Attached files
file | filename |
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EX-32 - EXHIBIT 32 - UGI CORP /PA/ | c95304exv32.htm |
EX-10.2 - EXHIBIT 10.2 - UGI CORP /PA/ | c95304exv10w2.htm |
EX-31.1 - EXHIBIT 31.1 - UGI CORP /PA/ | c95304exv31w1.htm |
EX-10.1 - EXHIBIT 10.1 - UGI CORP /PA/ | c95304exv10w1.htm |
EX-31.2 - EXHIBIT 31.2 - UGI CORP /PA/ | c95304exv31w2.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended December 31, 2009
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
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.) |
UGI CORPORATION
460 North Gulph Road, King of Prussia, PA
(Address of principal executive offices)
19406
(Zip Code)
(610) 337-1000
(Registrants telephone number, including area code)
460 North Gulph Road, King of Prussia, PA
(Address of principal executive offices)
19406
(Zip Code)
(610) 337-1000
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
At January 31, 2010, there were 108,859,989 shares of UGI Corporation Common Stock, without par value,
outstanding.
UGI CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS
PAGES | ||||||||
Part I Financial Information |
||||||||
Item 1. Financial Statements (unaudited) |
||||||||
1 | ||||||||
2 | ||||||||
3 | ||||||||
4 - 25 | ||||||||
26 - 38 | ||||||||
38 - 41 | ||||||||
42 | ||||||||
43 | ||||||||
43 | ||||||||
44 | ||||||||
Exhibit 10.1 | ||||||||
Exhibit 10.2 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32 |
-i-
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)
December 31, | September 30, | December 31, | ||||||||||
2009 | 2009 (1) | 2008 (1) | ||||||||||
ASSETS |
||||||||||||
Current assets: |
||||||||||||
Cash and cash equivalents |
$ | 215.6 | $ | 280.1 | $ | 175.5 | ||||||
Restricted cash |
9.6 | 7.0 | 116.4 | |||||||||
Accounts receivable (less allowances for doubtful accounts of
$38.0, $38.3 and $52.6, respectively) |
764.8 | 405.9 | 759.8 | |||||||||
Accrued utility revenues |
84.4 | 21.0 | 90.2 | |||||||||
Inventories |
387.4 | 363.2 | 345.2 | |||||||||
Deferred income taxes |
44.7 | 34.5 | 94.6 | |||||||||
Utility regulatory assets |
10.3 | 19.6 | 47.0 | |||||||||
Partnership collateral deposits |
| | 131.8 | |||||||||
Derivative financial instruments |
47.2 | 20.3 | 8.0 | |||||||||
Prepaid expenses and other current assets |
31.9 | 33.5 | 27.4 | |||||||||
Total current assets |
1,595.9 | 1,185.1 | 1,795.9 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation and
amortization of $1,822.5, $1,788.8 and $1,640.7, respectively) |
2,915.0 | 2,903.6 | 2,707.5 | |||||||||
Goodwill |
1,567.5 | 1,582.3 | 1,525.4 | |||||||||
Intangible assets, net |
158.6 | 165.5 | 154.4 | |||||||||
Other assets |
215.7 | 206.1 | 263.0 | |||||||||
Total assets |
$ | 6,452.7 | $ | 6,042.6 | $ | 6,446.2 | ||||||
LIABILITIES AND EQUITY |
||||||||||||
Current liabilities: |
||||||||||||
Current maturities of long-term debt |
$ | 94.6 | $ | 94.5 | $ | 81.2 | ||||||
Bank loans |
219.5 | 163.1 | 437.7 | |||||||||
Accounts payable |
530.7 | 334.9 | 546.7 | |||||||||
Derivative financial instruments |
33.7 | 37.5 | 251.6 | |||||||||
Other current liabilities |
507.8 | 467.3 | 481.9 | |||||||||
Total current liabilities |
1,386.3 | 1,097.3 | 1,799.1 | |||||||||
Long-term debt |
2,025.2 | 2,038.6 | 2,090.5 | |||||||||
Deferred income taxes |
514.2 | 504.9 | 446.2 | |||||||||
Deferred investment tax credits |
5.6 | 5.7 | 5.9 | |||||||||
Other noncurrent liabilities |
569.0 | 579.3 | 559.2 | |||||||||
Total liabilities |
4,500.3 | 4,225.8 | 4,900.9 | |||||||||
Commitments and contingencies (note 9) |
||||||||||||
Equity: |
||||||||||||
UGI Corporation stockholders equity: |
||||||||||||
UGI Common Stock, without par value (authorized - 300,000,000 shares;
issued - 115,261,294, 115,261,294 and 115,247,694 shares, respectively) |
877.8 | 875.6 | 860.4 | |||||||||
Retained earnings |
880.8 | 804.3 | 725.0 | |||||||||
Accumulated other comprehensive loss |
(27.8 | ) | (38.9 | ) | (121.7 | ) | ||||||
Treasury stock, at cost |
(49.0 | ) | (49.6 | ) | (55.8 | ) | ||||||
Total UGI Corporation stockholders equity |
1,681.8 | 1,591.4 | 1,407.9 | |||||||||
Noncontrolling interests |
270.6 | 225.4 | 137.4 | |||||||||
Total equity |
1,952.4 | 1,816.8 | 1,545.3 | |||||||||
Total liabilities and equity |
$ | 6,452.7 | $ | 6,042.6 | $ | 6,446.2 | ||||||
(1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to condensed consolidated financial statements.
- 1 -
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Millions of dollars, except per share amounts)
Three Months Ended | ||||||||
December 31, | ||||||||
2009 | 2008 (1) | |||||||
Revenues |
$ | 1,618.8 | $ | 1,778.5 | ||||
Costs and expenses: |
||||||||
Cost of sales |
1,026.8 | 1,171.1 | ||||||
Operating and administrative expenses |
296.7 | 313.0 | ||||||
Utility taxes other than income taxes |
4.5 | 4.6 | ||||||
Depreciation |
47.5 | 42.8 | ||||||
Amortization |
5.5 | 4.9 | ||||||
Other income, net |
(5.4 | ) | (47.3 | ) | ||||
1,375.6 | 1,489.1 | |||||||
Operating income |
243.2 | 289.4 | ||||||
Loss from equity investees |
| (0.2 | ) | |||||
Interest expense |
(34.2 | ) | (37.1 | ) | ||||
Income before income taxes |
209.0 | 252.1 | ||||||
Income taxes |
(63.5 | ) | (68.2 | ) | ||||
Net income |
145.5 | 183.9 | ||||||
Less: net income attributable to noncontrolling interests,
principally AmeriGas Partners |
(47.1 | ) | (69.0 | ) | ||||
Net income attributable to UGI Corporation |
$ | 98.4 | $ | 114.9 | ||||
Earnings per common share attributable to UGI stockholders: |
||||||||
Basic |
$ | 0.90 | $ | 1.06 | ||||
Diluted |
$ | 0.90 | $ | 1.05 | ||||
Average common shares outstanding (millions): |
||||||||
Basic |
109.077 | 108.224 | ||||||
Diluted |
109.877 | 109.009 | ||||||
Dividends declared per common share |
$ | 0.20 | $ | 0.1925 | ||||
(1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to condensed consolidated financial statements.
- 2 -
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Millions of dollars)
Three Months Ended | ||||||||
December 31, | ||||||||
2009 | 2008 (1) | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net income |
$ | 145.5 | $ | 183.9 | ||||
Reconcile to net cash from operating activities: |
||||||||
Depreciation and amortization |
53.0 | 47.7 | ||||||
Gain on sale of Partnership California storage facility |
| (39.9 | ) | |||||
Deferred income taxes, net |
(10.2 | ) | (29.2 | ) | ||||
Provision for uncollectible accounts |
9.5 | 17.7 | ||||||
Net change in settled accumulated other comprehensive income (loss) |
24.9 | (31.3 | ) | |||||
Other, net |
4.6 | (4.4 | ) | |||||
Net change in: |
||||||||
Accounts receivable and accrued utility revenues |
(436.9 | ) | (340.0 | ) | ||||
Inventories |
(25.2 | ) | 78.1 | |||||
Utility deferred fuel costs |
18.7 | 10.1 | ||||||
Accounts payable |
206.8 | 73.8 | ||||||
Partnership collateral deposits |
| (114.0 | ) | |||||
Other current assets |
1.7 | 14.1 | ||||||
Other current liabilities |
24.7 | 73.0 | ||||||
Net cash provided (used) by operating activities |
17.1 | (60.4 | ) | |||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Expenditures for property, plant and equipment |
(75.0 | ) | (72.9 | ) | ||||
Acquisitions of businesses, net of cash acquired |
(4.4 | ) | (300.7 | ) | ||||
Proceeds from sale of Partnership California storage facility |
| 42.4 | ||||||
Net proceeds from disposals of assets |
0.5 | 0.5 | ||||||
Increase in restricted cash |
(2.6 | ) | (46.1 | ) | ||||
Other |
(11.0 | ) | | |||||
Net cash used by investing activities |
(92.5 | ) | (376.8 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Dividends on UGI Common Stock |
(21.9 | ) | (20.8 | ) | ||||
Distributions on AmeriGas Partners publicly held Common Units |
(21.7 | ) | (20.7 | ) | ||||
Issuance of debt |
| 108.0 | ||||||
Repayments of debt |
(1.9 | ) | (0.6 | ) | ||||
Increase in bank loans |
56.9 | 306.1 | ||||||
Issuances of UGI Common Stock |
1.7 | 1.7 | ||||||
Net cash provided by financing activities |
13.1 | 373.7 | ||||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH |
(2.2 | ) | (6.2 | ) | ||||
Cash and cash equivalents decrease |
$ | (64.5 | ) | $ | (69.7 | ) | ||
Cash and cash equivalents: |
||||||||
End of period |
$ | 215.6 | $ | 175.5 | ||||
Beginning of period |
280.1 | 245.2 | ||||||
Decrease |
$ | (64.5 | ) | $ | (69.7 | ) | ||
(1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to condensed consolidated financial statements.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(Millions of dollars and euros, except per share amounts)
1. | Nature of Operations |
UGI Corporation (UGI) is a holding company that, through subsidiaries and affiliates,
distributes and markets energy products and related services. In the United States, we own
and operate (1) a retail propane marketing and distribution business; (2) natural gas and
electric distribution utilities; (3) electricity generation facilities; and (4) energy
marketing and services businesses. Internationally, we market and distribute propane and
other liquefied petroleum gases (LPG) in France, central and eastern Europe and China. We
refer to UGI and its consolidated subsidiaries collectively as the Company or we. |
||
We conduct a domestic propane marketing and distribution business through AmeriGas Partners,
L.P. (AmeriGas Partners), a publicly traded limited partnership, and its principal
operating subsidiaries AmeriGas Propane, L.P. (AmeriGas OLP) and AmeriGas OLPs
subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the Operating
Partnerships). AmeriGas Partners and the Operating Partnerships are Delaware limited
partnerships. UGIs 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 December 31,
2009, the General Partner held a 1% general partner interest and 42.8% limited partner
interest in AmeriGas Partners, and an effective 44.4% ownership interest in AmeriGas OLP.
Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners
Common Units (Common Units). The remaining 56.2% interest in AmeriGas Partners comprises
32,363,679 Common Units held by the general public as limited partner interests. |
||
Our wholly owned subsidiary UGI Enterprises, Inc. (Enterprises) through subsidiaries (1)
conducts an LPG distribution business in France (Antargaz); (2) conducts an LPG
distribution business in central and eastern Europe (Flaga); and (3) participates in an
LPG business in the Nantong region of China. We refer to our foreign operations collectively
as International Propane. Through other subsidiaries, Enterprises also conducts an energy
marketing and services business primarily in the Mid-Atlantic region of the United States
(collectively, Energy Services). Energy Services wholly owned subsidiary, UGI Development
Company (UGID), owns interests in electricity generation facilities located in
Pennsylvania. |
||
Our natural gas and electric distribution utility businesses are conducted through our
wholly owned subsidiary UGI Utilities, Inc. (UGI Utilities) and its subsidiaries UGI Penn
Natural Gas, Inc. (PNG) and UGI Central Penn Gas, Inc. (CPG). UGI Utilities, PNG and CPG
own and operate natural gas distribution utilities principally located in eastern,
northeastern and central Pennsylvania. UGI Utilities also owns and operates an electric
distribution utility in northeastern Pennsylvania (Electric Utility). UGI Utilities
natural gas distribution utility is referred to as UGI Gas; PNGs natural gas distribution
utility is referred to as PNG Gas; and CPGs natural gas distribution utility is referred
to as CPG Gas. UGI Gas, PNG Gas and CPG Gas are collectively referred to as Gas Utility.
Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (PUC)
and the Maryland Public Service Commission, and Electric Utility is subject to regulation by
the PUC. Gas Utility and Electric Utility are collectively referred to as Utilities. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
2. | Significant Accounting Policies |
Our condensed consolidated financial statements include the accounts of UGI and its
controlled subsidiary companies, which, except for the Partnership, are majority owned. We
eliminate all significant intercompany accounts and transactions when we consolidate. We
report the publics limited partner interests in the Partnership and the outside ownership
interests in certain subsidiaries of Antargaz and Flaga as noncontrolling interests.
