Attached files
file | filename |
---|---|
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INC | c11716exv31w2.htm |
EX-32 - EXHIBIT 32 - UGI UTILITIES INC | c11716exv32.htm |
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INC | c11716exv31w1.htm |
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INC | c11716exv12w1.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, 2010
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 1-1398
UGI UTILITIES, INC.
(Exact name of registrant as specified in its charter)
Pennsylvania | 23-1174060 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) |
UGI UTILITIES, INC.
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(Registrants telephone number, including area code)
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(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 o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Indicate 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, 2011, there were 26,781,785 shares of UGI Utilities, Inc. Common
Stock, par value $2.25 per share, outstanding, all of which were held, beneficially and of record,
by UGI Corporation.
UGI UTILITIES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PAGES | ||||||||
1 | ||||||||
2 | ||||||||
3 | ||||||||
4 20 | ||||||||
21 25 | ||||||||
25 26 | ||||||||
26 27 | ||||||||
27 | ||||||||
27 | ||||||||
28 | ||||||||
29 | ||||||||
Exhibit 12.1 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32 |
-i-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
December 31, | September 30, | December 31, | ||||||||||
2010 | 2010 | 2009 | ||||||||||
ASSETS |
||||||||||||
Current assets: |
||||||||||||
Cash and cash equivalents |
$ | 11,646 | $ | 4,318 | $ | 12,678 | ||||||
Restricted cash |
3,884 | 4,698 | 656 | |||||||||
Accounts receivable (less allowances for doubtful accounts of $8,492,
$7,072 and $11,889, respectively) |
124,417 | 64,844 | 132,499 | |||||||||
Accounts receivable related parties |
12,347 | 6,313 | 8,417 | |||||||||
Accrued utility revenues |
75,284 | 13,988 | 84,395 | |||||||||
Inventories |
108,027 | 118,858 | 177,087 | |||||||||
Deferred income taxes |
21,593 | 19,431 | 27,162 | |||||||||
Regulatory assets |
10,633 | 26,100 | 10,344 | |||||||||
Derivative financial instruments |
2,750 | 486 | 874 | |||||||||
Prepaid expenses & other current assets |
5,648 | 21,117 | 4,590 | |||||||||
Total current assets |
376,229 | 280,153 | 458,702 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation and
amortization of $746,891, $734,739 and $703,722, respectively) |
1,399,042 | 1,394,585 | 1,365,441 | |||||||||
Goodwill |
180,145 | 180,145 | 180,145 | |||||||||
Regulatory assets |
236,221 | 280,602 | 121,646 | |||||||||
Other assets |
10,746 | 4,091 | 5,470 | |||||||||
Total assets |
$ | 2,202,383 | $ | 2,139,576 | $ | 2,131,404 | ||||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||||||
Current liabilities: |
||||||||||||
Bank loans |
$ | 74,000 | $ | 17,000 | $ | 179,000 | ||||||
Accounts payable trade |
68,328 | 61,297 | 70,845 | |||||||||
Accounts payable related parties |
8,494 | 8,144 | 6,424 | |||||||||
Deferred fuel refunds |
15,175 | 8,295 | 40,343 | |||||||||
Derivative financial instruments |
5,890 | 10,564 | 125 | |||||||||
Other current liabilities |
148,909 | 133,935 | 127,755 | |||||||||
Total current liabilities |
320,796 | 239,235 | 424,492 | |||||||||
Long-term debt |
640,000 | 640,000 | 640,000 | |||||||||
Deferred income taxes |
286,347 | 281,101 | 184,641 | |||||||||
Deferred investment tax credits |
5,222 | 5,311 | 5,579 | |||||||||
Pension and postretirement benefit obligations |
117,127 | 161,338 | 151,561 | |||||||||
Other noncurrent liabilities |
74,785 | 78,137 | 60,278 | |||||||||
Total liabilities |
1,444,277 | 1,405,122 | 1,466,551 | |||||||||
Commitments and contingencies (note 7) |
||||||||||||
Common stockholders equity: |
||||||||||||
Common Stock, $2.25 par value (authorized - 40,000,000 shares;
issued and outstanding - 26,781,785 shares) |
60,259 | 60,259 | 60,259 | |||||||||
Additional paid-in capital |
467,903 | 467,631 | 467,160 | |||||||||
Retained earnings |
234,758 | 217,960 | 219,487 | |||||||||
Accumulated other comprehensive loss |
(4,814 | ) | (11,396 | ) | (82,053 | ) | ||||||
Total common stockholders equity |
758,106 | 734,454 | 664,853 | |||||||||
Total liabilities and stockholders equity |
$ | 2,202,383 | $ | 2,139,576 | $ | 2,131,404 | ||||||
See accompanying notes to condensed consolidated financial statements.
-1-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
Three Months Ended | ||||||||
December 31, | ||||||||
2010 | 2009 | |||||||
Revenues |
$ | 350,516 | $ | 362,203 | ||||
Costs and expenses: |
||||||||
Cost of sales gas, fuel and purchased power
(excluding depreciation shown below) |
213,484 | 231,217 | ||||||
Operating and administrative expenses |
39,894 | 44,222 | ||||||
Operating and administrative expenses related parties |
2,925 | 1,192 | ||||||
Taxes other than income taxes |
4,358 | 4,528 | ||||||
Depreciation |
12,606 | 12,681 | ||||||
Amortization |
632 | 607 | ||||||
Other income, net |
(2,263 | ) | (1,517 | ) | ||||
271,636 | 292,930 | |||||||
Operating income |
78,880 | 69,273 | ||||||
Interest expense |
10,633 | 10,637 | ||||||
Income before income taxes |
68,247 | 58,636 | ||||||
Income taxes |
27,173 | 23,473 | ||||||
Net income |
$ | 41,074 | $ | 35,163 | ||||
See accompanying notes to condensed consolidated financial statements.
-2-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
Three Months Ended | ||||||||
December 31, | ||||||||
2010 | 2009 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 41,074 | $ | 35,163 | ||||
Adjustments to reconcile net income to net cash from operating activities: |
||||||||
Depreciation and amortization |
13,238 | 13,288 | ||||||
Deferred income taxes, net |
(2,260 | ) | 11,724 | |||||
Provision for uncollectible accounts |
3,161 | 4,845 | ||||||
Other, net |
2,560 | 2,180 | ||||||
Net change in: |
||||||||
Accounts receivable and accrued utility revenues |
(130,063 | ) | (131,512 | ) | ||||
Inventories |
10,832 | 19,511 | ||||||
Deferred fuel and power costs |
15,459 | 18,737 | ||||||
Accounts payable |
29,886 | 15,258 | ||||||
Storage agreements security deposits |
| 3,500 | ||||||
Other current assets |
3,546 | 570 | ||||||
Other current liabilities |
4,341 | 13,414 | ||||||
Net cash (used) provided by operating activities |
(8,226 | ) | 6,678 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Expenditures for property, plant and equipment |
(17,587 | ) | (13,810 | ) | ||||
Net costs of property, plant and equipment disposals |
(668 | ) | (671 | ) | ||||
Decrease (increase) in restricted cash |
814 | (656 | ) | |||||
Net cash used by investing activities |
(17,441 | ) | (15,137 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Payment of dividends |
(24,277 | ) | (17,386 | ) | ||||
Increase in bank loans |
57,000 | 25,000 | ||||||
Other |
272 | | ||||||
Net cash provided by financing activities |
32,995 | 7,614 | ||||||
Cash and cash equivalents increase (decrease) |
$ | 7,328 | $ | (845 | ) | |||
CASH AND CASH EQUIVALENTS: |
||||||||
End of period |
$ | 11,646 | $ | 12,678 | ||||
Beginning of period |
4,318 | 13,523 | ||||||
Increase (decrease) |
$ | 7,328 | $ | (845 | ) | |||
See accompanying notes to condensed consolidated financial statements.
