as of September 30, 2018, relating to the UGI France Senior Facilities term loan; the Flaga
variable-rate term loan; and the Flaga U.S. dollar variable-rate term loan. These term loans were repaid on October 25, 2018
with net proceeds from the issuance of the UGI International 3.25% Senior Notes due November 2025 and the term loan
borrowings under the 2018 UGI International Credit Facilities Agreement due October 2023 and cash on hand (see “Subsequent
Event - UGI International Refinancing” below).
F-25
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Credit Facilities and Short-term Borrowings
Information about the Company’s principal credit agreements (excluding Energy Services, LLC’s Receivables Facility which is
discussed below) as of September 30, 2018 and 2017, is presented in the following table. Borrowings outstanding under these
agreements are classified as “Short-term borrowings” on the Consolidated Balance Sheets.
Expiration Date
Total
Capacity
Borrowings
Outstanding
Letters of
Credit and
Guarantees
Outstanding
Available
Borrowing
Capacity
Weighted
Average
Interest
Rate - End
of Year
December 2022
April 2020
April 2020
October 2020
March 2021
March 2020
June 2019
April 2020
October 2020
March 2021
March 2020
$
€
€
€
$
$
$
€
€
$
$
600.0
$
232.0
$
63.5
$
300.0
60.0
55.0
240.0
450.0
525.0
60.0
55.0
240.0
300.0
$
$
$
$
—
—
— €
—
189.5
140.0
—
$
$
— €
—
170.0
$
— $
— €
0.5
€
— $
2.0
67.2
$
$
— €
6.5
€
— $
2.0
$
304.5
300.0
60.0
54.5
240.0
258.5
317.8
60.0
48.5
240.0
128.0
4.58%
N.A.
N.A.
N.A.
N.A.
3.03%
3.74%
N.A.
N.A.
N.A.
2.11%
September 30, 2018
AmeriGas OLP (a)
UGI International, LLC (b)
UGI France (c)
Flaga (d)
Energy Services, LLC (e)
UGI Utilities (f)
September 30, 2017
AmeriGas OLP (a)
UGI France (c)
Flaga (d)
Energy Services, LLC (e)
UGI Utilities (f)
N.A. - Not applicable.
(a) The AmeriGas OLP Credit Agreement includes a $150 sublimit for letters of credit ($125 prior to its amendment in December
2017) and permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the
Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, or one-, two-, three-, or six-month Eurodollar
Rate, as defined, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.75%; the applicable
margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75%; and the facility fee ranges from 0.30% to 0.50%. The
aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to EBITDA, as defined.
(b) The UGI International Credit Agreement permits UGI International, LLC to borrow in euros or U.S. dollars. Loans made in
euros will bear interest at the associated euribor rate plus a margin ranging from 1.45% to 2.35%. Loans made in U.S. dollars
will bear interest at LIBOR plus a margin ranging from 1.70% to 2.60%. The aforementioned margins are dependent upon
certain indebtedness at UGI International, LLC. This facility was terminated concurrent with entering into the 2018 UGI
International Credit Facilities Agreement on October 25, 2018 (see “Subsequent Event - UGI International Refinancing”
below.)
(c) Borrowings under UGI France’s revolving credit facility bear interest at market rates (one-, two-, three-, or six-month euribor)
plus a margin. The margin on credit facility borrowings ranges from 1.45% to 2.55% based upon UGI France’s ratio of
consolidated total net debt to EBITDA, as defined. This facility was terminated concurrent with entering into the 2018 UGI
International Credit Facilities Agreement on October 25, 2018 (see “Subsequent Event - UGI International Refinancing”
below.)
(d) Flaga’s credit facility agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility and a €25
guarantee facility. Revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor
rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65%, are based upon the
actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, each as defined. Facility
fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. Guarantees outstanding
reduce the available capacity on the €25 guarantee facility. This facility was terminated concurrent with entering into the 2018
UGI International Credit Facilities Agreement on October 25, 2018 (see “Subsequent Event - UGI International Refinancing”
below.)
(e) Energy Services’ credit agreement includes a $50 sublimit for letters of credit and can be used for general corporate purposes
of Energy Services and its subsidiaries. Energy Services may not pay a dividend unless, after giving effect to such dividend
payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined, does not exceed 3.00 to 1.00. Borrowings
F-26
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
bear interest at either (i) the Alternate Base Rate plus a margin or (ii) a rate derived from LIBOR (“Adjusted LIBOR”) plus
a margin. The Alternate Base Rate, as defined, is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, and
(c) Adjusted LIBOR plus 1.00%. The margin on such borrowings ranges from 0.75% to 2.25%. The Energy Services credit
agreement is guaranteed by certain subsidiaries of Energy Services.
(f) UGI Utilities’ credit agreement includes a $100 sublimit for letters of credit. Borrowings bear interest at prevailing market
interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0%
to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. On September 21, 2018, UGI Utilities
entered into the Commitment and Acceptance which increased the total capacity under this facility to $450.
Accounts Receivable Securitization Facility. Energy Services, LLC has a receivables purchase facility (“Receivables Facility”)
with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2019. The Receivables Facility,
as amended, provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November
to April, and up to $75 of eligible receivables during the period May to October. Energy Services, LLC uses the Receivables
Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general
corporate purposes.
Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable
to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial
statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time sell, an undivided interest
in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as “Short-term borrowings” on the
Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services,
LLC and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company
reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the
bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses
on sales of receivables to the bank during Fiscal 2018, Fiscal 2017 and Fiscal 2016, which amounts are included in “Interest
expense” on the Consolidated Statements of Income, were not material.
Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2018,
Fiscal 2017 and Fiscal 2016, as well as the balance of ESFC trade receivables at September 30, 2018, 2017 and 2016 follows:
Trade receivables transferred to ESFC during the year
$
1,279.5
$
1,017.3
$
ESFC trade receivables sold to the bank during the year
ESFC trade receivables - end of year (a)
193.0
65.0
243.0
44.8
756.4
204.0
35.7
(a) At September 30, 2018 and 2017, the amounts of ESFC trade receivables sold to the bank were $2.0 and $39.0, respectively,
and are reflected as “Short-term borrowings” on the Consolidated Balance Sheets.
2018
2017
2016
Restrictive Covenants
Our long-term debt and credit facility agreements generally contain customary covenants and default provisions which may include,
among other things, restrictions on the incurrence of additional indebtedness and also restrict liens, guarantees, investments, loans
and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other
transactions.
The AmeriGas Propane OLP Credit Agreement requires that AmeriGas OLP and AmeriGas Partners maintain ratios of total
indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of
EBITDA to interest expense, as defined and as calculated on a rolling four-quarter basis. Generally, as long as no default exists
or would result therefrom, AmeriGas OLP is permitted to make cash distributions not more frequently than quarterly in an amount
not to exceed available cash, as defined, for the immediately preceding calendar quarter.
Under the AmeriGas Partners Senior Notes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal
to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30,
2018, these restrictions did not limit the amount of Available Cash. See Note 14 for the definition of Available Cash included in
the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P., as amended (“Partnership
Agreement”).
F-27
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The HOLP Senior Secured Notes financial covenants require AmeriGas OLP to maintain a ratio of Consolidated Funded
Indebtedness to Consolidated EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of Consolidated
EBITDA to Consolidated Interest Expense (as defined).
UGI Utilities’ credit agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital,
as defined, of 0.65 to 1.00. Certain of UGI Utilities’ Senior Notes contain financial covenants including a requirement that UGI
Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Energy Services’ credit agreement requires that Energy Services and subsidiaries not exceed a ratio of total indebtedness to
EBITDA, as defined, of 3.50 to 1.00, and maintain a minimum ratio of EBITDA to interest expense, as defined, of 3.50 to 1.00.
Restricted Net Assets
At September 30, 2018, the amount of net assets of UGI’s consolidated subsidiaries that were restricted from transfer to UGI under
debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,500.
Subsequent Event - UGI International Refinancing
On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, entered into a five-year unsecured
Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 variable-rate term loan which was drawn on
October 25, 2018, and (2) a €300 senior unsecured multicurrency revolving facility agreement (together, the “2018 UGI
International Credit Facilities Agreement”). The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023.
Term loan borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor
rate, which euribor rate has a floor of zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20%, is dependent
upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings is
1.70%. UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix
the underlying euribor rate on term loan borrowings at 0.34%. Under the multicurrency revolving credit facility agreement, UGI
International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus
a margin ranging from 1.20% to 2.85%. Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin
ranging from 1.45% to 3.10%. The margin on revolving facility borrowings is dependent upon a ratio of net consolidated
indebtedness to consolidated EBITDA, as defined.
Restrictive covenants under the 2018 UGI International Credit Facilities Agreement include restrictions on the incurrence of
additional indebtedness and also restrict liens, guarantees, investments, loans and advances, payments, mergers, consolidations,
asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. In addition, The 2018 UGI
International Credit Facilities Agreement requires a ratio of consolidated total net indebtedness to consolidated EBITDA, as
defined, not to exceed 3.85 to 1.00.
On October 25, 2018, UGI International, LLC issued in an underwritten private placement €350 principal amount of 3.25% senior
unsecured notes due November 1, 2025 (the “UGI International 3.25% Senior Notes”). The UGI International 3.25% Senior Notes
rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement.
The net proceeds from the UGI International 3.25% Senior Notes and the 2018 UGI International Credit Facilities Agreement
variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 outstanding principal of UGI France’s
variable-rate term loan under its 2015 Senior Facilities Agreement; €45.8 outstanding principal of Flaga’s variable-rate term loan;
and $49.9 outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest, and (2) for general
corporate purposes. Because these outstanding term loans were refinanced on a long-term basis in October 2018, we have classified
€60 of such debt due in April 2019 as long-term debt on the September 30, 2018 Consolidated Balance Sheet. Upon entering into
the 2018 UGI International Credit Facilities Agreement, we also terminated (1) the 2017 UGI International Credit Agreement, (2)
UGI France SAS’s revolving credit facility under the 2015 Senior Facilities Agreement and (3) Flaga’s credit facility agreement.
We have designated term loan borrowings under the 2018 UGI International Credit Facilities Agreement and the UGI International
3.25% Senior Notes as net investment hedges.
F-28
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 6 — Income Taxes
Income before income taxes comprises the following:
Domestic
Foreign
Total income before income taxes
The provisions for income taxes consist of the following:
Current expense (benefit):
Federal
State
Foreign
Total current expense
Deferred expense (benefit):
Federal
State
Foreign
Investment tax credit amortization
Total deferred expense
Total income tax expense
$
$
$
$
2018
2017
2016
576.0
278.5
854.5
$
$
527.3
174.1
701.4
$
$
518.9
191.1
710.0
2018
2017
2016
(2.7) $
26.0
77.6
100.9
(77.1)
6.7
1.9
(0.3)
(68.8)
32.1
(2.7) $
14.0
56.2
67.5
125.8
16.4
(31.8)
(0.3)
110.1
44.2
20.9
78.7
143.8
81.2
1.3
(4.8)
(0.3)
77.4
$
177.6
$
221.2
Federal income taxes for Fiscal 2018, Fiscal 2017 and Fiscal 2016 are net of foreign tax credits of $13.0, $40.9 and $25.6,
respectively.
A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
U.S. federal statutory tax rate
Difference in tax rate due to:
Effect of tax rate changes - TJCA
Effect of tax rate changes - France
Noncontrolling interests not subject to tax
State income taxes, net of federal benefit
Valuation allowance adjustments
Effects of foreign operations
Excess tax benefits on share-based payments
Other, net
Effective tax rate
2018
2017
2016
24.5%
35.0%
35.0%
(20.9)
(2.1)
(3.0)
2.9
1.1
3.1
(1.1)
(0.7)
3.8%
—
(4.1)
(4.3)
2.9
(1.1)
(1.1)
(1.3)
(0.7)
25.3%
—
—
(6.2)
3.0
(0.9)
0.6
—
(0.3)
31.2%
On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduced
the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018, created a territorial tax system with a one-time
mandatory “toll tax” on previously un-repatriated foreign earnings, and allowed for immediate capital expensing of certain qualified
property. It also applied restrictions on the deductibility of interest expense, eliminated bonus depreciation for regulated utilities
and certain FERC-regulated property beginning in Fiscal 2019 and applied a broader application of compensation limitations.
F-29
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
As a result of the TCJA, we reduced our net deferred income tax liabilities by $384.4 due to the remeasuring of our existing federal
deferred income tax assets and liabilities as of the date of the enactment of the TCJA on December 22, 2017. Because most of the
reduction to UGI Utilities’ net deferred income taxes relates to regulated utility plant assets, most of UGI Utilities’ reduction in
deferred income taxes is not being recognized immediately in income tax expense.
At September 30, 2018, the accounting for certain income tax effects of the TCJA with respect to existing deferred tax balances
and the one-time transition tax reflect provisional amounts. We have made a reasonable estimate of the effects in accordance with
U.S. Securities and Exchange Commission Staff Accounting Bulletin No. 118 and are still analyzing certain aspects of the TCJA
and refining our calculations, which could potentially result in changes to our current estimates. Revisions to our estimates, if any,
will be made by the first quarter of the fiscal year ending September 30, 2019.
In Fiscal 2018 we were subject to a blended federal tax rate of 24.5% because our fiscal year contains the effective date of the
rate change from 35% to 21%. The effects of the tax law changes on current period results (excluding the remeasurement impact
described above) decreased income tax by $52.1.