Entities in which we own 50 percent or less and in which we exercise significant influence
over operating and financial policies are accounted for by the equity method. |
||
The accompanying condensed consolidated financial statements are unaudited and have been
prepared in accordance with the rules and regulations of the U.S. Securities and Exchange
Commission (SEC). They include all adjustments which we consider necessary for a fair
statement of the results for the interim periods presented. Such adjustments consisted only
of normal recurring items unless otherwise disclosed. The September 30, 2009 condensed
consolidated balance sheet data were derived from audited financial statements but do not
include all disclosures required by accounting principles generally accepted in the United
States of America (GAAP). These financial statements should be read in conjunction with
the financial statements and related notes included in our Annual Report on Form 10-K for
the year ended September 30, 2009 (Companys 2009 Annual Report). Due to the seasonal
nature of our businesses, the results of operations for interim periods are not necessarily
indicative of the results to be expected for a full year. |
||
As discussed below, certain prior-period amounts have been adjusted to comply with recently
adopted Financial Accounting Standards Board (FASB) accounting guidance for the
presentation of noncontrolling interests in consolidated financial statements. |
||
Earnings Per Common Share. Basic earnings per share reflect the weighted-average number of
common shares outstanding. Diluted earnings per share include the effects of dilutive stock
options and common stock awards. |
||
Shares used in computing basic and diluted earnings per share are as follows: |
Three Months Ended | ||||||||
December 31, | ||||||||
2009 | 2008 | |||||||
Denominator (millions of shares): |
||||||||
Average common shares
outstanding for basic computation |
109.077 | 108.224 | ||||||
Incremental shares issuable for stock
options and awards |
0.800 | 0.785 | ||||||
Average common shares outstanding for
diluted computation |
109.877 | 109.009 | ||||||
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Comprehensive Income. The following table presents the components of comprehensive
income for the three months ended December 31, 2009 and 2008:
Three Months Ended | ||||||||
December 31, | ||||||||
2009 | 2008 | |||||||
Net income |
$ | 145.5 | $ | 183.9 | ||||
Other comprehensive income (loss) |
31.2 | (176.4 | ) | |||||
Comprehensive income (including noncontrolling interests) |
176.7 | 7.5 | ||||||
Less: comprehensive income attributable to
noncontrolling interests |
(67.2 | ) | 0.9 | |||||
Comprehensive income attributable to UGI Corporation |
$ | 109.5 | $ | 8.4 | ||||
Other comprehensive income (loss) principally comprises (1) gains and losses on
derivative instruments qualifying as cash flow hedges principally commodity instruments,
interest rate protection agreements, interest rate swaps and foreign currency derivatives,
net of reclassifications to net income; (2) actuarial gains and losses on postretirement
benefit plans, net of associated amortization; and (3) foreign currency translation
adjustments. On December 31, 2008, we merged two of our domestic defined benefit pension
plans. As a result of the merger, at December 31, 2008, the Company was required under GAAP
to remeasure the combined plans assets and obligations and record the funded status in our
Condensed Consolidated Balance Sheet. During the three months ended December 31, 2008, we
recorded an after-tax charge to other comprehensive income of $38.7 associated with the
merger of the pension plans.
Reclassifications. In addition to the previously mentioned prior-period adjustments
resulting from the adoption of accounting guidance relating to the presentation of
noncontrolling interests, we have reclassified certain other prior-period balances to
conform to the current-period presentation.
Use of Estimates. We make estimates and assumptions when preparing financial statements in
conformity with GAAP. These estimates and assumptions affect the reported amounts of assets
and liabilities, revenues and expenses, as well as the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates.
Income Taxes. As a result of settlements with tax authorities during the three months ended
December 31, 2009 and 2008, the Company adjusted its unrecognized tax benefits which reduced
income tax expense and increased net income by $0.9 and $2.0 for the three months ended
December 31, 2009 and 2008, respectively.
Subsequent Events. The Companys management has evaluated the impact of subsequent events
through February 5, 2010, the date the financial statements were filed with the SEC, and the
effects of such evaluation have been reflected in the financial statements and related
disclosures.
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
3. | Accounting Changes |
Adoption of New Accounting Standards |
||
Noncontrolling Interests. Effective October 1, 2009, we adopted new guidance regarding the
accounting for and presentation of noncontrolling interests in consolidated financial
statements. The new guidance changed the accounting and reporting relating to
noncontrolling interests in a consolidated subsidiary. Noncontrolling interests ($270.6,
$225.4 and $137.4 at December 31, 2009, September 30, 2009 and December 31, 2008,
respectively) are now classified within equity on the Condensed Consolidated Balance Sheets,
a change from their prior classification between liabilities and stockholders equity.
Earnings attributable to noncontrolling interests ($47.1 and $69.0 for the three months
ended December 31, 2009 and 2008, respectively) is now included in net income and deducted
from net income to determine net income attributable to UGI Corporation. In addition,
changes in a parents ownership interest while retaining control are accounted for as equity
transactions and any retained noncontrolling equity investments in a former subsidiary are
initially measured at fair value. In accordance with the new guidance, previous periods have
been adjusted to conform with the new presentation. |
||
Business Combinations. Effective October 1, 2009, we adopted new guidance on the accounting
for business combinations. The new guidance applies to all transactions or other events in
which an entity obtains control of one or more businesses. The new guidance establishes,
among other things, principles and requirements for how the acquirer (1) recognizes and
measures in its financial statements the identifiable assets acquired, the liabilities
assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the
goodwill acquired in a business combination or gain from a bargain purchase; and (3)
determines what information with respect to a business combination should be disclosed. The
new guidance applies prospectively to business combinations for which the acquisition date
is on or after the date of adoption. Among the more significant changes in accounting for
acquisitions are (1) transaction costs will generally be expensed (rather than being
included as costs of the acquisition); (2) contingencies, including contingent
consideration, will generally be recorded at fair value with subsequent adjustments
recognized in operations (rather than as adjustments to the purchase price); and (3)
decreases in valuation allowances on acquired deferred tax assets will be recognized in
operations (rather than decreases in goodwill). The new guidance did not have a material
impact on our financial statements for the three months ended December 31, 2009. |
||
Intangible Asset Useful Lives. On October 1, 2009, we adopted new accounting guidance
which amends the factors that should be considered in developing renewal or extension
assumptions used to determine the useful life of a recognized intangible asset under GAAP.
The intent of the new guidance is to improve the consistency between the useful life of a
recognized intangible asset under GAAP relating to intangible asset accounting and the
period of expected cash flows used to measure the fair value of the asset under GAAP
relating to business combinations and other applicable accounting literature. The new
guidance must be applied prospectively to intangible assets acquired after the effective
date. The adoption of the new guidance did not impact our financial statements. |
||
New Accounting Standards Not Yet Adopted |
||
Enhanced Disclosures of Postretirement Plan Assets. In December 2008, the FASB issued new
guidance requiring more detailed disclosures about employers postretirement plan assets,
including employers investment strategies, major categories of plan assets, concentrations
of risk within plan assets, and valuation techniques used to measure the fair value of plan
assets. The provisions of this annual disclosure guidance are effective for fiscal years
ending after December
15, 2009 (Fiscal 2010). Because this new guidance relates to disclosures only, it will not
impact the financial statements. |
||
Transfers of Financial Assets. In June 2009, the FASB issued new guidance regarding
accounting for transfers of financial assets. Among other things, the new guidance
eliminates the concept of Qualified Special Purpose Entities (QSPEs). It also amends
previous derecognition guidance. The new guidance is effective for financial asset transfers
occurring after the beginning of an entitys fiscal year that begins after November 15, 2009
(Fiscal 2011). We are currently evaluating the provisions of the new guidance. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
4. | Intangible Assets |
The Companys intangible assets comprise the following: |
December 31, | September 30, | December 31, | ||||||||||
2009 | 2009 | 2008 | ||||||||||
Goodwill (not subject to amortization) |
$ | 1,567.5 | $ | 1,582.3 | $ | 1,525.4 | ||||||
Other intangible assets: |
||||||||||||
Customer relationships, noncompete
agreements and other |
$ | 217.8 | $ | 219.1 | $ | 200.7 | ||||||
Trademark (not subject to amortization) |
48.6 | 49.7 | 47.4 | |||||||||
Gross carrying amount |
266.4 | 268.8 | 248.1 | |||||||||
Accumulated amortization |
(107.8 | ) | (103.3 | ) | (93.7 | ) | ||||||
Net carrying amount |
$ | 158.6 | $ | 165.5 | $ | 154.4 | ||||||
The decrease in goodwill and other intangible assets during the three months ended
December 31, 2009 principally reflects the effects of currency translation partially offset
by acquisitions. Amortization expense of intangible assets was $4.9 and $4.4 for the three
months ended December 31, 2009 and 2008, respectively. No amortization is included in cost
of sales in the Condensed Consolidated Statements of Income. Our expected aggregate
amortization expense of intangible assets for the next five fiscal years is as follows:
Fiscal 2010 $17.0; Fiscal 2011 $16.5; Fiscal 2012 $16.4; Fiscal 2013 $15.9; Fiscal
2014 $13.8. |
5. | Segment Information |
We have organized our business units into six reportable segments generally based upon
products sold, geographic location (domestic or international) or regulatory environment.
Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment
comprising Antargaz; (3) an international LPG segment comprising Flaga and our international
propane equity investments (Other); (4) Gas Utility; (5) Electric Utility; and (6) Energy
Services. We refer to both international segments collectively as International Propane. |
||
The accounting policies of our reportable segments are the same as those described in Note
2, Significant Accounting Policies in the Companys 2009 Annual Report. We evaluate
AmeriGas Propanes performance principally based upon the Partnerships earnings before
interest expense, income taxes, depreciation and amortization (Partnership EBITDA).
Although we use Partnership EBITDA to evaluate AmeriGas Propanes 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 EBITDA may be different from that used by other companies. We
evaluate the performance of our International Propane, Gas Utility, Electric Utility and
Energy Services segments principally based upon their income before income taxes. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
5. | Segment Information (continued) |
|
Three Months Ended December 31, 2009: |
Reportable Segments | ||||||||||||||||||||||||||||||||||||
AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 1,618.8 | $ | (39.9 | ) | $ | 656.6 | $ | 327.8 | $ | 34.0 | $ | 312.3 | $ | 264.1 | $ | 42.8 | $ | 21.1 | |||||||||||||||||
Cost of sales |
$ | 1,026.8 | $ | (38.5 | ) | $ | 389.6 | $ | 209.8 | $ | 21.5 | $ | 271.3 | $ | 135.2 | $ | 26.8 | $ | 11.1 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income |
$ | 243.2 | $ | (0.2 | ) | $ | 102.6 | $ | 63.7 | $ | 5.4 | $ | 27.7 | $ | 41.3 | $ | 2.6 | $ | 0.1 | |||||||||||||||||
Loss from equity investees |
| | | | | | | | | |||||||||||||||||||||||||||
Interest expense |
(34.2 | ) | | (16.5 | ) | (10.2 | ) | (0.4 | ) | | (6.1 | ) | (0.9 | ) | (0.1 | ) | ||||||||||||||||||||
Income before income taxes |
$ | 209.0 | $ | (0.2 | ) | $ | 86.1 | $ | 53.5 | $ | 5.0 | $ | 27.7 | $ | 35.2 | $ | 1.7 | $ | | |||||||||||||||||
Partnership EBITDA (c) |
$ | 123.0 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests net income |
$ | 47.1 | $ | | $ | 46.8 | $ | | $ | | $ | | $ | 0.3 | $ | | $ | | ||||||||||||||||||
Depreciation and amortization |
$ | 53.0 | $ | (0.1 | ) | $ | 21.4 | $ | 12.3 | $ | 1.0 | $ | 2.1 | $ | 13.2 | $ | 2.8 | $ | 0.3 | |||||||||||||||||
Capital expenditures |
$ | 75.0 | $ | | $ | 26.7 | $ | 13.0 | $ | 0.8 | $ | 22.5 | $ | 9.4 | $ | 2.2 | $ | 0.4 | ||||||||||||||||||
Total assets (at period end) |
$ | 6,452.7 | $ | (82.8 | ) | $ | 1,830.3 | $ | 2,015.4 | $ | 115.8 | $ | 429.0 | $ | 1,749.8 | $ | 256.5 | $ | 138.7 | |||||||||||||||||
Bank loans (at period end) |
$ | 219.5 | $ | | $ | 24.0 | $ | 169.2 | $ | 9.8 | $ | | $ | | $ | 16.5 | $ | | ||||||||||||||||||
Investments in equity investees (at period end) |
$ | 2.9 | $ | | $ | | $ | | $ | | $ | | $ | | $ | 2.9 | $ | | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,567.5 | $ | (4.0 | ) | $ | 670.8 | $ | 180.1 | $ | | $ | 11.8 | $ | 632.8 | $ | 68.9 | $ | 7.1 |
Three Months Ended December 31, 2008: |
Reportable Segments | ||||||||||||||||||||||||||||||||||||
AmeriGas | Gas | Electric | Energy | International Propane | Corporate | |||||||||||||||||||||||||||||||
Total | Elims. | Propane | Utility | Utility | Services | Antargaz | Other (a) | & Other (b) | ||||||||||||||||||||||||||||
Revenues |
$ | 1,778.5 | $ | (56.0 | ) | $ | 727.1 | $ | 410.4 | $ | 35.9 | $ | 359.1 | $ | 264.8 | $ | 12.3 | $ | 24.9 | |||||||||||||||||
Cost of sales |
$ | 1,171.1 | $ | (54.7 | ) | $ | 445.5 | $ | 293.0 | $ | 23.2 | $ | 326.7 | $ | 116.7 | $ | 6.7 | $ | 14.0 | |||||||||||||||||