-3-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
1. | Nature of Operations |
UGI Utilities, Inc. (UGI Utilities), a wholly owned subsidiary of UGI Corporation (UGI),
and UGI Utilities wholly owned subsidiaries UGI Penn Natural Gas, Inc. (PNG) and UGI
Central Penn Gas, Inc. (CPG) own and operate natural gas distribution utilities in
eastern, northeastern and central Pennsylvania. UGI Utilities also owns and operates an
electric distribution utility in northeastern Pennsylvania (Electric Utility). UGI
Utilities natural gas distribution utility is referred to as UGI Gas; PNGs natural gas
distribution utility is referred to as PNG Gas; and CPGs natural gas distribution utility
is referred to as CPG Gas. UGI Gas, PNG Gas and CPG Gas are collectively referred to as
Gas Utility. Gas Utility is subject to regulation by the Pennsylvania Public Utility
Commission (PUC) and the Maryland Public Service Commission, and Electric Utility is
subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred
to as Utilities. PNG also has a heating, ventilation and air-conditioning service business
(UGI Penn HVAC Services, Inc.) which operates principally in the PNG Gas service
territory. |
The term UGI Utilities is used sometimes as an abbreviated reference to UGI
Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG. |
2. | Significant Accounting Policies |
Basis of Presentation. Our condensed consolidated financial statements include the accounts
of UGI Utilities and its subsidiaries (collectively, we or the Company). We eliminate
all significant intercompany accounts when we consolidate. |
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, 2010 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, 2010 (Companys 2010
Annual Financial Statements and Notes). 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. |
-4-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Comprehensive Income. The following table presents the components of comprehensive income
for the three months ended December 31, 2010 and 2009: |
Three Months Ended | ||||||||
December 31, | ||||||||
2010 | 2009 | |||||||
Net income |
$ | 41,074 | $ | 35,163 | ||||
Other comprehensive income |
6,582 | 1,033 | ||||||
Comprehensive income |
$ | 47,656 | $ | 36,196 | ||||
Other comprehensive income principally reflects net gains on interest rate protection
agreements qualifying as cash flow hedges in the 2010 three month period and actuarial gains
and losses on postretirement benefit plans, net of reclassifications to net income. |
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that
it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were
required to remeasure the merged plans assets and benefit obligations as of December 31,
2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other
things, the remeasurement resulted in an
after-tax increase in other comprehensive income of $2,170 for the three months ended
December 31, 2010 (see Notes 5 and 6). |
Restricted Cash. Restricted cash represents those cash balances in our commodity futures and
option brokerage accounts which are restricted from withdrawal. |
Use of Estimates. The preparation of financial statements in accordance with GAAP requires
management to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues, expenses and costs. These estimates are based on managements
knowledge of current events, historical experience and various other assumptions that are
believed to be reasonable under the circumstances. Accordingly, actual results may be
different from these estimates and assumptions. |
3. | Segment Information |
We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric
Utility. Gas Utility revenues are derived principally from the sale and distribution of
natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility
derives its revenues principally from the sale and distribution of electricity in two
northeastern Pennsylvania counties. UGI Penn HVAC Services, Inc. does not meet the
quantitative thresholds for separate segment reporting under GAAP relating to business
segment reporting and has been included in Other. |
The accounting policies of our reportable segments are the same as those described in Note 2
of the Companys 2010 Annual Financial Statements and Notes. We evaluate the performance of our Gas Utility and
Electric Utility segments principally based upon their income before income taxes. |
-5-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
No single customer represents more than ten percent of our consolidated revenues and there
are no significant intersegment transactions. In addition, all of our reportable segments
revenues are derived from sources within the United States and all of our reportable
segments long-lived assets are located in the United States. |
Financial information by business segment follows: |
Three Months Ended December 31, 2010: |
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 350,516 | $ | 321,114 | $ | 28,940 | $ | 462 | ||||||||
Cost of sales |
$ | 213,484 | $ | 194,913 | $ | 18,571 | $ | | ||||||||
Depreciation and amortization |
$ | 13,238 | $ | 12,225 | $ | 1,013 | $ | | ||||||||
Operating income |
$ | 78,880 | $ | 75,067 | $ | 3,603 | $ | 210 | ||||||||
Interest expense |
$ | 10,633 | $ | 10,108 | $ | 525 | $ | | ||||||||
Income before income taxes |
$ | 68,247 | $ | 64,959 | $ | 3,078 | $ | 210 | ||||||||
Total assets (at period end) |
$ | 2,202,383 | $ | 2,061,337 | $ | 141,046 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 17,587 | $ | 16,086 | $ | 1,501 | $ | |
Three Months Ended December 31, 2009: |
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 362,203 | $ | 327,809 | $ | 33,999 | $ | 395 | ||||||||
Cost of sales |
$ | 231,217 | $ | 209,760 | $ | 21,457 | $ | | ||||||||
Depreciation and amortization |
$ | 13,288 | $ | 12,299 | $ | 989 | $ | | ||||||||
Operating income |
$ | 69,273 | $ | 63,728 | $ | 5,359 | $ | 186 | ||||||||
Interest expense |
$ | 10,637 | $ | 10,246 | $ | 391 | $ | | ||||||||
Income before income taxes |
$ | 58,636 | $ | 53,482 | $ | 4,968 | $ | 186 | ||||||||
Total assets (at period end) |
$ | 2,131,404 | $ | 2,015,558 | $ | 115,846 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 13,810 | $ | 13,040 | $ | 770 | $ | |
4. | Inventories |
Inventories comprise the following: |
December 31, | September 30, | December 31, | ||||||||||
2010 | 2010 | 2009 | ||||||||||
Gas Utility natural gas |
$ | 100,121 | $ | 111,531 | $ | 170,235 | ||||||
Materials, supplies and other |
7,905 | 7,327 | 6,852 | |||||||||
Total inventories |
$ | 108,026 | $ | 118,858 | $ | 177,087 | ||||||
-6-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
At December 31, 2010, UGI Utilities is a party to three storage contract administrative
agreements (SCAAs) two of which expire in October 2012 and one of which expires in October
2013 (see Note 8). Pursuant to these and predecessor SCAAs, UGI Utilities has, among other
things, released certain storage and transportation contracts for the terms of the SCAAs.