In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law
requires that excess deferred federal income taxes resulting from the remeasurement of deferred taxes on regulated utility plant
be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. As a
result of the TCJA, for Fiscal 2018, UGI Utilities initially recorded a net regulatory liability of $205.6 associated with excess
deferred federal income taxes related to its regulated utility plant assets. This regulatory liability was increased, and a federal
deferred income tax asset was recorded, in the amount of $83.6 to reflect the tax benefit generated by the amortization of the
excess deferred federal income taxes. This regulatory liability is being amortized to income tax expense over the remaining lives
of the assets that gave rise to the excess deferred income taxes. For further information on this regulatory liability, see Note 8.
As further described in Note 8, on May 17, 2018, the PAPUC issued a Temporary Rates Order for all PAPUC-regulated utilities
with regard to federal tax reform. Among other things, the Temporary Rates Order requires Pennsylvania utilities to establish a
regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the change
in the federal income tax rate from 35% to 21%. In accordance with the Temporary Rates Order, during Fiscal 2018, UGI Utilities
reduced its revenues by $24.1 and recorded a regulatory liability in an equal amount. The total reduction of $24.1 primarily reflects
(1) $17.1 of tax benefits accrued during the period January 1, 2018 to June 30, 2018, (2) $7.0 to reflect tax benefits expected to
be generated by the future amortization of the regulatory liability and accrued interest.
In Fiscal 2017 and Fiscal 2016, earnings of the Company’s foreign subsidiaries were generally subject to U.S. taxation upon
repatriation to the U.S. and the Company’s tax provisions reflected the related incremental U.S. tax except for certain foreign
subsidiaries whose unremitted earnings were considered to be indefinitely reinvested. No deferred tax liability had been recognized
with regard to remittance of those earnings because of the availability of U.S. foreign tax credits made it likely that no U.S. tax
would be due if such earnings were repatriated. Upon enactment of TCJA, substantially all prior unrepatriated earnings were
subjected to U.S. tax under the transition tax rules. The transition tax was immaterial to the Company and we generally expect to
have the ability to repatriate prior unrepatriated earnings without material U.S. federal tax cost.
Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax
depreciation. For Fiscal 2018, Fiscal 2017 and Fiscal 2016, the beneficial effects of state tax flow through of accelerated depreciation
reduced income tax expense by $4.2, $2.5 and $1.3, respectively.
F-30
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Deferred tax liabilities (assets) comprise the following at September 30:
2018
2017
Excess book basis over tax basis of property, plant and equipment
$
807.8
$
Investment in AmeriGas Partners
Intangible assets and goodwill
Utility regulatory assets
Derivative instruments
Other
Gross deferred tax liabilities
Pension plan liabilities
Employee-related benefits
Operating loss carryforwards
Foreign tax credit carryforwards
Utility regulatory liabilities
Derivative instruments
Utility environmental liabilities
Other
Gross deferred tax assets
Deferred tax assets valuation allowance
Net deferred tax liabilities
219.2
67.6
86.7
30.4
10.6
975.8
326.8
98.2
132.2
—
11.7
1,222.3
1,544.7
(20.0)
(43.6)
(26.2)
(106.1)
(118.6)
—
(14.7)
(29.0)
(358.2)
116.8
(57.7)
(65.4)
(30.9)
(106.1)
(9.3)
(1.7)
(22.2)
(27.8)
(321.1)
107.1
$
980.9
$
1,330.7
In December 2017, the French Parliament approved the Finance Bill for 2018 and the second amended Finance Bill for 2017
(collectively, the “December 2017 French Finance Bills”). One impact of the December 2017 French Finance Bills was an increase
in the Fiscal 2018 corporate income tax rate in France from 34.4% to 39.4%. The December 2017 French Finance Bills also
include measures to reduce the corporate income tax rate to 25.8%, effective for fiscal years starting after January 1, 2022 (Fiscal
2023).
As a result of the December 2017 French Finance Bills, the Company reduced its net French deferred income tax liabilities and
recognized an estimated deferred tax benefit of $12.1 to reflect the estimated impact of the corporate income tax rate reductions
that will be implemented through Fiscal 2023. The Company’s Fiscal 2018 effective income tax rate reflects the impact of the
higher Fiscal 2018 income tax rate in France as a result of the December 2017 French Finance Bills, which increased income tax
expense for the year by approximately $0.6.
In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively
the “Finance Bills”). The Finance Bills, among other things, at that time reduced the French corporate income tax rate from the
then-current 34.43% to 28.92%, effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of the future
income tax rate reduction, during Fiscal 2017 the Company reduced its net deferred income tax liabilities and recognized a deferred
tax benefit of $29.0.
At September 30, 2018, foreign net operating loss carryforwards principally relating to Flaga, UGI International Holdings BV
and certain subsidiaries of France SAS totaled $14.0, $2.5 and $23.3, respectively, with no expiration dates. We have state net
operating loss carryforwards primarily relating to certain subsidiaries which approximate $168.9 and expire through 2038. We
also have federal operating loss carryforwards of $19.7 for certain operations of AmeriGas Propane that expire through 2036. At
September 30, 2018, deferred tax assets relating to operating loss carryforwards include $2.9 for Flaga, $8.0 for certain subsidiaries
of France SAS, $0.7 for UGI International Holdings BV, $4.0 for AmeriGas Propane and $10.6 for certain other subsidiaries.
The valuation allowance for all deferred tax assets increased by $9.7 in Fiscal 2018 due to an increase of $7.6 to re-establish a
full valuation allowance associated with future utilization of foreign tax credits, primarily due to impacts of TCJA and an increase
in foreign operating loss carryforwards of $2.1. A valuation allowance of $9.6 exists for deferred tax assets related to certain
subsidiaries of France SAS, and certain subsidiaries of Flaga and UGI International Holdings BV.
F-31
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
In Fiscal 2017, the Company reversed $7.6 in valuation allowances associated with foreign tax credit carryforwards whose
utilization before expiration had previously not met a more-likely-than-not threshold. We have foreign tax credit carryforwards
of approximately $106.1 expiring through 2028 resulting from the actual and planned repatriation of France SAS’s accumulated
earnings since acquisition. The Company continuously monitors the potential utilization of these credits and performs the
appropriate weighing of positive and negative evidence in reaching a conclusion of whether utilization reaches a level of more
likely than not. In Fiscal 2017, the Company concluded it was more likely than not that $98.5 of the credits would expire before
utilization and therefore reversed $7.6 of the then existing valuation allowance against these credits. The amount of the deferred
tax asset considered realizable could be adjusted if estimates of future utilization during the carryforward period are reduced or
increased.
We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain other European
countries. Our U.S. federal income tax returns are settled through the 2014 tax year, our French tax returns are settled through the
2014 tax year, our Austrian tax returns are settled through 2016 and our other European tax returns are effectively settled for
various years from 2009 to 2016. State and other income tax returns in the U.S. are generally subject to examination for a period
of three to five years after the filing of the respective returns.
UGI Corporation and subsidiaries’ 2016 consolidated U.S. federal tax return is currently under examination by the Internal Revenue
Service. UGI France and subsidiaries’ 2015, 2016 and 2017 tax returns are currently under examination by the French Tax Authority.
As of September 30, 2018, we have unrecognized income tax benefits totaling $11.5 including related accrued interest of $1.0. If
these unrecognized tax benefits were subsequently recognized, $11.5 would be recorded as a benefit to income taxes on the
Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in
unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result
of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the
next twelve months.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
Unrecognized tax benefits — beginning of year
Additions for tax positions of the current year
Additions for tax positions taken in prior years
Settlements with tax authorities/statute lapses
Unrecognized tax benefits — end of year
Note 7 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans
2018
2017
2016
$
$
12.2
$
1.5
0.6
(2.8)
11.5
$
7.2
1.9
4.6
(1.5)
12.2
$
$
3.2
2.2
2.3
(0.5)
7.2
In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG,
CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). U.S. Pension Plan benefits are based
on years of service, age and employee compensation.
We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to certain U.S.
active and retired employees. In addition, certain UGI International employees in France, Belgium and the Netherlands are
covered by defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related
to the UGI International plans, such amounts are not material.
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the UGI
International pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets,
and the funded status of pension and other postretirement plans as of September 30, 2018 and 2017. ABO is the present value
of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future
compensation.
F-32
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Pension
Benefits
Other Postretirement
Benefits
2018
2017
2018
2017
Change in benefit obligations:
Benefit obligations — beginning of year
$
697.8
$
707.7
$
27.0
$
Service cost
Interest cost
Actuarial gain
Plan amendments
Curtailment
Foreign currency
Benefits paid
Benefit obligations — end of year
Change in plan assets:
Fair value of plan assets — beginning of year
Actual gain on plan assets
Foreign currency
Employer contributions
Benefits paid
Fair value of plan assets — end of year
Funded status of the plans — end of year
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other
noncurrent assets
Unfunded liabilities — included in other noncurrent
liabilities
Net amount recognized
Amounts recorded in UGI Corporation stockholders’
equity (pre-tax):
Prior service cost (benefit)
Net actuarial loss (gain)
Total
Amounts recorded in regulatory assets and liabilities
(pre-tax):
Prior service cost (benefit)
Net actuarial loss (gain)
Total
$
$
$
$
$
$
$
$
$
$
11.2
26.3
(37.0)
—
(0.6)
(1.0)
(27.5)
669.2
$
529.2
$
44.9
(0.6)
16.2
(26.4)
563.3
$
(105.9) $
11.9
25.0
(19.6)
1.2
(3.6)
2.9
(27.7)
697.8
$
0.5
0.8
(2.1)
(5.8)
(0.1)
—
(1.0)
19.3
$
493.7
$
14.8
$
47.0
1.6
14.6
(27.7)
529.2
$
(168.6) $
0.9
—
0.4
(0.8)
15.3
$
(4.0) $
30.9
1.0
0.8
(4.8)
—
(0.4)
0.4
(0.9)
27.0
13.7
1.3
—
0.6
(0.8)
14.8
(12.2)
— $
— $
6.7
$
5.4
(105.9)
(105.9) $
(168.6)
(168.6) $
(10.7)
(4.0) $
(17.6)
(12.2)
0.6
14.0
14.6
0.7
85.7
86.4
$
$
$
$
0.7
21.3
22.0
1.0
139.5
140.5
$
$
$
$
(1.3) $
(0.4)
(1.7) $
(1.2) $
(0.1)
(1.3) $
(1.5)
(0.6)
(2.1)
(1.6)
1.2
(0.4)
In Fiscal 2019, we estimate that we will amortize approximately $7.5 of net actuarial losses, primarily associated with the U.S.
Pension Plan, and $0.2 of net prior service benefits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.
Actuarial assumptions for our U.S. plans are described below. Assumptions for the UGI International plans are based upon market
conditions in France, Belgium and the Netherlands. The discount rate assumption was determined by selecting a hypothetical
portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount
rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the
plans’ benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as
well as historical and expected returns on various categories of plan assets (as further described below).
F-33
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Weighted-average assumptions:
Discount rate – benefit obligations
Discount rate – benefit cost
Expected return on plan assets
Rate of increase in salary levels
Pension Plan
2017
2018
2016
Other Postretirement Benefits
2016
2017
2018
4.40%
4.00%
7.40%
3.25%
4.00%
3.80%
7.50%
3.25%
3.80%
4.60%
7.55%
3.25%
4.40%
4.00%
5.00%
3.25%
4.00%
3.80%
5.00%
3.25%
3.80%
4.70%
5.00%
3.25%
The ABOs for the U.S. Pension Plan were $572.8 and $605.2 as of September 30, 2018 and 2017, respectively.
Net periodic pension expense and other postretirement benefit cost include the following components:
Pension Benefits
Other Postretirement Benefits
2018
2017
2016
2018
2017
2016
$
11.2
$
11.9
$
10.1
$
0.5
$
1.0
$
Service cost
Interest cost
Expected return on assets
Curtailment gain
Amortization of:
Prior service cost (benefit)
Actuarial loss (gain)
Net benefit cost
Change in associated regulatory liabilities
26.3
(35.0)
(0.2)
0.3
13.4
16.0
—
25.0
(33.6)
(1.4)
0.3
16.7
18.9
—
26.8
(32.4)
(1.2)
0.3
10.9
14.5
—
0.8
(0.7)
—
(6.3)
(0.1)
(5.8)
(0.5)
(6.3) $
0.8
(0.7)
—
(0.6)
0.3
0.8
(0.5)
0.3
$
0.7
0.9
(0.6)
—
(0.6)
—
0.4
1.0
1.4
Net benefit cost after change in regulatory liabilities
$
16.0
$
18.9
$
14.5
$
The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income
mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan
benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we
may, at our discretion, contribute additional amounts. During Fiscal 2018, Fiscal 2017 and Fiscal 2016, we made cash contributions
to the U.S. Pension Plan of $15.1, $11.4 and $9.9, respectively. The minimum required contributions in Fiscal 2019 are not
expected to be material.
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, if any, determined under
GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred
for future recovery from, or refund to, ratepayers. Any required contributions to the VEBA during Fiscal 2019 are not expected
to be material.
Expected payments for pension and other postretirement welfare benefits are as follows:
Fiscal 2019
Fiscal 2020
Fiscal 2021
Fiscal 2022
Fiscal 2023
Fiscal 2024 - 2028
Pension
Benefits
Other
Postretirement
Benefits
$
$
$
$
$
$
30.6
31.1
33.2
39.0
40.4
201.4
$
$
$
$
$
$
1.0
0.9
0.9
0.9
0.9
4.7
F-34
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The assumed domestic health care cost trend rates at September 30 are as follows:
Health care cost trend rate assumed for next year
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)
Fiscal year that the rate reaches the ultimate trend rate
2018
2017
6.75%
5.0%
2026
7.00%
5.0%
2026
A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2018
other postretirement benefit cost or September 30, 2018, other postretirement benefit ABO.