Segment profit: |
||||||||||||||||||||||||||||||||||||
Operating income |
$ | 289.4 | $ | | $ | 144.7 | $ | 56.9 | $ | 5.0 | $ | 18.2 | $ | 63.4 | $ | 0.7 | $ | 0.5 | ||||||||||||||||||
(Loss) income from equity investees |
(0.2 | ) | | | | | | (0.3 | ) | 0.1 | | |||||||||||||||||||||||||
Interest expense |
(37.1 | ) | | (18.7 | ) | (11.0 | ) | (0.4 | ) | | (6.3 | ) | (0.5 | ) | (0.2 | ) | ||||||||||||||||||||
Income before income taxes |
$ | 252.1 | $ | | $ | 126.0 | $ | 45.9 | $ | 4.6 | $ | 18.2 | $ | 56.8 | $ | 0.3 | $ | 0.3 | ||||||||||||||||||
Partnership EBITDA (c) |
$ | 164.1 | ||||||||||||||||||||||||||||||||||
Noncontrolling interests net income (loss) |
$ | 69.0 | $ | | $ | 69.4 | $ | | $ | | $ | | $ | (0.4 | ) | $ | | $ | | |||||||||||||||||
Depreciation and amortization |
$ | 47.7 | $ | (0.1 | ) | $ | 20.8 | $ | 11.5 | $ | 1.0 | $ | 1.8 | $ | 11.4 | $ | 0.9 | $ | 0.4 | |||||||||||||||||
Capital expenditures |
$ | 72.9 | $ | | $ | 19.1 | $ | 21.6 | $ | 1.2 | $ | 11.4 | $ | 18.3 | $ | 0.8 | $ | 0.5 | ||||||||||||||||||
Total assets (at period end) |
$ | 6,446.2 | $ | (96.4 | ) | $ | 1,952.7 | $ | 2,115.5 | $ | 115.1 | $ | 362.8 | $ | 1,638.7 | $ | 197.0 | $ | 160.8 | |||||||||||||||||
Bank loans (at period end) |
$ | 437.7 | $ | | $ | 146.0 | $ | 267.0 | $ | 16.0 | $ | | $ | | $ | 8.7 | $ | | ||||||||||||||||||
Investments in equity investees (at period end) |
$ | 63.9 | $ | | $ | | $ | | $ | | $ | | $ | | $ | 63.9 | $ | | ||||||||||||||||||
Goodwill (at period end) |
$ | 1,525.4 | $ | (4.0 | ) | $ | 665.0 | $ | 182.7 | $ | | $ | 11.8 | $ | 617.5 | $ | 45.4 | $ | 7.0 |
(a) | International Propane Other principally comprises Flaga, including, prior to the January 29, 2009
purchase of 50% equity interest it did not already own, its central and eastern European joint venture ZLH,
and our joint venture business in China. |
|
(b) | Corporate & Other results principally comprise UGI Enterprises heating, ventilation, air-conditioning,
refrigeration and electrical contracting business (HVAC/R), net expenses of UGIs captive general
liability insurance company, UGI Corporations unallocated corporate and general expenses and interest
income. Corporate & Other assets principally comprise cash, short-term investments, assets of HVAC/R and an
intercompany loan. The intercompany loan and associated interest is removed in the segment presentation. |
|
(c) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income: |
Three months ended December 31, | 2009 | 2008 | ||||||
Partnership EBITDA |
$ | 123.0 | $ | 164.1 | ||||
Depreciation and amortization |
(21.4 | ) | (20.8 | ) | ||||
Noncontrolling interests (i) |
1.0 | 1.4 | ||||||
Operating income |
$ | 102.6 | $ | 144.7 | ||||
(i) | Principally represents the General Partners 1.01% interest in AmeriGas OLP. |
- 9 -
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
6. | Energy Services Accounts Receivable Securitization Facility |
Energy Services has a $200 receivables purchase facility (Receivables Facility) with an
issuer of receivables-backed commercial paper currently scheduled to expire in April 2010,
although the Receivables Facility may terminate prior to such date due to the termination of
commitments of the Receivables Facility back-up purchasers. |
||
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 commercial paper conduit
of a major bank. ESFC was created and has been structured to isolate its assets from
creditors of Energy Services and its affiliates, including UGI. This two-step transaction is
accounted for as a sale of receivables following the FASBs guidance for accounting for
transfers and servicing of financial assets and extinguishments of liabilities. Energy
Services continues to service, administer and collect trade receivables on behalf of the
commercial paper issuer and ESFC. |
||
During the three months ended December 31, 2009 and 2008, Energy Services sold trade
receivables totaling $296.7 and $358.4, respectively, to ESFC. During the three months ended
December 31, 2009 and 2008, ESFC sold an aggregate $120.2 and $169.3, respectively, of
undivided interests in its trade receivables to the commercial paper conduit. At December
31, 2009, the outstanding balance of ESFC trade receivables was $88.3 which is net of $27.6
that was sold to the commercial paper conduit and removed from the balance sheet. At
December 31, 2008, the outstanding balance of ESFC trade receivables was $44.3 which is net
of $87.9 that was sold to the commercial paper conduit. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
7. | Utility Regulatory Assets and Liabilities and Regulatory Matters |
For a description of the Companys regulatory assets and liabilities other than those
described below, see Note 8 to the Companys 2009 Annual Report. UGI Utilities does not
recover a rate of return on its regulatory assets. The following regulatory assets and
liabilities associated with Gas Utility and Electric Utility are included in our
accompanying Condensed Consolidated Balance Sheets: |
December 31, | September 30, | December 31, | ||||||||||
2009 | 2009 | 2008 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 80.5 | $ | 79.5 | $ | 74.7 | ||||||
Postretirement benefits |
2.3 | 2.5 | 4.1 | |||||||||
CPG Gas pension and postretirement plans |
8.6 | 8.5 | 9.1 | |||||||||
Environmental costs |
25.8 | 26.9 | 9.1 | |||||||||
Deferred fuel costs |
10.3 | 19.6 | 47.0 | |||||||||
Other |
4.4 | 4.5 | 6.4 | |||||||||
Total regulatory assets |
$ | 131.9 | $ | 141.5 | $ | 150.4 | ||||||
Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 9.5 | $ | 9.3 | $ | 9.2 | ||||||
Environmental overcollections |
8.4 | 8.7 | 9.7 | |||||||||
Deferred fuel refunds |
40.3 | 30.8 | | |||||||||
Total regulatory liabilities |
$ | 58.2 | $ | 48.8 | $ | 18.9 | ||||||
Deferred fuel costs and refunds. Gas Utilitys tariffs contain clauses which permit
recovery of certain purchased gas costs through the application of purchased gas cost
(PGC) rates. The clauses provide for periodic adjustments to PGC rates for differences
between the total amount of purchased gas costs collected from customers and recoverable
costs incurred. Net undercollected gas costs are classified as a regulatory asset and net
overcollections are classified as a regulatory liability. Gas Utility uses derivative
financial instruments to reduce volatility in the cost of gas it purchases for firm-
residential, commercial and industrial (retail core-market) customers. Realized and
unrealized gains or losses on natural gas derivative financial instruments are included in
deferred fuel refunds or costs. Unrealized losses on such contracts at December 31, 2009 and
December 31, 2008 were $0.1 and $58.1, respectively. There were no such unrealized gains or
losses at September 30, 2009. |
8. | Defined Benefit Pension and Other Postretirement Plans |
We sponsor defined benefit pension plans for employees hired prior to January 1, 2009 of
UGI, UGI Utilities, CPG, PNG, and certain of UGIs other wholly owned domestic subsidiaries
(Pension Plans). We also provide postretirement health care benefits to certain retirees
and a limited number of active employees, and postretirement life insurance benefits to
nearly all domestic active and retired employees. In addition, Antargaz employees are
covered by certain defined benefit pension and postretirement plans. |
- 11 -
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Net periodic pension expense and other postretirement benefit costs include the following
components:
Other | ||||||||||||||||
Pension Benefits | Postretirement Benefits | |||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
Service cost |
$ | 2.2 | $ | 1.7 | $ | 0.1 | $ | 0.1 | ||||||||
Interest cost |
5.9 | 6.0 | 0.3 | 0.3 | ||||||||||||
Expected return on assets |
(6.5 | ) | (6.6 | ) | (0.1 | ) | (0.1 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service benefit |
| | (0.1 | ) | (0.1 | ) | ||||||||||
Actuarial loss |
1.5 | 0.2 | 0.1 | | ||||||||||||
Net benefit cost |
3.1 | 1.3 | 0.3 | 0.2 | ||||||||||||
Change in associated regulatory liabilities |
| | 0.7 | 0.8 | ||||||||||||
Net expense |
$ | 3.1 | $ | 1.3 | $ | 1.0 | $ | 1.0 | ||||||||
Pension Plans assets are held in trust and consist principally of equity and fixed
income mutual funds. It is our general policy to fund amounts for pension benefits equal to
at least the minimum contribution required by ERISA. The Company does not believe it will be
required to make any contributions to the Pension Plans during the year ending September 30,
2010 (Fiscal 2010) for ERISA funding purposes that will have a material effect on its
liquidity. Pursuant to orders previously issued by the PUC, UGI Utilities has established a
Voluntary Employees Beneficiary Association (VEBA) trust to fund and pay UGI Gas and
Electric Utilitys postretirement health care and life insurance benefits referred to above
by depositing into the VEBA the annual amount of postretirement benefit costs determined
under GAAP relating to postretirement benefits other than pensions. The difference between
the annual amount calculated and the amount included in UGI Gas and Electric Utilitys
rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to
the VEBA by UGI Utilities were not material during the three months ended December 31, 2009,
nor are they expected to be material for all of Fiscal 2010. |
We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement
income plans. We recorded pre-tax expense associated with these plans of $0.6 and $1.0 for
the three months ended December 31, 2009 and 2008. |
9. | Commitments and Contingencies |
Environmental Matters |
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned
and operated a number of manufactured gas plants (MGPs) prior to the general availability
of natural gas. Some constituents of coal tars and other residues of the manufactured gas
process are today considered hazardous substances under the Superfund Law and may be present
on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of
subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public Utility
Holding Company Act of 1935, 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. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
UGI Utilities does not expect its costs for investigation and remediation of hazardous
substances at Pennsylvania MGP sites to be material to its results of operations because UGI
Gas is currently permitted to include in rates, through future base rate proceedings, a
five-year average of such prudently incurred remediation costs. At December 31, 2009,
neither the undiscounted nor the accrued liability for environmental investigation and
cleanup costs for UGI Gas was material to UGI Utilities. |
UGI Utilities has been notified of several sites outside Pennsylvania on which private
parties allege MGPs were formerly owned or operated by it or owned or operated by its former
subsidiaries. Such parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating three claims
against it relating to out-of-state sites. |
Management believes that under applicable law UGI Utilities should not be liable in those
instances in which a former subsidiary owned or operated an MGP. There could be, however,
significant future costs of an uncertain amount associated with environmental damage caused
by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or
operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the
subsidiarys separate corporate form should be disregarded or (2) UGI Utilities should be
considered to have been an operator because of its conduct with respect to its subsidiarys
MGP. |
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South
Carolina Electric & Gas Company (SCE&G), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from
1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI
Utilities controlled operations of the plant from 1910 to 1926 and is liable for
approximately 25% of the costs associated with the site. SCE&G asserts that it has spent
approximately $22 in remediation costs and paid $26 in third-party claims relating to the
site and estimates that future response costs, including a claim by the United States
Justice Department for natural resource damages, could be as high as $14. Trial took place
in March 2009 and the courts decision is pending. |
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens
Communications Company, now known as Frontier Communications Company (Frontier), served a
complaint naming UGI Utilities as a third-party defendant in a civil action pending in the
United States District Court for the District of Maine. In that action, the City of Bangor,
Maine (City) sued Frontier to recover environmental response costs associated with MGP
wastes generated at a plant allegedly operated by Frontiers predecessors at a site on the
Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party
defendants alleging that the third-party defendants are responsible for an equitable share
of any costs Frontier would be required to pay to the City for cleaning up tar deposits in
the Penobscot River. Frontier alleged that through ownership and control of a subsidiary,
Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant
from 1901 to 1928. Frontier made similar allegations of control against another third-party
defendant, CenterPoint Energy Resources Corporation (CenterPoint), whose predecessor owned
the Bangor subsidiary from 1928 to 1944. Frontiers third-party claims were stayed pending a
resolution of the Citys suit against Frontier, which was tried in September 2005. On June
27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup
costs, which were estimated at $18. On February 14, 2007, Frontier and the City entered into
a settlement agreement pursuant to which Frontier agreed to pay $7.6. Frontier subsequently
filed the current action against the original third-party defendants, repeating its claims
for contribution. On September 22, 2009, the court granted summary judgment in favor of
co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has
filed for summary judgment with respect to Frontiers claims. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (KeySpan)
informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean
up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is
responsible for approximately 50% of these costs as a result of UGI Utilities alleged
direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006,
KeySpan reported that the New York Department of Environmental Conservation has approved a
remedy for the site that is estimated to cost approximately $10. KeySpan believes that the
cost could be as high as $20. UGI Utilities is in the process of reviewing the information
provided by KeySpan and is investigating this claim. |
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.
