Attached files
file | filename |
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EX-32 - EXHIBIT 32 - UGI UTILITIES INC | c15607exv32.htm |
EX-10.3 - EXHIBIT 10.3 - UGI UTILITIES INC | c15607exv10w3.htm |
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INC | c15607exv31w1.htm |
EX-10.2 - EXHIBIT 10.2 - UGI UTILITIES INC | c15607exv10w2.htm |
EX-10.1 - EXHIBIT 10.1 - UGI UTILITIES INC | c15607exv10w1.htm |
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INC | c15607exv31w2.htm |
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INC | c15607exv12w1.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 March 31, 2011
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)
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(Zip Code)
(610) 796-3400
(Registrants telephone number, including area code)
(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 April 30, 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 - 22 | ||||||||
23 - 29 | ||||||||
30 | ||||||||
31 | ||||||||
32 | ||||||||
32 | ||||||||
33 | ||||||||
34 | ||||||||
Exhibit 10.1 | ||||||||
Exhibit 10.2 | ||||||||
Exhibit 10.3 | ||||||||
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)
March 31, | September 30, | March 31, | ||||||||||
2011 | 2010 | 2010 | ||||||||||
ASSETS |
||||||||||||
Current assets: |
||||||||||||
Cash and cash equivalents |
$ | 75,472 | $ | 4,318 | $ | 7,492 | ||||||
Restricted cash |
3,996 | 4,698 | 12,573 | |||||||||
Accounts receivable (less allowances for doubtful accounts of $13,558,
$7,072 and $18,051, respectively) |
154,398 | 64,844 | 162,152 | |||||||||
Accounts receivable related parties |
13,181 | 6,313 | 11,371 | |||||||||
Accrued utility revenues |
43,163 | 13,988 | 33,294 | |||||||||
Inventories |
16,674 | 118,858 | 38,865 | |||||||||
Deferred income taxes |
33,201 | 19,431 | 24,671 | |||||||||
Regulatory assets |
1,762 | 26,100 | 6,662 | |||||||||
Derivative financial instruments |
1,920 | 486 | 525 | |||||||||
Prepaid expenses & other current assets |
19,794 | 21,117 | 16,131 | |||||||||
Total current assets |
363,561 | 280,153 | 313,736 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation and
amortization of $759,102, $734,739 and
$715,234, respectively) |
1,405,793 | 1,394,585 | 1,364,622 | |||||||||
Goodwill |
180,145 | 180,145 | 180,145 | |||||||||
Regulatory assets |
242,892 | 280,602 | 123,199 | |||||||||
Other assets |
11,060 | 4,091 | 6,405 | |||||||||
Total assets |
$ | 2,203,451 | $ | 2,139,576 | $ | 1,988,107 | ||||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||||||
Current liabilities: |
||||||||||||
Bank loans |
$ | | $ | 17,000 | $ | 37,000 | ||||||
Accounts payable |
49,203 | 61,297 | 46,726 | |||||||||
Accounts payable related parties |
10,742 | 8,144 | 10,482 | |||||||||
Deferred fuel refunds |
33,955 | 8,295 | 16,789 | |||||||||
Derivative financial instruments |
4,291 | 10,564 | 7,616 | |||||||||
Other current liabilities |
163,355 | 133,935 | 121,845 | |||||||||
Total current liabilities |
261,546 | 239,235 | 240,458 | |||||||||
Long-term debt |
640,000 | 640,000 | 640,000 | |||||||||
Deferred income taxes |
305,371 | 281,101 | 197,872 | |||||||||
Deferred investment tax credits |
5,134 | 5,311 | 5,489 | |||||||||
Pension and postretirement benefit obligations |
115,628 | 161,338 | 146,137 | |||||||||
Other noncurrent liabilities |
71,531 | 78,137 | 60,428 | |||||||||
Total liabilities |
1,399,210 | 1,405,122 | 1,290,384 | |||||||||
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 |
468,302 | 467,631 | 467,258 | |||||||||
Retained earnings |
279,856 | 217,960 | 251,226 | |||||||||
Accumulated other comprehensive loss |
(4,176 | ) | (11,396 | ) | (81,020 | ) | ||||||
Total common stockholders equity |
804,241 | 734,454 | 697,723 | |||||||||
Total liabilities and stockholders equity |
$ | 2,203,451 | $ | 2,139,576 | $ | 1,988,107 | ||||||
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)
Three Months Ended | Six Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues |
$ | 484,465 | $ | 477,273 | $ | 834,981 | $ | 839,476 | ||||||||
Costs and expenses: |
||||||||||||||||
Cost of sales gas, fuel and purchased power
(excluding depreciation shown below) |
308,778 | 312,171 | 522,262 | 543,388 | ||||||||||||
Operating and administrative expenses |
51,299 | 48,632 | 91,193 | 92,854 | ||||||||||||
Operating and administrative expenses related parties |
5,923 | 6,565 | 8,848 | 7,757 | ||||||||||||
Taxes other than income taxes |
5,469 | 4,894 | 9,827 | 9,422 | ||||||||||||
Depreciation |
12,683 | 12,438 | 25,289 | 25,119 | ||||||||||||
Amortization |
633 | 771 | 1,265 | 1,378 | ||||||||||||
Other income, net |
(4,429 | ) | (2,535 | ) | (6,692 | ) | (4,052 | ) | ||||||||
380,356 | 382,936 | 651,992 | 675,866 | |||||||||||||