We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined
Benefit Plans”). At September 30, 2018 and 2017, the PBOs of these plans, including obligations for amounts held in grantor
trusts, were $48.3 and $50.7, respectively. We recorded pre-tax costs for these plans of $4.3 in Fiscal 2018 (which amount includes
a $2.1 settlement charge), $3.1 in Fiscal 2017 and $2.6 in Fiscal 2016. These costs are not included in the tables above. Amounts
recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $4.3 and $11.3 at September 30, 2018 and 2017,
respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.5 of such pre-tax
actuarial losses into retiree benefit cost in Fiscal 2019. During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company made
payments with respect to the Supplemental Defined Benefit Plans totaling $0.1, $1.3 and $0.4, respectively. The total fair value
of the grantor trust investment assets associated with the Supplemental Defined Benefit Plans, which are included in “Other
assets” on the Consolidated Balance Sheets, totaled $34.3 and $31.8 at September 30, 2018 and 2017, respectively.
U.S. Pension Plan and VEBA Assets
The assets of the U.S. Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for
the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall
investment objective of the U.S. Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and
reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity
and fixed income index mutual funds and UGI Common Stock. Assets associated with the UGI International plans are excluded
from the disclosures in the tables below as such assets are not material.
F-35
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows:
U.S. Pension Plan
Equity investments:
Domestic
International
Total
Fixed income funds & cash equivalents
Total
VEBA
Domestic equity investments
Fixed income funds & cash equivalents
Total
Actual
2018
2017
Target
Asset
Allocation
Permitted
Range
58.2%
11.8%
70.0%
30.0%
55.2%
12.4%
67.6%
32.4%
52.5% 40.0% – 65.0%
12.5% 7.5% – 17.5%
65.0% 60.0% – 70.0%
35.0% 30.0% – 40.0%
100.0%
100.0%
100.0%
Actual
2018
2017
Target
Asset
Allocation
Permitted
Range
65.6%
34.4%
100.0%
63.1%
36.9%
100.0%
65.0% 60.0% – 70.0%
35.0% 30.0% – 40.0%
100.0%
Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and mid- and small-cap
index mutual funds. Investments in international equity mutual funds seek to track performance of companies primarily in
developed markets. The fixed income investments comprise investments designed to match the performance and duration of the
Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed
10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8.5% and 7.7% of U.S. Pension
Plan assets at September 30, 2018 and 2017, respectively.
F-36
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The fair values of U.S. Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these
instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The
fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described
in Note 2, as of September 30, 2018 and 2017 are as follows:
Level 1
Level 2
Level 3
Other(a)
Total
U.S. Pension Plan
September 30, 2018:
Domestic equity investments:
S&P 500 Index equity mutual funds
$
188.4
$
— $
— $
— $
188.4
75.7
45.2
309.3
62.9
154.3
5.2
159.5
531.7
171.6
65.2
38.1
274.9
61.6
156.2
5.3
161.5
498.0
Small and midcap equity mutual funds
UGI Corporation Common Stock
Total domestic equity investments
International index equity mutual funds
Fixed income investments:
Bond index mutual funds
Cash equivalents
Total fixed income investments
Total
September 30, 2017:
Domestic equity investments:
S&P 500 Index equity mutual funds
Small and midcap equity mutual funds
UGI Corporation Common Stock
Total domestic equity investments
International index equity mutual funds
Fixed income investments:
Bond index mutual funds
Cash equivalents
Total fixed income investments
$
$
75.7
45.2
309.3
62.9
154.3
—
154.3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
526.5
$
— $
— $
—
—
—
—
—
5.2
5.2
5.2
$
171.6
$
— $
— $
— $
65.2
38.1
274.9
61.6
156.2
—
156.2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5.3
5.3
5.3
$
Total
$
492.7
$
— $
— $
F-37
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Level 1
Level 2
VEBA
Level 3
Other (a)
Total
September 30, 2018:
S&P 500 Index equity mutual fund
Bond index mutual fund
Cash equivalents
Total
September 30, 2017:
S&P 500 Index equity mutual fund
Bond index mutual fund
Cash equivalents
Total
$
$
$
$
10.1
4.9
—
15.0
9.3
5.1
—
14.4
$
$
$
$
— $
—
—
— $
— $
—
—
— $
— $
—
—
— $
— $
—
—
— $
— $
—
0.3
0.3
$
— $
—
0.4
0.4
$
10.1
4.9
0.3
15.3
9.3
5.1
0.4
14.8
(a) Assets measured at net asset value (“NAV”) and therefore excluded from the fair value hierarchy.
The expected long-term rates of return on U.S. Pension Plan and VEBA trust assets have been developed using a best estimate
of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market
performance data and future expectations provided by independent consultants. Future expectations are determined by using
simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations
consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the
simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration,
credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation
to develop a reasonable return assumption.
Defined Contribution Plans
We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants
in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax
basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans
totaled $17.1 in Fiscal 2018, $15.1 in Fiscal 2017 and $14.3 in Fiscal 2016. The Company also sponsors certain nonqualified
supplemental defined contribution executive retirement plans. These plans generally provide supplemental benefits to certain
executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal
Revenue Code. The Company makes payments to self-directed grantor trusts with respect to these supplemental defined
contribution plans. Such payments during Fiscal 2018, Fiscal 2017 and Fiscal 2016 were not material. At September 30, 2018
and 2017, the total fair values of these grantor trust investment assets, which amounts are included in “Other assets” on the
Consolidated Balance Sheets, were $6.5 and $3.6, respectively.
F-38
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at
September 30:
Regulatory assets:
Income taxes recoverable
Underfunded pension and postretirement plans
Environmental costs
Deferred fuel and power costs
Removal costs, net
Other
Total regulatory assets
Regulatory liabilities (a):
Postretirement benefit overcollections
Deferred fuel and power refunds
State income tax benefits — distribution system repairs
PAPUC temporary rates order (b)
Excess federal deferred income taxes (c)
Other
Total regulatory liabilities
2018
2017
$
110.1
$
$
$
87.1
58.8
—
32.0
13.0
301.0
17.8
36.7
22.6
24.4
285.2
3.5
$
$
$
390.2
$
121.4
141.3
61.6
7.7
31.0
5.9
368.9
17.5
10.6
18.4
—
—
2.7
49.2
(a) Regulatory liabilities are recorded in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance
Sheets.
(b) Balance at September 30, 2018, comprises tax savings for the period January 1, 2018 to June 30, 2018, plus interest, resulting
from the enactment of the TCJA (see “PAPUC Temporary Rates Order” below and Note 6).
(c) Balance at September 30, 2018, comprises excess federal deferred income taxes resulting from the enactment of the TCJA
(see “Excess federal deferred income taxes” below and Note 6).
Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets included in the table
above.
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 the tax benefit on 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. UGI
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 65 years.
Underfunded pension and other postretirement plans. This regulatory asset represents the portion of net actuarial losses and prior
service costs (credits) associated with pension and other postretirement benefits which are probable of being 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. These costs are amortized over
the average remaining future service lives of plan participants.
Environmental costs. Environmental costs principally represent estimated probable future environmental remediation and
investigation costs that Gas Utility expects to incur, primarily at manufactured gas plant (“MGP”) sites in Pennsylvania, in
conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection
(“PADEP”). Pursuant to base rate orders, Gas Utility receives ratemaking recognition of its estimated environmental investigation
and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference
between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2018, the
F-39
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
period over which Gas Utility expects to recover these costs will depend upon future remediation activity. For additional information
on environmental costs, see Note 15.
Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable
utility plant. As required by PAPUC ratemaking, removal costs include actual costs incurred associated with asset retirement
obligations. Consistent with prior ratemaking treatment, Gas Utility expects to recover these costs over five years.
Postretirement benefit overcollections. This regulatory liability represents the difference between amounts recovered through
rates by Gas Utility and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With
respect to Gas Utility, postretirement benefit overcollections are generally being refunded to customers over a ten-year period
beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective
(see “Base Rate Filings” below). With respect to Electric Utility, the overcollections will be refunded to ratepayers over a 20-year
period effective October 27, 2018.
Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently
incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and
default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for
differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable
costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory
liability.
Gas Utility uses derivative 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 instruments are
included in deferred fuel costs or refunds. Net unrealized gains on such contracts at September 30, 2018 and 2017 were $2.9 and
$0.1, respectively.
State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits,
net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas
Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these
repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related
book assets.
PAPUC Temporary Rates Order. By Secretarial Letter dated January 12, 2018, the PAPUC initiated a review into whether public
utility rates should be adjusted to reflect the tax savings from the change in the federal income tax rate from 35% to 21% for the
period beginning January 1, 2018. Thereafter, on March 15, 2018, the PAPUC entered a Temporary Rates Order that converted
commission-approved rates of most large Pennsylvania public utilities, including Gas Utility, into “temporary rates” for a period
of no more than 12 months while the PAPUC reviewed the data and comments in response to the Secretarial Letter.
On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI
Gas, PNG and CPG, to reduce their rates through the establishment of a negative surcharge applied to bills rendered on or after
July 1, 2018. The temporary negative surcharge will be reconciled at the end of each fiscal year to actual tax savings realized. The
negative surcharge will remain in place until the effective date of new rates established in the utility’s next general base rate
proceeding. For the merged Gas Utility, such negative surcharge will reduce base rate revenues by 5.78%, 3.90% and 8.19%,
respectively, for the UGI South, UGI North and UGI Central rate districts.
In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that
accrued during the period beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. Gas
Utility reduced its combined utility revenues by $24.1 and recorded a regulatory liability in an equal amount. The total reduction
in revenues reflects (1) $17.1 of tax benefits accrued during the previously mentioned six-month period plus (2) $7.0 to reflect
tax benefits expected to be generated by the future amortization of the regulatory liability. The rate treatment of this regulatory
liability, plus accrued interest, for each of UGI Gas, PNG and CPG will be addressed in a future proceeding and the Company
cannot predict the ultimate treatment of this liability. Like other similarly situated utilities, if Gas Utility has not filed a general
base rate proceeding within three years of the Temporary Rates Order, Gas Utility will be required to file a petition to propose
how to distribute the balance of these regulatory liabilities.
F-40
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge will apply.
The tax benefits that accrue during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base
rate case became effective (see below) will be refunded to Electric Utility ratepayers through a one-time bill credit.
Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income
tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 6). In order for our utility assets
to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting
from the remeasurement be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess
federal deferred income taxes, ranging from 1 year to approximately 65 years. This regulatory liability has been increased to reflect
the tax benefit generated by the amortization of the excess deferred federal income taxes and is being amortized and credited to
tax expense.
Other. Other regulatory assets and liabilities comprise a number of deferred items including, among others, over or under refunds
of tax benefits related to TCJA for periods after June 30, 2018, certain information technology costs, energy efficiency conservation
costs and rate case expenses.
Other Regulatory Matters
Utilities Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and
MDPSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. After receiving
all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged into UGI Utilities effective October 1, 2018.
Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG
and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the
UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement
approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type
schedules for limited future ratemaking purposes.
Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution
revenues by $9.2, which was later reduced by Electric Utility to $7.7 to reflect the impact of the TCJA and other adjustments. The
increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric
service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 annual base distribution rate increase for
Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility is required to provide customers with a one-
time $0.2 billing credit associated with 2018 TCJA tax benefits.
On January 19, 2017, PNG (now the UGI North rate district of Gas Utility) filed a rate request with the PAPUC to increase PNG’s
annual base operating revenues for residential, commercial and industrial customers by $21.7 annually. The increased revenues
would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June
30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PAPUC providing
for an $11.3 PNG annual base distribution rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and the
increase became effective October 20, 2017.
On January 19, 2016, UGI Utilities (now the UGI South rate district of Gas Utility) filed a rate request with the PAPUC to increase
UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58.6. The increased revenues
would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30,
2016, a Joint Petition for Approval of Settlement of all issues providing for a $27.0 UGI Gas annual base distribution rate increase,
to be effective October 19, 2016, was filed with the PAPUC (“Joint Petition”). On October 14, 2016, the PAPUC approved the
Joint Petition with a minor modification which had no effect on the $27.0 base distribution rate increase. The increase became
effective on October 19, 2016.
Distribution System Improvement Charge. State legislation permits gas and electric utilities in Pennsylvania to recover a
distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism
providing for a more timely cost recovery of qualifying capital expenditures between base rate cases.
PNG and CPG received PAPUC approval on a DSIC tariff, initially set at zero, in 2014. PNG and CPG began charging a DSIC
at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PAPUC issued a final Order
to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG
and CPG, pending reconsideration at each company’s Long-Term Infrastructure Improvement Plan filing. PNG’s DSIC has been
F-41
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
reset to zero as a result of its most recent base rate case. The DSIC rate for PNG will resume under the UGI North rate district
upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its most recent base rate
case.
In November 2016, UGI Gas received PAPUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges
billed to customers, effective January 1, 2017. UGI Gas began recovering revenue under the mechanism effective July 1, 2018,
as it exceeded, during the third quarter of Fiscal 2018, the threshold amount of DSIC-eligible plant agreed upon in the settlement
of its recent base rate case.
Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor
Township, Lancaster County, PA, that resulted in the death of one UGI Utilities’ employee and injuries to two other UGI Utilities’
employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the PAPUC Bureau
of Investigation and Enforcement (“BIE”) filed a formal complaint at the PAPUC in which BIE alleges that UGI Utilities committed
multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the
explosion, and requested that the PAPUC order UGI Utilities to pay approximately $2.1 in civil penalties, which is the maximum
allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint.