UGI Utilities also transferred certain associated storage inventories upon commencement of
the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes
payments associated with refilling storage inventories during the terms of the SCAAs. The
historical cost of natural gas storage inventories released under the SCAAs, which
represents a portion of Gas 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 the SCAAs at December 31, 2010,
September 30, 2010 and December 31, 2009 comprising 11.1 billion cubic feet (bcf), 11.7
bcf, and 11.4 bcf of natural gas, was $58,363, $62,653 and $95,911, respectively. In
conjunction with the SCAAs, at December 31, 2010, September 30, 2010 and December 31, 2009,
UGI Utilities held a total of $22,500 of security deposits received from its SCAA
counterparties. These amounts are included in other current liabilities on the Condensed
Consolidated Balance Sheets. |
5. | Regulatory Assets and Liabilities and Regulatory Matters |
For a description of the Companys regulatory assets and liabilities other than those
described below, see Note 5 to the Companys 2010 Annual
Financial Statements and Notes. 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, | ||||||||||
2010 | 2010 | 2009 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 83,601 | $ | 82,525 | $ | 80,524 | ||||||
Underfunded pension and
postretirement plans |
116,288 | 159,154 | 10,908 | |||||||||
Environmental costs |
22,515 | 22,587 | 25,812 | |||||||||
Deferred fuel and power costs |
18,113 | 36,597 | 10,344 | |||||||||
Other |
6,337 | 5,839 | 4,402 | |||||||||
Total regulatory assets |
$ | 246,854 | $ | 306,702 | $ | 131,990 | ||||||
Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 10,835 | $ | 10,472 | $ | 9,538 | ||||||
Environmental overcollections |
6,990 | 7,211 | 8,392 | |||||||||
Deferred fuel and power refunds |
15,175 | 8,298 | 40,343 | |||||||||
State tax benefits
distribution system repairs |
6,716 | 6,685 | | |||||||||
Total regulatory liabilities |
$ | 39,716 | $ | 32,666 | $ | 58,273 | ||||||
-7-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Underfunded pension and postretirement plans. This regulatory asset represents the
portion of prior service cost and net actuarial losses associated with pension and
postretirement benefits which is probable of being recovered through future rates based upon
established regulatory practices. These regulatory assets are adjusted annually or more
frequently under certain circumstances when the funded status of the plans is recorded in
accordance with GAAP relating to accounting for retirement benefits. These costs are
amortized over the average remaining future service lives of the plan participants. |
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that
it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were
required to remeasure the merged plans assets and benefit obligations as of December 31,
2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other
things, the remeasurement resulted in a decrease in regulatory assets
of $42,962 (see Note
6). |
Deferred fuel and power costs and refunds. Gas Utilitys tariffs and, commencing January
1, 2010 Electric Utilitys default service tariffs, contain clauses which permit recovery of
all prudently incurred purchased gas and power costs through the application of purchased
gas cost (PGC) rates in the case of Gas Utility and default service (DS) rates in the
case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates
for differences between the total amount of purchased gas and electric generation supply
costs collected from customers and recoverable costs incurred. Net undercollected costs are
classified as a regulatory asset and net overcollections are classified as a regulatory
liability. |
Gas Utility uses derivative 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 costs or refunds. Unrealized gains (losses) on such contracts at
December 31, 2010, September 30, 2010 and December 31, 2009 were $2,214, $(1,359) and
$(125), respectively. |
Electric Utility enters into forward electricity purchase contracts to meet a substantial
portion of its electricity supply needs. As more fully described in Note 10, during Fiscal
2010, Electric Utility determined that it could no longer assert that it would take physical
delivery of substantially all of the electricity it had contracted for under its forward
power purchase agreements and, as a result, such contracts no longer qualified for the
normal purchases and normal sales exception under GAAP related to derivative financial
instruments. As a result, Electric Utilitys electricity supply contracts are required to be
recorded on the balance sheet at fair value, with an associated adjustment to regulatory
assets or liabilities in accordance with GAAP relating to rate-regulated entities and
Electric Utilitys DS procurement, implementation and contingency plans. At December 31,
2010 and September 30, 2010, the fair values of Electric Utilitys electricity supply
contracts were losses of $13,369 and $19,702, respectively, which amounts are reflected in
current derivative financial instrument liabilities and other noncurrent liabilities on the
Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in
deferred fuel and power costs in the table above. |
-8-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
In order to reduce volatility associated with a substantial portion of its electric
transmission congestion costs, Electric Utility obtains financial transmission rights
(FTRs). FTRs are derivative financial instruments that entitle the holder to receive
compensation for electricity transmission congestion
charges when there is insufficient electricity transmission capacity on the electric
transmission grid. Because Electric Utility is entitled to fully recover its DS costs
commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs
associated with periods beginning January 1, 2010 are included in deferred fuel and power
costs or refunds. Unrealized gains on FTRs at December 31, 2010 and 2009 were not material. |
Other Regulatory Matters |
Approval of Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy
Regulatory Commission (FERC) approved CPGs application to abandon a storage service and
approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along
with related assets, to UGI Storage Company, a subsidiary of UGI Energy Services, Inc.
(Energy Services), a second-tier wholly owned subsidiary of UGI. CPG will transfer the
natural gas storage facilities on April 1, 2011. The net book value of the storage facility
assets was approximately $11,000 as of December 31, 2010. |
Subsequent Event CPG Base Rate Filing. On January 14, 2011, CPG filed a request
with the PUC to increase its base operating revenues by $16,500 annually. The increased revenues
would fund system improvements and operations necessary to maintain safe and reliable
natural gas service and fund new programs that would provide rebates and other incentives
for customers to install new high-efficiency equipment. CPG is requesting that the new gas
rates become effective March 15, 2011. However, the PUC typically suspends the effective
date for general base rate proceedings to allow for investigation and public hearings. This
review process is expected to last approximately nine months, which would delay
implementation of the new rates until late October 2011. |
6. | Defined Benefit Pension and Other Postretirement Plans |
Subsequent to the December 31, 2010 plan merger described below, we currently sponsor one
defined benefit pension plan (Pension Plan) for employees hired prior to January 1, 2009
of UGI Utilities, PNG, CPG, UGI and certain of UGIs other wholly owned domestic
subsidiaries. In addition, we provide postretirement health care benefits to certain
retirees and a limited number of active employees, and postretirement life insurance
benefits to nearly all active and retired employees. |
-9-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Net periodic pension expense and other postretirement benefit costs relating to our
employees include the following components: |
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Service cost |
$ | 1,925 | $ | 1,745 | $ | 54 | $ | 40 | ||||||||
Interest cost |
5,355 | 5,284 | 182 | 212 | ||||||||||||
Expected return on assets |
(6,022 | ) | (5,858 | ) | (130 | ) | (126 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost (benefit) |
62 | 9 | (174 | ) | (102 | ) | ||||||||||
Actuarial loss |
2,128 | 1,333 | 121 | 89 | ||||||||||||
Net benefit cost |
3,448 | 2,513 | 53 | 113 | ||||||||||||
Change in associated
regulatory liabilities |
| | 785 | 736 | ||||||||||||
Net expense |
$ | 3,448 | $ | 2,513 | $ | 838 | $ | 849 | ||||||||
Pension Plan assets are held in trust and consist principally of publicly traded,
diversified equity and fixed income mutual funds and UGI Common Stock. It is our general
policy to fund amounts for pension benefits equal to at least the minimum contribution
required by ERISA. Based upon current assumptions, the Company estimates that it will be