On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services
Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities
(together the Northeast Companies), in the United States District Court for the District
of Connecticut seeking contribution from UGI Utilities for past and future remediation costs
related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities
in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled
operations of the plants from 1883 to 1941 through control of former subsidiaries that owned
the MGPs. The Northeast Companies estimated that remediation costs for all of the sites
could total approximately $215 and asserted that UGI Utilities is responsible for
approximately $103 of this amount. The Northeast Companies subsequently withdrew their
claims with respect to three of the sites and UGI Utilities acknowledged that it had
operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court
conducted a trial to determine whether UGI Utilities operated any of the nine remaining
sites that were owned and operated by former subsidiaries. On May 22, 2009, the court
granted judgment in favor of UGI Utilities with respect to all nine sites. In a second phase
of the trial scheduled for early 2010, the court will determine what, if any, contamination
at Waterbury North is related to UGI Utilities period of operation. The Northeast Companies
estimate that remediation costs at Waterbury North could total $25. |
AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of
Environmental Conservation (DEC) notified AmeriGas OLP that DEC had placed property owned
by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste
Disposal Sites. A site characterization study performed by DEC disclosed contamination
related to former MGP operations on the site. DEC has classified the site as a significant
threat to public health or environment with further action required. The Partnership has
researched the history of the site and its ownership interest in the site. The Partnership
has reviewed the preliminary site characterization study prepared by the DEC, the extent of
contamination and the possible existence of other potentially responsible parties. The
Partnership has communicated the results of its research to DEC and is awaiting a response
before doing any additional investigation. Because of the preliminary nature of available
environmental information, the ultimate amount of expected clean up costs cannot be
reasonably estimated. |
- 14 -
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Other Matters |
On May 27, 2009, the General Partner was named as a defendant in a purported class action
lawsuit in the Superior Court of the State of California in which plaintiffs are challenging
AmeriGas OLPs weight disclosure with regard to its portable propane grill cylinders. The
complaint purports to be brought on behalf of a class of all consumers in the state of
California during the four years prior to the date of the California complaint, who
exchanged an empty
cylinder and were provided with what is alleged to be only a partially-filled cylinder. The
plaintiffs seek restitution, injunctive relief, interest, costs, attorneys fees and other
appropriate relief. |
Since that initial suit, various AmeriGas entities have been named in more than a dozen
similar suits that have been filed in various courts throughout the United States. These
complaints purport to be brought on behalf of nationwide classes, which are loosely defined
as including all purchasers of liquefied propane gas cylinders marketed or sold by AmeriGas
OLP and another unaffiliated entity nationwide. The complaints claim that defendants
conduct constituted unfair and deceptive practices that injured consumers and violated the
consumer protection statutes of at least thirty-seven states and the District of Columbia,
thereby entitling the class to damages, restitution, disgorgement, injunctive relief, costs
and attorneys fees. Some of the complaints also allege violation of state slack filling
laws. Additionally, the complaints allege that defendants were unjustly enriched by their
conduct and they seek restitution of any unjust benefits received, punitive or treble
damages, and pre-judgment and post-judgment interest. A motion to consolidate the purported
class action lawsuits was heard by the Multidistrict Litigation Panel (MDL Panel) on
September 24, 2009 in the United States District Court for the District of Kansas. By Order,
dated October 6, 2009, the MDL Panel transferred the pending cases to the United States
District Court for the Western District of Missouri. |
On or about October 21, 2009, the General Partner received a notice that the Offices of the
District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the
City Attorney of San Diego have commenced an investigation into AmeriGas OLPs cylinder
labeling and filling practices in California and issued an administrative subpoena seeking
documents and information relating to these practices. We are cooperating with these
California governmental investigations and we are vigorously defending the lawsuits. |
Samuel and Brenda Swiger and their son (the Swigers) sustained personal injuries and
property damage as a result of a fire that occurred when propane that leaked from an
underground line ignited. In July 1998, the Swigers filed a class action lawsuit against
AmeriGas Propane, L.P. (named incorrectly as UGI/AmeriGas, Inc.), in the Circuit Court of
Monongalia County, West Virginia, in which they sought to recover an unspecified amount of
compensatory and punitive damages and attorneys fees, for themselves and on behalf of
persons in West Virginia for whom the defendants had installed propane gas lines, resulting
from the defendants alleged failure to install underground propane lines at depths required
by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury
and property damage claims of the Swigers. In 2004, the court granted the plaintiffs motion
to include customers acquired from Columbia Propane Corporation in August 2001 as additional
potential class members and the plaintiffs amended their complaint to name additional
parties pursuant to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a
crossclaim against Columbia Energy Group, former owner of Columbia Propane Corporation,
seeking indemnification for conduct undertaken by Columbia Propane Corporation prior to
AmeriGas OLPs acquisition. Class counsel has indicated that the class is seeking
compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys
fees. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
In 2005, the Swigers filed what purports to be a class action in the Circuit Court of
Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers
of UGI and
the General Partner, and their insurance carriers and insurance adjusters. In the Harrison
County lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the
putative class for violations of the West Virginia Insurance Unfair Trade Practice Act,
negligence, intentional misconduct, and civil conspiracy. The Swigers have also requested
that the Court rule that insurance coverage exists under the policies issued by the
defendant insurance companies for damages sustained by the members of the class in the
Monongalia County lawsuit. The Circuit Court of Harrison County has not certified the class
in the Harrison County lawsuit at this time and, in October 2008, stayed that lawsuit
pending resolution of the class action lawsuit in Monongalia County. We believe we have good
defenses to the claims in both actions. |
French tax authorities levy various taxes on legal entities and individuals regularly
operating a business in France which are commonly referred to collectively as business
tax. The amount of business tax charged annually is generally dependent upon the value of
the entitys tangible fixed assets. Antargaz has recorded liabilities for business taxes
related to various classes of equipment. Changes in the French governments interpretation
of the tax laws or in the tax laws themselves could have either an adverse or a favorable
effect on our results of operations. |
Antargaz Competition Authority Matter. In June 2005, officials from Frances General
Division of Competition, Consumption and Fraud Punishment (DGCCRF) conducted an
unannounced inspection of, and obtained documents from, Antargaz headquarters building.
Antargaz did not have any further contact with the DGCCRF regarding this matter until
February 2007, when it received a letter from the DGCCRF requesting documents and
information relating to Antargaz pricing policies and practices. In March 2007, and again
in August 2007, the DGCCRF requested additional information from Antargaz and three joint
ventures in which it participates. In July 2008, Frances Autorité de la concurrence
(Competition Authority) interviewed Mr. Varagne, as President of Antargaz and President of
the industry association, Comité Français du Butane et du Propane, about competitive
practices in the LPG cylinder market in France. |
On July 21, 2009, Antargaz received a Statement of Objections from the Competition Authority
with respect to the investigation of Antargaz by the DGCCRF. A Statement of Objections
(Statement) is part of French competition proceedings and generally follows an
investigation under French competition laws. The Statement sets forth the Competition
Authoritys findings; it is not a judgment or final decision. The Statement alleges that
Antargaz engaged in certain anti-competitive practices in violation of French and European
Union civil competition laws related to the cylinder market during the period from 1999
through 2004. The alleged violations occurred principally during periods prior to March 31,
2004, when UGI first obtained a controlling interest in Antargaz. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
We have completed our review of the Statement of Objections and the related evidence and
filed our written response with the Competition Authority on October 21, 2009. The
Competition Authority will undertake a review of Antargaz response and begin preparation of
its final pleading on the claims. This process is anticipated to take several months and
Antargaz will have the opportunity to prepare a response to the Competition Authoritys
final pleading. Based on an assessment of the information contained in the Statement, during
the quarter ended June 30, 2009 we recorded a provision of $10.0 (7.1) related to this
matter. The final resolution could result in payment of an amount significantly different
from the amount we have recorded. We are unable to predict the timing of the final
resolution of this matter. |
We cannot predict with certainty the final results of any of the environmental or other
pending claims or legal actions described above. However, it is reasonably possible that
some of them could be resolved unfavorably to us and result in losses in excess of recorded
amounts. We are unable to estimate any possible losses in excess of recorded amounts.
Although we currently believe, after consultation with counsel, that damages or settlements,
if any, recovered by the plaintiffs in such claims or actions will not have a material
adverse effect on our financial position, damages or settlements could be material to our
operating results or cash flows in future periods depending on the nature and timing of
future developments with respect to these matters and the amounts of future operating
results and cash flows. In addition to the matters described above, there are other pending
claims and legal actions arising in the normal course of our businesses. While the results
of these other pending claims and legal actions cannot be predicted with certainty, we
believe, after consultation with counsel, the final outcome of such other matters will not
have a significant effect on our consolidated financial position, results of operations or
cash flows. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
10. | Equity |
The following table sets forth changes in UGIs equity and the equity of the noncontrolling
interests for the three months ended December 31, 2009 and 2008: |
UGI Shareholders | ||||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||
Other | ||||||||||||||||||||||||
Non- | Comprehensive | |||||||||||||||||||||||
controlling | Common | Retained | Income | Treasury | Total | |||||||||||||||||||
Interests | Stock | Earnings | (Loss) | Stock | Equity | |||||||||||||||||||
Three Months Ended December 31,
2009: |
||||||||||||||||||||||||
Balance September 30, 2009 |
$ | 225.4 | $ | 875.6 | $ | 804.3 | $ | (38.9 | ) | $ | (49.6 | ) | $ | 1,816.8 | ||||||||||
Net income |
47.1 | 98.4 | 145.5 | |||||||||||||||||||||
Net gains on derivative instruments |
24.8 | 0.2 | 25.0 | |||||||||||||||||||||
Reclassifications of net
(gains) losses on derivative instruments |
(4.7 | ) | 15.7 | 11.0 | ||||||||||||||||||||
Benefit plans |
| 0.8 | 0.8 | |||||||||||||||||||||
Foreign currency translation
adjustments |
| (5.6 | ) | (5.6 | ) | |||||||||||||||||||
Comprehensive income |
67.2 | 98.4 | 11.1 | 176.7 | ||||||||||||||||||||
Dividends and distributions |
(21.7 | ) | (21.9 | ) | (43.6 | ) | ||||||||||||||||||
Transactions with owners |
0.2 | 2.2 | 0.6 | 3.0 | ||||||||||||||||||||
Other |
(0.5 | ) | (0.5 | ) | ||||||||||||||||||||
Balance December 31, 2009 |
$ | 270.6 | $ | 877.8 | $ | 880.8 | $ | (27.8 | ) | $ | (49.0 | ) | $ | 1,952.4 | ||||||||||
Three Months Ended December 31, 2008 (1): |
||||||||||||||||||||||||
Balance September 30, 2008 |
$ | 159.2 | $ | 858.3 | $ | 630.9 | $ | (15.2 | ) | $ | (56.3 | ) | $ | 1,576.9 | ||||||||||
Net income |
69.0 | 114.9 | 183.9 | |||||||||||||||||||||
Net losses on derivative instruments |
(100.9 | ) | (95.9 | ) | (196.8 | ) | ||||||||||||||||||
Reclassifications of net
losses on derivative instruments |
31.0 | 27.1 | 58.1 | |||||||||||||||||||||
Benefit plans |
| (38.7 | ) | (38.7 | ) | |||||||||||||||||||
Foreign currency translation
adjustments |
| 1.0 | 1.0 | |||||||||||||||||||||
Comprehensive income |
(0.9 | ) | 114.9 | (106.5 | ) | 7.5 | ||||||||||||||||||
Dividends and distributions |
(20.7 | ) | (20.8 | ) | (41.5 | ) | ||||||||||||||||||
Transactions with owners |
0.1 | 2.1 | 0.5 | 2.7 | ||||||||||||||||||||
Other |
(0.3 | ) | (0.3 | ) | ||||||||||||||||||||
Balance December 31, 2008 |
$ | 137.4 | $ | 860.4 | $ | 725.0 | $ | (121.7 | ) | $ | (55.8 | ) | $ | 1,545.3 | ||||||||||
(1) | As adjusted in accordance with the transition provisions for accounting for
noncontrolling interests in consolidated subsidiaries. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
11. | Fair Value Measurement |
The following table presents our financial assets and financial liabilities that are
measured at fair value on a recurring basis for each of the fair value hierarchy levels,
including both current and noncurrent portions, as of December 31, 2009 and 2008: |
Quoted Prices | ||||||||||||||||
in Active | Significant | |||||||||||||||
Markets for | Other | |||||||||||||||
Identical Assets | Observable | Unobservable | ||||||||||||||
and Liabilities | Inputs | Inputs | ||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
December 31, 2009: |
||||||||||||||||
Derivative
financial
instruments: |
||||||||||||||||
Assets |
$ | 0.6 | $ | 46.6 | $ | | $ | 47.2 | ||||||||
Liabilities |
$ | (8.9 | ) | $ | (33.8 | ) | $ | | $ | (42.7 | ) | |||||
December 31, 2008: |
||||||||||||||||
Derivative
financial
instruments: |
||||||||||||||||
Assets |
$ | 2.0 | $ | 8.4 | $ | | $ | 10.4 | ||||||||
Liabilities |
$ | (97.2 | ) | $ | (185.1 | ) | $ | | $ | (282.3 | ) |
12. | Disclosures About Derivative Instruments, Hedging Activities and Financial
Instruments |
Derivative Instruments and Hedging Activities |
We are exposed to certain market risks related to our ongoing business operations.
Management uses derivative financial and commodity instruments, among other things, to
manage these risks. The primary risks managed by derivative instruments are (1) commodity
price risk, (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. Because our derivative instruments, other than
FTRs and gasoline futures and swap contracts (as further described below), generally qualify
as hedges under GAAP or are subject to regulatory rate recovery mechanisms, we expect that
changes in the fair value of derivative instruments used to manage commodity, interest rate
or currency exchange rate risk would be substantially offset by gains or losses on the
associated anticipated transactions. |
Commodity Price Risk |
In order to manage market price risk associated with the Partnerships fixed-price programs
which permit customers to lock in the prices they pay for propane principally during the
months of October through March, the Partnership uses over-the-counter derivative commodity
instruments, principally price swap contracts. Certain other domestic business units and our
International Propane operations also use over-the-counter price swap and option contracts
to reduce commodity price volatility associated with a portion of their forecasted LPG
purchases. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Gas Utilitys tariffs contain clauses that permit recovery of all of the prudently incurred
costs of natural gas it sells to retail core-market customers. As permitted and agreed to by
the PUC pursuant to Gas Utilitys annual PGC filings, Gas Utility currently uses New York
Mercantile Exchange (NYMEX) natural gas futures contracts to reduce commodity price
volatility associated with a portion of the natural gas it purchases for its retail
core-market customers. At December 31, 2009, the volumes of natural gas associated with Gas
Utilitys unsettled NYMEX natural gas futures contracts was not material. With respect to
natural gas futures contracts associated with our Gas Utility, gains and losses on natural
gas futures contracts are recorded in deferred fuel costs on the Condensed Consolidated
Balance Sheets in accordance with FASBs guidance in Accounting Standards Codification
(ASC) 980 related to rate-regulated entities and reflected in cost of sales through the
PGC mechanism. |
In order to reduce volatility associated with a substantial portion of its electricity
transmission congestion costs, Electric Utility obtains FTRs through an annual PJM
Interconnection (PJM) allocation process and by purchases of FTRs at monthly PJM auctions.