Preliminary Stage Information Technology Costs. During Fiscal 2016, we determined that certain preliminary project stage costs
associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance
with GAAP related to regulated entities. As a result, during Fiscal 2016, we capitalized $5.8 of such project costs ($5.4 of which
had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ($2.7) and
regulatory assets ($3.1). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in
accordance with GAAP related to regulated entities.
Note 9 — Inventories
Inventories comprise the following at September 30:
Non-utility LPG and natural gas
Gas Utility natural gas
Materials, supplies and other
Total inventories
2018
2017
231.7
$
37.3
49.2
318.2
$
188.4
39.5
50.7
278.6
$
$
At September 30, 2018, UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) having
terms ranging from one to three years. Pursuant to 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 terms of the SCAAs. The historical cost of natural gas storage inventories
released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange
receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for
which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.
As of September 30, 2018, UGI Utilities had SCAAs with Energy Services, LLC, the effects of which are eliminated in
consolidation, and with a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-
affiliate at September 30, 2018 and 2017, comprising 2.3 billion cubic feet (“bcf”) and 2.3 bcf of natural gas, was $5.4 and $6.7,
respectively.
F-42
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 10 — Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:
Utilities:
Distribution
Transmission
Work in process
General and other
Total Utilities
Non-utility:
Land
Buildings and improvements
Transportation equipment
Equipment, primarily cylinders and tanks
Electric generation
Pipeline and related assets
Work in process
Other
Total non-utility
Total property, plant and equipment
2018
2017
$
3,106.6
97.1
130.9
281.7
3,616.3
191.4
364.9
257.1
3,375.4
319.5
473.0
57.9
306.6
5,345.8
8,962.1
$
2,835.3
96.4
112.6
241.0
3,285.3
180.1
351.2
289.3
3,529.4
310.0
454.5
95.3
354.8
5,564.6
8,849.9
$
$
F-43
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 11 — Goodwill and Intangible Assets
Changes in the carrying amount of goodwill by reportable segment are as follows:
Balance September 30, 2016
$
1,978.3
$
817.0
$
11.6
$
182.1
$
2,989.0
AmeriGas
Propane
UGI
International
Midstream &
Marketing
UGI Utilities
Total
Acquisitions
Purchase accounting adjustments
Foreign currency translation
Balance September 30, 2017
Acquisitions
Dispositions
Purchase accounting adjustments
Foreign currency translation
23.0
—
—
2,001.3
4.5
(2.8)
—
—
Balance September 30, 2018
$
2,003.0
$
Intangible assets comprise the following at September 30:
55.5
(1.7)
41.4
912.2
54.9
—
13.6
(17.0)
963.7
—
—
—
11.6
—
—
—
—
—
—
—
182.1
—
—
—
—
$
11.6
$
182.1
$
78.5
(1.7)
41.4
3,107.2
59.4
(2.8)
13.6
(17.0)
3,160.4
2018
2017
Customer relationships, noncompete agreements and other (subject to amortization)
$
848.6
$
Trademarks and tradenames (subject to amortization)
Trademarks and tradenames (not subject to amortization)
Gross carrying amount
Accumulated amortization
Intangible assets, net
7.9
50.3
906.8
(393.2)
$
513.6
$
817.8
—
134.1
951.9
(340.2)
611.7
Amortization expense of intangible assets was $58.6, $50.8 and $54.3 for Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively.
Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2019 — $57.2; Fiscal
2020 — $55.8; Fiscal 2021 — $52.5; Fiscal 2022 — $49.5; Fiscal 2023 — $48.0.
In April 2018, a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with its
January 2012 acquisition of Heritage Propane, was presented to the Partnership’s senior management. After considering the merits
of the plan, the Partnership’s senior management approved a plan to discontinue the use of these tradenames and trademarks over
a period of approximately three years. As a result, during the third quarter of Fiscal 2018, the Partnership determined that these
tradenames and trademarks no longer had indefinite lives and adjusted the carrying amounts of these tradenames and trademarks
to their estimated fair values of approximately $7.9. During the third quarter of Fiscal 2018, the Partnership recorded a non-cash,
pre-tax impairment charge of $75.0 which amount is reflected in “Impairment of Partnership tradenames and trademarks” on the
Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over
their estimated period of benefit of three years. See Note 16 for further information on the determination of fair values for the
affected tradenames and trademarks.
Note 12 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not
subject to mandatory redemption. UGI had no shares of UGI Series Preferred Stock outstanding at September 30, 2018 or 2017.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject
to and series not subject to mandatory redemption. At September 30, 2018 and 2017, there were no shares of UGI Utilities
Series Preferred Stock outstanding.
F-44
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 13 — Common Stock and Equity-Based Compensation
Common Stock
On January 30, 2014, the Company’s Board of Directors authorized the repurchase of up to 15,000,000 shares of UGI Corporation
Common Stock over a four-year period. On January 25, 2018, UGI’s Board of Directors authorized an extension of the share
repurchase program for up to 8,000,000 shares of UGI Corporation Common Stock for an additional four-year period. Pursuant
to these authorizations, during Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company purchased and placed in treasury stock
1,200,000, 900,000 and 1,250,000 shares at a total cost of $59.8, $43.3 and $47.6, respectively.
UGI Common Stock share activity for Fiscal 2016, Fiscal 2017 and Fiscal 2018 follows:
Balance at September 30, 2015
Issued:
Employee and director plans
Repurchases of common stock
Reacquired common stock – employee and director plans
Balance at September 30, 2016
Issued:
Employee and director plans
Sale of reacquired common stock
Repurchases of common stock
Reacquired common stock – employee and director plans
Balance at September 30, 2017
Issued:
Employee and director plans
Repurchases of common stock
Reacquired common stock – employee and director plans
Balance at September 30, 2018
Equity-Based Compensation
Issued
173,806,991
Treasury
(1,418,488)
Outstanding
172,388,503
87,150
—
—
173,894,141
2,355,202
(1,250,000)
(620,406)
(933,692)
2,442,352
(1,250,000)
(620,406)
172,960,449
93,550
1,051,704
1,145,254
—
—
—
173,987,691
155,306
—
—
174,142,997
50,000
(900,000)
(111,966)
(843,954)
50,000
(900,000)
(111,966)
173,143,737
1,804,712
(1,200,000)
(154,780)
(394,022)
1,960,018
(1,200,000)
(154,780)
173,748,975
The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, UGI Common
Stock-based equity instruments and AmeriGas Partners Common Unit-based equity instruments as further described below. We
recognized total pre-tax equity-based compensation expense of $22.5 ($15.7 after-tax), $19.3 ($11.8 after-tax) and $23.8 ($15.4
after-tax) in Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively.
UGI Equity-Based Compensation Plans and Awards. Under the UGI Corporation 2013 Omnibus Incentive Compensation Plan
(the “2013 OICP”), we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units
(comprising “Stock Units” and “UGI Performance Units”), other equity-based awards and cash to employees and non-employee
directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the
2013 OICP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from
the grant date. In addition, the 2013 OICP provides that awards of UGI Units may also provide for the crediting of 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.
Under the 2013 OICP, awards representing up to 21,750,000 shares of UGI Common Stock may be granted. Dividend equivalents
on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated
in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of UGI Common
Stock and cash. Substantially all UGI Unit awards granted to France SAS employees are settled in shares of UGI Common Stock
and do not accrue dividend equivalents. With respect to UGI Performance Unit awards, the actual number of shares (or their cash
F-45
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement
of market performance goals and service conditions. It is currently our practice to issue treasury shares to satisfy substantially all
option exercises and UGI Unit awards. Stock options may be net exercised whereby shares equal to the option price and the
grantee’s applicable payroll tax withholding are withheld from the number of shares payable (“net exercise”). We record shares
withheld pursuant to a net exercise as shares reacquired.
UGI Stock Option Awards. Stock option transactions under equity-based compensation plans during Fiscal 2016, Fiscal 2017 and
Fiscal 2018 follow:
Shares under option — September 30, 2015
9,255,377
$
23.97
$
104.5
6.6
Weighted
Average
Option Price
Total
Intrinsic
Value
Shares
Weighted
Average
Contract Term
(Years)
Granted
Canceled
Exercised
Shares under option — September 30, 2016
Granted
Canceled
Exercised
Shares under option — September 30, 2017
Granted
Canceled
Expired
Exercised
Shares under option — September 30, 2018
Options exercisable — September 30, 2016
Options exercisable — September 30, 2017
Options exercisable — September 30, 2018
Options not exercisable — September 30, 2018
1,510,625
$
(84,213) $
(2,193,338) $
$
8,488,451
$
1,343,800
(60,236) $
(990,267) $
$
8,781,748
1,401,400
$
(152,017) $
(1,666) $
(1,832,396) $
$
8,197,069
5,522,370
5,973,668
5,498,330
2,698,739
$
$
$
$
34.67
34.13
20.38
26.68
46.51
41.86
21.40
30.20
47.85
42.14
35.80
26.00
33.93
22.94
25.53
28.63
44.75
$
$
$
$
$
$
$
$
40.1
157.6
26.7
146.7
44.5
176.6
147.6
29.0
6.6
6.3
6.2
5.1
8.1
Cash received from stock option exercises and associated tax benefits were $43.4 and $12.6, $17.7 and $9.6, and $27.3 and $14.9
in Fiscal 2018, Fiscal 2017 and Fiscal 2016, respectively. As of September 30, 2018, there was $7.9 of unrecognized compensation
cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 2.1 years.
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2018:
Range of exercise prices
Under
$25.00
$25.00 –
$30.00
$30.01 –
$35.00
$35.01 –
$40.00
Over
$40.00
Options outstanding at September 30, 2018:
Number of options
2,322,904
1,133,676
1,150,685
917,843
2,671,961
Weighted average remaining contractual life (in years)
3.3
5.0
7.1
6.3
8.8
Weighted average exercise price
Options exercisable at September 30, 2018:
Number of options
Weighted average exercise price
$
$
20.53
$
27.38
$
33.66
$
37.80
$
47.16
2,322,904
1,133,676
714,201
809,899
517,650
20.53
$
27.38
$
33.59
$
37.81
$
46.46
UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option
plans was $7.51 in Fiscal 2018, $7.62 in Fiscal 2017 and $4.87 in Fiscal 2016. These amounts were determined using a Black-
F-46
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the
estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option.
The expected life of option awards represents the period of time during which option grants are expected to be outstanding and
is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common
Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury
bonds with terms comparable to the options in effect on the date of grant.
The assumptions we used for valuing option grants during Fiscal 2018, Fiscal 2017 and Fiscal 2016 are as follows:
Expected life of option
Weighted average volatility
Weighted average dividend yield
Expected volatility
Expected dividend yield
Risk free rate
2018
2017
2016
6.00 years
5.75 years
5.75 years
17.5%
2.1%
17.5%
2.1%
19.8%
2.1%
19.8%
2.1%
19.5%
2.6%
19.3%
2.6%
2.2% – 2.9%
1.8% – 2.1%
1.2% – 1.9%
UGI Unit Awards. UGI Stock Unit 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 market performance conditions.
UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units
ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target amount, or
even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to the Russell Midcap Utility Index, excluding
telecommunication companies (“UGI comparator group”). Grantees may receive 0% to 200% of the target award granted. For
such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid.
At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the
50th percentile, 100%; and at the 90th percentile and above, 200%. The actual amount of the award is interpolated between these
percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date plus the fair value
of dividend equivalents if applicable. Under GAAP, UGI Performance Units are equity awards with a market-based condition
which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless
of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo
valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over
the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit
awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common
Stock over a three-year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant.
Volatility for all companies in the UGI comparator groups is based on historical volatility.
The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit
awards and related compensation costs:
Risk free rate
Expected life
Expected volatility
Dividend yield
Grants Awarded in Fiscal Year
2018
2.0%
3 years
18.9%
2.1%
2017
1.5%
3 years
18.9%
2.1%
2016
1.3%
3 years
17.5%
2.7%
The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $55.26 for Units granted in
Fiscal 2018, $50.91 for Units granted in Fiscal 2017 and $32.64 for Units granted in Fiscal 2016.
F-47
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The following table summarizes UGI Unit award activity for Fiscal 2018:
Total UGI Units at September 30, 2017 (a)
UGI Performance Units:
Granted
Forfeited
Performance criteria not met
Unit awards paid
UGI Stock Units:
Granted (b)
Unit awards paid
Total UGI Units at September 30, 2018 (a)
Weighted-Average
Grant-Date
Fair Value
(per Unit)
UGI Units
978,834
$
143,800
$
(38,542) $
(43,672) $
(92,950) $
52,314
$
(40,066) $
$
959,718
28.83
55.26
41.19
37.57
37.85
48.11
21.39
32.38
(a) Total UGI Units includes UGI Stock Units issued to non-employee directors, which vest on the grant date, and UGI Performance
Units and UGI Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted
units at September 30, 2018 and September 30, 2017 were 660,795 and 660,886, respectively.
(b) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted
in Fiscal 2017 and Fiscal 2016 were 42,079 and 52,493, respectively.
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares
and cash as follows:
2018
2017
2016
UGI Performance Unit awards:
Number of original awards granted, net of forfeitures
Performance period beginning January 1:
Payment of awards:
136,621
2015
178,450
2014
Shares of UGI Common Stock issued, net of shares withheld for taxes
69,680
138,985
Cash paid
UGI Stock Unit awards:
Number of original awards granted, net of forfeitures
Payment of awards:
Shares of UGI Common Stock issued, net of shares withheld for taxes
Cash paid
$
$
1.6
$
10.9
$
39,680
43,699
51,037
29,095
15,990
0.6
$
0.3
$
39,422
0.7
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, we granted UGI Unit awards representing 196,114, 185,379 and 230,653 shares,
respectively, having weighted-average grant date fair values per Unit of $53.36, $50.08 and $33.04, respectively.