required to contribute approximately $20,303 to the Pension Plan during the next twelve
months. UGI Utilities has established a Voluntary Employees Beneficiary Association
(VEBA) trust to 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. The difference between such amounts
calculated under GAAP and the amounts included in UGI Gas and Electric Utilitys rates is
deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA
by UGI Utilities were not material during the three months ended December 31, 2010, nor are
they expected to be material for all of Fiscal 2011. |
We also participate in an unfunded and non-qualified defined benefit supplemental executive
retirement plan. Net benefit costs associated with this plan for all periods presented were
not material. |
Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The
merged plan will maintain separate benefit formulas and specific rights and features of each
predecessor plan. As a result of the merger and in accordance with GAAP relating to
accounting for retirement benefits, the Company remeasured the combined plans assets and
benefit obligations as of December 31, 2010 which decreased pension and postretirement
benefit obligations by $46,672; decreased associated regulatory assets by $42,962; and
increased pre-tax other comprehensive income by $3,710 (see Notes 2 and 5). |
-10-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
The following table provides a reconciliation of the projected benefit obligation (PBO),
plan assets and the funded status of the merged Pension Plan as of December 31, 2010: |
Three Months | ||||
Ended | ||||
December 31, | ||||
2010 | ||||
Change in benefit obligations: |
||||
Benefit obligations October 1, 2010 |
$ | 464,976 | ||
Service cost |
2,188 | |||
Interest cost |
5,805 | |||
Actuarial gain |
(30,639 | ) | ||
Benefits paid |
(4,664 | ) | ||
Benefit obligations December 31, 2010 |
$ | 437,666 | ||
Change in plan assets: |
||||
Fair value of plan assets October 1, 2010 |
$ | 287,902 | ||
Actual gain on assets |
19,285 | |||
Employer contribution |
1,788 | |||
Benefits paid |
(4,664 | ) | ||
Fair value of plan assets December 31, 2010 |
$ | 304,311 | ||
Funded status of the merged plan December 31, 2010 |
$ | (133,355 | ) | |
Liabilities recorded in the balance sheet: |
||||
Unfunded liabilities included in other current liabilities |
$ | (20,303 | ) | |
Unfunded liabilities included in other noncurrent liabilities |
(113,052 | ) | ||
Net amount recognized |
$ | (133,355 | ) | |
Amounts recorded in regulatory assets and liabilities: |
||||
Prior service cost |
$ | 257 | ||
Net actuarial loss |
112,733 | |||
Total |
$ | 112,990 | ||
Amounts recorded in stockholders equity: |
||||
Prior service cost |
$ | 29 | ||
Net actuarial loss |
9,925 | |||
Total |
$ | 9,954 | ||
The accumulated benefit obligation (ABO) of the merged plan at December 31, 2010 is
$391,192. Actuarial assumptions for the merged plan at December 31, 2010 are as follows:
discount rate 5.5%; expected return on plan assets 8.5%; rate of increase in salary
levels 3.8%. |
7. | Commitments and Contingencies |
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. |
-11-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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, 2010,
neither the undiscounted nor the accrued liability for environmental investigation and
cleanup costs for UGI Gas was material. |
UGI Utilities has been notified of several sites outside Pennsylvania on which private
parties allege MGPs were formerly owned or operated by it or owned or operated by its former
subsidiaries. Such parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating three claims
against it relating to out-of-state sites. |
Management believes that under applicable law UGI Utilities should not be liable in those
instances in which a former subsidiary owned or operated an MGP. There could be, however,
significant future costs of an uncertain amount associated with environmental damage caused
by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or
operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the
subsidiarys separate corporate form should be disregarded or (2) UGI Utilities should be
considered to have been an operator because of its conduct with respect to its subsidiarys
MGP. |
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South
Carolina Electric & Gas Company (SCE&G), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from
1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI
Utilities controlled operations of the plant from 1910 to 1926 and is liable for
approximately 25% of the costs associated with the site. SCE&G asserts that it has spent
approximately $22,000 in remediation costs and paid $26,000 in third-party claims
relating to the site and estimates that future response costs, including a claim by the
United States Justice Department for natural resource damages, could be as high as $14,000.
Trial took place in March 2009 and the courts decision is pending. |
-12-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens
Communications Company, now known as Frontier Communications Company (Frontier), served a
complaint naming UGI Utilities as a third-party defendant in a civil action pending in the
United States District Court for the District of Maine. In that action, the City of Bangor,
Maine (City) sued Frontier to recover environmental response costs associated with MGP
wastes generated at a plant allegedly operated by Frontiers predecessors at a site on the
Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party
defendants alleging that the third-party defendants are responsible for an equitable share
of any costs Frontier would be required to pay to the City for cleaning up tar deposits in
the Penobscot River. Frontier alleged that through ownership and control of a subsidiary,
Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant
from 1901 to 1928. Frontier made similar allegations of control against another third-party
defendant, CenterPoint Energy Resources Corporation (CenterPoint), whose predecessor owned
the Bangor subsidiary from 1928 to 1944. Frontiers third-party claims were stayed pending a
resolution of the Citys suit against Frontier, which was tried in September 2005. On June
27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup
costs, which were estimated at $18,000. On February 14, 2007, Frontier and the City entered
into a settlement agreement pursuant to which Frontier agreed to pay $7,600. The Citys suit
was dismissed, and Frontier 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 subsequently filed a
motion for summary judgment with respect to Frontiers claims and the court referred the
motion to a magistrate judge for findings and a recommendation. On October 19, 2010, the
magistrate judge entered an order recommending that the court grant UGI Utilities motion.
On November 19, 2010, the court affirmed the recommended decision of the magistrate judge
granting summary judgment in favor of UGI Utilities. |
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (KeySpan)
informed UGI Utilities that KeySpan has spent $2,300 and expects to spend another $11,000 to
clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is
responsible for approximately
50% of these costs as a result of UGI Utilities alleged direct ownership and operation of
the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New
York Department of Environmental Conservation has approved a remedy for the site that is
estimated to cost approximately $10,000. KeySpan believes that the cost could be as high as
$20,000. UGI Utilities is in the process of reviewing the information provided by KeySpan
and is investigating this claim. |
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities,
Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas
Services Company and Connecticut Light and Power Company, subsidiaries of Northeast
Utilities (together the Northeast Companies), in the United States District Court for the
District of Connecticut seeking contribution from UGI Utilities for past and future
remediation costs related to MGP operations on thirteen sites owned by the Northeast
Companies in nine cities in the State of Connecticut. The Northeast Companies allege that
UGI Utilities controlled operations of the plants from 1883 to 1941 through control of
former subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation
costs for all of the sites could total approximately $215,000 and asserted that UGI
Utilities is responsible for approximately $103,000 of this amount. The Northeast Companies
subsequently withdrew their claims with respect to three of the sites and UGI Utilities
acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease. In
April 2009, the court conducted a trial to determine whether UGI Utilities operated any of
the nine remaining sites that were owned and operated by former subsidiaries. On May 22,
2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites.