Operating income |
104,109 | 94,337 | 182,989 | 163,610 | ||||||||||||
Interest expense |
10,809 | 10,724 | 21,442 | 21,361 | ||||||||||||
Income before income taxes |
93,300 | 83,613 | 161,547 | 142,249 | ||||||||||||
Income taxes |
33,137 | 33,001 | 60,310 | 56,474 | ||||||||||||
Net income |
$ | 60,163 | $ | 50,612 | $ | 101,237 | $ | 85,775 | ||||||||
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)
Six Months Ended | ||||||||
March 31, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 101,237 | $ | 85,775 | ||||
Adjustments to reconcile net income to net cash from
operating activities: |
||||||||
Depreciation and amortization |
26,554 | 26,497 | ||||||
Deferred income taxes, net |
(1,627 | ) | 25,614 | |||||
Provision for uncollectible accounts |
8,626 | 12,176 | ||||||
Other, net |
3,524 | 4,747 | ||||||
Net change in: |
||||||||
Accounts receivable and accrued utility revenues |
(137,223 | ) | (120,350 | ) | ||||
Inventories |
102,184 | 157,734 | ||||||
Deferred fuel and power costs |
43,281 | (1,135 | ) | |||||
Accounts payable |
5,510 | (4,804 | ) | |||||
Other current assets |
3,277 | (10,407 | ) | |||||
Other current liabilities |
9,665 | 11,380 | ||||||
Net cash provided by operating activities |
165,008 | 187,227 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Expenditures for property, plant and equipment |
(37,658 | ) | (26,170 | ) | ||||
Net costs of property, plant and equipment disposals |
(1,220 | ) | (1,255 | ) | ||||
Decrease (increase) in restricted cash |
702 | (12,573 | ) | |||||
Net cash used by investing activities |
(38,176 | ) | (39,998 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Payment of dividends |
(39,348 | ) | (36,260 | ) | ||||
Decrease in bank loans |
(17,000 | ) | (117,000 | ) | ||||
Other |
670 | | ||||||
Net cash used by financing activities |
(55,678 | ) | (153,260 | ) | ||||
Cash and cash equivalents increase (decrease) |
$ | 71,154 | $ | (6,031 | ) | |||
CASH AND CASH EQUIVALENTS: |
||||||||
End of period |
$ | 75,472 | $ | 7,492 | ||||
Beginning of period |
4,318 | 13,523 | ||||||
Increase (decrease) |
$ | 71,154 | $ | (6,031 | ) | |||
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)
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)
Comprehensive Income. The following table presents the components of comprehensive income
for the three and six months ended March 31, 2011 and 2010:
Three Months Ended | Six Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income |
$ | 60,163 | $ | 50,612 | $ | 101,237 | $ | 85,775 | ||||||||
Other comprehensive income |
638 | 1,033 | 7,220 | 2,066 | ||||||||||||
Comprehensive income |
$ | 60,801 | $ | 51,645 | $ | 108,457 | $ | 87,841 | ||||||||
Other
comprehensive income in the 2011 periods principally reflects net gains on interest rate protection
agreements qualifying as cash flow hedges and, for all periods
presented, includes 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 a decrease in regulatory assets and an after-tax
increase in other comprehensive income of $2,060 which is reflected in the six months ended March 31, 2011 above (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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
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 March 31, 2011:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 484,465 | $ | 452,437 | $ | 31,711 | $ | 317 | ||||||||
Cost of sales |
$ | 308,778 | $ | 288,527 | $ | 20,251 | $ | | ||||||||
Depreciation and amortization |
$ | 13,316 | $ | 12,305 | $ | 1,011 | $ | | ||||||||
Operating income |
$ | 104,109 | $ | 100,968 | $ | 2,990 | $ | 151 | ||||||||
Interest expense |
$ | 10,809 | $ | 10,242 | $ | 567 | $ | | ||||||||
Income before income taxes |
$ | 93,300 | $ | 90,726 | $ | 2,423 | $ | 151 | ||||||||
Total assets (at period end) |
$ | 2,203,451 | $ | 2,045,178 | $ | 158,273 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 20,071 | $ | 17,465 | $ | 2,606 | $ | |
Three Months Ended March 31, 2010:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 477,273 | $ | 445,395 | $ | 31,553 | $ | 325 | ||||||||
Cost of sales |
$ | 312,171 | $ | 291,433 | $ | 20,738 | $ | | ||||||||
Depreciation and amortization |
$ | 13,209 | $ | 12,216 | $ | 993 | $ | | ||||||||
Operating income |
$ | 94,337 | $ | 91,112 | $ | 3,093 | $ | 132 | ||||||||
Interest expense |
$ | 10,724 | $ | 10,258 | $ | 466 | $ | | ||||||||
Income before income taxes |
$ | 83,613 | $ | 80,854 | $ | 2,627 | $ | 132 | ||||||||
Total assets (at period end) |
$ | 1,988,107 | $ | 1,862,489 | $ | 125,618 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 12,360 | $ | 11,499 | $ | 861 | $ | |