As of September 30, 2018, there was a total of approximately $9.4 of unrecognized compensation cost associated with 959,718
UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.8 years. The total fair values
of UGI Units that vested during Fiscal 2018, Fiscal 2017 and Fiscal 2016 were $7.3, $7.1 and $9.7, respectively. As of September 30,
2018 and 2017, total liabilities of $18.8 and $13.1, respectively, associated with UGI Unit awards are reflected in “Employee
compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.
At September 30, 2018, 9,043,267 shares of Common Stock were available for future grants under the 2013 OICP.
F-48
308,362
2013
209,592
13.9
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2010 Long-Term
Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and
non-employee directors grants of AmeriGas Partners Units (comprising “AmeriGas Stock Units” and “AmeriGas Performance
Units”), options, phantom units, unit appreciation rights and other Common Unit-based awards. The total aggregate number of
Common Units that may be issued under the 2010 Propane Plan is 2,800,000. The exercise price for options may not be less than
the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a
period of years, and options can be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan provides
that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’
accounts.
AmeriGas Stock Unit and AmeriGas Performance Unit awards entitle the grantee to AmeriGas Partners Common Units or cash
once the service condition is met and, with respect to AmeriGas Performance Units, subject to market performance conditions,
and for certain awards granted on or after January 1, 2015, actual net customer acquisition and retention performance. Recipients
of AmeriGas Performance Unit awards are awarded a target number of AmeriGas Performance Units. The number of AmeriGas
Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the
target number, or it may be zero. For that portion of Performance Unit awards whose ultimate payout is based upon market-based
conditions (as further described below), the number of awards ultimately paid is based upon AmeriGas Partners’ Total Unitholder
Return (“TUR”) percentile rank relative to entities in a master limited partnership peer group (“Alerian MLP Group”) and, for
certain AmeriGas Performance Unit awards granted in January 2014, based upon AmeriGas Partners’ TUR relative to the two
other publicly traded propane master limited partnerships in the Alerian MLP Group (“Propane MLP Group”). For Performance
Unit awards granted on or after January 1, 2015, the number of AmeriGas Performance Units ultimately paid is based upon
AmeriGas Partner’s TUR percentile rank relative to entities in the Alerian MLP Group as modified by AmeriGas Partners’
performance relative to the Propane MLP Group.
With respect to AmeriGas Performance Unit awards subject to measurement compared with the Alerian MLP Group, grantees
may receive from 0% to 200% of the target award granted. For such grants issued on or after January 1, 2013, if AmeriGas
Partners’ TUR is below the 25th percentile compared to the peer group, the grantee will not be paid. At the 25th percentile, the
employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70%; at the 50th percentile, 100%; at the
60th percentile, 125%; at the 75th percentile, 162.5%; and at the 90th percentile or above, 200%. The actual amount of the award
is interpolated between these percentile rankings. For such grants issued on or after January 1, 2015, the amount ultimately paid
shall be modified based upon AmeriGas Partners’ TUR ranking relative to the Propane MLP Group over the performance period
(“MLP Modifier”). Such modification ranges from 70% to 130%, but in no event shall the amount ultimately paid, after such
modification, exceed 200% of the target award grant.
With respect to AmeriGas Performance Unit awards granted in January 2014 subject to measurement compared with the Propane
MLP Group, grantees were eligible to receive 150% of the target award if AmeriGas Partners’ TUR exceeded the TUR of the other
two members in the Propane MLP Group. Otherwise there would be no payout of such AmeriGas Performance Units. For those
performance awards granted on or after January 1, 2015, that are subject to the MLP Modifier, if one of the other two members
of the Propane MLP Group ceases to exist as a publicly traded company or declares bankruptcy (“MLP Event”) and depending
upon the timing of such MLP Event, the ultimate amount of such AmeriGas Performance Unit awards to be issued, and the amount
of distribution equivalents to be paid, would depend upon AmeriGas Partners’ TUR rank relative to (1) the Alerian MLP Group
for the entire performance period; (2) the Alerian MLP Group for the entire performance period and the Propane MLP Group
(through the date of the MLP Event); or (3) the Propane MLP Group through the date of the MLP Event.
With respect to AmeriGas Performance Unit awards granted in January 2015 whose payout was based upon net customer gain
and retention performance, grantees could ultimately receive between 0% and 200% of the target award based upon the annual
actual net customer gain and retention performance as adjusted for the net customer gain and retention performance over the three-
year performance period. With respect to AmeriGas Performance Unit awards granted in January 2016 and thereafter whose payout
is based upon net customer gain and retention performance, grantees may ultimately receive between 0% and 200% of the target
award based upon the actual net customer gain and retention performance over the entire three-year performance period.
Common Unit distribution equivalents are paid in cash only on AmeriGas Performance Units that eventually vest. Generally,
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.
F-49
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Under GAAP, AmeriGas Performance Units awards that are subject to market-based conditions are equity awards that, if settled
in Common Units, result in the recognition of compensation cost over the requisite employee service period regardless of whether
the market-based condition is satisfied. The fair values of AmeriGas Performance Units subject to market-based conditions are
estimated using a Monte Carlo valuation model. The fair value associated with the target award, which will be paid in Common
Units, is accounted for as equity and the fair value of the award over the target, as well as all Common Unit distribution equivalents,
which will be paid in cash, is accounted for as a liability. For purposes of valuing AmeriGas Performance Unit awards that are
subject to market-based conditions, expected volatility is based on the historical volatility of Common Units over a three-year
period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all entities in the
peer group is based on historical volatility. The expected term of the AmeriGas Performance Unit awards is three years based on
the performance period. AmeriGas Performance Unit awards whose ultimate payout is based upon net customer acquisition and
retention performance measures are recorded as expense when it is probable all or a portion of the award will be paid. The fair
value associated with the target award is the market price of the Common Units on the date of grant. The fair value of the award
over the target, as well as all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability.
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance
Unit awards subject to market-based conditions and related compensation costs:
Risk-free rate
Expected life
Expected volatility
Dividend yield
Grants Awarded in Fiscal Year
2018
2.0%
3 years
21.1%
8.2%
2017
1.5%
3 years
21.7%
7.8%
2016
1.3%
3 years
20.6%
10.7%
The General Partner granted awards under the 2010 Propane Plan representing 84,811, 67,563 and 73,080 Common Units in Fiscal
2018, Fiscal 2017 and Fiscal 2016, respectively, having weighted-average grant date fair values per Common Unit subject to award
of $50.05, $52.37 and $37.93, respectively. At September 30, 2018, 2,242,468 Common Units were available for future award
grants under the 2010 Propane Plan.
F-50
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2018:
AmeriGas Partners
Common Units
Weighted-Average
Grant-Date
Fair Value
(per Unit)
Total Units at September 30, 2017 (a)
AmeriGas Performance Units:
Granted
Forfeited
Awards paid
Performance criteria not met
AmeriGas Stock Units:
Granted
Forfeited
Awards paid
Total Units at September 30, 2018 (a)
218,224
$
55,550
$
(1,900) $
(18,874) $
(37,099) $
29,261
$
(400) $
(8,000) $
$
236,762
50.03
52.14
56.70
46.23
86.53
46.09
45.66
(45.62)
47.12
(a) Total units includes AmeriGas Stock Units issued to non-employee directors, which vest on the grant date, and AmeriGas
Performance Units and AmeriGas Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total
vested restricted units at September 30, 2018 and September 30, 2017 were 71,148 and 65,989, respectively.
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit
awards in Common Units and cash as follows:
2018
2017
2016
AmeriGas Performance Unit awards:
Number of Common Units subject to original awards granted, net of
forfeitures
Performance periods beginning in fiscal year:
Payment of awards:
65,525
2015
53,800
2014
AmeriGas Partners Common Units issued, net of units withheld for taxes
13,164
29,489
Cash paid
AmeriGas Stock Unit awards:
$
1.2
$
2.9
$
44,800
2013
23,017
1.7
Number of Common Units subject to original awards granted, net of
forfeitures
14,811
32,658
20,336
Payment of awards:
AmeriGas Partners Common Units issued, net of units withheld for taxes
5,322
3,932
Cash paid
$
0.1
$
0.1
$
9,272
0.4
As of September 30, 2018, there was a total of approximately $1.9 of unrecognized compensation cost associated with 236,762
Common Units subject to award that is expected to be recognized over a weighted-average period of 1.7 years. The total fair values
of Common Unit-based awards that vested during Fiscal 2018, Fiscal 2017 and Fiscal 2016 were $2.2, $2.1 and $2.0, respectively.
As of September 30, 2018 and 2017, total liabilities of $2.3 and $2.5 associated with Common Unit-based awards are reflected
in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheets. It is
the Partnership’s practice to issue new AmeriGas Partners Common Units for the portion of any Common Unit-based awards paid
in AmeriGas Partners Common Units.
F-51
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 14 — Partnership Distributions
The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount
equal to its Available Cash (as defined in the Partnership Agreement) for such quarter. Available Cash generally means:
1. all cash on hand at the end of such quarter, plus
2. all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, less
3.
the amount of cash reserves established by the General Partner in its reasonable discretion.
The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the
next four quarters.
Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner
interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly
Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When
Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total
Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common
Unit to limited partners exceeds $0.605.
During Fiscal 2018, Fiscal 2017 and Fiscal 2016, the Partnership made quarterly distributions to Common Unitholders in excess
of $0.605 per limited partner unit. As a result, the General Partner has received a greater percentage of the total Partnership
distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. During Fiscal 2018, Fiscal
2017 and Fiscal 2016, the total amount of distributions received by the General Partner with respect to its aggregate 2% general
partner ownership interests totaled $54.9, $52.7 and $47.4, respectively. Included in these amounts are incentive distributions
received by the General Partner during Fiscal 2018, Fiscal 2017 and Fiscal 2016 of $45.3, $43.5 and $38.2, respectively.
Note 15 — Commitments and Contingencies
Commitments
Leases
We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of
our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such
leases was $106.2 in Fiscal 2018, $99.5 in Fiscal 2017 and $102.0 in Fiscal 2016.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as
follows:
AmeriGas Propane
UGI Utilities
UGI International
Other
Total
2019
2020
2021
2022
2023
After 2023
72.1
$
65.7
$
58.0
$
50.1
$
45.8
$
105.5
2.2
11.3
2.4
1.1
8.8
2.2
0.8
6.2
1.2
0.7
5.0
0.8
0.4
4.6
0.7
0.1
5.8
1.2
88.0
$
77.8
$
66.2
$
56.6
$
51.5
$
112.6
$
$
UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units
On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with
AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make
up to $225 of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions
may be made from time to time during the Commitment Period upon request of the Partnership. There have been no capital
contributions made to the Partnership under the Commitment Agreement.
In consideration for any capital contributions made pursuant to the Commitment Agreement, the Partnership will issue to UGI
or a wholly owned subsidiary new Class B Common Units representing limited partner interests in the Partnership (“Class B
Units”). The Class B Units will be issued at a price per unit equal to the 20-day volume-weighted average price of the Partnership’s
F-52
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
common units (“Common Units”) prior to the date of the Partnership’s related capital call. The Class B Units will be entitled to
cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call,
plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Units.
While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership.
At any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the
Class B Units they own into Common Units on a one-for-one basis, and at any time after six years from the initial issuance of
the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing
trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common
Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and
immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common
Units on a one-for-one basis.
Contingencies
Environmental Matters
UGI Utilities
From the late 1800s through the mid-1900s, UGI Utilities and its current and 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. 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.
Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG) with similar
histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG were merged into UGI Utilities effective
October 1, 2018 (“Utilities Merger”).
Prior to the Utilities Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to a consent order and
agreement (“COA”) with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance
with the COAs, as amended to recognize the merger, UGI Utilities, as the successor to CPG and PNG, is required to either obtain
a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at
the MGPs and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such
activities in an amount equal to an annual environmental cost cap. The cost cap of the three COAs, in the aggregate, is $5.4. The
three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. At September 30, 2018 and 2017, our aggregate
estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $51.0 and $54.3,
respectively. UGI Utilities has recorded associated regulatory assets for these costs because recovery of these costs from customers
is probable (see Note 8).
We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material
to UGI Utilities’ results of operations because UGI Utilities receives ratemaking recovery of actual environmental investigation
and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated
difference between historical costs and rate recoveries with an estimate of future costs associated with the sites.
From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly
owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of
environmental contamination or perform environmental remediation. 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 a former subsidiary of UGI Utilities if a court were to
conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to
have been an operator because of its conduct with respect to its subsidiary’s MGP. At September 30, 2018 and 2017, neither the
undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside
Pennsylvania was material.
F-53
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
AmeriGas Propane
AmeriGas OLP Saranac Lake. In 2008, the New York State Department of Environmental Conservation (“NYDEC”) notified
AmeriGas OLP that the NYDEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the
New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the NYDEC
disclosed contamination related to a former MGP. AmeriGas OLP responded to the NYDEC in 2009 to dispute the contention
it was a potentially responsible party (“PRP”) as it did not operate the MGP and appeared to only own a portion of the site. In
2017, the NYDEC communicated to AmeriGas OLP that the NYDEC had previously issued three Records of Decision (“RODs”)
related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s
purported ownership. AmeriGas renewed its challenge to designation as a PRP and identified potential defenses. The NYDEC
subsequently identified a third party PRP with respect to the site.
The NYDEC commenced implementation of the remediation plan in the spring of 2018. Based on our evaluation of the available
information, the Partnership accrued an undiscounted environmental remediation liability of $7.5 related to the site during the
third quarter of Fiscal 2017, which amount is included in “Operating and administrative expenses” on the Consolidated Statements
of Income. Our share of the actual remediation costs could be significantly more or less than the accrued amount.