Energy Services purchases FTRs to economically hedge electricity transmission congestion
costs associated with its fixed-price electricity sales contracts. FTRs are derivative
financial instruments that entitle the holder to receive compensation for electricity
transmission congestion charges that result when there is insufficient electricity
transmission capacity on the electric transmission grid. PJM is a regional transmission
organization that coordinates the movement of wholesale electricity in all or parts of 14
eastern and midwestern states. Because Electric Utility is entitled to fully recover its
default service costs commencing January 1, 2010 pursuant to a January 22, 2009 settlement
of its default service filing with the PUC, Electric Utility FTRs associated with periods
beginning January 1, 2010 are recorded at fair value with changes in fair value recorded as
regulatory assets or liabilities in accordance with ASC 980 and will be reflected in cost of
sales through the default service recovery mechanism. Electric Utility FTRs associated with
periods prior to January 2010 were recorded at fair value with changes in fair value
reflected in cost of
sales. Energy Services FTRs are recorded at fair value with changes in fair value reflected
in cost of sales. |
In order to reduce operating expense volatility, UGI Utilities from time to time enters into
NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be
used in the operation of its vehicles and equipment. The volumes of gasoline under these
contracts, the associated fair values and the effect on net income were not material for all
periods presented. |
In order to manage market price risk relating to fixed-price sales contracts for natural gas
and electricity, Energy Services enters into NYMEX and over-the-counter natural gas and
electricity futures contracts. |
At December 31, 2009, we had the following outstanding derivative commodity instruments
volumes that qualify for hedge accounting treatment: |
Commodity | Volumes | |||
LPG (millions of gallons) |
95.0 | |||
Natural gas (millions of dekatherms) |
23.5 | |||
Electricity (millions of kilowatt-hours) |
484.5 |
- 20 -
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
The maximum period over which we are currently hedging our exposure to the variability
in cash flows associated with LPG commodity price risk is 15 months with a weighted average
of 3 months. The maximum period over which we are currently hedging our exposure to the
variability in cash flows associated with natural gas commodity price risk (excluding Gas
Utility) is 38 months with a weighted average of 8 months. The maximum period over which we
are currently hedging our exposure to the variability in cash flows associated with
electricity price risk is 24 months with a weighted average of 8 months. The volume of
electric transmission congestion that is subject to FTRs (excluding Electric Utility) at
December 31, 2009 totaled 453.0 million kilowatt-hours. The maximum period over which we
are economically hedging such electricity congestion with FTRs is 5 months. |
We account for commodity price risk contracts (other than our Gas Utility natural gas
futures contracts, gasoline futures and swap contracts and FTRs) as cash flow hedges.
Changes in the fair values of contracts qualifying for cash flow hedge accounting are
recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the
extent effective in offsetting changes in the underlying commodity price risk. When earnings
are affected by the hedged commodity, gains or losses are recorded in cost of sales on the
Consolidated Statements of Income. At December 31, 2009, the amount of net gains associated
with commodity price risk hedges expected to be reclassified into earnings during the next
twelve months based upon current fair values is $15.6. |
||
Interest Rate Risk |
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). At December 31, 2009, the total notional amount of our
unsettled IRPAs was $150. Our current unsettled IRPA contracts hedge forecasted interest
payments associated with the issuance of debt forecasted to occur in June 2010. |
Antargaz and Flagas long-term debt agreements have interest rates that are generally
indexed to short-term market interest rates. Antargaz has effectively fixed the underlying
euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the
underlying euribor interest rate on a substantial portion of its two term loans through
their scheduled maturity dates in 2011 and 2014 through the use of pay-fixed,
receive-variable interest rate swap agreements. As of December 31, 2009, the total notional
amount of our interest rate swaps was 409.9. |
We account for IRPAs and interest rate swaps as cash flow hedges. Changes in the fair values
of IRPAs and interest rate swaps are recorded in AOCI and, with respect to the Partnership,
noncontrolling interests, to the extent effective in offsetting changes in the underlying
interest rate risk, until earnings are affected by the hedged interest expense. At such
time, gains and losses are recorded in interest expense. At December 31, 2009, 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
based upon current fair values is $2.2. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Foreign Currency Exchange Rate Risk |
In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S.
dollar-denominated LPG product purchases through the use of forward foreign currency
exchange contracts. The amount of dollar-denominated purchases of LPG associated with such
contracts generally represents approximately 15% 20% of estimated dollar-denominated
purchases of LPG to occur during the heating-season months of October through March. At
December 31, 2009, we were hedging a total of $89.0 of U.S. dollar denominated LPG
purchases. The maximum period over which we are currently hedging our exposure to the
variability in cash flows associated with the dollar denominated purchases of LPG is 24
months with a weighted average of 10 months. We also enter into forward foreign currency
exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our
International Propane euro-denominated net investment. At December 31, 2009, we were hedging
a total of 30.8 of our euro-denominated net investments. As of December 31, 2009, our
foreign currency contracts extend through December 2011. |
We account for foreign currency exchange contracts associated with anticipated purchases of
U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign
currency exchange contracts are recorded in AOCI, to the extent effective in offsetting
changes in the underlying currency exchange rate risk, until earnings are affected by the
hedged LPG
purchase, at which time gains and losses are recorded in cost of sales. At December 31,
2009, the amount of net losses associated with currency rate risk (other than net investment
hedges) expected to be reclassified into earnings during the next twelve months based upon
current fair values is $1.3. Gains and losses on net investment hedges are included in AOCI
until such foreign operations are liquidated. |
||
Derivative Financial Instrument Credit Risk |
We are exposed to risk of loss in the event of nonperformance by our derivative financial
instrument counterparties. Our derivative financial instrument counterparties principally
comprise major 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. Certain of these agreements call for the posting of collateral by
the counterparty or by the Company in the form of letters of credit, parental guarantees or
cash. Additionally, our natural gas and electricity exchange-traded futures contracts which
are guaranteed by the NYMEX generally require cash deposits in margin accounts. At December
31, 2009, restricted cash in brokerage accounts totaled $9.6. Although we have
concentrations of credit risk associated with derivative financial instruments held by
certain derivative financial instrument counterparties, the maximum amount of loss due to
credit risk that, based upon the gross fair values of the derivative financial instruments,
we would incur if these counterparties that make up the concentration failed to perform
according to the terms of their contracts was not material at December 31, 2009. We
generally do not have credit-risk-related contingent features in our derivative contracts. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
The following table provides information regarding the balance sheet location and fair
value of derivative assets and liabilities existing as of December 31, 2009: |
Derivative Assets | Derivative (Liabilities) | |||||||||||
Balance Sheet | Fair | Balance Sheet | Fair | |||||||||
As of December 31, 2009: | Location | Value | Location | Value | ||||||||
Derivatives Designated as
Hedging Instruments: |
||||||||||||
Commodity contracts: |
||||||||||||
LPG
|
Derivative financial instruments and Other assets |
$ | 40.0 | Derivative financial instruments |
$ | (1.8 | ) | |||||
Natural gas |
||||||||||||
Derivative financial instruments |
0.3 | Derivative financial instruments and Other noncurrent liabilities |
(6.4 | ) | ||||||||
Electricity |
||||||||||||
Derivative financial instruments and Other noncurrent liabilities |
(2.3 | ) | ||||||||||
Foreign currency contracts |
||||||||||||
Derivative financial instruments |
0.7 | Derivative financial instruments and Other noncurrent liabilities |
(3.1 | ) | ||||||||
Interest rate contracts |
||||||||||||
Derivative financial instruments |
3.9 | Derivative financial instruments and Other noncurrent liabilities |
(29.0 | ) | ||||||||
Total Derivatives Designated
as Hedging Instruments |
$ | 44.9 | $ | (42.6 | ) | |||||||
Derivatives Accounted for
under ASC 980: |
||||||||||||
Natural gas |
Derivative financial instruments | $ | (0.1 | ) | ||||||||
FTRs |
Derivative financial instruments | $ | 0.6 | |||||||||
Total Derivatives Accounted for
under ASC 980 |
$ | 0.6 | $ | (0.1 | ) | |||||||
Derivatives Not Designated as
Hedging Instruments: |
||||||||||||
FTRs |
Derivative financial instruments | $ | 1.5 | |||||||||
Gasoline contracts |
Derivative financial instruments | 0.2 | ||||||||||
Total Derivatives Not Designated
as Hedging instruments |
$ | 1.7 | ||||||||||
Total Derivatives |
$ | 47.2 | $ | (42.7 | ) | |||||||
- 23 -
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
The following tables provide information on the effects of derivative instruments on
the Consolidated Statement of Income and changes in AOCI and noncontrolling interest for the
three months ended December 31, 2009: |
Location of | ||||||||||
Gain or (Loss) | Gain or (Loss) | Gain or (Loss) | ||||||||
Recognized in | Reclassified from | Reclassified from | ||||||||
Three Months Ended | AOCI and | AOCI and Noncontrolling | AOCI and Noncontrolling | |||||||
December 31, 2009: | Noncontrolling Interests | Interests into Income | Interests into Income | |||||||
Cash Flow |
||||||||||
Hedges: |
||||||||||
Commodity contracts: |
||||||||||
LPG |
$ | 39.4 | $ | 9.8 | Cost of sales | |||||
Natural gas |
(12.1 | ) | (25.9 | ) | Cost of sales | |||||
Electricity |
1.3 | (1.6 | ) | Cost of sales | ||||||
Foreign currency contracts |
2.6 | 0.3 | Cost of sales | |||||||
Interest rate contracts |
5.3 | 3.4 | Interest expense /other income | |||||||
Total |
$ | 36.5 | $ | (14.0 | ) | |||||
Net Investment |
||||||||||
Hedges: |
||||||||||
Foreign currency contracts |
$ | 1.0 | ||||||||
Gain | Location of Gain | |||||
Recognized in | Recognized in | |||||
Income | Income | |||||
Derivatives
Not Designated as Hedging Instruments: |
||||||
FTRs |
$ | 0.5 | Cost of sales | |||
Gasoline contracts |
0.2 | Operating expenses / other income | ||||
Total |
$ | 0.7 | ||||
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 the three months ended December 31, 2009. |
We are also a party to a number of contracts that have elements of a derivative instrument.
These contracts include, among others, binding purchase orders, contracts which provide for
the purchase and delivery, or sale, of natural gas, LPG and electricity, and service
contracts that require the counterparty to provide commodity storage, transportation or
capacity service to meet our normal sales commitments. Although many of these contracts have
the requisite elements of a derivative instrument, these contracts qualify for normal
purchase and normal sale exception accounting under GAAP because they provide for the
delivery of products or services in quantities that are expected to be used in the normal
course of operating our business and the price based on the contract underlying is directly
associated with the price or value of a service. |
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Table of Contents
UGI CORPORATION AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)
(unaudited)
(Millions of dollars and euros, except per share amounts)
Financial Instruments |
The carrying amounts of financial instruments included in current assets and current
liabilities (excluding unsettled derivative instruments and current maturities of long-term
debt) approximate their fair values because of their short-term nature. The carrying amounts
and estimated fair values of our remaining financial instrument assets and (liabilities) at
December 31, 2009 (including unsettled derivative instruments) are as follows: |
Asset (Liability) | ||||||||
Carrying | Estimated | |||||||
Amount | Fair Value | |||||||
December 31, 2009: |
||||||||
Derivative financial instruments |
$ | 4.5 | $ | 4.5 | ||||
Long-term debt |
$ | (2,119.8 | ) | $ | (2,176.6 | ) |
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. |
Financial instruments other than derivative financial instruments, such as our short-term
investments and trade accounts receivable, could expose us to concentrations of credit risk.
We limit our credit risk from short-term investments by investing only in investment-grade
commercial paper, money market mutual funds and securities guaranteed by the U.S. Government
or its agencies. The credit risk from trade accounts receivable is limited because we have a
large customer base, which extends across many different U.S. markets and several foreign
countries. |
13. | Inventories |
Inventories comprise the following: |
December 31, | September 30, | December 31, | ||||||||||
2009 | 2009 | 2008 | ||||||||||
Non-utility LPG and natural gas |
$ | 159.0 | $ | 118.0 | $ | 131.8 | ||||||
Gas Utility natural gas |
170.2 | 189.7 | 160.1 | |||||||||
Materials, supplies and other |
58.2 | 55.5 | 53.3 | |||||||||
Total inventories |
$ | 387.4 | $ | 363.2 | $ | 345.2 | ||||||
At December 31, 2009, UGI Utilities is a party to three storage contract administrative
agreements (SCAAs). Pursuant to the SCAAs, UGI Utilities has, among other things, released
certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also
transferred certain associated storage inventories upon commencement of the SCAAs, will
receive a transfer of storage inventories at the end of the SCAAs, and makes payments
associated with refilling storage inventories during the term of the SCAAs. The historical
cost of natural gas storage inventories released under the SCAAs, which represent a portion of Gas
Utilitys total natural gas storage inventories, and any exchange receivable (representing
amounts of natural gas inventories used by the other parties to the agreement but not yet
replenished), are included in the caption Gas Utility natural gas in the table above. The
carrying value of gas storage inventories released under SCAAs with non-affiliates at
December 31, 2009, September 30, 2009 and December 31, 2008 comprising 7.4 billion cubic
feet (bcf), 1.3 bcf and 1.5 bcf of natural gas was $63.1, $10.5 and $11.9, respectively. |
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ITEM 2: MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Forward-Looking Statements
Information contained in this Managements Discussion and Analysis of Financial Condition and
Results of Operations may contain forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements
use forward-looking words such as believe, plan, anticipate, continue, estimate,
expect, may, will, or other similar words. These statements discuss plans, strategies, events
or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the
forward-looking statement. We believe that we have chosen these assumptions or bases in good faith
and that they are reasonable. However, we caution you that actual results almost always vary from
assumed facts or bases, and the differences between actual results and assumed facts or bases can
be material, depending on the circumstances. When considering forward-looking statements, you
should keep in mind the following important factors which could affect our future results and could
cause those results to differ materially from those expressed in our forward-looking statements:
(1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of
propane and other LPG, oil, 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 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 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) large customer, counter-party or supplier
defaults; (12) liability in excess of insurance coverage for personal injury and property damage
arising from explosions and other catastrophic events, including acts of terrorism, resulting from
operating hazards and risks incidental to generating and distributing electricity and transporting,
storing and distributing natural gas and LPG; (13) political, regulatory and economic conditions in
the United States and in foreign countries, including foreign currency exchange rate fluctuations,
particularly the euro; (14) capital market conditions, including reduced access to capital markets
and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly
higher cash collateral requirements; (16) reduced distributions from subsidiaries; and (17) the
timing and success of our acquisitions and investments to grow our businesses.
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.