The Northeast Companies have appealed the decision. With respect to Waterbury North, the
Northeast Companies are expected to complete additional environmental investigations in
early 2011. A second phase of the trial is scheduled for August 2011 to determine what, if
any, contamination at Waterbury North is related to UGI Utilities period of operation. The
Northeast Companies previously estimated that remediation costs at Waterbury North could
total $25,000. |
-13-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
We cannot predict with certainty the final results of any of the environmental claims or
legal actions described above. However, it is reasonably possible that some of them could be
resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable
to estimate any possible losses in excess of recorded amounts. Although we currently
believe,
after consultation with counsel, that damages or settlements, if any, recovered by the
plaintiffs in such claims or actions will not have a material adverse effect on our
financial position, damages or settlements could be material to our operating results or
cash flows in future periods depending on the nature and timing of future developments with
respect to these matters and the amounts of future operating results and cash flows. In
addition to the matters described above, there are other pending claims and legal actions
arising in the normal course of our businesses. While the results of these other pending
claims and legal actions cannot be predicted with certainty, we believe, after consultation
with counsel, the final outcome of such other matters will not have a significant effect on
our consolidated financial position, results of operations or cash flows. |
8. | Related Party Transactions |
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI
Utilities monthly for all direct expenses incurred by UGI on behalf of UGI Utilities and an
allocated share of indirect corporate expenses incurred or paid with respect to services
provided to UGI Utilities. The allocation of indirect UGI corporate expenses to UGI
Utilities utilizes a weighted, three-component formula comprising revenues, operating
expenses and net assets employed and considers UGI Utilities relative percentage of such
items to the total of such items for all UGI operating subsidiaries for which general and
administrative services are provided. Management believes that this allocation method is
reasonable and equitable to UGI Utilities and this allocation method has been accepted by
the PUC in past rate case proceedings and management audits as a reasonable method of
allocating such expenses. These billed expenses are classified as operating and
administrative expenses related parties in the Condensed Consolidated Statements of
Income. In addition, UGI Utilities provides limited administrative services to UGI and
certain of UGIs subsidiaries, principally payroll-related services. Amounts billed to these
entities by UGI Utilities for all periods presented were not material. |
-14-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
From time to time, UGI Utilities is a party to SCAAs with Energy Services. At December 31,
2010, UGI Utilities was a party to two three-year SCAAs with Energy Services expiring
October 31, 2012 and October 31, 2013 and, during the periods covered by the financial
statements, was a party to other SCAAs with Energy Services. Under the SCAAs, UGI Utilities
has, among other things, and subject to recall for operational
purposes, released certain storage and transportation contracts to Energy Services for the
terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories
upon the commencement of the SCAAs, receives a transfer of storage inventories at the end of
the SCAAs, and makes payments associated with refilling storage inventories during the term
of the SCAAs. Energy Services, in turn, provides a firm delivery service and makes certain
payments to UGI Utilities for its various obligations under the SCAAs. UGI Utilities
incurred costs associated with Energy Services SCAAs totaling $2,293 and $7,484 during the
three months ended December 31, 2010 and 2009, respectively. In conjunction with the SCAAs,
UGI Utilities received security deposits from Energy Services. The amounts of such security
deposits, which amounts are included in other current liabilities on the Condensed
Consolidated Balance Sheets, were $15,000, $7,500 and $7,500 as of December 31, 2010,
September 30, 2010 and December 31, 2009, respectively. |
UGI Utilities reflects the historical cost of the gas storage inventories and any exchange
receivable from Energy Services (representing amounts of natural gas inventories used but
not yet replenished by Energy Services) on its balance sheet under the caption
Inventories. The carrying value of these gas storage inventories at December 31, 2010,
comprising approximately 7.5 bcf of natural gas, was $39,447. The carrying value of
these gas storage inventories at September 30, 2010, comprising approximately 4.1 bcf of natural gas, was $20,749. The carrying value of these gas storage inventories at December
31, 2009, comprising approximately 4.0 bcf of natural gas, was $32,855. |
UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant
to which Energy Services provides certain gas supply and related delivery service to Gas
Utility during the months of November through March. In addition, from time to time, Gas
Utility purchases natural gas or pipeline capacity from Energy Services. The aggregate
amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the
three months ended December 31, 2010 and 2009, totaled $18,755 and $16,282, respectively. |
From time to time, the Company sells natural gas or pipeline capacity to Energy Services.
During the three months ended December 31, 2010 and 2009, revenues associated with such sales to
Energy Services totaled $22,034 and $9,244, respectively. Also from time to time, the
Company purchases natural gas or pipeline capacity from Energy Services (in addition to
those transactions already described above). During the three months
ended December 31, 2010 and 2009, the aggregate amount of such purchases totaled $13,497 and $5,977,
respectively. These transactions did not have a material effect on the Companys financial
position, results of operations or cash flows. |
-15-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
9. | Fair Value Measurements |
Derivative Financial Instruments |
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, 2010, September 30, 2010
and December 31, 2009: |
Asset (Liability) | ||||||||||||||||
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, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 2,398 | $ | 352 | $ | | $ | 2,750 | ||||||||
Interest rate contracts |
$ | | $ | 7,249 | $ | | $ | 7,249 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (1,438 | ) | $ | (11,932 | ) | $ | | $ | (13,370 | ) | |||||
September 30, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 61 | $ | 425 | $ | | $ | 486 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (3,263 | ) | $ | (17,798 | ) | $ | | $ | (21,061 | ) | |||||
December 31, 2009: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 233 | $ | 641 | $ | | $ | 874 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (125 | ) | $ | | $ | | $ | (125 | ) |
The fair values of our Level 1 exchange-traded commodity futures and option derivative
contracts and certain non exchange-traded electricity forward contracts are based upon
actively-quoted market prices for identical assets and liabilities. The fair values of the
remainder of our derivative financial instruments and electricity forward contracts, which
are designated as Level 2, are generally based upon recent market transactions and related
market indicators. |
-16-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Other 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 amount and estimated fair value of
our long-term debt at December 31, 2010 were $640,000 and $720,011 respectively. The
carrying amount and estimated fair value of our long-term debt at December 31, 2009 were
$640,000 and $697,137, respectively. 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
types of debt. |
10. | Disclosures About Derivative Instruments and Hedging Activities |
We are exposed to certain market risks related to our ongoing business operations.
Management uses derivative financial and commodity instruments, among other things, to
manage these risks. The primary risks managed by derivative instruments are (1) commodity
price risk and (2) interest rate risk. Although we use derivative financial and commodity
instruments to reduce market risk associated with forecasted transactions, we do not use
derivative financial and commodity instruments for speculative or trading purposes. The use
of derivative instruments is controlled by our risk management and credit policies which
govern, among other things, the derivative instruments we can use, counterparty credit
limits and contract authorization limits. Because most of our commodity derivative
instruments are generally subject to regulatory ratemaking mechanisms, we have limited
commodity price risk associated with our Gas Utility or Electric Utility operations. |
Commodity Price Risk |
Gas Utilitys tariffs contain clauses that permit recovery of all of the prudently incurred
costs of natural gas it sells to retail core-market customers. As permitted and agreed to by
the PUC pursuant to Gas Utilitys annual PGC filings, Gas Utility currently uses New York
Mercantile Exchange (NYMEX) natural gas futures and option contracts to reduce commodity
price volatility associated with a portion of the natural gas it purchases for its retail
core-market customers. With respect to natural gas futures and option contracts, gains and
losses on Gas Utility unsettled natural gas futures contracts and any gains on natural gas
option contracts are recorded in regulatory assets or liabilities on the Condensed
Consolidated Balance Sheets in accordance with Accounting Standards Codification (ASC) 980
related to rate-regulated entities. |
Beginning January 1, 2010, Electric Utilitys DS tariffs permit the recovery of all
prudently incurred costs of electricity it sells to DS customers. Electric Utility enters
into forward electricity purchase contracts to meet a substantial portion of its electricity
supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert
that it would take physical delivery of substantially all of the electricity it had
contracted for under its forward power purchase agreements and, as a result, such contracts
no longer qualified for the normal purchases and normal sales exception under GAAP related
to derivative financial instruments. The inability of Electric Utility to continue to assert
that it would take physical delivery of such power resulted principally from a greater than
anticipated number of customers, primarily certain commercial and industrial customers,
choosing an alternative electricity supplier. Because these contracts no longer qualify for
the normal purchases and normal sales exception under GAAP, the fair value of these
contracts are required to be recognized on the balance sheet and measured at fair value. At
December 31, 2010, the fair values of Electric Utilitys forward purchase power agreements
comprising a loss of $13,369 are reflected in current derivative financial instrument
liabilities and other noncurrent liabilities in the Condensed Consolidated Balance Sheet. In
accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded
equal and offsetting amounts in regulatory assets on the December 31, 2010 Condensed
Consolidated Balance Sheet. |
-17-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
In order to reduce volatility associated with a substantial portion of its electric
transmission congestion costs, Electric Utility obtains FTRs through an annual PJM
Interconnection (PJM) allocation process and by purchases of FTRs at monthly PJM auctions.