Other Matters
Purported Class Action Lawsuits. Between May and October of 2014, purported class action lawsuits were filed in multiple
jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers. The
class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce
the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their common customer,
Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in
violation of federal and certain state antitrust laws. The claims seek treble damages, injunctive relief, attorneys’ fees and costs
on behalf of the putative classes.
On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action
cases to the Western Division of the United States District Court for the Western District of Missouri (“District Court”). As of
June 2018, as the result of rulings on a series of procedural filings, including petitions filed with the Eighth Circuit and the U.S.
Supreme Court, both the federal and state law claims of the direct customer plaintiffs and the state law claims of the indirect
customer plaintiffs have been remanded to the District Court. The decision of the District Court to dismiss the federal antitrust
claims of the indirect customer plaintiffs was upheld by the Eighth Circuit. Motions are pending before the District Court regarding
the indirect purchasers’ state law claims.
We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the
claims and intend to vigorously defend against them.
In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our
businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation
with counsel, that the final outcome of these matters will not have a material effect on our financial statements.
F-54
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 16 — Fair Value Measurements
Recurring Fair Value Measurements
The following table presents, on a gross basis, our financial assets and liabilities including both current and noncurrent portions,
that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2, as of September 30,
2018 and 2017:
Level 1
Level 2
Level 3
Total
Asset (Liability)
September 30, 2018:
Derivative instruments:
Assets:
Commodity contracts
Foreign currency contracts
Cross-currency contracts
Liabilities:
Commodity contracts
Foreign currency contracts
Interest rate contracts
Non-qualified supplemental postretirement
grantor trust investments (a)
September 30, 2017
Derivative instruments:
Assets:
Commodity contracts
Foreign currency contracts
Liabilities:
Commodity contracts
Foreign currency contracts
Interest rate contracts
Cross-currency contracts
Non-qualified supplemental postretirement
grantor trust investments (a)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
93.5
$
— $
— $
(33.6) $
— $
— $
117.5
20.6
0.9
$
$
$
(9.8) $
(14.4) $
(1.0) $
— $
— $
— $
— $
— $
— $
211.0
20.6
0.9
(43.4)
(14.4)
(1.0)
40.8
$
— $
— $
40.8
27.2
$
— $
(27.7) $
— $
— $
— $
76.9
12.2
$
$
(11.4) $
(38.2) $
(2.3) $
(2.9) $
— $
— $
— $
— $
— $
— $
104.1
12.2
(39.1)
(38.2)
(2.3)
(2.9)
35.6
$
— $
— $
35.6
(a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement
plans (see Note 7).
The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity
futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of
our derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives
designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent
market transactions and related market indicators. The fair values of our Level 2 interest rate contracts, foreign currency contracts
and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair
values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these
trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented.
F-55
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Nonrecurring Fair Value Measurements
As discussed in Note 11, in April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain
indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage
Propane, over a period of approximately three years. This action required the Partnership to remeasure the fair values of these
tradenames and trademarks based upon their remaining period of benefit. The Partnership used the relief from royalty method
to estimate the fair values of the tradenames and trademarks, which method estimates our theoretical royalty savings from
ownership of the tradenames and trademarks. Key assumptions used in this method include discount rates, royalty rates, growth
rates and sales projections. These assumptions reflect current economic conditions, management expectations and projected
future cash flows expected to be generated from these tradenames and trademarks. The Partnership has determined that the lowest
level of the input that is significant to the fair value measurement are unobservable inputs that fall within Level 3 of the fair
value hierarchy. As of the April 2018 measurement date, these tradenames and trademarks had an estimated fair value of $7.9.
Other Financial Instruments
The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities
of long-term debt) approximate their fair values because of their short-term nature. 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 (Level 2). The
carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt
issuance costs) at September 30, 2018 and 2017 were as follows:
Carrying amount
Estimated fair value
2018
2017
$
$
4,199.4
4,150.3
$
$
4,211.9
4,346.8
Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could
expose us to concentrations of credit risk. We limit credit risk from short-term investments by investing only in investment-
grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC
insured bank deposits. The credit risk arising from concentrations of trade accounts receivable is limited because we have a large
customer base that extends across many different U.S. markets and a number of foreign countries. For information regarding
concentrations of credit risk associated with our derivative instruments, see Note 17. Our investment in a private equity partnership
is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the
investment does not have a readily available market value. See Note 2 for additional information on this investment.
Note 17 — 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; (2) interest rate risk; and (3) foreign currency exchange 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. Although our commodity derivative instruments extend over a number of years, a significant portion of our
commodity derivative instruments economically hedge commodity price risk during the next twelve months. For information on
the accounting for our derivative instruments, see Note 2.
Commodity Price Risk
Regulated Utility Operations
Natural Gas
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-
market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by
the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”)
natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases
for its retail core-market customers. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts
F-56
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will
be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 8).
Electricity
Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the
cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to
meet a substantial portion of its electricity supply needs. At September 30, 2018 and 2017, all Electric Utility forward electricity
purchase contracts were subject to the NPNS exception.
Non-utility Operations
LPG
In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter
derivative commodity instruments, principally price swap contracts. In addition, AmeriGas Partners, certain other domestic
businesses and our UGI International operations also use over-the-counter price swap contracts to reduce commodity price volatility
associated with a portion of their forecasted LPG purchases. The Partnership from time to time enters into price swap agreements
to reduce the effects of short-term commodity price volatility. Also, Midstream & Marketing, from time to time, uses NYMEX
futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of
propane.
Natural Gas
In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into
NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis
swap contracts. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin
associated with the purchase and anticipated later near-term sale of natural gas. UGI International also uses natural gas futures
and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers.
Electricity
In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into
electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures
contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation
facilities. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion
costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System
Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the
NYISO electricity grid. UGI International also uses electricity futures and forward contracts to economically hedge market price
risk associated with fixed-price sales and purchase contracts for electricity.
Interest Rate Risk
The UGI Utilities Term Loan has an interest rate that is indexed to short-term market interest rates. UGI Utilities has entered into
a forward starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019, that
generally fixes the underlying variable interest rate on borrowings at 3.00% through July 2022. We have designated this interest
rate swap as a cash flow hedge.
Prior to their repayment on October 25, 2018 (see Note 5), UGI France SAS’s and Flaga’s long-term debt agreements had interest
rates that were generally indexed to short-term market interest rates. UGI France and Flaga entered into pay-fixed, receive variable
interest rate swap agreements to hedge the underlying euribor rates and LIBOR rates of interest on this variable rate debt. These
interest rate swaps were settled concurrent with the repayment of the UGI France and Flaga long-term debt. In November 2018,
UGI International, LLC entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying
euribor rate on 2018 UGI International Credit Facilities Agreement term loan borrowings at 0.34%.
F-57
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
The remainder of our domestic businesses’ long-term debt is typically 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 interest
rate swaps and IRPAs as cash flow hedges.
At September 30, 2018 and 2017, we had no unsettled IRPAs. At September 30, 2018, the amount of net losses associated with
interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the
next twelve months is $3.5.
Foreign Currency Exchange Rate Risk
Forward Foreign Currency Exchange Contracts
In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016,
we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG
product purchases primarily during the heating-season months of October through March. We account for these foreign currency
exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30,
2018, the amount of net gains associated with these contracts expected to be reclassified into earnings during the next twelve
months based upon current fair values is $1.1.
Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a
result of changes in the U.S. dollar exchange rate to the euro and British pound sterling, we have entered into forward foreign
currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains
and losses on these contracts are recorded in “Gain (loss) on foreign currency contracts, net” on the Consolidated Statements of
Income.
From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value
of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts
as net investment hedges. At September 30, 2018 and 2017, there were no unsettled net investment hedges outstanding. In October
2018, in connection with entering into the 2018 UGI International Credit Facilities Agreement and the UGI International Senior
Notes, we designated the borrowings under these agreements as net investment hedges (see Note 5).
Cross-currency Swaps
Prior to its repayment on October 25, 2018 (see Note 5), Flaga entered into cross-currency swaps to hedge its exposure to the
variability in expected future cash flows associated with the foreign currency and interest rate risk of its U.S. dollar denominated
variable-rate term loan. These cross-currency hedges included initial and final exchanges of principal from a fixed euro
denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market
spot rate on the date of issuance. These cross-currency swaps also included interest rate swaps of a floating U.S. dollar-denominated
interest rate to a fixed euro-denominated interest rate. We designated these cross-currency swaps as cash flow hedges.
At September 30, 2018, the amount of net gains associated with such cross-currency swaps expected to be reclassified into earnings
during the next twelve months is not material.
F-58
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Quantitative Disclosures Related to Derivative Instruments
The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at September 30,
2018 and 2017 and the final settlement date of the Company's open derivative transactions as of September 30, 2018, excluding
those derivatives that qualified for the NPNS exception:
Type
Commodity Price Risk:
Regulated Utility Operations
Notional Amounts
(in millions)
Units
Settlements
Extending Through
2018
2017
Gas Utility NYMEX natural gas futures and option contracts Dekatherms
September 2019
23.2
14.8
FTRs contracts
Non-utility Operations
LPG swaps
Natural gas futures, forward and pipeline contracts
Natural gas basis swap contracts
NYMEX natural gas storage
NYMEX propane storage
Electricity long forward and futures contracts
Electricity short forward and futures contracts
Interest Rate Risk:
Interest rate swaps
Interest rate swaps
Foreign Currency Exchange Rate Risk:
Forward foreign currency exchange contracts
Cross-currency swaps
Derivative Instrument Credit Risk
Kilowatt
hours
N/A
—
101.2
Gallons
September 2020
Dekatherms
Dekatherms
Dekatherms
Gallons
Kilowatt
hours
Kilowatt
hours
Euro
USD
USD
USD
October 2022
March 2023
May 2019
April 2019
394.3
159.7
54.4
1.8
0.6
325.5
75.9
104.2
1.9
0.3
May 2022
4,307.6
4,440.3
March 2022
359.3
447.0
October 2020
€ 585.8
€ 645.8
July 2022
$ 114.1
$
—
September 2021
$ 512.2
$ 424.8
April 2020
$
49.9
$
59.1
We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument
counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain
credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and
monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties
that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances
for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the
counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-
traded futures contracts generally require cash deposits in margin accounts. At September 30, 2018 and 2017, restricted cash in
brokerage accounts totaled $9.6 and $10.3, respectively. Although we have concentrations of credit risk associated with derivative
instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their
contracts, based upon the gross fair values of the derivative instruments, was not material at September 30, 2018. Certain of the
Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral
in the event of a downgrade of the Partnership’s debt rating. At September 30, 2018, if the credit-risk-related contingent features
were triggered, the amount of collateral required to be posted would not be material.
F-59
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Offsetting Derivative Assets and Liabilities
Derivative assets and liabilities are presented net by counterparty on the Consolidated Balance Sheets if the right of offset exists.
We offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts
recognized for derivative instruments executed with the same counterparty. Our derivative instruments include both those that are
executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a
financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Over-the-counter contracts are
bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual
rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition,
the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions.
In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of
collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties,
if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter
derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and
accounts payable balances recognized on the Consolidated Balance Sheets with our derivative counterparties are not included in
the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or
similar arrangements.
F-60
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Fair Value of Derivative Instruments
The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of
September 30, 2018 and 2017:
2018
2017
1.5
0.9
2.4
3.0
208.0
19.1
227.1
232.5
(34.3)
(12.2)
186.0
$
$
3.2
—
3.2
1.7
102.4
9.0
111.4
116.3
(35.7)
(8.3)
72.3
(0.4) $
—
(1.0)
(1.4)
(5.5)
(2.9)
(2.3)
(10.7)
(0.1)
(1.5)
(43.3)
(14.0)
(57.3)
(58.8)
34.3
(24.5) $
(37.6)
(32.7)
(70.3)
(82.5)
35.7
(46.8)
$
$
$
$
Derivative assets:
Derivatives designated as hedging instruments:
Foreign currency contracts
Cross-currency contracts
Derivatives subject to PGC and DS mechanisms:
Commodity contracts
Derivatives not designated as hedging instruments:
Commodity contracts
Foreign currency contracts
Total derivative assets – gross
Gross amounts offset in the balance sheet
Cash collateral received
Total derivative assets – net
Derivative liabilities:
Derivatives designated as hedging instruments:
Foreign currency contracts
Cross-currency contracts
Interest rate contracts
Derivatives subject to PGC and DS mechanisms:
Commodity contracts
Derivatives not designated as hedging instruments:
Commodity contracts
Foreign currency contracts
Total derivative liabilities – gross
Gross amounts offset in the balance sheet
Total derivative liabilities – net
F-61
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Effects of Derivative Instruments
The following tables provide information on the effects of derivative instruments on the Consolidated Statements of Income and
changes in AOCI for Fiscal 2018, Fiscal 2017 and Fiscal 2016:
Gain (Loss)
Recognized in
AOCI
Gain (Loss)
Reclassified from
AOCI and Noncontrolling
Interests into Income
2018
2017
2016
2018
2017
2016
Location of Gain (Loss)
Reclassified from
AOCI and
Noncontrolling
Interests into Income
Cash Flow Hedges:
Foreign currency contracts
$
0.4
$
0.2
$
3.6
$
(3.0) $
17.8
$
17.2
Cost of sales
Cross-currency contracts
Interest rate contracts
Total
1.2
0.2
1.8
$
0.5
1.5
2.2
0.1
(32.5)
$ (28.8) $
1.1
(5.0)
(6.9) $
(0.1)
(3.9)
13.8
$
0.4
(4.5)
13.1
$
Interest expense /other
operating income, net
Interest expense
Gain (Loss)
Recognized in Income
2018
2017
2016
Location of
Gain (Loss)
Recognized in Income
Derivatives Not Designated as
Hedging Instruments:
Commodity contracts
Commodity contracts
Commodity contracts
Foreign currency contracts
Total
$ 155.4
$ 166.0
(5.3)
(2.0)
0.3
16.2
0.2
(23.8)
$ 166.6
$ 140.4
$ (65.0)
(2.2)
(0.1)
—
$ (67.3)
Cost of sales
Revenues
Operating and administrative expenses / other operating
income, net
Gain (loss) on foreign currency contracts, net
For Fiscal 2018 and Fiscal 2017, the amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains
or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material. For Fiscal 2016
the amounts of derivative gains or losses representing ineffectiveness were losses of $5.5, which were recorded in “Other operating
income, net,” on the Consolidated Statements of Income and are related to interest rate swap agreements at UGI France SAS prior
to their amendments in March 2016.
