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EXCEL - IDEA: XBRL DOCUMENT - UGI UTILITIES INC | Financial_Report.xls |
EX-32 - EXHIBIT 32 - UGI UTILITIES INC | c18818exv32.htm |
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INC | c18818exv31w2.htm |
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INC | c18818exv31w1.htm |
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INC | c18818exv12w1.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 June 30, 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)
(610) 796-3400
(Registrants telephone number, including area code)
(Zip Code)
(610) 796-3400
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No þ
At July 29, 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
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31 - 32 | ||||||||
32 | ||||||||
33 | ||||||||
33 - 34 | ||||||||
35 | ||||||||
Exhibit 12.1 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT |
-i-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
June 30, | September 30, | June 30, | ||||||||||
2011 | 2010 | 2010 | ||||||||||
ASSETS |
||||||||||||
Current assets: |
||||||||||||
Cash and cash equivalents |
$ | 108,914 | $ | 4,318 | $ | 38,055 | ||||||
Restricted cash |
4,055 | 4,698 | 3,639 | |||||||||
Accounts receivable (less allowances for doubtful accounts of $12,927,
$7,072 and $17,297, respectively) |
87,858 | 64,844 | 90,280 | |||||||||
Accounts receivable related parties |
4,277 | 6,313 | 4,395 | |||||||||
Accrued utility revenues |
7,417 | 13,988 | 9,736 | |||||||||
Inventories |
58,751 | 118,858 | 67,611 | |||||||||
Deferred income taxes |
32,302 | 19,431 | 21,483 | |||||||||
Regulatory assets |
2,037 | 26,100 | 6,316 | |||||||||
Derivative financial instruments |
329 | 486 | 612 | |||||||||
Prepaid expenses & other current assets |
15,490 | 21,117 | 18,450 | |||||||||
Total current assets |
321,430 | 280,153 | 260,577 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation and
amortization of $766,533, $734,739 and $727,484, respectively) |
1,404,250 | 1,394,585 | 1,369,530 | |||||||||
Goodwill |
180,145 | 180,145 | 180,145 | |||||||||
Regulatory assets |
244,061 | 280,602 | 135,397 | |||||||||
Other assets |
8,678 | 4,091 | 4,205 | |||||||||
Total assets |
$ | 2,158,564 | $ | 2,139,576 | $ | 1,949,854 | ||||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||||||
Current liabilities: |
||||||||||||
Bank loans |
$ | | $ | 17,000 | $ | | ||||||
Accounts payable |
41,487 | 61,297 | 49,500 | |||||||||
Accounts payable related parties |
9,260 | 8,144 | 6,039 | |||||||||
Deferred fuel refunds |
22,451 | 8,295 | 16,576 | |||||||||
Derivative financial instruments |
5,334 | 10,564 | 828 | |||||||||
Other current liabilities |
142,797 | 133,935 | 110,360 | |||||||||
Total current liabilities |
221,329 | 239,235 | 183,303 | |||||||||
Long-term debt |
640,000 | 640,000 | 640,000 | |||||||||
Deferred income taxes |
327,039 | 281,101 | 222,568 | |||||||||
Deferred investment tax credits |
5,046 | 5,311 | 5,400 | |||||||||
Pension and postretirement benefit obligations |
113,235 | 161,338 | 143,987 | |||||||||
Other noncurrent liabilities |
69,898 | 78,137 | 70,797 | |||||||||
Total liabilities |
1,376,547 | 1,405,122 | 1,266,055 | |||||||||
Commitments and contingencies (note 9) |
||||||||||||
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 |
468,323 | 467,631 | 467,571 | |||||||||
Retained earnings |
259,307 | 217,960 | 235,955 | |||||||||
Accumulated other comprehensive loss |
(5,872 | ) | (11,396 | ) | (79,986 | ) | ||||||
Total common stockholders equity |
782,017 | 734,454 | 683,799 | |||||||||
Total liabilities and stockholders equity |
$ | 2,158,564 | $ | 2,139,576 | $ | 1,949,854 | ||||||
See accompanying notes to condensed consolidated financial statements.
- 1 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
Three Months Ended | Nine Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues |
$ | 172,714 | $ | 175,021 | $ | 1,007,695 | $ | 1,014,497 | ||||||||
Costs and expenses: |
||||||||||||||||
Cost of sales gas, fuel and purchased power
(excluding depreciation shown below) |
93,383 | 98,864 | 615,645 | 642,252 | ||||||||||||
Operating and administrative expenses |
42,910 | 40,515 | 134,103 | 133,369 | ||||||||||||
Operating and administrative expenses related parties |
1,747 | 2,792 | 10,595 | 10,549 | ||||||||||||
Taxes other than income taxes |
3,523 | 4,167 | 13,350 | 13,589 | ||||||||||||
Depreciation |
12,058 | 12,728 | 37,347 | 37,847 | ||||||||||||
Amortization |
631 | 709 | 1,896 | 2,087 | ||||||||||||
Other income, net |
(1,024 | ) | (1,133 | ) | (7,716 | ) | (5,185 | ) | ||||||||
153,228 | 158,642 | 805,220 | 834,508 | |||||||||||||
Operating income |
19,486 | 16,379 | 202,475 | 179,989 | ||||||||||||
Interest expense |
10,518 | 10,481 | 31,960 | 31,842 | ||||||||||||
Income before income taxes |
8,968 | 5,898 | 170,515 | 148,147 | ||||||||||||
Income taxes |
3,490 | 2,294 | 63,800 | 58,768 | ||||||||||||
Net income |
$ | 5,478 | $ | 3,604 | $ | 106,715 | $ | 89,379 | ||||||||
See accompanying notes to condensed consolidated financial statements.