FTRs are derivative financial instruments that entitle the holder to receive compensation
for electricity transmission congestion charges that result when there is insufficient
electricity transmission capacity on the electric transmission grid. PJM is a regional
transmission organization that coordinates the movement of wholesale electricity in all or
parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully
recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs
associated with periods beginning on or after January 1, 2010 are recorded in regulatory
assets or liabilities in accordance with ASC 980 relating to rate-regulated entities and
reflected in cost of sales through the DS recovery mechanism (see Note 5). Gains and losses
associated with periods prior to January 2010 are reflected in cost of sales. At December
31, 2010 and 2009, the volumes associated with Electric Utility FTRs totaled
342.0 million kilowatt hours and 730.0 million kilowatt hours, respectively. |
At December 31, 2010, the volume of natural gas associated with our unsettled NYMEX natural
gas futures and option contracts totaled 25.2 million dekatherms and the maximum period over
which we are currently hedging natural gas futures and option contracts is 9 months. At
December 31, 2009, the volume of natural gas associated with unsettled NYMEX natural gas
futures contracts was not material. At December 31, 2010, the volume of electricity under
Electric Utilitys forward electricity purchase contracts was 984.3 million kilowatt hours
and the maximum period over which these contracts extend is 40 months with a weighted
average term of 16 months. |
In order to reduce operating expense volatility, UGI Utilities from time to time enters into
NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be
used in the operation of its vehicles and equipment. The volumes of gasoline under these
contracts and the values of these contracts were not material for all periods presented. |
-18-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Interest Rate Risk |
Our long-term debt typically is issued at fixed rates of interest. As these long-term debt
issues mature, we typically refinance such debt with new debt having interest rates
reflecting then-current market conditions. In order to reduce market rate risk on the
underlying benchmark rate of interest associated with near- to medium-term forecasted
issuances of fixed-rate debt, from time to time we enter into interest rate protection
agreements (IRPAs). We account for IRPAs as cash flow hedges. Changes in the fair values
of IRPAs are recorded in accumulated other comprehensive income (AOCI), to the extent
effective in offsetting changes in the underlying interest rate risk, until earnings are
affected by the hedged interest expense. As of December 31, 2010, the total notional amount
of our unsettled IRPA contracts was $106,500. Our current unsettled IRPA contracts hedge
forecasted interest payments associated with the issuance of long-term debt forecasted to
occur in September 2012 and September 2013. There were no unsettled IPRA contracts
outstanding at December 31, 2009. |
We account for IRPAs as cash flow hedges. Changes in the fair values of IRPAs are recorded
in AOCI, to the extent effective in offsetting changes in the underlying interest rate risk,
until earnings are affected by the hedged interest expense. At such time, gains and losses
are recorded in interest expense. |
At December 31, 2010, the amount of net losses associated with IRPAs expected to be
reclassified into earnings during the next twelve months is $1,165. |
Derivative Financial Instrument Credit Risk |
Our natural gas exchange-traded futures and options contracts are guaranteed by the NYMEX
and have limited credit risk. These contracts generally require cash deposits in margin
accounts. At December 31, 2010 and 2009, restricted cash in margin accounts totaled $3,884
and $656, respectively. We generally do not have credit-risk-related contingent features in
our derivative contracts. |
The following table provides information regarding the fair values and balance sheet
locations of our derivative assets and liabilities existing as of December 31, 2010 and
2009: |
Derivative Assets | Derivative (Liabilities) | |||||||||||||||||||||||
Balance Sheet | Fair Value | Balance Sheet | Fair Value | |||||||||||||||||||||
Location | 2010 | 2009 | Location | 2010 | 2009 | |||||||||||||||||||
Derivatives Designated as Hedging Instruments: |
||||||||||||||||||||||||
Interest rate contracts |
Other Assets | $ | 7,249 | $ | | |||||||||||||||||||
Derivatives Accounted for Under ASC 980: |
||||||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | 2,566 | 644 | Derivative financial instruments and Other noncurrent liabilities | $ | (13,370 | ) | $ | (125 | ) | ||||||||||||||
Derivatives Not Designated as Hedging Instruments: |
||||||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | 184 | 230 | |||||||||||||||||||||
Total Derivatives |
$ | 9,999 | $ | 874 | $ | (13,370 | ) | $ | (125 | ) | ||||||||||||||
-19-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
The amount of derivative
gains or losses representing ineffectiveness, and the amounts of
gains or losses recognized in income as a result of excluding IRPAs
from ineffectiveness testing were not material for the three months
ended December 31, 2010. During the three months ended December 31, 2010 and 2009, the amounts of IRPA net
losses included in AOCI that were reclassified into net income were not material. During
the three months ended December 31, 2009, the impact on net income from changes in the fair
value of FTRs not accounted for under ASC 980 was not material. |
We are also a party to a number of contracts that have elements of a derivative instrument.
These contracts include, among others, binding purchase orders, contracts which provide for
the purchase and delivery of natural gas, and 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 in the contract is based on an underlying that is directly associated with the
price of the product or service being purchased or sold. |
-20-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
ITEM
2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Such statements use forward-looking words such as believe, plan,
anticipate, continue, estimate, expect, may, will, or other similar words. These
statements discuss plans, strategies, events or developments that we expect or anticipate will or
may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the
forward-looking statement. We believe that we have chosen these assumptions or bases in good faith
and that they are reasonable. However, we caution you that actual results almost always vary from
assumed facts or bases, and the differences between actual results and assumed facts or bases can
be material, depending on the circumstances. When considering forward-looking statements, you
should keep in mind the following important factors which could affect our future results and could
cause those results to differ materially from those expressed in our forward-looking statements:
(1) adverse weather conditions resulting in reduced demand; (2) price volatility and availability
of oil, electricity and natural gas and the capacity to transport them to market areas; (3) changes
in laws and regulations, including safety, tax and accounting matters; (4) inability to timely
recover costs through utility rate proceedings; (5) the impact of pending and future legal
proceedings; (6) competitive pressures from the same and alternative energy sources; (7) liability
for environmental claims; (8) customer conservation measures due to high energy prices and
improvements in energy efficiency and technology resulting in reduced demand; (9) adverse labor
relations; (10) large customer, counterparty or supplier defaults; (11) increased uncollectible
accounts expense; (12) liability for personal injury and property damage arising from explosions
and other catastrophic events, including acts of terrorism, resulting from operating hazards and
risks incidental to generating and distributing electricity and transporting, storing and
distributing natural gas, including liability in excess of insurance coverage; (13) political,
regulatory and economic conditions in the United States; (14) capital market conditions, including
reduced access to capital markets and interest rate fluctuations; and (15) changes in commodity
market prices resulting in significantly higher cash collateral requirements.