- 6 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Six Months Ended March 31, 2011:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 834,981 | $ | 773,551 | $ | 60,651 | $ | 779 | ||||||||
Cost of sales |
$ | 522,262 | $ | 483,440 | $ | 38,822 | $ | | ||||||||
Depreciation and amortization |
$ | 26,554 | $ | 24,530 | $ | 2,024 | $ | | ||||||||
Operating income |
$ | 182,989 | $ | 176,035 | $ | 6,593 | $ | 361 | ||||||||
Interest expense |
$ | 21,442 | $ | 20,350 | $ | 1,092 | $ | | ||||||||
Income before income taxes |
$ | 161,547 | $ | 155,685 | $ | 5,501 | $ | 361 | ||||||||
Total assets (at period end) |
$ | 2,203,451 | $ | 2,045,178 | $ | 158,273 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 37,658 | $ | 33,551 | $ | 4,107 | $ | |
Six Months Ended March 31, 2010:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 839,476 | $ | 773,204 | $ | 65,552 | $ | 720 | ||||||||
Cost of sales |
$ | 543,388 | $ | 501,193 | $ | 42,195 | $ | | ||||||||
Depreciation and amortization |
$ | 26,497 | $ | 24,515 | $ | 1,982 | $ | | ||||||||
Operating income |
$ | 163,610 | $ | 154,840 | $ | 8,452 | $ | 318 | ||||||||
Interest expense |
$ | 21,361 | $ | 20,504 | $ | 857 | $ | | ||||||||
Income before income taxes |
$ | 142,249 | $ | 134,336 | $ | 7,595 | $ | 318 | ||||||||
Total assets (at period end) |
$ | 1,988,107 | $ | 1,862,489 | $ | 125,618 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 26,170 | $ | 24,539 | $ | 1,631 | $ | |
4. | Inventories |
Inventories comprise the following:
March 31, | September 30, | March 31, | ||||||||||
2011 | 2010 | 2010 | ||||||||||
Gas Utility natural gas |
$ | 7,927 | $ | 111,531 | $ | 31,693 | ||||||
Materials, supplies and
other |
8,747 | 7,327 | 7,172 | |||||||||
Total inventories |
$ | 16,674 | $ | 118,858 | $ | 38,865 | ||||||
At March 31, 2011, 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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
The carrying value of gas storage inventories released under the SCAAs at March 31,
2011, September 30, 2010 and March 31, 2010 comprising 1.1 billion cubic feet (bcf), 11.7
bcf and 2.8 bcf of natural gas, was $5,089, $62,653 and $20,469, respectively. In
conjunction with the SCAAs, at March 31, 2011, September 30, 2010 and March 31, 2010, 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:
March 31, | September 30, | March 31, | ||||||||||
2011 | 2010 | 2010 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 89,875 | $ | 82,525 | $ | 81,561 | ||||||
Underfunded pension and postretirement plans |
116,003 | 159,154 | 10,405 | |||||||||
Environmental costs |
22,014 | 22,587 | 25,301 | |||||||||
Deferred fuel and power costs |
8,153 | 36,597 | 6,662 | |||||||||
Other |
8,609 | 5,839 | 5,932 | |||||||||
Total regulatory assets |
$ | 244,654 | $ | 306,702 | $ | 129,861 | ||||||
Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 11,196 | $ | 10,472 | $ | 9,899 | ||||||
Environmental overcollections |
6,811 | 7,211 | 8,398 | |||||||||
Deferred fuel and power refunds |
33,955 | 8,298 | 16,789 | |||||||||
State tax benefits distribution system repairs |
6,339 | 6,685 | | |||||||||
Total regulatory liabilities |
$ | 58,301 | $ | 32,666 | $ | 35,086 | ||||||
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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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 $43,150 (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
March 31, 2011, September 30, 2010 and March 31, 2010 were $1,503, $(1,359) and $7,611,
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 March 31, 2011
and September 30, 2010, the fair values of Electric Utilitys electricity supply contracts
were losses of $10,682 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.
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 March 31, 2011, September 30, 2010 and March 31, 2010 were not material.
- 9 -
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Other Regulatory Matters
Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory
Commission (FERC) approved and later affirmed 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. The PUC approved the transfer
subject to, among other things, a reduction in base rates and CPGs agreement to charge PGC
customers, for a period of three years, no more for storage services from the transferred
assets than they would have paid before the transfer, to the extent used. On April 1, 2011
the storage facilities were dividended to UGI and subsequently contributed to UGI Storage
Company. The net book value of the storage facility assets was $10,900 as of March 31, 2011.
The dividend of the storage assets is not expected to have a material impact on the results
of operations of UGI Utilities. Concurrent with the April 1, 2011 transfer, CPG entered into
a firm storage service agreement with UGI Storage Company.
CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to
increase its 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 requested that the new gas rates become
effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the
effective date for the rate increase to allow for investigation and public hearing. Unless a settlement is reached sooner, this
review process is expected to last approximately nine months which may 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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
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 | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost |
$ | 1,750 | $ | 1,745 | $ | 54 | $ | 40 | ||||||||
Interest cost |
5,564 | 5,284 | 183 | 212 | ||||||||||||
Expected return on assets |
(5,971 | ) | (5,858 | ) | (131 | ) | (126 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost (benefit) |
80 | 9 | (174 | ) | (102 | ) | ||||||||||
Actuarial loss |
1,570 | 1,333 | 121 | 89 | ||||||||||||
Net benefit cost |
2,993 | 2,513 | 53 | 113 | ||||||||||||
Change in associated
regulatory liabilities |
| | 785 | 736 | ||||||||||||
Net expense |
$ | 2,993 | $ | 2,513 | $ | 838 | $ | 849 | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Six Months Ended | Six Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost |
$ | 3,675 | $ | 3,490 | $ | 107 | $ | 81 | ||||||||
Interest cost |
10,919 | 10,568 | 365 | 423 | ||||||||||||
Expected return on assets |
(11,993 | ) | (11,717 | ) | (261 | ) | (252 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost (benefit) |
142 | 18 | (348 | ) | (203 | ) | ||||||||||
Actuarial loss |
3,698 | 2,666 | 243 | 179 | ||||||||||||
Net benefit cost |
6,441 | 5,025 | 106 | 228 | ||||||||||||
Change in associated
regulatory liabilities |
| | 1,570 | 1,472 | ||||||||||||
Net expense |
$ | 6,441 | $ | 5,025 | $ | 1,676 | $ | 1,700 | ||||||||
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 $14,400 to the Pension Plan during the next twelve
months. During the six months ended March 31, 2011, the Company made contributions to the
Pension Plan of $12,576. 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 six months ended March 31, 2011, 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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The
merged plan maintains the 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 $43,150; and
increased pre-tax other comprehensive income by $3,522 (see Notes 2 and 5).
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%.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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.
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 March 31, 2011, 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 two 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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
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 they are responsible for an equitable share of any clean up costs
Frontier would be required to pay to the City. Frontier alleged that through ownership and
control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant
from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to
Frontiers claims. On October 19, 2010, the magistrate judge recommended 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. The Northeast Companies alleged that UGI Utilities controlled operations of the
plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. 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 in Waterbury, CT
(Waterbury North). After a trial, on May 22, 2009, the District Court granted judgment in
favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States
Court of Appeals for the Second Circuit affirmed the District Courts judgment in favor of
UGI Utilities. 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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Other Matters
Allentown, Pennsylvania Natural Gas Explosion. On February 9, 2011, a natural gas explosion
occurred in Allentown, Pennsylvania which resulted in five deaths, several personal injuries
and significant property damage. The PUC is investigating the Allentown accident and UGI
Utilities is cooperating with that investigation. Based on a visual inspection, UGI
Utilities identified a fracture in a segment of its cast iron natural gas pipeline in the
area of the accident. The affected segment of pipeline is undergoing forensic testing by an
expert, independent laboratory; however, the cause of the fracture has not yet been
determined.
UGI Utilities has received claims as a result of the explosion, although no lawsuits have
yet been filed. UGI Utilities maintains liability insurance for personal injury, property
and casualty damages and believes that third-party claims associated with the explosion, in
excess of a $500 deductible, will be recovered through UGI Utilities insurance. We believe
that claims and expenses associated with the explosion will not have a material impact on
UGI Utilities consolidated financial position, results of operations or cash flows.
We cannot predict with certainty the final results of any of the claims, potential 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 UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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.
From time to time, UGI Utilities is a party to SCAAs with Energy Services. At March 31,
2011, 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 $297 and $2,590 during the three and six
months ended March 31, 2011, respectively, and $94 and $7,579 during the three and six
months ended March 31, 2010, respectively. In conjunction with the SCAAs, UGI Utilities
received security deposits from Energy Services. The amounts of such security deposits,
which are included in other current liabilities on the Condensed Consolidated Balance
Sheets, were $15,000, $7,500 and $7,500 as of March 31, 2011, September 30, 2010 and March
31, 2010, 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 March 31, 2011,
comprising approximately 0.7 bcf of natural gas, was $3,452. 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 March 31, 2010,
comprising approximately 1.1 bcf of natural gas, was $8,543.
- 16 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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 heating season 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 and six months ended March 31, 2011 totaled $11,338 and $30,093,
respectively. During the three and six months ended March 31, 2010, such transactions
totaled $9,658 and $25,940, respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services.
During the three and six months ended March 31, 2011, revenues associated with such sales to
Energy Services totaled $38,497 and $61,059, respectively. During the three and six months
ended March 31, 2010, such revenues totaled $28,341 and $37,586, 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 and six months
ended March 31, 2011, the aggregate amount of such purchases totaled $22,002 and $35,498,
respectively. During the three and six months ended March 31, 2010, such transactions
totaled $12,417 and $18,395, respectively. These transactions did not have a material
effect on the Companys financial position, results of operations or cash flows.
- 17 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
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 March 31, 2011, September 30, 2010 and
March 31, 2010:
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 | |||||||||||||
March 31, 2011: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | 1,806 | $ | 114 | $ | | $ | 1,920 | ||||||||
Interest rate contracts |
$ | | $ | 7,827 | $ | | $ | 7,827 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | (1,371 | ) | $ | (9,311 | ) | $ | | $ | (10,682 | ) | |||||
September 30, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | 61 | $ | 425 | $ | | $ | 486 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | (3,263 | ) | $ | (17,798 | ) | $ | | $ | (21,061 | ) | |||||
March 31, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | 226 | $ | 299 | $ | | $ | 525 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | (7,616 | ) | $ | | $ | | $ | (7,616 | ) |
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.
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 March 31, 2011 were $640,000 and $707,512
respectively. The carrying amount and estimated fair value of our long-term debt at March
31, 2010 were $640,000 and $702,100, 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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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. Gains and losses on Gas Utility 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 and reflected in cost of sales
through the PGC mechanism (see Note 5).
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
March 31, 2011, the fair values of Electric Utilitys forward purchase power agreements
comprising a loss of $10,682 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 March 31, 2011 Condensed
Consolidated Balance Sheet.
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UGI UTILITIES, INC. AND SUBSIDIARIES
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 associated with certain default service customers, 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 March 31, 2011 and 2010, the volumes associated with Electric Utility
FTRs totaled 138.2 million kilowatt hours and 477.6 million kilowatt hours, respectively.
At March 31, 2011, the volume of natural gas associated with our unsettled NYMEX natural gas
futures and option contracts totaled 21.5 million dekatherms and the maximum period over
which we are currently hedging natural gas futures and option contracts is 18 months. At
March 31, 2010, the volume of natural gas associated with unsettled NYMEX natural gas
futures contracts and option contracts totaled 14.1 million dekatherms. At March 31, 2011,
the volume of electricity under Electric Utilitys forward electricity purchase contracts
was 835.5 million kilowatt hours and the maximum period over which these contracts extend is
37 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. Associated volumes, fair values and
effects on net income were not material for all periods presented.
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 March 31, 2011, 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 March 31, 2010.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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 March 31, 2011, 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 March 31, 2011 and 2010, restricted cash in margin accounts totaled $3,996 and
$12,573, 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 March 31, 2011 and 2010:
As of March 31:
Derivative Assets | Derivative (Liabilities) | |||||||||||||||||||
Balance Sheet | Fair Value | Balance Sheet | Fair Value | |||||||||||||||||
Location | 2011 | 2010 | Location | 2011 | 2010 | |||||||||||||||
Derivatives Designated
as
Hedging Instruments: |
||||||||||||||||||||
Interest rate contracts |
Other assets | $ | 7,827 | $ | | |||||||||||||||
Derivatives Accounted
for
Under ASC 980: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | 1,617 | 226 | Derivative financial instruments and Other noncurrent liabilities |
$ | (10,682 | ) | $ | (7,616 | ) | ||||||||||
Derivatives Not
Designated as
Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | 303 | 299 | |||||||||||||||||
Total Derivatives |
$ | 9,747 | $ | 525 | $ | (10,682 | ) | $ | (7,616 | ) | ||||||||||
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
There was no ineffectiveness, and no gains or losses recognized in income as a result
of excluding IRPAs from ineffectiveness testing, during the three or six months ended March
31, 2011. During the three and six months ended March 31, 2011 and 2010, the amounts of IRPA
net losses included in AOCI that were reclassified into net income were not material.
Additionally, during the six months ended March 31, 2010, 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.
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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 of this Quarterly Report on
Form 10-Q and 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.
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UGI UTILITIES, INC. AND SUBSIDIARIES
ANALYSIS OF RESULTS OF OPERATIONS
The following analyses compare our results of operations for the three months ended March 31, 2011
(2011 three-month period) with the three months ended March 31, 2010 (2010 three-month period)
and the six months ended March 31, 2011 (2011 six-month period) with the six months ended March
31, 2010 (2010 six-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.
2011 three-month period compared with 2010 three-month period
Increase | ||||||||||||||||
Three Months Ended March 31, | 2011 | 2010 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 452.4 | $ | 445.4 | $ | 7.0 | 1.6 | % | ||||||||
Total margin (a) |
$ | 163.9 | $ | 154.0 | $ | 9.9 | 6.4 | % | ||||||||
Operating income |
$ | 101.0 | $ | 91.1 | $ | 9.9 | 10.9 | % | ||||||||
Income before income taxes |
$ | 90.7 | $ | 80.9 | $ | 9.8 | 12.1 | % | ||||||||
System throughput bcf |
61.3 | 54.6 | 6.7 | 12.3 | % | |||||||||||
Heating degree days % colder (warmer) than normal (b) |
6.6 | % | (2.0 | )% | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 31.7 | $ | 31.6 | $ | 0.1 | 0.3 | % | ||||||||
Total margin (a) |
$ | 9.7 | $ | 9.1 | $ | 0.6 | 6.6 | % | ||||||||
Operating income |
$ | 3.0 | $ | 3.1 | $ | (0.1 | ) | (3.2 | )% | |||||||
Income before income taxes |
$ | 2.4 | $ | 2.6 | $ | (0.2 | ) | (7.7 | )% | |||||||
Distribution sales gwh |
279.0 | 262.8 | 16.2 | 6.2 | % |
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 $1.8 million and $1.7 million during the
three-month periods ended March 31, 2011 and 2010, respectively. For financial statement
purposes, revenue-related taxes are included in Taxes other than income taxes in the
Condensed Consolidated Statements of Income. |
|
(b) | 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. |
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days
were 6.6% colder than normal in the 2011 three-month period compared with temperatures that were
2.0% warmer than normal in the prior-year period. Total distribution system throughput increased
6.7 bcf (12.3%) principally reflecting the effects of the colder weather on core market customers,
higher throughput to certain low-margin interruptible delivery service customers and the benefits
of an improving economy. 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.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Gas Utility revenues increased $7.0 million during the 2011 three-month period principally
reflecting a $22.2 million increase in revenues from low-margin off-system sales partially offset
by a decline in revenues from core market customers ($15.2 million). The decrease in core market
revenues principally reflects lower average purchased gas cost (PGC) rates resulting from lower
natural gas prices ($36.2 million) partially offset by the greater core market volumes. 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 $288.5 million in the 2011 three-month period compared with $291.4 million in the
prior-year period principally reflecting the lower average PGC rates partially offset by the
effects of the higher off-system sales.
Gas Utility total margin increased $9.9 million in the 2011 three-month period. The increase
principally reflects a $9.1 million increase in core market margin resulting from the higher core
market throughput.
The increases in Gas Utility operating income and income before income taxes during the 2011
three-month period principally reflect (1) the previously mentioned increase in total margin ($9.9
million) and (2) greater other income ($2.0 million). These increases were partially offset by
slightly higher operating and administrative and depreciation expenses ($2.1 million).
Electric Utility. Electric Utilitys kilowatt-hour sales in the 2011 three-month period were 6.2%
higher than in the prior-year three-month period on heating degree day weather that was 8.5%
colder. Notwithstanding the effects on heating-related sales from the colder weather, Electric
Utility revenues were about equal to last year principally as a result of certain commercial and
industrial customers switching to an alternate supplier for the electricity generation portion of
their service. Electric Utility cost of sales declined to $20.3 million in the 2011 three-month
period compared to $20.7 million in the 2010 three-month period principally reflecting the effects
of the previously mentioned electricity generation supplier customer switching.
Electric Utility total margin increased $0.6 million in the 2011 three-month period principally
reflecting the impact of the greater sales.
Notwithstanding the greater total margin, Electric Utility 2011 three-month period operating income
and income before income taxes declined $0.1 million and $0.2 million, respectively, principally
reflecting higher operating expenses.
Interest Expense and Income Taxes. Our consolidated interest expense in the 2011 three-month period
was about equal to interest expense in the prior-year three-month period. Our annual estimated
effective tax rate was lower in the 2011 three-month period principally reflecting the regulatory
effects of greater state tax depreciation (as further described below under Financial Condition &
Liquidity).
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UGI UTILITIES, INC. AND SUBSIDIARIES
2011 six-month period compared with 2010 six-month period
Increase | ||||||||||||||||
Six Months Ended March 31, | 2011 | 2010 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 773.6 | $ | 773.2 | $ | 0.4 | 0.1 | % | ||||||||
Total margin (a) |
$ | 290.1 | $ | 272.0 | $ | 18.1 | 6.7 | % | ||||||||
Operating income |
$ | 176.0 | $ | 154.8 | $ | 21.2 | 13.7 | % | ||||||||
Income before income taxes |
$ | 155.7 | $ | 134.3 | $ | 21.4 | 15.9 | % | ||||||||
System throughput bcf |
110.2 | 96.9 | 13.3 | 13.7 | % | |||||||||||
Heating degree days % colder (warmer) than normal (b) |
7.2 | % | (0.9 | )% | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 60.7 | $ | 65.6 | $ | (4.9 | ) | (7.5 | )% | |||||||
Total margin (a) |
$ | 18.4 | $ | 19.7 | $ | (1.3 | ) | (6.6 | )% | |||||||
Operating income |
$ | 6.6 | $ | 8.5 | $ | (1.9 | ) | (22.4 | )% | |||||||
Income before income taxes |
$ | 5.5 | $ | 7.6 | $ | (2.1 | ) | (27.6 | )% | |||||||
Distribution sales gwh |
529.5 | 505.2 | 24.3 | 4.8 | % |
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 $3.4 million and $3.6 million during the
six-month periods ended March 31, 2011 and 2010, respectively. For financial statement
purposes, revenue-related taxes are included in Taxes other than income taxes in the
Condensed Consolidated Statements of Income. |
|
(b) | 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. |
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days
were 7.2% colder than normal in the 2011 six-month period compared with temperatures that were 0.9%
warmer than normal in the prior-year period. Total distribution system throughput increased 13.3
bcf reflecting higher throughput to certain low-margin interruptible delivery service customers,
the effects of the colder weather on core market customers and the benefits of an improving
economy.
Gas Utility revenues were about equal to the prior-year period principally reflecting a decline in
revenues from core market customers ($34.9 million) partially offset by a $33.7 million increase in
revenues from low-margin off-system sales. The decrease in core market revenues principally
resulted from lower average PGC rates reflecting lower natural gas prices ($68.7 million) partially offset by the greater core market volumes. Gas
Utilitys cost of gas was $483.4 million in the 2011 six-month period compared with $501.2 million
in the prior-year period principally reflecting the lower average PGC rates offset in part by an
increase in retail core-market sales.
Gas Utility total margin increased $18.1 million in the 2011 six-month period. The increase
principally reflects a $16.1 million increase in core market margin reflecting the increase in core
market throughput.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Gas Utility operating income during the 2011 six-month period increased $21.2 million principally
reflecting the previously mentioned increase in total margin ($18.1 million) and higher other
income ($2.7 million). The $21.4 million increase in income before income taxes reflects the
previously mentioned increase in Gas Utility operating income ($21.2 million).
Electric Utility. Electric Utilitys kilowatt-hour sales in the 2011 six-month period were 4.8%
higher than in the prior-year six-month period on heating degree day weather that was 7.2% colder.
Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $4.9 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 through December 31, 2009. 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
$38.8 million in the 2011 six-month period compared to $42.2 million in the 2010 six-month period
principally reflecting the effects of the previously mentioned electricity generation supplier
customer switching.
Electric Utility total margin declined $1.3 million in the 2011 six-month period, notwithstanding
the greater sales, principally reflecting the absence of margin from electric generation service
beginning January 1, 2010.
Electric Utility 2011 six-month period operating income and income before income taxes declined
$1.9 million and $2.1 million, respectively, principally reflecting the previously mentioned lower
total margin and higher operating and maintenance expenses.
Interest Expense and Income Taxes. Our consolidated interest expense in the 2011 six-month period
was about equal to interest expense in the prior-year six-month period. Our annual estimated
effective tax rate was lower in the 2011 six-month period principally reflecting the regulatory
effects of greater state tax depreciation (as further described below under Financial Condition &
Liquidity).
FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
The Companys total debt outstanding at March 31, 2011 was $640 million compared to total debt
outstanding at September 30, 2010 of $657 million which includes $17 million 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. At March 31, 2011, there were no amounts outstanding under its Revolving
Credit Agreement. Borrowings under the Revolving Credit Agreement are classified as bank loans.
During the 2011 and 2010 six-month periods, average daily bank loan borrowings were $35.1 million
and $136.8 million, respectively, and peak bank loan borrowings totaled $90 million and $239.8
million, respectively. Peak bank loan borrowings typically occur during the
heating season months of December and January when UGI Utilities investment in working capital,
principally accounts receivable and inventories, is greatest. UGI Utilities expects to replace its
Revolving Credit Agreement during the third quarter of Fiscal 2011 but to reduce the available
borrowings to $300 million due to decreases in natural gas prices.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Based upon cash expected to be generated from Gas Utility and Electric Utility operations and
bank loan borrowings, UGI Utilities management believes that it
will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2011.
In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying
capital expenditures incurred after September 8, 2010 through the end of calendar 2011, when such
property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes,
Pennsylvania taxpayers will also be permitted to fully deduct such qualifying capital expenditures
for Pennsylvania state corporate net income tax purposes. In accordance with Pennsylvania utility
ratemaking practice, UGI Utilities Fiscal 2011 effective tax rate reflects the beneficial effects
of this greater state tax depreciation. The additional state and federal tax depreciation
deductions described above will reduce federal and state income taxes otherwise payable and
increase UGI Utilities deferred income tax liabilities.
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. Due to the impacts of strong operating cash flows
resulting from the greater operating results and the effects of low natural gas prices, our cash
and cash equivalents at March 31, 2011 totaled $75.5 million compared to $4.3 million at September
30, 2010. Additionally, at March 31, 2011 there were no amounts outstanding under our Revolving
Credit Agreement.
Cash flow provided by operating activities was $165.0 million in the 2011 six-month period compared
to cash provided by operating activities of $187.2 million in the prior-year six-month period. Cash
flow from operating activities before changes in operating working capital decreased to $138.3
million in the 2011 six-month period from $154.8 million in the prior-year six-month period,
notwithstanding the increase in operating results, primarily due to lower noncash charges for
deferred income taxes. Changes in operating working capital provided $26.7 million of operating
cash flow during the 2011 six-month period, comparable to the $32.4 million provided during the
prior-year six-month period. Among other things, the cash flow from changes in operating working
capital in the 2011 six-month period reflects higher cash from deferred fuel recoveries in the
current period offset by lower cash from changes in natural gas inventories.
Investing activities. Cash used by investing activities was $38.2 million in the 2011 six-month
period compared to $40.0 million in the 2010 six-month period. The prior-year six-month period
reflects greater cash used to fund margin deposits in futures brokerage accounts. Total capital
expenditures were $37.7 million in the 2011 six-month period compared with $26.2 million recorded
in the prior-year period. The 2011 six-month period principally reflects higher UGI Gas capital
expenditures and an
increase in Electric Utility capital expenditures associated with an electricity transmission
capacity project in its service territory.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Financing activities. Cash used by financing activities was $55.7 million in the 2011 six-month
period compared with cash used by financing activities of $153.3 million in the 2010 six-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 $39.3 million and $36.3 million during the 2011 and
2010 six-month periods, respectively. During the 2011 six-month period, net bank loan repayments
totaled $17 million compared with net bank loan repayments of $117 million in the prior-year
six-month period.
Merger of Pension Plans
Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it
sponsors. The merged plan maintains the 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 Fiscal 2011 pension expense beginning January 1, 2011.
Transfer of CPG Storage Assets
On October 21, 2010, the Federal Energy Regulatory Commission (FERC) approved and later affirmed 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. The PUC approved
the transfer subject to, among other things, a reduction in base rates and CPGs agreement to
charge PGC customers, for a period of three years, no more for storage services from the
transferred assets than they would have paid before the transfer, to the extent used. On April 1,
2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage
Company. The net book value of the storage facility assets was $10.9 million as of March 31, 2011.
The dividend of the storage assets is not expected to have a material impact on the results of
operations of UGI Utilities. Concurrent with the April 1, 2011 transfer, CPG entered into a firm
storage service agreement with UGI Storage Company.
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
requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated
March 17, 2011, suspending the effective date for the rate increase to allow for investigation and
public hearing. Unless a settlement is reached sooner, this review process is expected to last approximately nine months which may delay
implementation of the new rates until late October 2011.
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UGI UTILITIES, INC. AND SUBSIDIARIES
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 March 31, 2011 and
2010, Gas Utility had $4.0 million and $12.6 million, respectively, of restricted cash associated
with natural gas futures accounts with brokers. At March 31, 2011, the fair values of our natural
gas futures and option contracts were gains of $1.5 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. The clauses provide for
periodic adjustments to DS rates for differences between the total amount of power costs collected
from customers and recoverable power costs incurred. 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 March 31,
2011 the fair values of FTRs were not material.
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 March 31, 2011 and 2010 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 March 31, 2011 was an asset of $7.8 million. A hypothetical 10% adverse
change in the three-month LIBOR would result in a decrease in fair value of $3.7 million. There
were no unsettled interest rate protection agreements outstanding as of March 31, 2010.
Our unsettled derivative instruments at March 31, 2011 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.
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UGI UTILITIES, INC. AND SUBSIDIARIES
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. |
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
PART II OTHER INFORMATION
ITEM 1. | LEGAL PROCEEDINGS |
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. The Northeast Companies alleged that UGI Utilities
controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that
owned the MGPs. 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 in Waterbury, CT
(Waterbury North). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI
Utilities with respect to the remaining nine sites. On April
13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Courts
judgment in favor of UGI Utilities. 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 million.
ITEM 1A. | RISK FACTORS |
In addition to the information presented below and 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 below and 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.
As a result of recent natural gas explosions in the United States, including the Companys
February 9, 2011 natural gas explosion in Allentown, Pennsylvania, regulators may adopt new laws
or reinterpret existing laws and regulations relating to the replacement of cast iron and bare
steel natural gas pipelines which may adversely affect our results of operations and cash flows.
On February 9, 2011, a natural gas explosion occurred in Allentown, Pennsylvania which
resulted in five deaths, several personal injuries and significant property damage. The
Pennsylvania Public Utility Commission (the PUC) is investigating the Allentown accident and we
are cooperating with that investigation. Based on a visual inspection, we identified a fracture in
a segment of our cast iron natural gas pipeline in the area of the accident. The affected segment of
pipeline is undergoing forensic testing by an expert, independent laboratory; however, the cause of
the fracture has not yet been determined. We are unable to predict the outcome of the PUCs
investigation, including whether the Company will be found to have violated any law, regulation,
PUC order or decision in connection with the Allentown accident.
In addition, new federal or state laws may be adopted, or state and/or federal regulatory
agencies, such as the PUC and United States Department of Transportation, may reinterpret existing
laws and regulations relating to the timing of the replacement of cast iron and bare steel natural
gas pipelines by all natural gas distribution and transmission companies under their respective
jurisdictions. If the
Company is required to comply with new or changed laws and regulations or the Company is not
permitted to charge increased rates to recover a mandated increase in our costs, our cash flows and
earnings may decrease.
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UGI UTILITIES, INC. AND SUBSIDIARIES
ITEM 6. | EXHIBITS |
Exhibit No. |
Exhibit | Registrant | Filing | Exhibit | ||||||
10.1 | FTS-1 Service
Agreement No. 46283
dated November 1,
1993, as amended by
that certain letter
agreement dated May
5, 2004 between
Columbia Gulf
Transmission Company
and UGI Utilities,
Inc. |
|||||||||
10.2 | FTS Service Agreement
No. 46284 dated
November 1, 1993, as
amended by that
certain letter
agreement dated May
5, 2004, between
Columbia Transmission
Corporation and UGI
Utilities, Inc. |
|||||||||
10.3 | Amendment to FTS-1
Service Agreement No.
46283 and FTS Service
Agreement No. 46284
each dated November
1, 1993, as amended
by that certain
letter agreement
dated May 5, 2004
dated November 1,
1993 |
|||||||||
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
March 31, 2011,
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
March 31, 2011,
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 March
31, 2011, pursuant to
Section 906 of the
Sarbanes-Oxley Act of
2002 |
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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: May 6, 2011 | By: | /s/ Donald E. Brown | ||
Donald E. Brown | ||||
Vice President Finance and Chief Financial Officer |
||||
Date: May 6, 2011 | By: | /s/ Matthew J. Nolan | ||
Matthew J. Nolan | ||||
Controller |
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UGI UTILITIES, INC. AND SUBSIDIARIES
EXHIBIT INDEX
10.1 | FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that
certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation
and UGI Utilities, Inc. |
|||
10.2 | FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that
certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company
and UGI Utilities, Inc. |
|||
10.3 | Amendment to FTS-1 Service Agreement No. 46283 and FTS Service Agreement No.
46284 each dated November 1, 1993, as amended by that certain letter agreement dated May
5, 2004 dated November 1, 1993 |
|||
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 March 31, 2011, 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 March 31, 2011, 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 March 31, 2011,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
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