- 2 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
Nine Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 106,715 | $ | 89,379 | ||||
Adjustments to reconcile net income to net cash from operating activities: |
||||||||
Depreciation and amortization |
39,243 | 39,934 | ||||||
Deferred income taxes, net |
18,700 | 49,532 | ||||||
Provision for uncollectible accounts |
9,495 | 13,273 | ||||||
Other, net |
8,712 | 11,330 | ||||||
Net change in: |
||||||||
Accounts receivable and accrued utility revenues |
(23,902 | ) | (19,040 | ) | ||||
Inventories |
60,107 | 128,987 | ||||||
Deferred fuel and power costs |
32,951 | (1,002 | ) | |||||
Accounts payable |
(3,688 | ) | (6,472 | ) | ||||
Other current assets |
5,340 | (9,529 | ) | |||||
Other current liabilities |
(17,988 | ) | (12,755 | ) | ||||
Net cash provided by operating activities |
235,685 | 283,637 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Expenditures for property, plant and equipment |
(59,590 | ) | (44,484 | ) | ||||
Net costs of property, plant and equipment disposals |
(1,414 | ) | (1,848 | ) | ||||
Decrease (increase) in restricted cash |
643 | (3,639 | ) | |||||
Net cash used by investing activities |
(60,361 | ) | (49,971 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Payment of dividends |
(54,419 | ) | (55,134 | ) | ||||
Decrease in bank loans |
(17,000 | ) | (154,000 | ) | ||||
Other |
691 | | ||||||
Net cash used by financing activities |
(70,728 | ) | (209,134 | ) | ||||
Cash and cash equivalents increase |
$ | 104,596 | $ | 24,532 | ||||
CASH AND CASH EQUIVALENTS: |
||||||||
End of period |
$ | 108,914 | $ | 38,055 | ||||
Beginning of period |
4,318 | 13,523 | ||||||
Increase |
$ | 104,596 | $ | 24,532 | ||||
See accompanying notes to condensed consolidated financial statements.
- 3 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
(unaudited)
(Thousands of dollars)
1. | Nature of Operations |
UGI Utilities, Inc. (UGI Utilities), a wholly owned subsidiary of UGI Corporation (UGI),
and UGI Utilities wholly owned subsidiaries UGI Penn Natural Gas, Inc. (PNG) and UGI
Central Penn Gas, Inc. (CPG) own and operate natural gas distribution utilities in
eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI
Utilities also owns and operates an electric distribution utility in northeastern
Pennsylvania (Electric Utility). UGI Utilities natural gas distribution utility is
referred to as UGI Gas; PNGs natural gas distribution utility is referred to as PNG
Gas; and CPGs natural gas distribution utility is referred to as CPG Gas. UGI Gas, PNG
Gas and CPG Gas are collectively referred to as Gas Utility. Gas Utility is subject to
regulation by the Pennsylvania Public Utility Commission (PUC) and the Maryland Public
Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility
and Electric Utility are collectively referred to as Utilities. PNG also has a heating,
ventilation and air-conditioning service business (UGI Penn HVAC Services, Inc.) which
operates principally in the PNG Gas service territory.
The term UGI Utilities is used sometimes as an abbreviated reference to UGI
Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries, including PNG and CPG.
2. | Significant Accounting Policies |
Basis of Presentation. Our condensed consolidated financial statements include the accounts
of UGI Utilities and its subsidiaries (collectively, we or the Company). We eliminate
all significant intercompany accounts when we consolidate.
The accompanying condensed consolidated financial statements are unaudited and have been
prepared in accordance with the rules and regulations of the U.S. Securities and Exchange
Commission (SEC). They include all adjustments which we consider necessary for a fair
statement of the results for the interim periods presented. Such adjustments consisted only
of normal recurring items unless otherwise disclosed. The September 30, 2010 condensed
consolidated balance sheet data were derived from audited financial statements but do not
include all disclosures required by accounting principles generally accepted in the United
States of America (GAAP). These financial statements should be read in conjunction with
the financial statements and related notes included in our Annual Report on Form 10-K for
the year ended September 30, 2010 (Companys 2010 Annual Financial Statements and Notes).
Due to the seasonal nature of our businesses, the results of operations for interim periods
are not necessarily indicative of the results to be expected for a full year.
- 4 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Comprehensive Income. The following table presents the components of comprehensive income
for the three and nine months ended June 30, 2011 and 2010:
Three Months Ended | Nine Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income |
$ | 5,478 | $ | 3,604 | $ | 106,715 | $ | 89,379 | ||||||||
Other comprehensive income |
(1,696 | ) | 1,034 | 5,524 | 3,100 | |||||||||||
Comprehensive income |
$ | 3,782 | $ | 4,638 | $ | 112,239 | $ | 92,479 | ||||||||
Other comprehensive income (loss) in the 2011 periods principally reflects net gains or
losses 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 other comprehensive
income in the nine months ended June 30, 2011 above (see Notes 6 and 7).
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. | New Accounting Standards Not Yet Adopted |
Fair Value Measurements. In May 2011, the Financial Accounting Standards Board
(FASB) issued Accounting Standards Update (ASU) 2011-04 Amendments to Achieve Common
Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS. The amendments
in ASU 2011-04 result in common fair value measurement and disclosure requirements in GAAP
and International Financial Reporting Standards (IFRS). The new guidance applies to all
reporting entities that are required or permitted to measure or disclose the fair value of
an asset, liability or an instrument classified in shareholders equity. Among other things,
the new guidance requires quantitative information about unobservable inputs, valuation
processes and sensitivity analysis associated with fair value measurements
categorized within Level 3 of the fair value hierarchy. The new guidance is effective for
our interim period ending March 31, 2012 and is required to be applied prospectively. We do
not expect that it will have a material impact on our results of operations or financial condition.
- 5 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05,
Presentation of Comprehensive Income, which revises the manner in which entities present
comprehensive income in their financial statements. The new guidance removes the
presentation options in Accounting Standards Codification (ASC) Topic 220 and requires
entities to report components of comprehensive income in either (1) a continuous statement
of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not
change the items that must be reported in other comprehensive income. The change in
presentation is effective for fiscal years, and interim periods within those fiscal years,
beginning after December 15, 2011 and the guidance is required to be applied
retrospectively. Early adoption is permitted.
4. | 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.
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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Financial information by business segment follows:
Three Months Ended June 30, 2011:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 172,714 | $ | 148,104 | $ | 24,022 | $ | 588 | ||||||||
Cost of sales |
$ | 93,383 | $ | 78,811 | $ | 14,572 | $ | | ||||||||
Depreciation and amortization |
$ | 12,689 | $ | 11,596 | $ | 1,093 | $ | | ||||||||
Operating income |
$ | 19,486 | $ | 17,171 | $ | 2,432 | $ | (117 | ) | |||||||
Interest expense |
$ | 10,518 | $ | 9,852 | $ | 666 | $ | | ||||||||
Income before income taxes |
$ | 8,968 | $ | 7,319 | $ | 1,766 | $ | (117 | ) | |||||||
Total assets (at period end) |
$ | 2,158,564 | $ | 2,002,033 | $ | 156,531 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 21,932 | $ | 20,902 | $ | 1,030 | $ | |
Three Months Ended June 30, 2010:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 175,021 | $ | 149,043 | $ | 25,377 | $ | 601 | ||||||||
Cost of sales |
$ | 98,864 | $ | 83,050 | $ | 15,814 | $ | | ||||||||
Depreciation and amortization |
$ | 13,437 | $ | 12,445 | $ | 992 | $ | | ||||||||
Operating income |
$ | 16,379 | $ | 13,733 | $ | 2,666 | $ | (20 | ) | |||||||
Interest expense |
$ | 10,481 | $ | 9,994 | $ | 487 | $ | | ||||||||
Income before income taxes |
$ | 5,898 | $ | 3,739 | $ | 2,179 | $ | (20 | ) | |||||||
Total assets (at period end) |
$ | 1,949,854 | $ | 1,829,427 | $ | 120,427 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 18,314 | $ | 16,043 | $ | 2,271 | $ | |
- 7 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Nine Months Ended June 30, 2011:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 1,007,695 | $ | 921,655 | $ | 84,673 | $ | 1,367 | ||||||||
Cost of sales |
$ | 615,645 | $ | 562,251 | $ | 53,394 | $ | | ||||||||
Depreciation and amortization |
$ | 39,243 | $ | 36,126 | $ | 3,117 | $ | | ||||||||
Operating income |
$ | 202,475 | $ | 193,206 | $ | 9,025 | $ | 244 | ||||||||
Interest expense |
$ | 31,960 | $ | 30,202 | $ | 1,758 | $ | | ||||||||
Income before income taxes |
$ | 170,515 | $ | 163,004 | $ | 7,267 | $ | 244 | ||||||||
Total assets (at period end) |
$ | 2,158,564 | $ | 2,002,033 | $ | 156,531 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 59,590 | $ | 54,453 | $ | 5,137 | $ | |
Nine Months Ended June 30, 2010:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 1,014,497 | $ | 922,247 | $ | 90,929 | $ | 1,321 | ||||||||
Cost of sales |
$ | 642,252 | $ | 584,243 | $ | 58,009 | $ | | ||||||||
Depreciation and amortization |
$ | 39,934 | $ | 36,960 | $ | 2,974 | $ | | ||||||||
Operating income |
$ | 179,989 | $ | 168,573 | $ | 11,118 | $ | 298 | ||||||||
Interest expense |
$ | 31,842 | $ | 30,498 | $ | 1,344 | $ | | ||||||||
Income before income taxes |
$ | 148,147 | $ | 138,075 | $ | 9,774 | $ | 298 | ||||||||
Total assets (at period end) |
$ | 1,949,854 | $ | 1,829,427 | $ | 120,427 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 44,484 | $ | 40,582 | $ | 3,902 | $ | |
5. | Inventories |
Inventories comprise the following:
June 30, | September 30, | June 30, | ||||||||||
2011 | 2010 | 2010 | ||||||||||
Gas Utility natural gas |
$ | 50,082 | $ | 111,531 | $ | 60,272 | ||||||
Materials, supplies and
other |
8,669 | 7,327 | 7,339 | |||||||||
Total inventories |
$ | 58,751 | $ | 118,858 | $ | 67,611 | ||||||
At June 30, 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 10). 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)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
The carrying value of gas storage inventories released under the SCAAs at June 30, 2011,
September 30, 2010 and June 30, 2010 comprising 6.0 billion cubic feet (bcf), 11.7 bcf,
and 6.4 bcf of natural gas, was $28,633, $62,653 and $35,322, respectively. In conjunction
with the SCAAs, at June 30, 2011, September 30, 2010 and June 30, 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.
6. | 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:
June 30, | September 30, | June 30, | ||||||||||
2011 | 2010 | 2010 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 92,695 | $ | 82,525 | $ | 95,334 | ||||||
Underfunded pension and postretirement plans |
116,003 | 159,154 | 10,260 | |||||||||
Environmental costs |
20,712 | 22,587 | 24,328 | |||||||||
Deferred fuel and power costs |
7,836 | 36,597 | 6,316 | |||||||||
Other |
8,852 | 5,839 | 5,475 | |||||||||
Total regulatory assets |
$ | 246,098 | $ | 306,702 | $ | 141,713 | ||||||
Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 11,558 | $ | 10,472 | $ | 10,261 | ||||||
Environmental overcollections |
6,182 | 7,211 | 8,354 | |||||||||
Deferred fuel and power refunds |
22,451 | 8,298 | 16,576 | |||||||||
State tax benefits distribution system repairs |
6,166 | 6,685 | 10,983 | |||||||||
Total regulatory liabilities |
$ | 46,357 | $ | 32,666 | $ | 46,174 | ||||||
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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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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
7).
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 losses on such contracts at June 30,
2011, September 30, 2010 and June 30, 2010 were $1,050, $1,359 and $558, 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 12, 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 June 30, 2011
and September 30, 2010, the fair values of Electric Utilitys electricity supply contracts
were losses of $10,082 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 June 30, 2011, September 30, 2010 and June 30, 2010 were not material.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Other 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
transferred was $10,949. Compliance with the provisions of the PUC Order approving the
transfer 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
one-year 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. Among other things, 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 (collectively, Energy and Efficiency Conservation Program).
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. On June 23, 2011, a Joint Petition for Approval of
Settlement of All Issues (Joint Petition) was filed with the PUC based upon agreements
with the active parties regarding the requested base operating revenue increase. Under the
terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8,000
in additional base rate revenue as well as $900 in revenues per year for use in CPGs Energy
and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by
the two assigned administrative law judges (ALJs) who recommended that the PUC approve the
Joint Petition without modification. The recommended decision of the ALJs is subject to
PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.
7. | Defined Benefit Pension and Other Postretirement Plans |
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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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Net periodic pension expense and other postretirement benefit costs relating to our
employees include the following components:
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost |
$ | 1,751 | $ | 1,745 | $ | 54 | $ | 40 | ||||||||
Interest cost |
5,564 | 5,284 | 182 | 212 | ||||||||||||
Expected return on assets |
(5,972 | ) | (5,858 | ) | (131 | ) | (126 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost
(benefit) |
80 | 9 | (174 | ) | (102 | ) | ||||||||||
Actuarial loss |
1,570 | 1,333 | 122 | 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 | |||||||||||||||
Nine Months Ended | Nine Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Service cost |
$ | 5,426 | $ | 5,235 | $ | 161 | $ | 121 | ||||||||
Interest cost |
16,483 | 15,852 | 547 | 635 | ||||||||||||
Expected return on assets |
(17,965 | ) | (17,575 | ) | (392 | ) | (378 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost
(benefit) |
222 | 27 | (522 | ) | (305 | ) | ||||||||||
Actuarial loss |
5,268 | 3,999 | 364 | 268 | ||||||||||||
Net benefit cost |
9,434 | 7,538 | 158 | 341 | ||||||||||||
Change in associated
regulatory liabilities |
| | 2,356 | 2,208 | ||||||||||||
Net expense |
$ | 9,434 | $ | 7,538 | $ | 2,514 | $ | 2,549 | ||||||||
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 $15,978 to the Pension Plan during the next twelve
months. During the nine months ended June 30, 2011, the Company made contributions to the
Pension Plan of $16,682. 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 nine months ended June 30, 2011, nor are they
expected to be material for all of Fiscal 2011.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
We also participate in an unfunded and non-qualified defined benefit supplemental executive
retirement plan. Net benefit costs associated with this plan for all periods presented were
not material.
Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The
merged plan 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 6).
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 | ||
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
The 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%.
8. | UGI Utilities 2011 Credit Agreement |
On May 25, 2011, UGI Utilities entered into an unsecured, revolving credit agreement (the
2011 Credit Agreement) with a group of banks providing for borrowings up to $300,000
(including a $100,000 sublimit for letters of credit). Concurrently with entering into the
2011 Credit Agreement, UGI Utilities terminated its then-existing $350,000 revolving credit
agreement dated as of August 11, 2006. Under the 2011 Credit Agreement, UGI Utilities may
borrow at various prevailing market interest rates, including LIBOR and the banks prime
rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based
upon the credit ratings of certain indebtedness of UGI Utilities. The 2011 Credit Agreement
requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total
Capital, as defined, of 0.65 to 1.00. This 2011 Credit Agreement is currently scheduled to
expire in May 2012, but may be extended by UGI Utilities to October 2015 if on or before May
23, 2012, the Company satisfies certain requirements relating to approval by the PUC. The
Company is in the process of seeking such regulatory approval.
9. | 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 June 30, 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.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Management believes that under applicable law UGI Utilities should not be liable in those
instances in which a former subsidiary owned or operated an MGP. There could be, however,
significant future costs of an uncertain amount associated with environmental damage caused
by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or
operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the
subsidiarys separate corporate form should be disregarded or (2) UGI Utilities should be
considered to have been an operator because of its conduct with respect to its subsidiarys
MGP.
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South
Carolina Electric & Gas Company (SCE&G), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from
1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI
Utilities controlled operations of the plant from 1910 to 1926 and is liable for
approximately 25% of the costs associated with the site. SCE&G asserts that it has spent
approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating
to the site and estimates that future response costs, including a claim by the United States
Justice Department for natural resource damages, could be as high as $14,000. Trial took
place in March 2009 and the courts decision is pending.
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens
Communications Company, now known as Frontier Communications Company (Frontier), served a
complaint naming UGI Utilities as a third-party defendant in a civil action pending in the
United States District Court for the District of Maine. In that action, the City of Bangor,
Maine (City) sued Frontier to recover environmental response costs associated with MGP
wastes generated at a plant allegedly operated by Frontiers predecessors at a site on the
Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party
defendants alleging that 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. On July 1, 2011,
Frontier appealed the Courts decision to the United States Court of Appeals for the First
Circuit.
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.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
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.
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.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
We cannot
predict 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. We believe, after consultation
with counsel, the final outcome of such other matters will not have a material effect on
our consolidated financial position, results of operations or cash flows.
10. | 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 June 30, 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 $16,566 and $19,156 during the three and nine months ended June 30,
2011, respectively, and $6,783 and $14,362 during the three and nine months ended June
30, 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 June 30, 2011, September 30, 2010 and June 30, 2010, respectively.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
UGI Utilities 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 June 30, 2011,
comprising approximately 4.0 bcf of natural gas, was $19,035. 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 June 30, 2010,
comprising approximately 2.2 bcf of natural gas, was $12,140.
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. The amount of these
transactions (exclusive of transactions pursuant to the SCAAs) during the nine months ended
June 30, 2011 and 2010 totaled $30,093 and $25,941, respectively. There were no such
transactions during the three months ended June 30, 2011 or 2010.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services.
During the three and nine months ended June 30, 2011, revenues associated with such sales to
Energy Services totaled $13,529 and $74,589, respectively. During the three and nine months
ended June 30, 2010, such revenues totaled $15,489 and $43,074, 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) and beginning April 1, 2011,
purchases a firm storage service from UGI Storage Company, a
subsidiary of Energy Services, under a one-year agreement.
During the three and nine months ended June 30, 2011, the aggregate amount of such
transactions totaled $9,351 and $44,849, respectively. During the three and nine months
ended June 30, 2010, such transactions totaled $7,145 and $22,034, respectively. These
transactions did not have a material effect on the Companys financial position, results of
operations or cash flows.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
11. | 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 June 30, 2011, September 30, 2010 and
June 30, 2010:
Asset (Liability) | ||||||||||||||||
Quoted Prices | ||||||||||||||||
in Active | ||||||||||||||||
Markets for | Significant | |||||||||||||||
Identical | Other | |||||||||||||||
Assets and | Observable | Unobservable | ||||||||||||||
Liabilities | Inputs | Inputs | ||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
June 30, 2011: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | 128 | $ | 201 | $ | | $ | 329 | ||||||||
Interest rate contracts |
$ | | $ | 5,047 | $ | | $ | 5,047 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | (2,330 | ) | $ | (8,802 | ) | $ | | $ | (11,132 | ) | |||||
September 30, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | 61 | $ | 425 | $ | | $ | 486 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | (3,263 | ) | $ | (17,798 | ) | $ | | $ | (21,061 | ) | |||||
June 30, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | 315 | $ | 297 | $ | | $ | 612 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Commodity contracts |
$ | (828 | ) | $ | | $ | | $ | (828 | ) |
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 June 30, 2011 were $640,000 and $715,954
respectively. The carrying amount and estimated fair value of our long-term debt at June
30, 2010 were $640,000 and $734,356, 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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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
12. | 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 ASC No. 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
June 30, 2011, the fair values of Electric Utilitys
forward purchase power agreements comprising a loss of $10,082 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 June 30, 2011 Condensed Consolidated Balance Sheet.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
In order to reduce volatility associated with a substantial portion of its electric
transmission congestion costs 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 6). Gains and losses associated with periods prior to January 2010 are reflected
in cost of sales. At June 30, 2011 and 2010, the volumes associated with Electric Utility
FTRs totaled 287.3 million kilowatt hours and 739.3 million kilowatt hours, respectively.
The maximum period which we are currently hedging FTRs is 11 months.
At June 30, 2011, the volume of natural gas associated with our unsettled NYMEX natural gas
futures and option contracts totaled 18.6 million dekatherms and the maximum period over
which we are currently hedging natural gas futures and option contracts is 16 months. At
June 30, 2010, the volume of natural gas associated with unsettled NYMEX natural gas futures
contracts and option contracts totaled 11.3 million dekatherms. At June 30, 2011, the
volume of electricity under Electric Utilitys forward electricity purchase contracts was
874.4 million kilowatt hours and the maximum period over which these contracts extend is 35
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 June 30, 2011, the total notional amount of our unsettled IRPA contracts was $173,000.
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 June 30, 2010.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
We 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 June 30, 2011, the amount of net losses associated
with previously settled 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 June 30, 2011 and 2010, restricted cash in margin accounts totaled $4,055 and
$3,639, 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 June 30, 2011 and 2010:
As of June 30:
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 | $ | 5,047 | $ | | |||||||||||||||
Derivatives Accounted for Under ASC 980: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | 201 | 287 | Derivative financial instruments and Other noncurrent liabilities | $ | (11,132 | ) | $ | (828 | ) | ||||||||||
Derivatives Not
Designated as Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | 128 | 325 | |||||||||||||||||
Total Derivatives |
$ | 5,376 | $ | 612 | $ | (11,132 | ) | $ | (828 | ) | ||||||||||
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
There amounts of derivative gains or losses representing ineffectiveness were not
material in the three or nine months ended June 30, 2011 and 2010. During the three and nine
months ended June 30, 2011 and 2010, the amounts of IRPA net losses included in AOCI that
were reclassified into net income were not material. Additionally, during nine months
ended June 30, 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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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
ITEM 2. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL 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 our Quarterly Report on Form
10-Q for the fiscal quarter ended March 31, 2011 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 June 30, 2011
(2011 three-month period) with the three months ended June 30, 2010 (2010 three-month period)
and the nine months ended June 30, 2011 (2011 nine-month period) with the nine months ended June
30, 2010 (2010 nine-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 June 30, | 2011 | 2010 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 148.1 | $ | 149.0 | $ | (0.9 | ) | (0.6 | )% | |||||||
Total margin (a) |
$ | 69.3 | $ | 66.0 | $ | 3.3 | 5.0 | % | ||||||||
Operating income |
$ | 17.2 | $ | 13.7 | $ | 3.5 | 25.5 | % | ||||||||
Income before income taxes |
$ | 7.3 | $ | 3.7 | $ | 3.6 | 97.3 | % | ||||||||
System throughput bcf |
33.4 | 28.0 | 5.4 | 19.3 | % | |||||||||||
Heating degree days % (warmer) than normal (b) |
(17.3 | )% | (25.7 | )% | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 24.0 | $ | 25.4 | $ | (1.4 | ) | (5.5 | )% | |||||||
Total margin (a) |
$ | 8.1 | $ | 8.1 | $ | | 0.0 | % | ||||||||
Operating income |
$ | 2.4 | $ | 2.7 | $ | (0.3 | ) | (11.1 | )% | |||||||
Income before income taxes |
$ | 1.8 | $ | 2.2 | $ | (0.4 | ) | (18.2 | )% | |||||||
Distribution sales gwh |
224.7 | 218.6 | 6.1 | 2.8 | % |
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 $1.4 million in each of the three-month
periods ended June 30, 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 in the 2011 three-month period
based upon heating degree days were 17.3% warmer than normal and 11.3% colder than the prior-year
period. Total distribution system throughput increased 19.3% principally reflecting the effects of
higher throughput to certain low-margin interruptible delivery service customers, the impact of
colder early spring weather on throughput to core market 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 decreased $0.9 million during the 2011 three-month period, notwithstanding the
greater throughput, principally reflecting a decline in revenues from retail core market customers
($1.9 million). The decrease in retail core market revenues principally reflects lower average
purchased gas cost (PGC) rates resulting from lower natural gas prices ($11.9 million) partially
offset by the greater retail 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 $78.8 million in
the 2011 three-month period compared with $83.1 million in the prior-year period reflecting the
previously mentioned lower average PGC rates.
Gas Utility total margin increased $3.3 million in the 2011 three-month period. The increase
reflects a $4.0 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 reflects the previously mentioned increase in total margin ($3.3
million).
Electric Utility. Electric Utilitys kilowatt-hour sales in the 2011 three-month period were 2.8%
higher than in the prior-year three-month period on heating degree day weather that was 17% colder.
Notwithstanding the effects on heating-related sales from the colder weather, Electric Utility
revenues were less than the prior 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 $14.6 million in the 2011 three-month period
compared to $15.8 million in the 2010 three-month period principally reflecting the effects of the
previously mentioned electricity generation supplier customer switching.
Electric Utility total margin was $8.1 million in the 2011 three-month period, equal to the margin
recorded in the prior-year period.
Electric Utility 2011 three-month period operating income and income before income taxes declined
$0.3 million and $0.4 million, respectively, principally reflecting slightly higher operating
expenses and, with respect to income before income taxes, higher allocated interest charges.
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 in the 2011 three-month period was about equal to the effective tax rate
reflected in the prior-year three-month period.
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UGI UTILITIES, INC. AND SUBSIDIARIES
2011 nine-month period compared with 2010 nine-month period
Increase | ||||||||||||||||
Nine Months Ended June 30, | 2011 | 2010 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 921.7 | $ | 922.2 | $ | (0.5 | ) | (0.1 | )% | |||||||
Total margin (a) |
$ | 359.4 | $ | 338.0 | $ | 21.4 | 6.3 | % | ||||||||
Operating income |
$ | 193.2 | $ | 168.6 | $ | 24.6 | 14.6 | % | ||||||||
Income before income taxes |
$ | 163.0 | $ | 138.1 | $ | 24.9 | 18.0 | % | ||||||||
System throughput bcf |
143.5 | 124.9 | 18.6 | 14.9 | % | |||||||||||
Heating degree days % colder (warmer) than normal (b) |
4.2 | % | (3.9 | )% | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 84.7 | $ | 90.9 | $ | (6.2 | ) | (6.8 | )% | |||||||
Total margin (a) |
$ | 26.5 | $ | 27.9 | $ | (1.4 | ) | (5.0 | )% | |||||||
Operating income |
$ | 9.0 | $ | 11.1 | $ | (2.1 | ) | (18.9 | )% | |||||||
Income before income taxes |
$ | 7.3 | $ | 9.8 | $ | (2.5 | ) | (25.5 | )% | |||||||
Distribution sales gwh |
754.2 | 723.8 | 30.4 | 4.2 | % |
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 $4.8 million and $5.0
million during the nine-month periods ended June 30, 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 4.2% colder than normal in the 2011 nine-month period compared with temperatures that were
3.9% warmer than normal in the prior-year period. Total distribution system throughput increased
18.6 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 ($34.5 million) partially offset by a $33.1 million increase in
revenues from low-margin off-system sales. The decrease in core market revenues principally
resulted from lower average retail core market PGC rates reflecting lower natural gas prices ($80.2
million) offset by the effects of the higher throughput. Gas Utilitys cost of gas was $562.3
million in the 2011 nine-month period compared with $584.2 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 $21.4 million in the 2011 nine-month period. The increase
principally reflects a $20.1 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 and income before income taxes during the 2011 nine-month period
increased $24.6 million and $24.9 million, respectively, principally reflecting the previously
mentioned increase in total margin ($21.4 million) and higher other income ($2.6 million).
Electric Utility. Electric Utilitys kilowatt-hour sales in the 2011 nine-month period were 4.2%
higher than in the prior-year nine-month period on heating degree day weather that was 8.1% colder.
Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $6.2 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 the provider of last resort (POLR) rates
that were 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 $53.4 million in the 2011 nine-month period compared to $58.0 million in the 2010
nine-month period principally reflecting the effects of the previously mentioned electricity
generation supplier customer switching.
Electric Utility total margin declined $1.4 million in the 2011 nine-month period, notwithstanding
the greater sales, principally reflecting the absence of margin from electric generation service
beginning January 1, 2010.
Electric Utility 2011 nine-month period operating income and income before income taxes declined
$2.1 million and $2.5 million, respectively, principally reflecting the previously mentioned lower
total margin, higher operating and maintenance expenses and, with respect to income before income
taxes, higher allocated interest expense.
Interest Expense and Income Taxes. Our consolidated interest expense in the 2011 nine-month period
was about equal to interest expense in the prior-year nine-month period. Our annual estimated
effective tax rate was lower in the 2011 nine-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 June 30, 2011 was $640 million compared to total debt
outstanding at September 30, 2010 of $657 million which includes $17 million outstanding under UGI
Utilities Credit Agreement (as further described below).
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UGI UTILITIES, INC. AND SUBSIDIARIES
On May 25, 2011, UGI Utilities entered into an unsecured revolving credit agreement (the 2011
Credit Agreement) with a group of banks providing for borrowings up to $300 million (including a
$100 million sublimit for letters of credit). Concurrently with entering into the 2011 Credit
Agreement, UGI Utilities terminated its then-existing $350 million revolving credit agreement dated
as of August 11, 2006. The 2011 Credit Agreement is currently scheduled to expire in May 2012, but
may be extended by UGI Utilities to October 2015 if on or before May 23, 2012, the Company
satisfies certain requirements relating to approval by the PUC. The Company is in the process of
seeking regulatory approval. At June 30, 2011, there were no amounts outstanding under the 2011
Credit Agreement. Borrowings under the 2011 Credit Agreement and a predecessor credit agreement are
classified as bank loans. During the 2011 and 2010 nine-month periods, average daily bank loan
borrowings were $23.5 million and $93.1 million, respectively, and peak bank loan borrowings
totaled $90 million and $203 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. 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
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 credit agreement borrowings to manage
seasonal cash flow needs. Due to the impact of strong operating cash flows reflecting the greater
operating results, lower cash paid for income taxes due to in large part to accelerated tax
depreciation deductions, and the continuing effects of low natural gas prices, our cash and cash
equivalents at June 30, 2011 increased to $108.9 million compared to $4.3 million at September 30,
2010 and there were no amounts outstanding under our 2011 Credit Agreement.
Cash flow provided by operating activities was $235.7 million in the 2011 nine-month period
compared to $283.6 million in the prior-year nine-month period. Cash flow from operating activities
before changes in operating working capital decreased to $182.9 million in the 2011 nine-month
period from $203.4 million in the prior-year nine-month period, notwithstanding the increase in
operating results, primarily due to lower noncash charges for deferred income taxes. Changes in
operating working capital provided $52.8 million of operating cash flow during the 2011 nine-month
period compared to $80.2 million provided during the prior-year nine-month period. Among other
things, the lower cash flow from changes in operating working capital in the 2011 nine-month
period reflects lower cash from changes in natural gas inventories partially offset by greater cash
from deferred fuel recoveries.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Investing activities. Cash used by investing activities was $60.4 million in the 2011 nine-month
period compared to $50.0 million in the 2010 nine-month period. Total capital expenditures were
$59.6 million in the 2011 nine-month period compared with $44.5 million recorded in the prior-year
period. The 2011 nine-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.
Financing activities. Cash used by financing activities was $70.7 million in the 2011 nine-month
period compared with $209.1 million in the 2010 nine-month period. Financing activity cash flows
are primarily the result of net borrowings and repayments under our revolving credit agreements,
cash dividends paid to UGI and capital contributions from UGI. We paid cash dividends to UGI
totaling $54.4 million and $55.1 million during the 2011 and 2010 nine-month periods, respectively.
During the 2011 nine-month period, net bank loan repayments totaled $17 million compared with net
bank loan repayments of $154 million in the prior-year nine-month period.
On July 29, 2011, after the end of the June 2011 quarter, UGI Utilities paid a cash dividend to UGI of 45.1 million.
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 associated regulatory assets, and an increase in other
comprehensive income (see Notes 2, 6 and 7). 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 transferred was $10.9
million. Compliance with the provisions of the PUC Order approving the transfer 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 one-year firm storage service agreement with
UGI Storage Company.
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UGI UTILITIES, INC. AND SUBSIDIARIES
CPG Base Rate Filing
On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5
million annually. Among other things, 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 (collectively, Energy and Efficiency Conservation Program). 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.
On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (Joint Petition) was
filed with the PUC based upon agreements with the active parties regarding the requested base
operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to
increase distribution rates by $8.0 million in additional base rate revenue as well as $0.9 million
in revenues per year for use in CPGs Energy and Efficiency Conservation Program. On July 19, 2011, a
recommended decision was issued by the two assigned administrative law judges (ALJs) who
recommended that the PUC approve the Joint Petition without modification. The recommended
decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude
by the end of Fiscal 2011.
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Gas Utilitys tariffs contain clauses that permit recovery of all of the prudently incurred costs
of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for
the difference between the total amounts actually collected from customers through PGC rates and
the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity
price risk associated with Gas Utility operations. Gas Utility uses derivative financial
instruments including natural gas futures and option contracts traded on the New York Mercantile
Exchange (NYMEX) to reduce volatility in the cost of gas it purchases for its retail core-market
customers. The cost of natural gas derivative financial instruments, net of any associated gains or
losses, is included in Gas Utilitys PGC recovery mechanism. The change in market value of natural
gas futures contracts can require daily deposits of cash in futures accounts. At June 30, 2011 and
2010, Gas Utility had $4.1 million and $3.6 million, respectively, of restricted cash associated
with natural gas futures accounts with brokers. At June 30, 2011, the fair values of our natural
gas futures and option contracts were losses of $1.1 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 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 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 June 30, 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 June 30, 2011 and 2010 were not material.
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UGI UTILITIES, INC. AND SUBSIDIARIES
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 June 30, 2011 was an asset of $5.0 million. A hypothetical 10% adverse
change in the three-month LIBOR would result in a decrease in fair value of $5.9 million. There
were no unsettled IRPAs outstanding at June 30, 2010.
Our unsettled derivative instruments at June 30, 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.
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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UGI UTILITIES, INC. AND SUBSIDIARIES
PART II OTHER INFORMATION
ITEM 1A. | RISK FACTORS |
In addition to the other information presented in this report, you should carefully consider the
factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the
fiscal year ended September 30, 2010 and in Part II, Item 1A. Risk Factors in our Quarterly
Report on Form 10-Q for the fiscal quarter ended March 31, 2011, which could materially affect our
business, financial condition or future results. The risks described in our Annual Report on Form
10-K and Quarterly Report on Form 10-Q are not the only risks facing the Company. Other unknown or
unpredictable factors could also have material adverse effects on future results.
ITEM 6. | EXHIBITS |
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are
set forth with the name of the registrant, the type of report and registration number or last date
of the period for which it was filed, and the exhibit number in such filing):
Incorporation by Reference
Exhibit | ||||||||||||
No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
10.1 | Credit Agreement, dated as of May
25, 2011 among UGI Utilities, Inc.,
as borrower, and PNC Bank, National
Association, as administrative
agent, Citizens Bank of
Pennsylvania, as syndication agent,
PNC Capital Markets LLC and RBS
Citizens, N.A., as joint lead
arrangers and joint bookrunners,
and PNC Bank, National Association,
Citizens Bank of Pennsylvania,
Citibank, N.A., Credit Suisse AG,
Cayman Islands Branch, JPMorgan
Chase Bank, N.A., Wells Fargo Bank,
National Association, The Bank of
New York Mellon, and the other
financial institutions from time to
time parties thereto.
|
UGI Utilities | Form 8-K (5/25/2011) | 10.1 | ||||||||
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 June 30,
2011, pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 |
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UGI UTILITIES, INC. AND SUBSIDIARIES
Exhibit | ||||||||||||
No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
31.2 | Certification by the Chief
Financial Officer relating to the
Registrants Report on Form 10-Q
for the quarter ended June 30,
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 June 30,
2011, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 |
|||||||||||
101 | .INS* | XBRL Instance |
||||||||||
101 | .SCH* | XBRL Taxonomy Extension Schema |
||||||||||
101 | .CAL* | XBRL Taxonomy Extension Calculation |
||||||||||
101 | .DEF* | XBRL Taxonomy Extension Definition |
||||||||||
101 | .LAB* | XBRL Taxonomy Extension Labels |
||||||||||
101 | .PRE* | XBRL Taxonomy Extension Presentation |
* | XBRL information will be considered to be furnished, not filed, for the first two years of a
companys submission of XBRL information. |
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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: August 5, 2011 | By: | /s/ Donald E. Brown | ||
Donald E. Brown | ||||
Vice President Finance and Chief Financial Officer | ||||
Date: August 5, 2011 | By: | /s/ Matthew J. Nolan | ||
Matthew J. Nolan | ||||
Controller |
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UGI UTILITIES, INC. AND SUBSIDIARIES
EXHIBIT INDEX
12.1 | Computation of ratio of earnings to fixed charges |
|||
31.1 | Certification by the Chief Executive Officer relating to the Registrants Report on
Form 10-Q for the quarter ended June 30, 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 June 30, 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 June 30, 2011, pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 |
|||
101 | .INS* | XBRL.Instance |
||
101 | .SCH* | XBRL Taxonomy Extension Schema |
||
101 | .CAL* | XBRL Taxonomy Extension Calculation |
||
101 | .DEF* | XBRL Taxonomy Extension Definition |
||
101 | .LAB* | XBRL Taxonomy Extension Labels |
||
101 | .PRE* | XBRL Taxonomy Extension Presentation |
* | XBRL information will be considered to be furnished, not filed, for the first two years of
a companys submission of XBRL information. |