We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among
others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service
contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales
commitments. Although certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify
for NPNS exception accounting 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 in the contract is based on an underlying that is directly associated
with the price of the product or service being purchased or sold.
Note 18 — Accumulated Other Comprehensive Income (Loss)
Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow
hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated
amortization; and (3) foreign currency translation and long-term intra-company transaction adjustments.
F-62
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Changes in AOCI during Fiscal 2018, Fiscal 2017 and Fiscal 2016 are as follows:
Postretirement
Benefit
Plans
Derivative
Instruments
Foreign
Currency
Total
AOCI - September 30, 2015
$
(20.4)
$
11.2
$
(105.4) $
(114.6)
Other comprehensive loss before reclassification adjustments
(after-tax)
(10.9)
(16.5)
(6.8)
(34.2)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)
Reclassification adjustments tax (benefit) expense
Reclassification adjustments (after-tax)
Other comprehensive loss attributable to UGI
2.6
(0.4)
2.2
(8.7)
(13.1)
5.0
(8.1)
(24.6)
—
—
—
(6.8)
(10.5)
4.6
(5.9)
(40.1)
AOCI - September 30, 2016
$
(29.1)
$
(13.4) $
(112.2) $
(154.7)
Other comprehensive income before reclassification
adjustments (after-tax)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)
Reclassification adjustments tax (benefit) expense
Reclassification adjustments (after-tax)
Other comprehensive income (loss) attributable to UGI
6.5
1.7
59.4
67.6
5.5
(2.1)
3.4
9.9
(13.8)
4.1
(9.7)
(8.0)
—
—
—
59.4
(8.3)
2.0
(6.3)
61.3
AOCI - September 30, 2017
$
(19.2)
$
(21.4) $
(52.8) $
(93.4)
Other comprehensive income (loss) before reclassification
adjustments (after-tax)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)
Reclassification adjustments tax expense (benefit)
Reclassification adjustments (after-tax)
Other comprehensive income (loss) attributable to UGI
AOCI - September 30, 2018
$
10.4
1.0
(30.5)
(19.1)
(3.3)
1.1
(2.2)
8.2
(11.0)
6.9
(2.6)
4.3
5.3
(16.1) $
$
—
—
—
(30.5)
(83.3) $
3.6
(1.5)
2.1
(17.0)
(110.4)
For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 17.
Note 19 — Other Operating Income, Net
Other operating income, net, comprises the following:
Finance charges
AFUDC associated with pipeline projects
Interest and interest-related income
Utility non-tariff service income
Loss on private equity partnership investment
Gains (losses) on sales of fixed assets, net
Other, net
Total other operating income, net
2018
2017
2016
$
16.4
$
11.8
$
15.2
—
3.2
2.8
—
5.3
3.6
5.5
1.7
1.5
(11.0)
(3.9)
4.9
$
31.3
$
10.5
$
3.3
0.2
2.6
—
3.3
(2.2)
22.4
F-63
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Note 20 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception
of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results
fluctuate primarily because of the seasonal nature of our businesses and the effects of unrealized gains and losses on commodity
and certain foreign currency derivative instruments (see Note 17).
December 31,
March 31,
June 30,
September 30,
2017
(a)
2016
(b)(d)
2018
(a)
2017
(d)
2018
(a) (c)
2017
(d)
2018
(a)
2017
(b)
Revenues
Operating income (loss)
Net income (loss) including
noncontrolling interests
Net income (loss) attributable
to UGI Corporation
Earnings (loss) per common
share attributable to UGI
Corporation stockholders:
Basic
Diluted
Weighted-average common
shares outstanding (thousands):
$
$
$
$
$
$
2,125.2 $ 1,679.5
391.8 $
466.2
434.2 $
290.9
365.9 $
230.7
2.11 $
2.07 $
1.33
1.30
$
$
$
$
$
$
2,812.0 $ 2,173.8
$ 1,440.9 $ 1,153.5
$ 1,273.1 $ 1,113.9
589.5 $
513.2
407.7 $
311.8
276.0 $
219.9
1.59 $
1.57 $
1.27
1.24
$
$
$
$
$
28.5 $
(2.8) $
54.3 $
27.6
(11.7) $
(62.2) $
(7.8) $
(16.7)
52.4 $
(19.0) $
24.4 $
5.0
0.30 $
0.30 $
(0.11) $
(0.11) $
0.14 $
0.14 $
0.03
0.03
Basic
Diluted
173,670
173,512
173,570
173,624
173,991
173,742
174,391
173,769
176,948
176,984
176,350
177,136
176,807
173,742
177,506
177,175
(a) The quarters ended December 31, 2017, March 31, 2018, June 30, 2018 and September 30, 2018, include the impact of
adjustments to remeasure net deferred income tax liabilities associated with (1) the TCJA, including adjustments to provisional
amounts, which increased (decreased) net income by $166.0, $5.3, $0.8 and $(5.8), respectively, and (2) the 2017 French
Finance Bills which increased (decreased) net income by $17.3, $(3.7), $(0.1) and $(1.4), respectively (see Note 6).
(b) The quarters ended December 31, 2016 and September 30, 2017, include the beneficial impact of adjustments to net deferred
income tax liabilities associated with a change in the French income tax rate of $27.4 and $1.6, respectively (see Note 6).
(c) Includes the impact of the impairment of Partnership tradenames and trademarks which decreased net income attributable to
UGI by $14.5 (see Notes 11 and 16).
(d) The quarters ended December 31, 2016, March 31, 2017 and June 30, 2017 include loss on extinguishments of debt at AmeriGas
Partners which reduced net income attributable to UGI by $5.3, $3.6 and $0.7, respectively (see Note 5).
Note 21 — Segment Information
Our operations comprise four reportable segments generally based upon products or services sold, geographic location and
regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities.
AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers
in all 50 states. UGI International derives its revenues principally from the distribution of LPG to retail customers in France and
in northern, central and eastern European countries. In addition, UGI International derives revenue from natural gas marketing
businesses in France, Belgium and the United Kingdom and a natural gas and electricity marketing business in the Netherlands.
Midstream & Marketing derives its revenues principally from the sale of natural gas and, to a lesser extent, electricity, LPG and
fuel oil as well as revenues and fees from storage, pipeline transportation and natural gas production activities primarily in the
Mid-Atlantic region of the U.S. Midstream & Marketing also derives revenues from the sale of electricity through PJM, a regional
electricity transmission organization in the eastern U.S., and, to a lesser extent, also from contracting services provided by HVAC
to customers in portions of eastern and central Pennsylvania. UGI Utilities derives its revenues principally from the sale and
distribution of natural gas to customers in eastern and central Pennsylvania and, to a lesser extent, from the sale and distribution
of electricity in two northeastern Pennsylvania counties.
Corporate & Other principally comprise (1) net expenses of UGI’s captive general liability insurance company and UGI’s corporate
headquarters facility, and UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other
F-64
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period
transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures
evaluated by our Chief Operating Decision Maker (“CODM”) in assessing our reportable segments’ performance or allocating
resources. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company,
and UGI corporate headquarters’ assets.
The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate AmeriGas Propane’s
performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization
as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions
and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership
Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an
indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations)
and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be
different from that used by other companies. Our CODM evaluates the performance of our other reportable segments principally
based upon their income before income taxes excluding gains and losses on commodity and certain foreign currency derivative
instruments not associated with current-period transactions, as previously mentioned.
No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’
revenues, other than those of UGI International, are derived from sources within the United States, and all of our reportable
segments’ long-lived assets, other than those of UGI International, are located in the United States. The amounts of revenues and
long-lived assets associated with our operations in France represent approximately 20% and 15% of the respective consolidated
amounts.
Total
Elim-
inations
AmeriGas
Propane
UGI
International
Midstream
&
Marketing
UGI
Utilities
Corporate &
Other (b)
2018 (f)
Revenues from external customers
Intersegment revenues
Cost of sales
Operating income
Income (loss) from equity investees
Gain (loss) on foreign currency
contracts, net
Interest expense
Income before income taxes
Net income attributable to UGI
Depreciation and amortization
Noncontrolling interests’ net income
(loss)
Partnership Adjusted EBITDA (a)
Total assets
Short-term borrowings
Capital expenditures (including the
effects of accruals)
Investments in equity investees
Goodwill
2017
Revenues from external customers
Intersegment revenues
Cost of sales
Operating income
Income from equity investees
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Loss on foreign currency contracts, net $
Loss on extinguishments of debt
$
7,651.2
$
—
$
2,823.0
— $ (370.8) (c) $
—
4,074.9
$ (366.6) (c) $
1,314.7
$
$
$
2,683.8
—
1,620.1
347.2 (e) $
223.1
1,064.1
4.3
16.2
(230.1)
854.5
718.7
455.1
103.7
$
$
$
$
$
$
$
$
0.3
—
—
—
0.3
(1.1)
(0.3)
—
11,980.9
$ (125.3)
424.9
597.0
87.6
3,160.4
$
$
$
$
—
—
—
—
$
$
$
$
$
$
$
$
$
$
$
$
$
$
—
—
(163.1)
184.1
174.7
185.8
97.6
605.5
3,933.9
232.0
101.3
—
2,003.0
6,120.7
$
—
$
2,453.5
— $ (222.7) (c) $
—
2,837.3
$ (218.3) (c) $
1,002.9
1,004.2
4.3
(23.9)
(59.7)
$
$
$
$
0.3
—
—
—
$
$
$
$
355.3
—
—
(59.7)
F-65
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(0.5)
(12.7)
(21.1)
188.8
138.6
140.6
(3.0)
3,279.0
1.4
111.4
12.8
963.7
1,877.5
—
935.3
195.7
—
(0.1)
—
— $
9.1
1,328.9
$ 3,266.6
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,149.1
272.6
1,090.8
173.9
$
$
$
$
998.5
93.9
522.9
237.5
$
$
$
$
4.8 (d) $
— $
—
(2.4)
176.3
196.8
43.5
—
$
$
$
$
$
$
2.0
43.1
74.8
11.6
943.0
178.2
856.7
139.2
$
$
$
$
$
$
$
$
4.3 (d) $
—
—
$
$
— $
(42.9)
194.6
148.9
84.6
$
$
$
$
$
$
$
189.5
338.5
— $
182.1
$
847.5
40.1
367.3
228.3
$
$
$
$
— $
— $
— $
(3.2)
4.3
(107.0)
82.1
—
28.9
(0.6)
110.4
60.8
0.9
297.8
—
2.7
—
—
(0.8)
4.4
(106.6)
85.4
—
(23.8)
—
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
Elim-
inations
AmeriGas
Propane
UGI
International
Midstream
&
Marketing
UGI
Utilities
Corporate &
Other (b)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(20.6)
175.0
158.6
117.4
0.2
3,132.0
17.9
90.3
8.1
912.2
1,868.8
—
903.8
206.6
(0.2)
—
(24.4)
182.0
111.6
112.4
—
2,865.1
0.5
99.9
8.5
817.0
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(2.1)
141.4
86.9
35.4
—
$
$
$
$
$
(40.2)
188.1
116.0
72.3
$
$
$
$
— $
1,165.5
$ 2,994.0
39.0
117.5
51.0
11.6
752.3
114.3
602.2
146.7
—
—
(2.1)
144.6
87.1
30.6
—
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
25.5
140.4
17.4
11.6
$
$
$
$
$
$
$
170.0
317.7
— $
182.1
$
751.4
17.1
289.8
200.9
$
$
$
$
— $
— $
(37.6)
163.3
97.4
67.3
$
$
$
$
— $
$
$
$
112.5
262.5
— $
182.1
$
1,038.2
$ 2,743.1
(0.4)
61.2
30.4
0.9
22.6
272.8
—
0.7
—
—
1.4
2.5
(91.6)
77.3
—
—
(0.7)
76.6
25.3
0.8
48.2
265.6
—
0.1
—
—
Interest expense
Income before income taxes
Net income attributable to UGI
Depreciation and amortization
Noncontrolling interests’ net income
Partnership Adjusted EBITDA (a)
Total assets
Short-term borrowings
Capital expenditures (including the
effects of accruals)
Investments in equity investees
Goodwill
2016
Revenues from external customers
Intersegment revenues
Cost of sales
Operating income
Loss from equity investees
Loss on extinguishments of debt
Interest expense
Income before income taxes
Net income attributable to UGI
Depreciation and amortization
Noncontrolling interests’ net income
Partnership Adjusted EBITDA (a)
Total assets
Short-term borrowings
Capital expenditures (including the
effects of accruals)
Investments in equity investees
Goodwill
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Total
(223.5)
701.4
436.6
416.3
87.2
$
$
$
$
$
—
0.3
0.1
(0.2)
—
11,582.2
$ (51.5)
366.9
624.3
59.1
3,107.2
$
$
$
$
—
—
—
—
$
$
$
$
$
$
$
$
$
$
$
(160.2)
135.4
44.6
190.5
64.4
551.3
4,069.4
140.0
98.1
—
2,001.3
5,685.7
$
—
$
2,311.8
— $ (133.9) (c) $
2,437.5
$ (131.5) (c) $
988.0
(0.2)
(48.9)
(228.9)
710.0
364.7
400.9
124.1
$
$
$
$
$
$
$
$
0.2
—
—
—
0.2
0.1
(0.2)
—
10,847.2
$ (136.6)
291.7
604.6
25.9
2,989.0
$
$
$
$
—
—
—
—
$
$
$
$
$
$
$
$
$
$
$
$
$
$
—
864.8
356.3
—
(48.9)
(164.1)
143.3
43.2
190.0
75.9
543.0
4,071.8
153.2
101.7
—
1,978.3
F-66
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Currency in millions, except per share amounts and where indicated otherwise)
(a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income
taxes:
Partnership Adjusted EBITDA
Depreciation and amortization
Interest expense
Impairment of Partnership tradenames and trademarks
Loss on extinguishments of debt
MGP environmental accrual
Noncontrolling interest (i)
Income before income taxes
2018
2017
2016
$
$
605.5
(185.8)
(163.1)
(75.0)
—
—
2.5
$
551.3
(190.5)
(160.2)
—
(59.7)
(7.5)
2.0
$
184.1
$
135.4
$
543.0
(190.0)
(164.1)
—
(48.9)
—
3.3
143.3
(i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b) Includes net pre-tax gains on commodity and certain foreign currency derivative instruments not associated with current-
period transactions (including such amounts attributable to noncontrolling interests) totaling $132.8, $82.0 and $91.6 in Fiscal
2018, Fiscal 2017 and Fiscal 2016, respectively. Fiscal 2017 also includes a pre-tax loss of $11.0 associated with the impairment
of a cost basis investment (see Note 2).
(c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and
AmeriGas Propane.
(d) Represents AFUDC associated with PennEast (see Note 2).
(e) Includes pre-tax impairment charge of $75.0 as a result of a plan to discontinue the use of certain Partnership tradenames and
trademarks (see Note 11).
(f) Fiscal 2018 results include impacts from the TCJA in the U.S. See Notes 6 and 8 for additional information.
F-67
UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)
September 30,
2018
2017
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable – related parties
Prepaid expenses and other current assets
Total current assets
Property, plant and equipment, net
Investments in subsidiaries
Other assets
Total assets
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts and notes payable
Accrued liabilities
Total current liabilities
Noncurrent liabilities
Commitments and contingencies (Note 1)
Common stockholders’ equity:
Common Stock, without par value (authorized – 450,000,000 shares; issued – 174,142,997
and 173,987,691 shares, respectively)
Retained earnings
Accumulated other comprehensive loss
Treasury stock, at cost
Total common stockholders’ equity
$
$
$
13.4
12.8
10.5
36.7
2.6
3,652.0
71.9
3,763.2
$
$
14.9
$
6.7
21.6
60.2
1,200.8
2,610.7
(110.4)
(19.7)
3,681.4
Total liabilities and common stockholders’ equity
$
3,763.2
$
15.8
4.5
15.6
35.9
0.4
3,119.7
82.0
3,238.0
12.3
5.9
18.2
56.5
1,188.6
2,106.7
(93.4)
(38.6)
3,163.3
3,238.0
Note 1 — Commitments and Contingencies:
At September 30, 2018, UGI Corporation had agreed to indemnify the issuers of $70.3 of surety bonds issued on behalf of certain
UGI subsidiaries. UGI Corporation is authorized to guarantee up to $500.0 of obligations to suppliers and customers of Energy
Services, LLC and subsidiaries of which $448.5 of such obligations were outstanding as of September 30, 2018.
S-1
UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
Revenues
Costs and expenses:
Operating and administrative expenses
Other operating income, net (a)
Operating loss
Intercompany interest income
Loss before income taxes
Income tax expense (benefit)
(Loss) income before equity in income of unconsolidated subsidiaries
Equity in income of unconsolidated subsidiaries
Net income attributable to UGI Corporation
Other comprehensive income (loss)
Equity in other comprehensive (loss) income of unconsolidated
subsidiaries
Comprehensive income attributable to UGI Corporation
Earnings per common share attributable to UGI Corporation stockholders:
Basic
Diluted
Year Ended September 30,
2018
2017
2016
$
— $
— $
—
64.7
(52.2)
12.5
(12.5)
0.1
(12.4)
6.1
(18.5)
737.2
46.3
(45.9)
0.4
(0.4)
—
(0.4)
(5.7)
5.3
431.3
$
$
$
$
718.7
$
436.6
$
3.4
(20.4)
701.7
4.13
4.06
$
$
$
1.3
60.0
497.9
2.51
2.46
$
$
$
45.7
(45.3)
0.4
(0.4)
0.1
(0.3)
(4.0)
3.7
361.0
364.7
(1.1)
(39.0)
324.6
2.11
2.08
Weighted - average common shares outstanding (thousands):
Basic
Diluted
173,908
176,905
173,662
177,159
173,154
175,572
(a) UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly
for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense
incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its
subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed
and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries
for which general and administrative services are provided. Management believes that this allocation method is reasonable
and equitable to its subsidiaries. These billed expenses are classified as “Other operating income, net” in the Statements of
Income above.
S-2
UGI CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
NET CASH PROVIDED BY OPERATING ACTIVITIES (a)
$
208.2
$
253.2
$
195.6
Year Ended September 30,
2018
2017
2016
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment
Net investments in unconsolidated subsidiaries
Net cash used by investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends on Common Stock
Repurchases of UGI Common Stock
Issuances of Common Stock
Other
Net cash used by financing activities
Cash and cash equivalents (decrease) increase
Cash and cash equivalents:
End of year
Beginning of year
(Decrease) increase
(2.3)
(6.5)
(8.8)
(176.9)
(59.8)
34.9
—
(201.8)
$
$
$
(2.4) $
13.4
$
15.8
(2.4) $
(0.4)
(40.7)
(41.1)
(168.9)
(43.3)
11.0
0.1
(201.1)
11.0
15.8
4.8
11.0
$
$
$
—
(8.9)
(8.9)
(160.7)
(47.6)
24.5
—
(183.8)
2.9
4.8
1.9
2.9
(a) Includes dividends received from unconsolidated subsidiaries of $190.5, $241.9 and $193.1 for the years ended September 30,
2018, 2017 and 2016, respectively.
S-3
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
Balance at
beginning
of year
Charged
(credited)
to costs and
expenses
Other
Balance at
end of
year
Year Ended September 30, 2018
Reserves deducted from assets in the consolidated
balance sheet:
Allowance for doubtful accounts
Other reserves:
Deferred tax assets valuation allowance
Year Ended September 30, 2017
Reserves deducted from assets in the consolidated
balance sheet:
Allowance for doubtful accounts
Other reserves:
Deferred tax assets valuation allowance
Year Ended September 30, 2016
Reserves deducted from assets in the consolidated
balance sheet:
Allowance for doubtful accounts
Other reserves:
Deferred tax assets valuation allowance
$
$
$
$
$
$
(1) Uncollectible accounts written off, net of recoveries.
(2) Foreign tax credit valuation allowance adjustment.
(3) Decrease in unusable foreign operating loss carryforwards.
26.9
$
35.6
$
(27.4) (1) $
35.1
107.1
$
9.7
$
—
$
116.8
27.3
114.3
29.7
131.3
$
$
$
$
30.7
$
(31.1) (1) $
26.9
(7.6) $
0.4 (2) $
107.1
21.7
$
(24.1) (1) $
27.3
(5.8) $
(8.8) (2) $
(2.4) (3)
114.3
S-4
I, John L. Walsh, certify that:
CERTIFICATION
EXHIBIT 31.1
1.
I have reviewed this annual report on Form 10-K of UGI Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: November 20, 2018
/s/ John L. Walsh
John L. Walsh
President and Chief Executive Officer of
UGI Corporation
EXHIBIT 31.2
I, Ted J. Jastrzebski, certify that:
CERTIFICATION
1.
I have reviewed this annual report on Form 10-K of UGI Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
Date: November 20, 2018
/s/ Ted J. Jastrzebski
Ted J. Jastrzebski
Chief Financial Officer of UGI Corporation
Certification by the Chief Executive Officer and Chief Financial Officer
Relating to a Periodic Report Containing Financial Statements
EXHIBIT 32
I, John L. Walsh, Chief Executive Officer, and I, Ted J. Jastrzebski, Chief Financial Officer, of UGI
Corporation, a Pennsylvania corporation (the “Company”), hereby certify that to our knowledge:
(1) The Company’s annual report on Form 10-K for the period ended September 30, 2018 (the “Form 10-K”)
fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended;
and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition
and results of operations of the Company.
CHIEF EXECUTIVE OFFICER
CHIEF FINANCIAL OFFICER
/s/ John L. Walsh
John L. Walsh
/s/ Ted J. Jastrzebski
Ted J. Jastrzebski
Date: November 20, 2018
Date: November 20, 2018
Corporate Information
Annual Meeting
Board of Directors:
The Annual Meeting of Shareholders will be held at 10:00 a.m. on Wednesday, January 30,
2019 in Ballrooms A and B of the The Desmond Malvern, One Liberty Boulevard, Malvern,
Pennsylvania 19355.
Marvin O. Schlanger
Chairman of the Board
Principal, Cherry Hill Chemical Investments, LLC
Investor Services
Transfer Agent and Registrar
Shareholder communications regarding transfer of shares, book-entry shares, lost
certificates, lost dividend checks or changes of address should be directed to:
By Mail:
Computershare Investor Services
P.O. Box 505000
Louisville, KY 40233
By Overnight Delivery:
Computershare Investor Services
462 South 4th Street, Suite 1600
Louisville, KY 40202
800-850-1774 (U.S. and Canada), 312-360-5100 (other countries)
Shareholders can also view real-time account information and request transfer agent
services online at the Computershare Investor Services website: www.computershare.com/
investor. Computershare Investor Services can be accessed through telecommunications
devices for the hearing impaired by calling:
800-822-2794 (U.S. and Canada), 312-588-4110 (other countries)
Dividend Reinvestment and Direct Stock Purchase Plan
The plan is sponsored and administered by Computershare, N.A. and provides investors
with a simple and convenient method to purchase shares of UGI Common Stock.
Shareholders may use all or any part of the dividends they receive to purchase shares of
Common Stock. The plan also permits participants to make monthly cash purchases of
Common Stock not exceeding $75,000 per year. Investors may become participants by
making an initial cash investment of at least $1,000 but not more than $75,000. All such
purchases are without brokerage commissions or service charges. For information about
the Plan, write or call:
Computershare CIP c/o Computershare Investor Services
P.O. Box 30170
College Station, TX 77842-3170
800-850-1774
Plan information is also available on the Computershare Investor Services website:
www.computershare.com/investor
Investor Relations
Securities analysts, portfolio managers and other members of the professional investment
community should direct inquiries about the Company to:
Treasurer
UGI Corporation
P.O. Box 858
Valley Forge, PA 19482
610-337-1000
News, Earnings, Financial Reports and Governance Documents
Comprehensive news, webcast events, governance documents and other information
about UGI and AmeriGas Partners, L.P. are available via the internet at www.ugicorp.com.
You can request reports filed with the SEC and corporate governance documents, including
the Company’s Codes of Ethics, Principles of Corporate Governance, and the charters for
each of the companies’ Board Committees, free of charge by writing to Treasurer,
UGI Corporation, at the address above.
John L. Walsh
President and Chief Executive Officer
M. Shawn Bort
Retired Senior Vice President – Finance, Saint-Gobain Corporation
Theodore A. Dosch
Executive Vice President of Finance and
Chief Financial Officer of Anixter International Inc.
Richard W. Gochnauer
Retired Chief Executive Officer, United Stationers, Inc.
Alan N. Harris
Retired Senior Advisor and Chief Development and
Operations Officer of Spectra Energy Corporation
Frank S. Hermance
Retired Chairman and Chief Executive Officer of AMETEK, Inc.
Anne Pol
Retired President and Chief Operating Officer,
Trex Enterprises Corporation
James B. Stallings, Jr.
CEO, PS27 Ventures
Officers
UGI Corporation
John L. Walsh
President and Chief Executive Officer
Robert F. Beard
Executive Vice President, Natural Gas
Roger Perreault
Executive Vice President, Global LPG
Ted Jastrzebski
Chief Financial Officer
Robert J. Cane
General Auditor
G. Gary Garcia
Treasurer
Monica M. Gaudiosi
Vice President and
General Counsel, Secretary
Macgill James
Vice President – Supply Strategy
AmeriGas Propane, Inc.
Hugh Gallagher
President and
Chief Executive Officer
UGI Utilities, Inc.
Robert F. Beard
President and
Chief Executive Officer
UGI Energy Services, LLC
Joseph L. Hartz
President
UGI International, LLC
Roger Perreault
President
Ann P. Kelly
Vice President – Chief Accounting Officer
and Corporate Controller
John Koerwer
Vice President – Information Technology
Michael R. Pearson
Vice President – Corporate Tax Administration
Erika A. Spott
Vice President – Human Resources and
Global Leadership Development
P.O. Box 858
Valley Forge, PA 19482
You can obtain news and other information about
UGI Corporation and AmeriGas Partners, L.P. at
www.ugicorp.com or www.amerigas.com