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ANALYSIS OF RESULTS OF OPERATIONS
The following analyses compare our results of operations for the three months ended December 31,
2009 (2009 three-month period) with the three months ended December 31, 2008 (2008 three-month
period). Our analyses of results of operations should be read in conjunction with the segment
information included in Note 5 to the condensed consolidated financial statements.
Executive Overview
Because most of our businesses sell 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. As a result, our earnings are
generally higher in our first and second fiscal quarters.
We recorded net income attributable to UGI Corporation of $98.4 million for the 2009 three-month
period compared to net income attributable to UGI Corporation of $114.9 million in the prior-year
three-month period. Net income attributable to UGI Corporation in the prior-year three-month period
includes an after-tax gain of $10.4 million associated with the Partnerships sale of its
California LPG storage facility. The decline in the 2009 three-month period results compared to the
2008 three-month period also reflects a $14.4 million decrease in net income from International
Propane reflecting lower volume sales, due in large part to a weaker crop drying season, warmer
2009 three-month period temperatures and lower retail unit margins. Last years first quarter unit
margins at Antargaz were significantly higher than normal due to a rapid and sharp decline in LPG
commodity costs that occurred as Antargaz entered the Fiscal 2009 winter heating season.
The previously-mentioned decreases in net income attributable to UGI Corporation in the 2009
three-month period were partially offset principally by higher net income from Energy Services and
Gas Utility. Energy Services results improved in the 2009 three-month period principally due to
higher total margin and lower electric generation maintenance costs. Gas Utility net income
increased, notwithstanding the effects of warmer heating-season weather, due to the margin effects
of the August 2009 base revenue increases at PNG Gas and CPG Gas and lower operating and
administrative expenses. Excluding the effects on the prior year of the previously-mentioned $10.4
million after-tax gain on the sale of the Partnerships California LPG storage facility, AmeriGas
Propanes 2009 three-month period net income attributable to UGI Corporation was comparable to the
prior year as lower total margin on lower volume sales was substantially offset by lower operating
and administrative costs and lower interest expense.
The U.S. dollar was weaker versus the euro in the 2009 three-month period compared to the 2008
three-month period. Although the weaker dollar generally resulted in higher translated
International Propane operating results, the effects of the weaker dollar on reported International
Propane net income were substantially offset by losses on forward currency contracts used to hedge
purchases of dollar-denominated LPG.
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As further described in Note 3 to condensed consolidated financial statements, effective October 1,
2009, we adopted guidance regarding the accounting for and presentation of noncontrolling interests
in consolidated financial statements. The new guidance significantly changed the
accounting and reporting relating to noncontrolling interests in a consolidated subsidiary.
Noncontrolling interests are now classified as a component of equity on the Condensed Consolidated
Balance Sheets, a change from their prior classification between liabilities and stockholders
equity. Earnings attributable to noncontrolling interests are now included in net income and
deducted from net income to determine net income attributable to UGI Corporation. In accordance
with the new guidance, prior-year periods have been adjusted. The new guidance had no effect on
basic or diluted earnings per share.
Net income attributable to UGI by business unit:
Three Months Ended | Variance- | |||||||||||
December 31, | Favorable | |||||||||||
2009 | 2008 | (Unfavorable) | ||||||||||
(Millions of dollars) | ||||||||||||
Net income (loss) attributable to UGI: |
||||||||||||
AmeriGas Propane |
$ | 23.0 | $ | 34.3 | (a) | $ | (11.3 | ) | ||||
International Propane |
25.8 | 40.2 | (14.4 | ) | ||||||||
Gas Utility |
32.1 | 28.3 | 3.8 | |||||||||
Electric Utility |
2.9 | 2.8 | 0.1 | |||||||||
Energy Services |
16.4 | 10.7 | 5.7 | |||||||||
Corporate & Other |
(1.8 | ) | (1.4 | ) | (0.4 | ) | ||||||
Net income attributable to UGI |
$ | 98.4 | $ | 114.9 | $ | (16.5 | ) | |||||
(a) | Includes net income of $10.4 million from sale of the Partnerships California LPG storage
facility. |
2009 three-month period compared to the 2008 three-month period
AmeriGas Propane:
For the three months ended December 31, | 2009 | 2008 | Decrease | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Revenues |
$ | 656.6 | $ | 727.1 | $ | (70.5 | ) | (9.7 | )% | |||||||
Total margin (a) |
$ | 267.0 | $ | 281.6 | $ | (14.6 | ) | (5.2 | )% | |||||||
Partnership EBITDA (b) |
$ | 123.0 | $ | 164.1 | $ | (41.1 | ) | (25.0 | )% | |||||||
Operating income |
$ | 102.6 | $ | 144.7 | $ | (42.1 | ) | (29.1 | )% | |||||||
Retail gallons sold (millions) |
267.4 | 278.2 | (10.8 | ) | (3.9 | )% | ||||||||||
Degree days % colder (warmer)
than normal (c) |
1.3 | % | (0.8 | )% | | |
(a) | Total margin represents total revenues less total cost of sales. |
|
(b) | Partnership EBITDA (earnings before interest expense, income taxes and depreciation and
amortization) 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
accounting principles generally accepted in the United States of America. Management uses
Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane
segment (see Note 5 to condensed consolidated financial statements). EBITDA (and operating
income) in the 2008 three-month period includes a pre-tax gain of $39.9 million associated
with the sale of the Partnerships California LPG storage
facility which amount is included in other income, net on
the Condensed Consolidated Statement of Income. |
|
(c) | Deviation from average heating degree-days for the 30-year period 1971-2000 based upon
national weather statistics provided by the National Oceanic and Atmospheric Administration
(NOAA) for 335 airports in the United States, excluding Alaska. |
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Based upon heating degree-day data, average temperatures in our service territories were 1.3%
colder than normal during the 2009 three-month period compared with temperatures in the prior-year
period that were 0.8% warmer than normal. Notwithstanding the slightly colder 2009 three-month
period weather, retail gallons sold were lower than in the prior-year period reflecting, among
other things, the continuing adverse effects of the economic recession on commercial and motor fuel
customers and continued customer conservation.
Retail propane revenues declined $74.0 million during the 2009 three-month period reflecting a
$49.4 million decrease due to lower average selling prices and a $24.6 million decrease as a result
of the lower retail volumes sold. Wholesale propane revenues increased $9.7 million principally
reflecting higher year-over-year wholesale selling prices and higher wholesale volumes
sold. Average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply
points in the U.S., were approximately 36% higher in the 2009
three-month period compared to such prices
in the 2008 three-month period. The higher average wholesale propane commodity prices in the
current year reflect the effects of an increase in wholesale propane commodity prices during the
current-year period and a precipitous decline in such prices during the 2008 three-month
period. At December 31, 2009, wholesale propane commodity prices at Mont Belvieu were $1.32 a
gallon compared with $0.62 a gallon at December 31, 2008. Other non-propane revenues were lower in
the 2009 three-month period due in large part to lower fee, hauling and terminal revenues. Total
cost of sales decreased $55.9 million to $389.6 million principally reflecting the effects of the
lower propane product costs and lower volume sales.
Total margin was $14.6 million lower in the 2009 three-month period primarily due to the lower
retail volumes sold.
The $41.1 million decrease in EBITDA during the 2009 three-month period reflects the absence of a
$39.9 million pre-tax gain recorded in the prior-year period associated with the November 2008 sale
of the Partnerships California LPG storage facility and the previously mentioned lower 2009
three-month period total margin. The reduction in total margin was substantially offset by lower
operating and administrative expenses, principally lower uncollectible accounts expense and lower
general insurance and uninsured litigation expenses.
Operating income in the 2009 three-month period decreased $42.1 million reflecting the $41.1
million decrease in EBITDA, principally due to the previously mentioned absence of the gain from
the sale of the Partnerships California storage facility, and slightly higher depreciation and
amortization expense associated with acquisitions and plant and equipment expenditures made since
the prior year.
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International Propane:
Increase | ||||||||||||||||
For the three months ended December 31, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of euros) | ||||||||||||||||
Revenues |
| 208.3 | | 210.5 | | (2.2 | ) | (1.0 | )% | |||||||
Total margin (a) |
| 98.3 | | 116.8 | | (18.5 | ) | (15.8 | )% | |||||||
Operating income |
| 29.8 | | 48.3 | | (18.5 | ) | (38.3 | )% | |||||||
Income before income taxes |
| 25.2 | | 43.1 | | (17.9 | ) | (41.5 | )% | |||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 306.9 | $ | 277.1 | $ | 29.8 | 10.8 | % | ||||||||
Total margin (a) |
$ | 144.9 | $ | 153.7 | $ | (8.8 | ) | (5.7 | )% | |||||||
Operating income |
$ | 43.9 | $ | 64.1 | $ | (20.2 | ) | (31.5 | )% | |||||||
Income before income taxes |
$ | 36.9 | $ | 57.1 | $ | (20.2 | ) | (35.4 | )% | |||||||
Antargaz retail gallons sold |
82.0 | 96.1 | (14.1 | ) | (14.7 | )% | ||||||||||
Degree days % (warmer) colder than
normal (b) |
(9.1 | )% | 4.9% | | |
(a) | Total margin represents total revenues less total cost of sales. |
|
(b) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30
locations in our French service territory. |
International Propane operating results in the 2009 three-month period reflect the
consolidation of ZLH subsequent to Flagas acquisition in January 2009 of the 50% interest in ZLH
it did not already own. Based upon heating degree day data, temperatures in Antargaz service
territory were approximately 9.1% warmer than normal during the 2009 three-month period compared
with temperatures that were approximately 4.9% colder than normal during the prior-year period.
Temperatures in Flagas service territory were also warmer than normal and warmer than the prior
year. Average LPG wholesale product prices were higher in the 2009 three-month period compared with
such prices in the prior-year period. LPG wholesale prices during the 2009 three-month period
increased while LPG wholesale prices during the 2008 three-month period declined significantly. The
average wholesale commodity price for propane in northwest Europe during the 2009 three-month
period was approximately 44% higher than such price during the same period last year, and average
wholesale butane prices were approximately 38% higher in the 2009 three-month period. Antargaz
2009 three-month period retail propane volumes were lower than in the prior-year period principally
as a result of reduced demand for crop drying due to an exceptionally dry summer, the warmer 2009
three-month period weather and the effects of continued customer conservation and recessionary
economic conditions in France.
As previously mentioned, our International Propane base-currency results are translated into U.S.
dollars based upon exchange rates experienced during each of the reporting periods. During the
2009 three-month period, the average currency translation rate was $1.47 per euro compared to a
rate of $1.32 per euro during the prior-year three-month period. Although the weaker dollar
resulted in higher translated International Propane operating results in the 2009 three-month
period, the effects of the weaker dollar on International Propane net income were substantially
offset by losses on forward currency contracts used to hedge purchases of dollar-denominated LPG.
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International Propane euro-based revenues decreased 2.2 million or 1.0% reflecting the lower
Antargaz retail gallons sold substantially offset by higher Antargaz average selling prices and, to
a lesser extent, greater Flaga revenues resulting from the consolidation of ZLH. The higher average
selling prices reflect the effects of the previously mentioned year-over-year increase in wholesale
LPG product costs. In U.S. dollars, revenues increased $29.8 million or 10.8% principally
reflecting the effects of the weaker U.S. dollar on euro base-currency revenues. International
Propanes total cost of sales increased to 110.0 million in the 2009 three-month period from
93.7 million in the prior year, an increase of 17.4%, reflecting the higher per-unit LPG
commodity costs and the consolidation of ZLH. On a U.S. dollar basis, cost of sales increased to
$162.0 million from $123.4 million in the prior-year period, an increase of 31.3%, reflecting the
higher euro base-currency cost of sales and the effects of the weaker U.S. dollar.
International Propane euro-denominated total margin decreased 18.5 million or 15.8% in the 2009
three-month period principally reflecting the lower Antargaz retail gallons sold and lower average
Antargaz retail unit margins partially offset by incremental total margin from the consolidation of
ZLH. Antargaz euro-denominated retail unit margins were lower in the 2009 three-month period
compared with the prior-year period as the prior-year unit margins were higher than normal due to
the rapid and sharp decline in LPG commodity costs that occurred as Antargaz entered the Fiscal
2009 winter heating season. In U.S. dollars, total margin decreased $8.8 million or 5.7%
reflecting the effects of the weaker dollar on translated euro base-currency revenues and cost of
sales.
International Propane euro base-currency operating income decreased 18.5 million or 38.3%
principally reflecting the previously mentioned decrease in International Propane total margin.
International Propane euro base-currency operating and administrative expenses were about equal to
the prior year as lower Antargaz operating and administrative costs, principally lower vehicle and
benefits expenses, were offset by higher Flaga operating and administrative costs and greater
depreciation expense resulting from the consolidation of ZLH. On a U.S. dollar basis, operating
income decreased $20.2 million or 31.5% reflecting the previously mentioned decrease in U.S.
dollar-denominated total margin and higher U.S dollar-denominated operating and administrative
expenses due principally to the effects of the weaker dollar on euro base-currency expenses. Euro
base-currency income before income taxes was 17.9 million (41.5%) lower than in the prior-year
period principally reflecting the lower euro-denominated operating income and the effect of
slightly lower interest expense. In U.S. dollars, income before income taxes decreased
$20.2 million (35.4%) reflecting the previously mentioned lower operating income.
Gas Utility:
Increase | ||||||||||||||||
For the three months ended December 31, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Revenues |
$ | 327.8 | $ | 410.4 | $ | (82.6 | ) | (20.1 | )% | |||||||
Total margin (a) |
$ | 118.0 | $ | 117.4 | $ | 0.6 | 0.5 | % | ||||||||
Operating income |
$ | 63.7 | $ | 56.9 | $ | 6.8 | 12.0 | % | ||||||||
Income before income taxes |
$ | 53.5 | $ | 45.9 | $ | 7.6 | 16.6 | % | ||||||||
System throughput
billions of cubic feet (bcf) |
42.3 | 44.0 | (1.7 | ) | (3.9 | )% | ||||||||||
Degree days % colder than normal (b) |
0.4 | % | 7.1 | % | | |
(a) | Total margin represents total revenues less total cost of sales. |
|
(b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (NOAA)
for airports located within Gas Utilitys service territory. |
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Temperatures in the Gas Utility service territory based upon heating degree days were
essentially normal in the 2009 three-month period compared with temperatures that were 7.1% colder than normal in the prior-year
period. Total distribution system throughput decreased 1.7 bcf in the 2009 three-month period
principally reflecting the effects of the warmer weather on core-market customers. Gas Utilitys
core-market customers are comprised of firm- residential, commercial and industrial (retail
core-market) customers who purchase their gas from Gas Utility and, to a much lesser extent,
residential and small commercial customers who purchase their gas from alternate suppliers.
Gas Utility revenues decreased $82.6 million during the 2009 three-month period principally
reflecting a decline in revenues from retail core-market customers and, to a much lesser extent,
lower revenues from low-margin off-system sales. The decrease in retail core-market revenues
principally resulted from lower average purchased gas cost (PGC) rates and lower retail
core-market volumes partially offset by the effects of the PNG Gas and CPG Gas base operating
revenue increases that became effective August 28, 2009. Under Gas Utilitys PGC recovery
mechanism, Gas Utility records the cost of gas associated with sales to retail core-market
customers at amounts included in PGC rates. The difference between actual gas costs and the amounts
included in rates is deferred on the balance sheet as a regulatory asset or liability and
represents amounts to be collected from or refunded to customers in a future period. As a result of
this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail
core-market customers have no direct effect on retail core-market margin. Gas Utilitys cost of gas
was $209.8 million in the 2009 three-month period compared with $293.0 million in the prior-year
period principally reflecting the lower average PGC rates and to a much lesser extent the lower
retail core-market and off-system sales.
Notwithstanding the decrease in core-market volumes, Gas Utility total margin increased
$0.6 million in the 2009 three-month period. The increase reflects the impact of the PNG Gas and
CPG Gas base operating revenue increases.
Gas Utility operating income during the 2009 three-month period increased $6.8 million principally
reflecting lower operating and administrative costs and the previously mentioned slight increase in
total margin. The 2009 three-month period operating and administrative costs include, among other
things, lower provisions for uncollectible accounts, lower charges associated with environmental
matters and lower UGI corporate allocated expenses. These decreases in operating and administrative
expenses were partially offset by higher pension
expense due in large part to the amortization of actuarial losses experienced by the pension plans
during Fiscal 2009. The increase in income before income taxes reflects the previously mentioned
higher operating income and lower interest expense associated with bank loan borrowings due to
lower average bank loan borrowings and lower average interest rates.
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Electric Utility:
Increase | ||||||||||||||||
For the three months ended December 31, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Revenues |
$ | 34.0 | $ | 35.9 | $ | (1.9 | ) | (5.3 | )% | |||||||
Total margin (a) |
$ | 10.7 | $ | 10.7 | $ | | 0.0 | % | ||||||||
Operating income |
$ | 5.4 | $ | 5.0 | $ | 0.4 | 8.0 | % | ||||||||
Income before income taxes |
$ | 5.0 | $ | 4.6 | $ | 0.4 | 8.7 | % | ||||||||
Distribution sales millions of
kilowatt hours (gwh) |
242.4 | 252.8 | (10.4 | ) | (4.1 | )% |
(a) | Total margin represents total revenues less total cost of sales and revenue-related taxes,
i.e. Electric Utility gross receipts taxes, of $1.9 million and $2.0 million during the
three-month periods ended December 31, 2009 and 2008, respectively. For financial statement
purposes, revenue-related taxes are included in Utility taxes other than income taxes on the
Condensed Consolidated Statements of Income. |
Electric Utilitys kilowatt-hour sales in the 2009 three-month period were lower than in the
prior year. The decline in sales principally reflects lower sales to commercial and industrial
customers as a result of the deterioration in general economic activity over the last year and the
effects of a warmer 2009 three-month period on heating-related sales volumes. Temperatures based
upon heating degree days were approximately 3.9% warmer than in the prior-year period. Electric
Utility revenues decreased $1.9 million principally as a result of the lower sales partially offset
by slightly higher Provider of Last Resort (POLR) revenues. Electric Utility increased its POLR
rates effective January 1, 2009, which increased the average cost to a residential heating customer
by approximately 1.5% over such costs in effect during calendar year 2008. Electric Utility cost of
sales declined to $21.5 million in the 2009 three-month period compared to $23.2 million in the
2008 three-month period principally reflecting the effects of the lower volume sales and changes in
the fair value of FTRs partially offset by higher transmission costs.
Electric Utility total margin was equal to the prior year, notwithstanding the decrease in
revenues, principally reflecting the lower total cost of sales and slightly lower gross receipts
taxes.
Electric Utility operating income and income before income taxes in the 2009 three-month period
were $0.4 million higher than such amounts in the prior-year period reflecting lower distribution
system maintenance and uncollectible accounts expenses.
Energy Services:
Increase | ||||||||||||||||
For the three months ended December 31, | 2009 | 2008 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Revenues |
$ | 312.3 | $ | 359.1 | $ | (46.8 | ) | (13.0 | )% | |||||||
Total margin (a) |
$ | 41.0 | $ | 32.4 | $ | 8.6 | 26.5 | % | ||||||||
Operating income |
$ | 27.7 | $ | 18.2 | $ | 9.5 | 52.2 | % | ||||||||
Income before income taxes |
$ | 27.7 | $ | 18.2 | $ | 9.5 | 52.2 | % |
(a) | Total margin represents total revenues less total cost of sales. |
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Energy Services total revenues declined $46.8 million, notwithstanding a slight increase in
sales of natural gas, principally reflecting the effects on revenues of lower average unit sales
prices for natural gas partially offset by higher revenues from sales of electricity and propane
due to higher volumes sold and higher average unit sales prices.
Total margin from Energy Services increased $8.6 million principally reflecting a significant
increase in natural gas marketing margin resulting from 5% higher volumes sold and higher unit
margins, stronger peaking and asset management margins, and an increase in electric generation
total margin from 16% greater total sales volume and higher average unit margins. Electric
generation sales volumes increased primarily due to the absence of production facility outages
experienced in the prior-year period as well as additional sales from the Broad Mountain landfill
gas plant generation facility which commenced commercial operations in January 2009. The increases
in Energy Services operating income and income before income taxes largely reflects the previously
mentioned increase in total margin and lower electric generation operating and administrative costs
as the prior year included additional maintenance costs associated with the electric generation
production outages.
FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
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 proceeds from credit facilities or, in the case of Energy Services, a
receivables securitization facility. These facilities are further described below. Long-term cash
needs are generally met through issuance of long-term debt or equity securities.
Our cash and cash equivalents, excluding cash in commodity futures brokerage accounts restricted
from withdrawal, totaled $215.6 million at December 31, 2009 compared with $280.1 million at
September 30, 2009. Excluding cash and cash equivalents that reside at UGIs operating
subsidiaries, at December 31, 2009 and September 30, 2009, UGI had $98.6 million and $102.7
million, respectively, of cash and cash equivalents.
The Companys debt outstanding at December 31, 2009 totaled $2,339.3 million (including current
maturities of long-term debt of $94.6 million) compared to $2,296.2 million of debt outstanding
(including current maturities of long-term debt of $94.5 million) at September 30, 2009. Total debt
outstanding at December 31, 2009 consists of $890.9 million of Partnership
debt, $615.8 million (430.1 million) of International Propane debt, $819 million of UGI
Utilities debt, and $13.6 million of other debt.
AmeriGas Partners total debt at December 31, 2009 includes long-term debt comprising
$779.7 million of AmeriGas Partners Senior Notes, $80.0 million of AmeriGas OLP First Mortgage
Notes and $7.2 million of other long-term debt. At December 31, 2009, there were $24 million of
AmeriGas OLP bank loan borrowings outstanding.
International Propanes total debt at December 31, 2009 includes long-term debt principally
comprising $544.0 million (380 million) outstanding under Antargaz Senior Facilities term loan
and a combined $52.0 million (36.3 million) outstanding under Flagas two term loans. Total
International Propane debt outstanding at December 31, 2009 also includes combined borrowings of
$16.5 million (11.5 million) outstanding under Flagas working capital facilities and
$3.3 million (2.3 million) of other long-term debt.
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UGI Utilities total debt at December 31, 2009 includes long-term debt comprising $383 million of
Senior Notes and $257 million of Medium-Term Notes. Total debt outstanding at December 31, 2009
also includes $179 million outstanding under UGI Utilities Revolving Credit Agreement.
As previously mentioned, as a result of the adoption of new accounting guidance, noncontrolling
interests in our consolidated subsidiaries, principally AmeriGas Partners, L.P., are now reflected
in equity on our consolidated balance sheets. The new classification of noncontrolling interests in
equity had the effect of decreasing the Company ratio of debt to total equity for all periods
presented.
AmeriGas Partners. In order to meet its short-term cash needs, AmeriGas OLP has a $200 million
credit agreement (Credit Agreement) which expires on October 15, 2011. AmeriGas OLP also has a
$75 million unsecured revolving credit facility (2009 AmeriGas Supplemental Credit Agreement)
with three major banks. AmeriGas OLPs Credit Agreement consists of (1) a $125 million Revolving
Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be
used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides
AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane
businesses or propane business assets or, to the extent it is not so used, for working capital and
general purposes. The 2009 AmeriGas Supplemental Credit Agreement expires on July 1, 2010 and
permits AmeriGas OLP to borrow up to $75 million for working capital and general purposes.
At December 31, 2009, there were $24 million of borrowings outstanding under the Credit Agreement
and no amounts outstanding under the 2009 AmeriGas Supplemental Credit Agreement. Issued and
outstanding letters of credit under the Revolving Credit Facility, which reduce the amount
available for borrowings, totaled $36.1 million at December 31, 2009. AmeriGas OLPs short-term
borrowing needs are seasonal and are typically greatest during the fall and winter heating-season
months due to the need to fund higher levels of working capital. The average daily and peak bank
loan borrowings outstanding under the AmeriGas OLP credit agreements during the three months ended
December 31, 2009 were $13.2 million and $48.0 million, respectively. The average daily and peak
bank loan borrowings outstanding under AmeriGas OLP credit agreements during the three months ended
December 31, 2008 were $131.8 million and $184.5 million, respectively. The higher average and peak
bank loan
borrowings in the prior-year three-month period resulted from the need to fund counterparty cash
collateral obligations associated with derivative financial instruments used by the Partnership to
manage market price risk associated with fixed sales price commitments to customers. These
collateral obligations resulted from the precipitous decline in propane commodity prices that
occurred in early Fiscal 2009. At December 31, 2009, the Partnerships available borrowing capacity
under the credit agreements was $214.9 million.
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AmeriGas Partners expects to issue $150 million of long-term debt during the summer of 2010. The
proceeds from the issuance of such long-term debt is expected to be used to repay $80 million of
maturing AmeriGas OLP Series E First Mortgage Notes and for general Partnership purposes.
Based on existing cash balances, cash expected to be generated from operations, borrowings
available under AmeriGas OLPs credit agreements and the previously mentioned issuance of AmeriGas
Partners long-term debt, the Partnerships management believes that the Partnership will be able
to meet its anticipated contractual commitments and projected cash needs during Fiscal 2010.
International Propane. Antargaz has a Senior Facilities Agreement that expires on March 31, 2011.
The Senior Facilities Agreement consists of (1) a 380 million variable-rate term loan and (2) a
50 million revolving credit facility. Antargaz has executed interest rate swap agreements to
fix the underlying euribor or libor rate for the duration of the term loan. Antargaz had no amounts
outstanding under the revolving credit facility at December 31, 2009.
Flaga has two working capital facilities totaling 24 million. Flaga has a multi-currency
working capital facility that provides for borrowings and issuances of guarantees totaling 16
million of which 9.4 million ($13.5 million) was outstanding at December 31, 2009. Flaga also
has an 8 million euro-denominated working capital facility of which 2.1 million ($3.0
million) was outstanding at December 31, 2009. Issued and outstanding guarantees, which reduce
available borrowings under the working capital facilities, totaled 4.4 million ($6.3 million)
at December 31, 2009. Amounts outstanding under the working capital facilities are classified as
bank loans. During the 2009 three-month period, average and peak bank loan borrowings totaled
9.9 million and 11.6 million, respectively.
UGI Utilities. UGI Utilities may borrow up to a total of $350 million under its Revolving Credit
Agreement which expires in August 2011. At December 31, 2009, UGI Utilities had $179 million of
borrowings outstanding under its Revolving Credit Agreement. Borrowings under its Revolving Credit
Agreement are classified as bank loans on the Condensed Consolidated Balance Sheets. During the
2009 and 2008 three-month periods, average daily bank loan borrowings were $161.2 million and
$242.8 million, respectively, and peak bank loan borrowings totaled $203 million and $304 million,
respectively. Peak bank loan borrowings typically occur during the heating season months of
December and January. During the prior-year three month period ended December 31, 2008, average
daily and peak bank loan borrowings were higher than the current year due in large part to higher
margin deposits associated with natural gas futures accounts resulting from a decline in wholesale
natural gas prices.
Energy Services. Energy Services has a $200 million receivables purchase facility (Receivables
Facility) with an issuer of receivables-backed commercial paper expiring in April 2010, although
the Receivables Facility may terminate prior to such date due to the
termination of commitments of the Receivables Facilitys back-up purchasers. Management expects it
will extend or replace the Receivables Facility prior to its termination date. Energy Services uses
the Receivables Facility to fund working capital, margin calls under commodity futures contracts
and capital expenditures.
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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 commercial paper conduit of a major bank.
ESFC was created and has been structured to isolate its assets from creditors of Energy Services
and its affiliates, including UGI. This two-step transaction is accounted for as a sale of
receivables following GAAP for accounting for transfers and servicing of financial assets and
extinguishments of liabilities. Energy Services continues to service, administer and collect trade
receivables on behalf of the commercial paper issuer and ESFC. During the three months ended
December 31, 2009 and 2008, Energy Services sold trade receivables totaling $296.7 million and
$358.4 million, respectively, to ESFC. During the three months ended December 31, 2009 and 2008,
ESFC sold an aggregate $120.2 million and $169.3 million, respectively, of undivided interests in
its trade receivables to the commercial paper conduit. At December 31, 2009, the outstanding
balance of ESFC receivables was $88.3 million which is net of $27.6 million that was sold to the
commercial paper conduit and removed from the balance sheet. At December 31, 2008, the outstanding
balance of ESFC receivables was $44.3 million which is net of $87.9 million that was sold to the
commercial paper conduit. During the three months ended December 31, 2008, sales of receivables by
ESFC to the commercial paper conduit were higher due in large part to the need to fund greater
levels of margin deposits in natural gas futures accounts resulting from a decline in wholesale
natural gas prices.
Cash Flows
Due to the seasonal nature of the Companys 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 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 Companys investment in working capital, principally inventories and
accounts receivable, is generally greatest.
Operating Activities. Cash flow provided by operating activities was $17.1 million in the 2009
three-month period compared to $60.4 million of cash used by operating activities in the 2008
three-month period. Cash flow from operating activities before changes in operating working capital
was $227.3 million in the 2009 three-month period compared to $144.5 million of such cash flow in
the prior-year three-month period. The increase in the 2009 three-month period cash flow from
operating activities before changes in operating working capital reflects in large part the amounts
and the timing of recognition of gains (losses) on settled derivative commodity contracts. Changes
in operating working capital used $210.2 million of operating cash flow in the 2009 three-month
period compared to $204.9 million used in the 2008 three-month period. Cash flow from changes in
working capital in the 2008 three-month period benefited from the impact of the precipitous decline
in LPG prices on changes in accounts receivable and
inventories. However, the decline in LPG prices in the prior-year period required greater cash to
fund Partnership counterparty collateral deposits associated with product cost management activities. The lower
cash used for changes in accounts receivable in the 2008 three-month period also reflects greater
sales of receivables by ESFC under its Receivables Facility to fund natural gas futures margin
deposits.
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UGI CORPORATION AND SUBSIDIARIES
Investing Activities. Cash flow used in investing activities was $92.5 million in the 2009
three-month period compared with $376.8 million of cash used in the prior-year period. The
significantly higher cash used in investing activities in the prior year principally reflects the
net cash used for the CPG Acquisition. Cash flows from investing activities in the prior year
include $42.4 million of cash proceeds from the sale of the Partnerships California LPG storage
facility. Increases in restricted cash for futures brokerage accounts were lower in the 2009
three-month period as the prior-year period margin deposits were impacted by a decline in natural
gas prices. Cash used by investing activities in the 2009 three-month period includes $11.0 million
of cash invested in a limited partnership that focuses on the alternative energy sector.
Financing
Activities. Cash flow provided by financing activities was $13.1 million in the 2009
three-month period compared with $373.7 million in the prior-year period. Cash flow from financing
activities in the 2009 three-month period includes seasonal increases in bank loan borrowings at
the Partnership, Flaga and UGI Utilities to fund seasonal increases in working capital. Cash flow
from financing activities in the 2008 three-month period principally reflects the issuance of
$108 million of UGI Utilities Senior Notes to fund a portion of the October 1, 2008 acquisition
of CPG and increases in UGI Utilities bank loans principally to fund a portion of the CPG
acquisition and natural gas brokerage accounts margin deposits. The prior year also includes
higher Partnership bank loan borrowings to fund counterparty collateral deposits.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 International Propane
operations pay for LPG is principally a result of market forces reflecting changes in supply and
demand for propane 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
International Propane may not, however, always be able to pass through product cost increases fully
or on a timely basis, 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
instruments including price swap and option contracts. In addition, Antargaz hedges a portion of
its future U.S. dollar denominated LPG product purchases through the use of forward foreign
exchange contracts. Antargaz has used over-the-counter derivative
commodity instruments and may from time-to-time enter into other derivative contracts, similar to
those used by the Partnership. Flaga has used and may use derivative commodity instruments to
reduce market risk associated with a portion of its LPG purchases. Over-the-counter derivative
commodity instruments utilized to hedge forecasted purchases of propane are generally settled at
expiration of the contract.
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UGI CORPORATION AND SUBSIDIARIES
Gas Utilitys tariffs contain clauses that permit recovery of all of the prudently incurred costs
of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment
for the difference between the total amounts actually collected from customers through PGC rates
and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited
commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative
financial instruments comprising futures contracts traded on the New York Mercantile Exchange
(NYMEX) to reduce volatility in the cost of gas it purchases for its retail core-market
customers. The cost of these derivative financial instruments, net of any associated gains or
losses, is included in Gas Utilitys PGC recovery mechanism.
Electric Utility purchases its electric power needs from electricity suppliers under fixed-price
energy contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity
can be volatile especially during periods of high demand or tight supply. Electric Utility has
diversified its purchases across several suppliers and entered into bilateral collateral
arrangements with certain of them. Changes in electricity prices could require Electric Utility to
provide cash collateral to its supply counterparties. Electric Utility obtains financial
transmission rights (FTRs) through an annual PJM Interconnection (PJM) auction process and, to
a lesser extent, by purchases at monthly PJM auctions. FTRs are financial instruments that entitle
the holder to receive compensation for electricity transmission congestion charges that result when
there is insufficient electricity transmission capacity on the electricity transmission grid. PJM
is a regional transmission organization that coordinates the movement of wholesale electricity in
all or parts of 14 eastern and midwestern states. On January 22, 2009, the PUC approved a
settlement of a rate filing that provides for Electric Utility to fully recover its default service
costs. Because of this default service ratemaking, beginning January 1, 2010, there is limited
electricity price and transmission congestion price risk associated with Electric Utility.
Energy Services purchases FTRs to economically hedge certain transmission costs that may be
associated with its fixed-price electricity sales contracts. Although Energy Services FTRs are
economically effective as hedges of congestion charges, they do not currently qualify for hedge
accounting treatment.
In order to manage market price risk relating to substantially all of Energy Services fixed-price
sales contracts for natural gas, Energy Services purchases over-the-counter and exchange-traded
natural gas futures contracts or enters into fixed-price supply arrangements. Energy Services
exchange-traded natural gas and electricity futures contracts are traded on the NYMEX and have
nominal credit risk. Although Energy Services fixed-price supply arrangements mitigate most risks
associated with its fixed-price sales contracts, should any of the natural gas suppliers under
these arrangements fail to perform, increases, if any, in the cost of replacement natural gas would
adversely impact Energy Services results. In order to reduce this risk of supplier nonperformance,
Energy Services has diversified its purchases across a number of suppliers.
Energy Services has entered into and may continue to enter into fixed-price sales agreements for a
portion of its propane sales. In order to manage the market price risk relating to substantially
all of its fixed-price sales contracts for propane, Energy Services enters into price swap and
option contracts.
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UGI CORPORATION AND SUBSIDIARIES
UGID 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, UGID
would be required to purchase such electricity on the spot market or under contract with other
electricity suppliers. Accordingly, increases in the cost of replacement power could negatively
impact the Companys results.
Because our business units have product cost management programs with contracts that include
collateral and margin deposit requirement provisions, rapid declines in natural gas and LPG product
costs can require our business units to post cash collateral with counterparties or make margin
deposits in brokerage accounts.
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 their fair value. Conversely, changes in interest
rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt includes borrowings under AmeriGas OLPs credit agreements, UGI Utilities
Revolving Credit Agreement and a substantial portion of Antargaz and Flagas debt. These debt
agreements have interest rates that are generally indexed to short-term market interest rates.
Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt
through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial
portion of its term loans through their scheduled maturity dates through the use of interest rate
swaps. At December 31, 2009 combined borrowings outstanding under these agreements, excluding
Antargaz and Flagas effectively fixed-rate debt, totaled approximately $221.4 million.
Our long-term debt associated with our domestic businesses is typically issued at fixed rates of
interest based upon market rates for debt having similar terms and credit ratings. As these
long-term debt issues mature, we 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.
Foreign Currency Exchange Rate Risk
Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The
U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in
the associated foreign currency exchange rates. We use derivative instruments to hedge portions of
our net investments in foreign subsidiaries (net investment hedges). Realized gains or losses
remain in accumulated other comprehensive income until such foreign operations are liquidated. At
December 31, 2009, the fair value of unsettled net investment hedges was a loss of $2.4 million,
which is included in foreign currency exchange rate risk in the table below. With respect to our
net investments in Flaga and Antargaz, a 10% decline in the value of the euro versus the U.S.
dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book
value by approximately $63.1 million, which amount would be reflected in other comprehensive
income.
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UGI CORPORATION AND SUBSIDIARIES
The following table summarizes the fair values of unsettled market risk sensitive derivative
instruments assets and (liabilities) held at December 31, 2009. The table also includes the changes
in fair value that would result if there were a 10% adverse change in (1) the market price of LPG,
gasoline, natural gas, electricity and electricity transmission congestion charges; (2) the
three-month LIBOR and the three- and nine-month Euribor; and (3) the value of the euro versus the
U.S. dollar. The fair value of Gas Utilitys exchange-traded natural gas futures contracts
(comprising losses of $0.1 million at December 31, 2009), and the fair value of Electric Utilitys
FTRs (comprising gains of $0.6 million at December 31, 2009), 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.
Asset (Liability) | ||||||||
Change in | ||||||||
(Millions of dollars) | Fair Value | Fair Value | ||||||
December 31, 2009: |
||||||||
LPG commodity price risk |
$ | 38.2 | $ | (12.3 | ) | |||
FTR price risk |
1.5 | (0.1 | ) | |||||
Natural gas commodity price risk |
(6.1 | ) | (13.4 | ) | ||||
Gasoline commodity price risk |
0.2 | (0.1 | ) | |||||
Electricity commodity price risk |
(2.3 | ) | (2.4 | ) | ||||
Interest rate risk |
(25.1 | ) | (6.1 | ) | ||||
Foreign currency exchange rate risk |
(2.4 | ) | (13.6 | ) |
Because our derivative instruments, other than FTRs and gasoline futures contracts, generally
qualify as hedges under GAAP, we expect that changes in the fair value of derivative instruments
used to manage commodity, currency or interest rate market risk would be substantially offset by
gains or losses on the associated anticipated transactions.
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UGI CORPORATION AND SUBSIDIARIES
ITEM 4. CONTROLS AND PROCEDURES
(a) | Evaluation of Disclosure Controls and Procedures |
|
The Companys management, with the participation of the Companys Chief Executive Officer
and Chief Financial Officer, evaluated the effectiveness of the Companys disclosure
controls and procedures as of the end of the period covered by this report. Based on that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the
Companys disclosure controls and procedures as of the end of the period covered by this
report were designed and functioning effectively to provide reasonable assurance that the
information required to be disclosed by the Company in reports filed under the Securities
Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commissions rules and forms, and
(ii) accumulated and communicated to our management, including the Chief Executive Officer
and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. |
||
(b) | Change in Internal Control over Financial Reporting |
|
No change in the Companys internal control over financial reporting occurred during the
Companys most recent fiscal quarter that has materially affected, or is reasonably likely
to materially affect, the Companys internal control over financial reporting. |
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UGI CORPORATION AND SUBSIDIARIES
PART II OTHER INFORMATION
ITEM 1A. RISK FACTORS
In addition to the other information presented in this report, you should carefully consider the
factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the
fiscal year ended September 30, 2009, which could materially affect our business, financial
condition or future results. The risks described in our Annual Report on Form 10-K are not the
only risks facing the Company. Other unknown or unpredictable factors could also have material
adverse effects on future results.
ITEM 6. 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 last date of the period for which
it was filed, and the exhibit number in such filing):
Incorporation by Reference
Exhibit | ||||||||||||
No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
10.1 | Amendment 2009-1 to the UGI
Corporation
Supplemental
Executive
Retirement Plan and
Supplemental
Savings Plan as Amended and Restated effective
January 1, 2009 |
|||||||||||
10.2 | UGI Corporation
2009 Supplemental
Executive
Retirement Plan For New Employees |
|||||||||||
10.3 | AmeriGas Propane,
Inc. Supplemental
Executive
Retirement Plan as
Amended and
Restated Effective
January 1, 2009
|
AmeriGas Partners, L.P. | Form 10-Q (12/31/09) | 10.1 | ||||||||
31.1 | Certification by
the Chief Executive
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended December 31,
2009, pursuant to
Section 302 of the
Sarbanes-Oxley Act
of 2002 |
|||||||||||
31.2 | Certification by
the Chief Financial
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended December 31,
2009, pursuant to
Section 302 of the
Sarbanes-Oxley Act
of 2002 |
|||||||||||
32 | Certification by
the Chief Executive
Officer and the
Chief Financial
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended December 31,
2009, pursuant to
Section 906 of the
Sarbanes-Oxley Act
of 2002 |
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UGI CORPORATION AND SUBSIDIARIES
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
UGI Corporation (Registrant) |
||||
Date: February 5, 2010 | By: | /s/ Peter Kelly | ||
Peter Kelly | ||||
Vice President Finance and Chief Financial Officer |
||||
Date: February 5, 2010 | By: | /s/ Davinder Athwal | ||
Davinder Athwal | ||||
Vice President Accounting and Financial Control and Chief Risk Officer |
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UGI CORPORATION AND SUBSIDIARIES
EXHIBIT INDEX
10.1 | Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan
and Supplemental Savings Plan as Amended and Restated effective January 1, 2009. |
|
10.2 | UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees. |
|
31.1 | Certification by the Chief Executive Officer relating to the Registrants Report on Form 10-Q
for the quarter ended December 31, 2009, pursuant to Section 302 of the Sarbanes-Oxley Act of
2002. |
|
31.2 | Certification by the Chief Financial Officer relating to the Registrants Report on Form 10-Q
for the quarter ended December 31, 2009, pursuant to Section 302 of the Sarbanes-Oxley Act of
2002. |
|
32 | Certification by the Chief Executive Officer and the Chief Financial Officer relating to the
Registrants Report on Form 10-Q for the quarter ended December 31, 2009, pursuant to Section
906 of the Sarbanes-Oxley Act of 2002. |