These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form
10-K for the fiscal year ended September 30, 2010, 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 our business, financial condition or 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.
-21-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
ANALYSIS OF RESULTS OF OPERATIONS
The following analyses compare our results of operations for the three months ended December 31,
2010 (2010 three-month period) with the three months ended December 31, 2009 (2009 three-month
period). Our analyses of results of operations should be read in conjunction with the segment
information included in Note 3 to the condensed consolidated financial statements.
2010 three-month period compared with 2009 three-month period
Increase | ||||||||||||||||
Three Months Ended December 31, | 2010 | 2009 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 321.1 | $ | 327.8 | $ | (6.7 | ) | (2.0 | )% | |||||||
Total margin (a) |
$ | 126.2 | $ | 118.0 | $ | 8.2 | 6.9 | % | ||||||||
Operating income |
$ | 75.1 | $ | 63.7 | $ | 11.4 | 17.9 | % | ||||||||
Income before income taxes |
$ | 64.9 | $ | 53.5 | $ | 11.4 | 21.3 | % | ||||||||
System throughput bcf |
48.9 | 42.3 | 6.6 | 15.6 | % | |||||||||||
Heating degree days % colder than normal (b) |
7.9 | % | 0.4 | % | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 28.9 | $ | 34.0 | $ | (5.1 | ) | (15.0 | )% | |||||||
Total margin (a) |
$ | 8.8 | $ | 10.7 | $ | (1.9 | ) | (17.8 | )% | |||||||
Operating income |
$ | 3.6 | $ | 5.4 | $ | (1.8 | ) | (33.3 | )% | |||||||
Income before income taxes |
$ | 3.1 | $ | 5.0 | $ | (1.9 | ) | (38.0 | )% | |||||||
Distribution sales gwh |
250.5 | 242.4 | 8.1 | 3.3 | % |
bcf billions of cubic feet. gwh millions of kilowatt-hours. |
||
(a) | Gas Utilitys total margin represents total revenues less total cost of sales. Electric
Utilitys total margin represents total revenues less total cost of sales and revenue-related
taxes, i.e. Electric Utility gross receipts taxes, of $1.6 million and $1.9 million during the
three-month periods ended December 31, 2010 and 2009, respectively. For financial statement
purposes, revenue-related taxes are included in Taxes other than income taxes in the
Condensed Consolidated Statements of Income. |
|
(b) | For 2010, deviation from average heating degree days for the 15-year period 1995-2009 based
upon weather statistics provided by the National Oceanic and Atmospheric Administration
(NOAA) for airports located within Gas Utilitys service territory. For 2009, deviation from
average heating degree days for the 15-year period 1990-2004 based upon weather statistics
provided by the National Oceanic and Atmospheric Administration (NOAA) for airports located
within Gas Utilitys service territory. |
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days
were 7.9% colder than normal in the 2010 three-month period compared with temperatures that were
0.4% colder than normal in the prior-year period. Total distribution system throughput increased
6.6 bcf principally reflecting higher throughput to certain low-margin interruptible delivery
service customers and the effects of the colder weather on core market customers. Gas Utilitys
core market customers comprise firm- residential, commercial and industrial (retail core-market)
customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and
small commercial customers who purchase their gas from alternate suppliers.
-22-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Gas Utility revenues decreased $6.7 million during the 2010 three-month period principally
reflecting a decline in revenues from retail core market customers ($19.7 million) partially offset
by an $11.5 million increase in low-margin off-system sales. The decrease in core market revenues
principally resulted from lower average purchased gas cost (PGC) rates resulting from lower
natural gas prices. Under Gas Utilitys PGC recovery mechanisms, 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 $194.9 million in the 2010 three-month period
compared with $209.8 million in the prior-year period reflecting lower average PGC rates.
Gas Utility total margin increased $8.2 million in the 2010 three-month period. The increase
principally reflects a $7.0 million increase in core market margin resulting from the increase in
core market throughput.
Gas Utility operating income and income before income taxes during the 2010 three-month period each
increased $11.4 million. The increases principally reflect the previously mentioned increase in
total margin ($8.2 million) and lower operating and administrative costs ($2.4 million).
Electric Utility. Electric Utilitys kilowatt-hour sales in the 2010 three-month period were 3.3%
higher than in the prior year three-month period on heating degree day weather that was 5.4%
colder. Notwithstanding the effects on heating-related sales from the colder weather, Electric
Utility revenues decreased $5.1 million principally as a result of certain commercial and
industrial customers switching to an alternate supplier for the electricity generation portion of
their service and, to a much lesser extent, lower average default service (DS) rates compared to
provider of last resort (POLR) rates in effect in the prior year. Under DS rates, Electric
Utility is no longer subject to electricity price and congestion cost risk as it is permitted to
pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences
between actual costs and amounts recovered in DS rates are deferred for future recovery from or
refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in
excess of actual costs of electricity as was possible under POLR rates. Electric Utility cost of
sales declined to $18.6 million in the 2010 three-month period compared to $21.5 million in the
2009 three-month period principally reflecting the effects of the previously mentioned electricity
generation supplier customer switching.
Electric Utility total margin declined $1.9 million in the 2010 three-month period principally
reflecting the absence of margin from electric generation service beginning January 1, 2010.
Electric Utility 2010 three-month period operating income and income before income taxes were $1.8
million and $1.9 million lower, respectively, principally reflecting the previously mentioned lower
total margin.
-23-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
The Companys total debt outstanding at December 31, 2010 was $714 million compared to
total debt outstanding of $657 million at September 30, 2010. Included in these
amounts are $74 million and $17 million, respectively, of bank loans outstanding under UGI Utilities
Revolving Credit Agreement (as further described below).
UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement which
expires in August 2011. UGI Utilities expects to renew this facility before its expiration. At
December 31, 2010, UGI Utilities had $74 million of borrowings
outstanding under its Revolving Credit Agreement. Borrowings under the
Revolving Credit Agreement are classified as bank loans on the Condensed Consolidated Balance
Sheets. During the three months ended December 31, 2010 and 2009, average daily bank loan
borrowings were $49.3 million and $161.2 million, respectively, and peak bank loan borrowings
totaled $90 million and $203 million, respectively. Peak bank loan borrowings typically occur
during the peak heating season months of December and January when UGI Utilities investment in
working capital, principally accounts receivable and inventories, is greatest.
Based
upon cash expected to be generated from Gas Utility and Electric
Utility operations and borrowings available under the Revolving
Credit Agreement, UGI Utilities management believes that it
will be able to meet its anticipated contractual and projected cash
commitments during Fiscal 2011.
Cash Flows
Operating activities. Due to the seasonal nature of UGI Utilities businesses, cash flows from our
operating activities are generally strongest during the second and third fiscal quarters when
customers pay for natural gas and electricity consumed during the peak heating season months.
Conversely, operating cash flows are generally at their lowest levels during the first and fourth
fiscal quarters when the Companys investment in working capital, principally accounts receivable
and inventories, is generally greatest. UGI Utilities uses borrowings under its Revolving Credit
Agreement to manage seasonal cash flow needs.
Cash flow used by operating activities was $8.2 million in the 2010 three-month period compared to
cash provided by operating activities of $6.7 million in the prior-year three-month period. Cash
flow from operating activities before changes in operating working capital decreased to $57.8
million in the 2010 three-month period from $67.2 million in the prior-year three-month period. The
decrease principally reflects changes in noncash charges for deferred income taxes. Changes in
operating working capital used $66.0 million of operating cash flow during the 2010 three-month
period, comparable to the $60.5 million used during the prior-year three-month period.
Investing activities. Cash used by investing activities was $17.4 million in the 2010 three-month
period compared to $15.1 million in the 2009 three-month period. The greater cash used in the 2010
three-month period principally reflects higher Gas Utility capital expenditures.
Financing activities. Cash provided by financing activities was $33.0 million in the 2010
three-month period compared with cash provided by financing activities of $7.6 million in the 2009
three-month period. Financing activity cash flows are primarily the result of net borrowings and
repayments under our Revolving Credit Agreement, cash dividends paid to UGI and capital
contributions from UGI. We paid cash dividends to UGI totaling $24.3 million and $17.4 million
during the 2010 and 2009 three-month periods, respectively. During the 2010 three-month period, net
bank loan borrowings totaled $57 million compared with net bank loan borrowings of $25 million in
the prior-year three-month period.
-24-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Merger of Pension Plans
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it
sponsors. The merged plan will maintain separate benefit formulas and specific rights and features
of each predecessor plan. As a result of the merger and in accordance with GAAP related to
accounting for retirement benefits, the Company remeasured the combined plans assets and benefit
obligations as of December 31, 2010. The remeasurement resulted in a decrease in pension and
postretirement benefit obligations and associated regulatory assets, and an increase in other
comprehensive income (see Notes 2, 5 and 6). The remeasurement will result in an approximate $1.4
million decrease in pension expense during the remainder of Fiscal 2011.
Subsequent Event CPG Base Rate Filing
On January 14, 2011, CPG filed a request with the PUC to increase its base operating revenues by
$16.5 million annually. The increased revenues would fund system improvements and operations
necessary to maintain safe and reliable natural gas service and fund new programs that would
provide rebates and other incentives for customers to install new high-efficiency equipment. CPG is
requesting that the new gas rates become effective March 15, 2011. However, the PUC typically
suspends the effective date for general base rate proceedings to allow for investigation and public
hearings. This review process is expected to last approximately nine months, which would delay
implementation of the new rates until late October 2011.
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Gas Utilitys tariffs contain clauses that permit recovery of all of the prudently incurred costs
of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for
the difference between the total amounts actually collected from customers through PGC rates and
the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity
price risk associated with Gas Utility operations. Gas Utility uses derivative financial
instruments including natural gas futures and option contracts traded on the New York Mercantile
Exchange (NYMEX) to reduce volatility in the cost of gas it purchases for its retail core-market
customers. The cost of natural gas derivative financial instruments, net of any associated gains or
losses, is included in Gas Utilitys PGC recovery mechanism. The change in market value of natural
gas futures contracts can require daily deposits of cash in futures accounts. At December 31, 2010
and 2009, Gas Utility had $3.9 million and $0.7 million, respectively, of restricted cash
associated with natural gas futures accounts with brokers. At December 31, 2010, the fair values
of our natural gas futures and option contracts were gains of $2.2 million.
Beginning January 1, 2010, Electric Utilitys DS tariffs contain clauses which permit recovery of
all prudently incurred power costs through the application of DS rates. Because of this ratemaking mechanism,
beginning January 1, 2010 there is limited power cost risk, including the cost of financial
transmission rights (FTRs) and forward electricity purchase contracts, associated with our
Electric Utility operations. 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. Electric Utility obtains FTRs through an annual PJM
Interconnection (PJM) auction process and, to a lesser extent, through purchases at monthly PJM
auctions. PJM is a regional transmission organization that coordinates the movement of wholesale
electricity in all or parts of 14 eastern and midwestern states. At
December 31, 2010, the fair
values of FTRs were gains of $0.4 million.
-25-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures
and swap contracts for a portion of gasoline volumes expected to be used in their operations. These
gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected
in other income. The amount of unrealized gains on these contracts and associated volumes under
contract at December 31, 2010 and 2009 were not material.
In order to reduce interest rate risk associated with near- or medium-term issuances of fixed-rate
debt, from time to time we enter into interest rate protection agreements (IRPAs). The fair value
of unsettled IRPAs held at December 31, 2010 was a gain of $7.2 million. A hypothetical 10%
adverse change in the three-month LIBOR and the three- and nine-month Euribor would result in a
decrease in fair value of $3.8 million. There were no unsettled interest rate protection agreements
outstanding as of December 31, 2009.
Our unsettled derivative instruments at December 31, 2010 comprise (1) Gas Utilitys
exchange-traded natural gas futures and options contracts, which are included in Gas Utilitys PGC
recovery mechanism; (2) Electric Utilitys FTRs and electricity forward purchase contracts, which
are included in Electric Utilitys DS recovery mechanism; (3) exchange-traded gasoline futures and
swap contracts; and (4) IRPAs.
ITEM 4. | CONTROLS AND PROCEDURES |
(a) | Evaluation of Disclosure Controls and Procedures |
The Companys disclosure controls and procedures are designed to provide reasonable
assurance that the information required to be disclosed by the Company in reports filed
under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed,
summarized, and reported within the time periods specified in the SECs rules and forms, and
(ii) accumulated and communicated to our management, including the Chief Executive Officer
and Chief Financial Officer, as appropriate to allow timely decisions regarding required
disclosure. 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 effective at the reasonable assurance level. |
(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. |
-26-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
PART II OTHER INFORMATION
ITEM 1. | LEGAL PROCEEDINGS |
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 million. On February 14, 2007, Frontier
and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7.6
million. The Citys suit was dismissed, and Frontier 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 subsequently filed a
motion for summary judgment with respect to Frontiers claims and the court referred the motion to
a magistrate judge for findings and a recommendation. On October 19, 2010, the magistrate judge
entered an order recommending that the court grant UGI Utilities motion. On November 19, 2010,
the court affirmed the recommended decision of the magistrate judge granting summary judgment in
favor of UGI Utilities.
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, 2010, 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.
-27-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
ITEM 6. | EXHIBITS |
The exhibits filed as part of this report are as follows:
Exhibit No. | Exhibit | |||
12.1 | Computation of
ratio of earnings to
fixed charges |
|||
31.1 | Certification by the
Chief Executive
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter ended
December 31, 2010,
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, 2010,
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, 2010,
pursuant to Section
906 of the
Sarbanes-Oxley Act of
2002 |
-28-
Table of Contents
UGI UTILITIES, INC. 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 Utilities, Inc. (Registrant) |
||||
Date: February 4, 2011 | By: | /s/ Donald E. Brown | ||
Donald E. Brown | ||||
Vice President - Finance and Chief Financial Officer |
||||
Date: February 4, 2011 | By: | /s/ Matthew J. Nolan | ||
Matthew J. Nolan | ||||
Controller |
-29-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
EXHIBIT INDEX
12.1 | Computation of ratio of earnings to fixed charges |
|||
31.1 | Certification by the Chief Executive Officer relating to the Registrants Report
on Form 10-Q for the quarter ended December 31, 2010, 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, 2010, 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,
2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |