Attached files
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EX-32 - EXHIBIT 32 - UGI UTILITIES INC | c00277exv32.htm |
EX-31.1 - EXHIBIT 31.1 - UGI UTILITIES INC | c00277exv31w1.htm |
EX-12.1 - EXHIBIT 12.1 - UGI UTILITIES INC | c00277exv12w1.htm |
EX-31.2 - EXHIBIT 31.2 - UGI UTILITIES INC | c00277exv31w2.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2010
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-1398
UGI UTILITIES, INC.
(Exact name of registrant as specified in its charter)
Pennsylvania | 23-1174060 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) |
UGI UTILITIES, INC.
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(Registrants telephone number, including area code)
2525 N. 12th Street, Suite 360
Reading, PA
(Address of principal executive offices)
19612
(Zip Code)
(610) 796-3400
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
At April 30, 2010, there were 26,781,785 shares of UGI Utilities, Inc. Common Stock, par value
$2.25 per share, outstanding, all of which were held, beneficially and of record, by UGI
Corporation.
UGI UTILITIES, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PAGES | ||||||||
Part I Financial Information |
||||||||
Item 1. Financial Statements (unaudited) |
||||||||
1 | ||||||||
2 | ||||||||
3 | ||||||||
4 18 | ||||||||
19 25 | ||||||||
25 26 | ||||||||
26 | ||||||||
27 | ||||||||
27 | ||||||||
28 | ||||||||
Exhibit 12.1 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32 |
-i-
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Thousands of dollars)
March 31, | September 30, | March 31, | ||||||||||
2010 | 2009 | 2009 | ||||||||||
ASSETS |
||||||||||||
Current assets: |
||||||||||||
Cash and cash equivalents |
$ | 7,492 | $ | 13,523 | $ | 22,440 | ||||||
Restricted cash |
12,573 | | 92,613 | |||||||||
Accounts receivable (less allowances for doubtful accounts of $18,051,
$11,384 and $25,619, respectively) |
162,152 | 74,286 | 200,674 | |||||||||
Accounts receivable related parties |
11,371 | 3,378 | 5,107 | |||||||||
Accrued utility revenues |
33,294 | 20,980 | 51,402 | |||||||||
Inventories |
38,865 | 196,598 | 26,765 | |||||||||
Deferred income taxes |
24,671 | 24,905 | 21,659 | |||||||||
Regulatory assets |
6,662 | 19,584 | 61,067 | |||||||||
Derivative financial instruments |
525 | 867 | 962 | |||||||||
Prepaid expenses & other current assets |
16,131 | 5,167 | 12,941 | |||||||||
Total current assets |
313,736 | 359,288 | 495,630 | |||||||||
Property, plant and equipment, at cost (less accumulated depreciation and
amortization of $715,234, $692,082 and $680,722, respectively) |
1,364,622 | 1,364,795 | 1,345,450 | |||||||||
Goodwill |
180,145 | 180,145 | 176,906 | |||||||||
Regulatory assets |
123,199 | 121,960 | 112,572 | |||||||||
Other assets |
6,405 | 4,049 | 13,592 | |||||||||
Total assets |
$ | 1,988,107 | $ | 2,030,237 | $ | 2,144,150 | ||||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||||||
Current liabilities: |
||||||||||||
Bank loans |
$ | 37,000 | $ | 154,000 | $ | 178,000 | ||||||
Accounts payable |
46,726 | 53,265 | 76,944 | |||||||||
Accounts payable related parties |
10,482 | 8,746 | 6,428 | |||||||||
Deferred fuel refunds |
16,789 | 30,846 | 4,736 | |||||||||
Derivative financial instruments |
7,616 | | 82,275 | |||||||||
Other current liabilities |
121,845 | 110,966 | 148,402 | |||||||||
Total current liabilities |
240,458 | 357,823 | 496,785 | |||||||||
Long-term debt |
640,000 | 640,000 | 640,000 | |||||||||
Deferred income taxes |
197,872 | 168,830 | 132,518 | |||||||||
Deferred investment tax credits |
5,489 | 5,670 | 5,853 | |||||||||
Pension and postretirement benefit obligations |
146,137 | 150,499 | 138,615 | |||||||||
Other noncurrent liabilities |
60,428 | 61,372 | 56,353 | |||||||||
Total liabilities |
1,290,384 | 1,384,194 | 1,470,124 | |||||||||
Commitments and contingencies (note 8) |
||||||||||||
Common stockholders equity: |
||||||||||||
Common Stock, $2.25 par value (authorized 40,000,000 shares;
issued and outstanding - 26,781,785 shares) |
60,259 | 60,259 | 60,259 | |||||||||
Additional paid-in capital |
467,258 | 467,160 | 466,990 | |||||||||
Retained earnings |
251,226 | 201,710 | 228,902 | |||||||||
Accumulated other comprehensive loss |
(81,020 | ) | (83,086 | ) | (82,125 | ) | ||||||
Total common stockholders equity |
697,723 | 646,043 | 674,026 | |||||||||
Total liabilities and stockholders equity |
$ | 1,988,107 | $ | 2,030,237 | $ | 2,144,150 | ||||||
See accompanying notes to condensed consolidated financial statements.
- 1 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(Thousands of dollars)
Three Months Ended | Six Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenues |
$ | 477,273 | $ | 581,260 | $ | 839,476 | $ | 1,027,952 | ||||||||
Costs and expenses: |
||||||||||||||||
Cost of sales gas, fuel and purchased power
(excluding depreciation shown below) |
312,171 | 416,976 | 543,388 | 733,210 | ||||||||||||
Operating and administrative expenses |
48,632 | 57,245 | 92,854 | 107,923 | ||||||||||||
Operating and administrative expenses related parties |
6,565 | 6,393 | 7,757 | 9,138 | ||||||||||||
Taxes other than income taxes |
4,894 | 5,022 | 9,422 | 9,626 | ||||||||||||
Depreciation |
12,438 | 12,082 | 25,119 | 24,113 | ||||||||||||
Amortization |
771 | 480 | 1,378 | 961 | ||||||||||||
Other income, net |
(2,535 | ) | (2,611 | ) | (4,052 | ) | (4,704 | ) | ||||||||
382,936 | 495,587 | 675,866 | 880,267 | |||||||||||||
Operating income |
94,337 | 85,673 | 163,610 | 147,685 | ||||||||||||
Interest expense |
10,724 | 10,809 | 21,361 | 22,189 | ||||||||||||
Income before income taxes |
83,613 | 74,864 | 142,249 | 125,496 | ||||||||||||
Income taxes |
33,001 | 30,118 | 56,474 | 49,616 | ||||||||||||
Net income |
$ | 50,612 | $ | 44,746 | $ | 85,775 | $ | 75,880 | ||||||||
See accompanying notes to condensed consolidated financial statements.
- 2 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(Thousands of dollars)
Six Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 85,775 | $ | 75,880 | ||||
Adjustments to reconcile net income to net cash from operating activities: |
||||||||
Depreciation and amortization |
26,497 | 25,074 | ||||||
Deferred income taxes, net |
25,614 | (14,603 | ) | |||||
Provision for uncollectible accounts |
12,176 | 19,846 | ||||||
Other, net |
4,747 | 2,054 | ||||||
Net change in: |
||||||||
Accounts receivable and accrued utility revenues |
(120,350 | ) | (166,819 | ) | ||||
Inventories |
157,734 | 157,091 | ||||||
Deferred fuel and power costs |
(1,135 | ) | 38,983 | |||||
Accounts payable |
(4,804 | ) | 1,924 | |||||
Storage agreements security deposits |
3,500 | 22,500 | ||||||
Other current assets |
(10,407 | ) | (8,942 | ) | ||||
Other current liabilities |
7,880 | 30,968 | ||||||
Net cash provided by operating activities |
187,227 | 183,956 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Expenditures for property, plant and equipment |
(26,170 | ) | (36,831 | ) | ||||
Net costs of property, plant and equipment disposals |
(1,255 | ) | (990 | ) | ||||
Acquisition of CPG, net of cash acquired |
| (298,671 | ) | |||||
Proceeds from sale of CPG propane business assets |
| 32,269 | ||||||
Increase in restricted cash |
(12,573 | ) | (58,576 | ) | ||||
Net cash used by investing activities |
(39,998 | ) | (362,799 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Payment of dividends |
(36,260 | ) | (31,200 | ) | ||||
Issuance of long-term debt |
| 108,000 | ||||||
(Decrease) increase in bank loans |
(117,000 | ) | 121,000 | |||||
Net cash (used) provided by financing activities |
(153,260 | ) | 197,800 | |||||
Cash and cash equivalents (decrease) increase |
$ | (6,031 | ) | $ | 18,957 | |||
CASH AND CASH EQUIVALENTS: |
||||||||
End of period |
$ | 7,492 | $ | 22,440 | ||||
Beginning of period |
13,523 | 3,483 | ||||||
(Decrease) increase |
$ | (6,031 | ) | $ | 18,957 | |||
See accompanying notes to condensed consolidated financial statements.
- 3 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
1. | Nature of Operations |
UGI Utilities, Inc., a wholly owned subsidiary of UGI Corporation (UGI), and its wholly
owned subsidiaries UGI Penn Natural Gas, Inc. (PNG) and UGI Central Penn Gas, Inc. (CPG)
own and operate natural gas distribution utilities primarily located in eastern,
northeastern and central Pennsylvania. UGI Utilities also owns and operates an electric
distribution utility in northeastern Pennsylvania (Electric Utility). UGI Utilities,
Inc.s natural gas distribution utility is referred to herein as UGI Gas; PNGs natural
gas distribution utility is referred to herein as PNG Gas; and CPGs natural gas
distribution utility is referred to herein as CPG Gas. UGI Gas, PNG Gas and CPG Gas are
collectively referred to as Gas Utility. 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.
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. The term UGI Utilities is used sometimes as an abbreviated reference to UGI
Utilities, Inc., or to UGI Utilities, Inc. and its subsidiaries. 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.
2. | Significant Accounting Policies |
Basis of Presentation. The accompanying condensed consolidated financial statements are
unaudited and have been prepared in accordance with the rules and regulations of the U.S.
Securities and Exchange Commission (SEC). They include all adjustments which we consider
necessary for a fair statement of the results for the interim periods presented. Such
adjustments consisted only of normal recurring items unless otherwise disclosed. The
September 30, 2009 condensed consolidated balance sheet data were derived from audited
financial statements but do not include all disclosures required by accounting principles
generally accepted in the United States of America (GAAP). These financial statements
should be read in conjunction with the financial statements and related notes included in
our Annual Report on Form 10-K for the year ended September 30, 2009 (Companys 2009 Annual
Report). Due to the seasonal nature of our businesses, the
results of operations for interim periods are not necessarily indicative of the results to
be expected for a full year.
Comprehensive Income. The following table presents the components of comprehensive income
for the three and six months ended March 31, 2010 and 2009:
Three Months Ended | Six Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net income |
$ | 50,612 | $ | 44,746 | $ | 85,775 | $ | 75,880 | ||||||||
Other comprehensive income (loss) |
1,033 | 171 | 2,066 | (38,347 | ) | |||||||||||
Comprehensive income |
$ | 51,645 | $ | 44,917 | $ | 87,841 | $ | 37,533 | ||||||||
- 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)
Other comprehensive income (loss) includes reclassifications of losses on interest rate
protection agreements and actuarial gains and losses on postretirement benefit plans, net of
reclassifications to net income. On December 31, 2008, we merged two of our defined benefit
pension plans that we sponsored. As a result of the merger, at December 31, 2008, the
Company was required under GAAP to remeasure the combined plans assets and obligations and
record the funded status in our Condensed Consolidated Balance Sheet. The associated
after-tax charge to other comprehensive loss of $38,688 is included in the table above for
the six months ended March 31, 2009.
Restricted Cash. Restricted cash represents those cash balances in our futures brokerage
accounts which are restricted from withdrawal.
Reclassifications. We have reclassified certain prior-year period balances to conform to
the current-period presentation.
Use of Estimates. We make estimates and assumptions when preparing financial statements in
conformity with GAAP. These estimates and assumptions affect the reported amounts of assets
and liabilities, revenues and expenses, as well as the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates.
Income Taxes. As a result of settlements with tax authorities, in December 2009 and December
2008 the Company adjusted its unrecognized tax benefits. The reduction decreased income tax
expense for the six months ended March 31, 2010 and 2009 by $290 and $490, respectively.
3. | Accounting Changes |
Adoption of New Accounting Standards
Intangible Asset Useful Lives. On October 1, 2009, we adopted new accounting guidance which
amends the factors that should be considered in developing renewal or extension assumptions
used to determine the useful life of a recognized intangible asset under GAAP. The intent of
the new guidance is to improve the consistency between the useful life of a recognized
intangible asset under GAAP relating to intangible asset accounting and the period of
expected cash flows used to measure the fair value of the asset under GAAP relating to
business combinations and other applicable accounting literature. The new guidance must be
applied prospectively to intangible assets acquired after the effective date. The adoption
of the new guidance did not impact our financial statements.
Business Combinations. Effective October 1, 2009, we adopted new guidance on the accounting
for business combinations. The new guidance applies to all transactions or other events in
which an entity obtains control of one or more businesses. The new guidance establishes,
among other things, principles and requirements for how the acquirer (1) recognizes and
measures in its financial statements the identifiable assets acquired, the liabilities
assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the
goodwill acquired in a business combination or gain from a bargain purchase; and (3)
determines what information with respect to a business combination should be disclosed. The
new guidance applies prospectively to business combinations for which the acquisition date
is on or after October 1, 2009. Among the more significant changes in accounting for
acquisitions are (1) transaction costs are generally expensed (rather than being included as
costs of the acquisition); (2) contingencies, including contingent consideration, are
generally recorded at fair value with subsequent adjustments recognized in operations
(rather than as adjustments to the purchase price); and (3) decreases in valuation
allowances on acquired deferred tax assets are recognized in operations (rather than
decreases in goodwill). The new guidance did not have an impact on our financial statements.
- 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)
Fair Value Measurements. On January 1, 2010, the Financial Accounting Standards Board
(FASB) issued new guidance with respect to fair value measurements disclosures. The new
guidance requires additional disclosure related to transfers between Levels 1 and 2 and
separate disclosures about purchases, sales, issuances, and settlements related to Level 3.
The new guidance clarifies existing disclosure guidance about inputs and valuation
techniques for fair value measurements and levels of disaggregation. We apply fair value
measurements to certain assets and liabilities, principally commodity and interest rate
derivative instruments. The new disclosures and clarifications of existing disclosures are
effective for interim and annual reporting periods beginning after December 15, 2009 except
for the disclosures about
purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair
value measurements. Those disclosures are effective for fiscal years beginning after
December 15, 2009 (Fiscal 2011) and interim periods thereafter. The adoption of the new
guidance for the quarter ended March 31, 2010 did not have a material effect on our
disclosures.
New Accounting Standards Not Yet Adopted
Enhanced Disclosures of Postretirement Plan Assets. In December 2008, the FASB issued new
guidance requiring more detailed disclosures about employers postretirement plan assets,
including employers investment strategies, major categories of plan assets, concentrations
of risk within plan assets, and valuation techniques used to measure the fair value of plan
assets. The provisions of this annual disclosure guidance are effective for fiscal years
ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to
disclosure only, it will not impact the financial statements.
4. | Segment Information |
We have two reportable segments: (1) Gas Utility and (2) Electric Utility. The accounting
policies of our two reportable segments are the same as those described in the Significant
Accounting Policies note contained in the Companys 2009 Annual Report. We evaluate each
segments profitability principally based upon its income before income taxes. No single
customer represents more than 10% of the total revenues of either Gas Utility or Electric
Utility. There are no significant intersegment transactions. In addition, all of our
reportable segments revenues are derived from sources within the United States.
UGI Penn HVAC Services, Inc. does not meet the quantitative thresholds for separate business
segment reporting under GAAP and has been included in Other.
- 6 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Financial information by business segment follows:
Three Months Ended March 31, 2010:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 477,273 | $ | 445,395 | $ | 31,553 | $ | 325 | ||||||||
Cost of sales |
$ | 312,171 | $ | 291,433 | $ | 20,738 | $ | | ||||||||
Depreciation and amortization |
$ | 13,209 | $ | 12,216 | $ | 993 | $ | | ||||||||
Operating income |
$ | 94,337 | $ | 91,112 | $ | 3,093 | $ | 132 | ||||||||
Interest expense |
$ | 10,724 | $ | 10,258 | $ | 466 | $ | | ||||||||
Income before income taxes |
$ | 83,613 | $ | 80,854 | $ | 2,627 | $ | 132 | ||||||||
Total assets (at period end) |
$ | 1,988,107 | $ | 1,862,489 | $ | 125,618 | $ | | ||||||||
Goodwill (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 12,360 | $ | 11,499 | $ | 861 | $ | |
Three Months Ended March 31, 2009:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 581,260 | $ | 542,796 | $ | 38,118 | $ | 346 | ||||||||
Cost of sales |
$ | 416,976 | $ | 392,823 | $ | 24,153 | $ | | ||||||||
Depreciation and amortization |
$ | 12,562 | $ | 11,587 | $ | 975 | $ | | ||||||||
Operating income |
$ | 85,673 | $ | 80,017 | $ | 5,417 | $ | 239 | ||||||||
Interest expense |
$ | 10,809 | $ | 10,377 | $ | 432 | $ | | ||||||||
Income before income taxes |
$ | 74,864 | $ | 69,640 | $ | 4,985 | $ | 239 | ||||||||
Total assets (at period end) |
$ | 2,144,150 | $ | 2,019,932 | $ | 124,218 | $ | | ||||||||
Goodwill (at period end) |
$ | 176,906 | $ | 176,906 | $ | | $ | | ||||||||
Capital expenditures |
$ | 14,020 | $ | 12,727 | $ | 1,293 | $ | |
- 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)
Six Months Ended March 31, 2010:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 839,476 | $ | 773,204 | $ | 65,552 | $ | 720 | ||||||||
Cost of sales |
$ | 543,388 | $ | 501,193 | $ | 42,195 | $ | | ||||||||
Depreciation and amortization |
$ | 26,497 | $ | 24,515 | $ | 1,982 | $ | | ||||||||
Operating income |
$ | 163,610 | $ | 154,840 | $ | 8,452 | $ | 318 | ||||||||
Interest expense |
$ | 21,361 | $ | 20,504 | $ | 857 | $ | | ||||||||
Income before income taxes |
$ | 142,249 | $ | 134,336 | $ | 7,595 | $ | 318 | ||||||||
Total assets (at period end ) |
$ | 1,988,107 | $ | 1,862,489 | $ | 125,618 | $ | | ||||||||
Good will (at period end) |
$ | 180,145 | $ | 180,145 | $ | | $ | | ||||||||
Capital expenditures |
$ | 26,170 | $ | 24,539 | $ | 1,631 | $ | |
Six Months Ended March 31, 2009:
Reportable Segments | ||||||||||||||||
Gas | Electric | |||||||||||||||
Total | Utility | Utility | Other | |||||||||||||
Revenues |
$ | 1,027,952 | $ | 953,162 | $ | 74,039 | $ | 751 | ||||||||
Cost of sales |
$ | 733,210 | $ | 685,847 | $ | 47,363 | $ | | ||||||||
Depreciation and amortization |
$ | 25,074 | $ | 23,136 | $ | 1,938 | $ | | ||||||||
Operating income |
$ | 147,685 | $ | 136,902 | $ | 10,464 | $ | 319 | ||||||||
Interest expense |
$ | 22,189 | $ | 21,352 | $ | 837 | $ | | ||||||||
Income before income taxes |
$ | 125,496 | $ | 115,550 | $ | 9,627 | $ | 319 | ||||||||
Total assets (at period end) |
$ | 2,144,150 | $ | 2,019,932 | $ | 124,218 | $ | | ||||||||
Good will (at period end) |
$ | 176,906 | $ | 176,906 | $ | | $ | | ||||||||
Capital expenditures |
$ | 36,831 | $ | 34,384 | $ | 2,447 |
5. | Inventories |
Inventories comprise the following:
March 31, | September 30, | March 31, | ||||||||||
2010 | 2009 | 2009 | ||||||||||
Gas Utility natural gas |
$ | 31,693 | $ | 189,747 | $ | 19,227 | ||||||
Materials, supplies and other |
7,172 | 6,851 | 7,538 | |||||||||
Total inventories |
$ | 38,865 | $ | 196,598 | $ | 26,765 | ||||||
From time to time UGI Utilities enters into storage contract administrative agreements
(SCAAs) pursuant to which it has, among other things, released certain storage and
transportation contracts for the terms of the storage agreements. At March 31, 2010, UGI
Utilities had three SCAAs, two of which are scheduled to expire in October 2010 and one that
is scheduled to expire in October 2012 (see Note 9).
- 8 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and
transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain
associated storage inventories upon commencement of the SCAAs, will receive a transfer of
storage inventories at the end of the SCAAs, and makes payments associated with refilling
storage inventories during the terms of the SCAAs.
The historical cost of natural gas storage inventories released under these agreements,
which represent a portion of Gas Utilitys total natural gas storage inventories, and any
exchange receivable (representing amounts of natural gas inventories used by the other
parties to the agreements but not yet replenished) are included in the caption Gas Utility
natural gas in the table above. The carrying value of gas storage inventories released
under these agreements at March 31, 2010, September 30, 2009 and March 31, 2009, comprising
2.8 billion cubic feet (bcf), 9.0 bcf, and 1.8 bcf of natural gas, was $20,469, $77,948
and $14,089, respectively. In conjunction with the SCAAs, at March 31, 2010, September 30,
2009 and March 31, 2009, UGI Utilities held a total of $22,500, $19,000 and $22,500,
respectively, of security deposits received from its SCAAs counterparties which 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 2009 Annual Report. UGI Utilities does not
recover a rate of return on its regulatory assets. The following regulatory assets and
liabilities associated with Gas Utility and Electric Utility are included in our
accompanying Condensed Consolidated Balance Sheets:
March 31, | September 30, | March 31, | ||||||||||
2010 | 2009 | 2009 | ||||||||||
Regulatory assets: |
||||||||||||
Income taxes recoverable |
$ | 81,561 | $ | 79,492 | $ | 75,660 | ||||||
Postretirement benefits |
1,833 | 2,473 | 3,561 | |||||||||
CPG Gas pension and postretirement plans |
8,572 | 8,572 | 5,551 | |||||||||
Environmental costs |
25,301 | 26,877 | 20,665 | |||||||||
Deferred fuel and power costs |
6,662 | 19,584 | 61,067 | |||||||||
Other |
5,932 | 4,546 | 7,135 | |||||||||
Total regulatory assets |
$ | 129,861 | $ | 141,544 | $ | 173,639 | ||||||
Regulatory liabilities: |
||||||||||||
Postretirement benefits |
$ | 9,899 | $ | 9,310 | $ | 9,609 | ||||||
Environmental overcollections |
8,398 | 8,720 | 9,724 | |||||||||
Deferred fuel refunds |
16,789 | 30,846 | 4,736 | |||||||||
Total regulatory liabilities |
$ | 35,086 | $ | 48,876 | $ | 24,069 | ||||||
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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)
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 generation service (GS) rates in the case of Electric Utility.
The clauses provide for periodic adjustments to PGC and GS 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 March 31,
2010 and March 31, 2009 were $7,611 and $81,893, respectively. There were no such unrealized
gains or losses at September 30, 2009.
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 default service costs commencing January 1, 2010
through GS rates, realized and unrealized gains or losses on FTRs associated with periods
beginning January 1, 2010 are included in deferred fuel and power costs or refunds.
Unrealized gains on FTRs at March 31, 2010 were not material.
7. | Defined Benefit Pension and Other Postretirement Plans |
We currently sponsor two defined benefit pension plans (Pension Plans) 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 postretirement life insurance benefits to nearly all active and retired
employees.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Net periodic pension expense and other postretirement benefit costs relating to our
employees include the following components:
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Three Months Ended | Three Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Service cost |
$ | 1,745 | $ | 1,492 | $ | 40 | $ | 2 | ||||||||
Interest cost |
5,284 | 5,263 | 212 | 162 | ||||||||||||
Expected return on assets |
(5,858 | ) | (5,892 | ) | (126 | ) | (130 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost (benefit) |
9 | 7 | (102 | ) | (87 | ) | ||||||||||
Actuarial loss |
1,333 | 1,138 | 89 | 30 | ||||||||||||
Net benefit cost |
2,513 | 2,008 | 113 | (23 | ) | |||||||||||
Change in associated regulatory liabilities |
| | 736 | 803 | ||||||||||||
Net expense |
$ | 2,513 | $ | 2,008 | $ | 849 | $ | 780 | ||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
Six Months Ended | Six Months Ended | |||||||||||||||
March 31, | March 31, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Service cost |
$ | 3,490 | $ | 2,873 | $ | 81 | $ | 66 | ||||||||
Interest cost |
10,568 | 10,717 | 423 | 422 | ||||||||||||
Expected return on assets |
(11,717 | ) | (11,998 | ) | (252 | ) | (260 | ) | ||||||||
Amortization of: |
||||||||||||||||
Prior service cost (benefit) |
18 | 14 | (203 | ) | (174 | ) | ||||||||||
Actuarial loss |
2,666 | 1,311 | 179 | 60 | ||||||||||||
Net benefit cost |
5,025 | 2,917 | 228 | 114 | ||||||||||||
Change in associated
regulatory liabilities |
| | 1,472 | 1,606 | ||||||||||||
Net expense |
$ | 5,025 | $ | 2,917 | $ | 1,700 | $ | 1,720 | ||||||||
Pension Plans assets are held in trust and consist principally of equity and fixed
income mutual funds. It is our general policy to fund amounts for pension benefits equal to
at least the minimum contribution required by ERISA. The Company does not believe it will be
required to make any contributions to the Pension Plans during the year ending September 30,
2010 (Fiscal 2010) for ERISA funding purposes that will have a material effect on its
liquidity. Pursuant to orders previously issued by the PUC, UGI Utilities has established a
Voluntary Employees Beneficiary Association (VEBA) trust to fund and pay UGI Gas and
Electric Utilitys postretirement health care and life insurance benefits referred to above
by depositing into the VEBA the annual amount of postretirement benefit costs determined
under GAAP for postretirement benefits other than pensions. The difference between the
annual amount calculated and the amount included in UGI Gas and Electric Utilitys rates is
deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA
by UGI Utilities were not material
during the six months ended March 31, 2010, nor are they expected to be material for all of
Fiscal 2010.
We also sponsor an unfunded and non-qualified defined benefit supplemental executive
retirement income plan. Net benefit costs associated with this plan for all periods
presented were not material.
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
8. | Commitments and Contingencies |
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned
and operated a number of manufactured gas plants (MGPs) prior to the general availability
of natural gas. Some constituents of coal tars and other residues of the manufactured gas
process are today considered hazardous substances under the Superfund Law and may be present
on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of
subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public Utility
Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility
operations other than certain Pennsylvania operations, including those which now constitute
UGI Gas and Electric Utility.
UGI Utilities does not expect its costs for investigation and remediation of hazardous
substances at Pennsylvania MGP sites to be material to its results of operations because UGI
Gas is currently permitted to include in rates, through future base rate proceedings, a
five-year average of such prudently incurred remediation costs. At March 31, 2010, neither
UGI Gas undiscounted nor its accrued liability for environmental investigation and cleanup
costs was material.
UGI Utilities has been notified of several sites outside Pennsylvania on which private
parties allege MGPs were formerly owned or operated by it or owned or operated by its former
subsidiaries. Such parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating three claims
against it relating to out-of-state sites.
Management believes that under applicable law UGI Utilities should not be liable in those
instances in which a former subsidiary owned or operated an MGP. There could be, however,
significant future costs of an uncertain amount associated with environmental damage caused
by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or
operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the
subsidiarys separate corporate form should be disregarded or (2) UGI Utilities should be
considered to have been an operator because of its conduct with respect to its subsidiarys
MGP.
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South
Carolina Electric & Gas Company (SCE&G), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from
1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI
Utilities controlled operations of the plant from 1910 to 1926 and is liable for
approximately 25% of the costs associated with the site. SCE&G asserts that it has spent
approximately $22,000 in remediation costs and paid $26,000 in third-party claims relating
to the site and estimates that future response costs, including a claim by the United States
Justice Department for natural resource damages, could be as high as $14,000. Trial took
place in March 2009 and the courts decision is pending.
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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)
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens
Communications Company, now known as Frontier Communications Company (Frontier), served a
complaint naming UGI Utilities as a third-party defendant in a civil action pending in the
United States District Court for the District of Maine. In that action, the City of Bangor,
Maine (City) sued Frontier to recover environmental response costs associated with MGP
wastes generated at a plant allegedly operated by Frontiers predecessors at a site on the
Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party
defendants alleging that the third-party defendants are responsible for an equitable share
of any costs Frontier would be required to pay to the City for cleaning up tar deposits in
the Penobscot River. Frontier alleged that through ownership and control of a subsidiary,
Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant
from 1901 to 1928. Frontier made similar allegations of control against another third-party
defendant, CenterPoint Energy Resources Corporation (CenterPoint), whose predecessor owned
the Bangor subsidiary from 1928 to 1944. Frontiers third-party claims were stayed pending a
resolution of the Citys suit against Frontier, which was tried in September 2005. On June
27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup
costs, which were estimated at $18,000. On February 14, 2007, Frontier and the City entered
into a settlement agreement pursuant to which Frontier agreed to pay $7,600. Frontier
subsequently filed the current action against the original third-party defendants, repeating
its claims for contribution. On September 22, 2009, the court granted summary judgment in
favor of co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and
has filed a motion for summary judgment with respect to Frontiers claims.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (KeySpan)
informed UGI Utilities that KeySpan
has spent $2,300 and expects to spend another $11,000 to clean up an MGP site it owns in Sag
Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50%
of these costs as a result of UGI Utilities alleged direct ownership and operation of the
plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York
Department of Environmental Conservation has approved a remedy for the site that is
estimated to cost approximately $10,000. KeySpan believes that the cost could be as high as
$20,000. UGI Utilities is in the process of reviewing the information provided by KeySpan
and is investigating this claim.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.
On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services
Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities
(together the Northeast Companies), in the United States District Court for the District
of Connecticut seeking contribution from UGI Utilities for past and future remediation costs
related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities
in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled
operations of the plants from 1883 to 1941 through control of former subsidiaries that owned
the MGPs. The Northeast Companies estimated that remediation costs for all of the sites
could total approximately $215,000 and asserted that UGI Utilities is responsible for
approximately $103,000 of this amount. The Northeast Companies subsequently withdrew their
claims with respect to three of the sites and UGI Utilities acknowledged that it had
operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court
conducted a trial to determine whether UGI Utilities operated any of the nine remaining
sites that were owned and operated by former subsidiaries. On May 22, 2009, the court
granted judgment in favor of UGI Utilities with respect to all nine sites. After additional
environmental investigations have been performed, there will be a second phase of the trial,
that has not yet been scheduled, in which the court will determine what, if any,
contamination at Waterbury North is related to UGI Utilities period of operation. The
Northeast Companies estimate that remediation costs at Waterbury North could total $25,000.
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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 cannot predict with certainty the final results of any of the environmental claims or
legal actions described above. However, it is reasonably possible that some of them could be
resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable
to estimate any possible losses in excess of recorded amounts. Although we currently
believe, after consultation with counsel, that damages or settlements, if any, recovered by
the plaintiffs in such claims or actions will not have a material adverse effect on our
financial position, damages or settlements could be
material to our operating results or cash flows in future periods depending on the nature
and timing of future developments with respect to these matters and the amounts of future
operating results and cash flows. In addition to the matters described above, there are
other pending claims and legal actions arising in the normal course of our businesses. While
the results of these other pending claims and legal actions cannot be predicted with
certainty, we believe, after consultation with counsel, the final outcome of such other
matters will not have a significant effect on our consolidated financial position, results
of operations or cash flows.
9. | 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 UGI Energy Services, Inc., a
second-tier wholly owned subsidiary of UGI (Energy Services). At March 31, 2010, UGI
Utilities was a party to a three-year SCAA with Energy Services expiring October 31, 2012
and, during the periods covered by the financial statements, was a party to other one-year
SCAAs with Energy Services. Under all of 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 $94 and $7,579
during the three and six months ended March 31, 2010, respectively, and $5,279 and $19,861
during the three and six months ended March 31, 2009, respectively. In conjunction with the
SCAAs, UGI Utilities received security deposits from Energy Services. The amount of such
security deposits, which amounts are included in other current liabilities on the Condensed
Consolidated Balance Sheets, was $7,500, $15,000 and $15,000 as of March 31, 2010, September
30, 2009 and March 31, 2009, respectively.
- 14 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
The volumes and carrying amounts of gas storage inventories released under Energy Services
SCAAs at March 31, 2010, September 30, 2009 and March 31, 2009 are as follows: at March 31,
2010, gas storage inventories comprising approximately 1.1 bcf of natural gas totaling
$8,543; at September 30, 2009, gas storage inventories comprising approximately 7.7 bcf of
natural gas totaling $67,436; and at March 31, 2009, gas storage inventories comprising
approximately 1.3 bcf of natural gas totaling $11,086.
UGI Utilities has gas supply and delivery service agreements with Energy Services pursuant
to which Energy Services provides certain gas supply and related delivery service to Gas
Utility during the months of November through March. In addition, from time to time, Gas
Utility purchases natural gas or pipeline capacity from Energy Services. The aggregate
amount of these transactions (exclusive of transactions pursuant to the SCAAs) during the
three and six months ended March 31, 2010 totaled $5,754 and $22,036, respectively. During
the three and six months ended March 31, 2009, such transactions
totaled $7,078 and $23,064,
respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services.
During the three and six months ended March 31, 2010, revenues associated with such sales to
Energy Services totaled $18,340 and $27,585, respectively. During the three and six months
ended March 31, 2009, such revenues totaled $12,826 and $20,813, respectively. Also from
time to time, the Company purchases natural gas or pipeline capacity from Energy Services
(in addition to the transactions already described above). During the three and six months
ended March 31, 2010, the aggregate amount of such purchases totaled $8,911 and $14,888,
respectively. During the three and six months ended March 31, 2009, such transactions
totaled $4,294 and $10,139, respectively. These transactions did not have a material effect
on the Companys financial position, results of operations or cash flows.
- 15 -
Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
Notes to Condensed Consolidated Financial Statements
(unaudited)
(Thousands of dollars)
10. | Fair Value Measurements |
Derivative Financial Instruments
The following table presents our financial assets and financial liabilities that are
measured at fair value on a recurring basis for each of the fair value hierarchy levels,
including both current and noncurrent portions, as of March 31, 2010, September 30, 2009 and
March 31, 2009:
Quoted | ||||||||||||||||
Prices in | ||||||||||||||||
Active | ||||||||||||||||
Markets for | Significant | |||||||||||||||
Identical | Other | |||||||||||||||
Assets and | Observable | Unobservable | ||||||||||||||
Liabilities | Inputs | Inputs | ||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
March 31, 2010: |
||||||||||||||||
Derivative financial
instruments: |
||||||||||||||||
Assets |
$ | 226 | $ | 299 | $ | | $ | 525 | ||||||||
Liabilities |
$ | (7,616 | ) | $ | | $ | | $ | (7,616 | ) | ||||||
September 30, 2009: |
||||||||||||||||
Derivative
financial
instruments: |
||||||||||||||||
Assets |
$ | 102 | $ | 765 | $ | | $ | 867 | ||||||||
Liabilities |
$ | | $ | | $ | | $ | | ||||||||
March 31, 2009: |
||||||||||||||||
Derivative
financial
instruments: |
||||||||||||||||
Assets |
$ | | $ | 962 | $ | | $ | 962 | ||||||||
Liabilities |
$ | (82,275 | ) | $ | | $ | | $ | (82,275 | ) |
The fair values of our Level 1 exchange-traded derivative contracts are based upon
actively-quoted market prices for identical assets and liabilities. The fair values of the
remainder of our derivative financial instruments, which are designated as Level 2, are
generally based upon recent market transactions and related market indicators.
Other Financial Instruments
The carrying amounts of financial instruments included in current assets and current
liabilities (excluding unsettled derivative instruments and current maturities of long-term
debt) approximate their fair values because of their short-term nature. The carrying amount
and estimated fair value of our long-term debt at March 31, 2010 were $640,000 and $702,100,
respectively. The carrying amount and estimated fair value of our long-term debt at March
31, 2009 were $640,000 and $632,900, 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 type debt.
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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)
11. |
Disclosures About Derivative Instruments, Hedging Activities and Financial Instruments
|
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.
In order to reduce volatility associated with a substantial portion of its electric
transmission congestion costs, Electric Utility obtains FTRs through an annual PJM
Interconnection (PJM) allocation process and by purchases of FTRs at monthly PJM auctions.
FTRs are derivative financial instruments that entitle the holder to receive compensation
for electricity transmission congestion charges that result when there is insufficient
electricity transmission capacity on the electric transmission grid. PJM is a regional
transmission organization that coordinates the movement of wholesale electricity in all or
parts of 14 eastern and midwestern states.
At March 31, 2010 and 2009, the volume of natural gas associated with our unsettled NYMEX
natural gas futures contracts totaled 14.1 million dekatherms and 16.4 million dekatherms,
respectively. The volume of transmission congestion that is subject to FTRs at March 31,
2010 and 2009 totaled 477.6 million kilowatt-hours and 1,017.2 million kilowatt-hours,
respectively.
With respect to natural gas futures and option contracts associated with Gas Utility, gains
and losses on unsettled
natural gas futures and option contracts are recorded in deferred fuel costs on the
Condensed Consolidated Balance Sheets in accordance with the FASBs guidance in Accounting
Standards Codification (ASC) 980 related to rate-regulated entities and reflected in cost
of sales through the PGC mechanism. Because Electric Utility is entitled to fully recover
its default service costs commencing January 1, 2010 pursuant to a January 22, 2009
settlement of its default service rate filing with the PUC, gains and losses on FTRs
associated with periods beginning on or after January 1, 2010 are recorded in regulatory
assets and liabilities in accordance with ASC 980 and reflected in cost of sales through the
GS recovery mechanism (see Note 6). Gains and losses associated with periods prior to January 1, 2010 are
reflected in cost of sales.
In order to reduce operating expense volatility, UGI Utilities from time to time enters into
NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be
used in the operation of its vehicles and equipment. The volumes of gasoline under these
contracts were not material for all periods presented.
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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)
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. At March 31, 2010 there were no unsettled IRPA
contracts outstanding. The amount of net losses associated with IRPAs expected to be
reclassified into earnings during the next twelve months is $1,165.
Derivative Financial Instrument Credit Risk
Our natural gas exchange-traded futures contracts are guaranteed by the NYMEX and have
limited credit risk. These contracts generally require cash deposits in margin accounts. At
March 31, 2010 and 2009, Gas Utilitys restricted cash in brokerage accounts totaled $12,573
and $92,613, respectively. We generally do not have credit-risk-related contingent features
in our derivative contracts.
The following table provides information regarding the balance sheet location and fair
values of derivative assets and liabilities existing as of March 31, 2010 and 2009:
As of March 31:
Derivative Assets | Derivative (Liabilities) | |||||||||||||||||||||||
Balance Sheet | Fair Value | Balance Sheet | Fair Value | |||||||||||||||||||||
Location | 2010 | 2009 | Location | 2010 | 2009 | |||||||||||||||||||
Derivatives Accounted for Under ASC 980: |
||||||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | $ | 226 | $ | | Derivative financial instruments | $ | (7,616 | ) | $ | (81,893 | ) | ||||||||||||
Derivatives Not
Designated as
Hedging Instruments: |
||||||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | 299 | 962 | Derivative financial instruments | | (382 | ) | |||||||||||||||||
Total Derivatives |
$ | 525 | $ | 962 | $ | (7,616 | ) | $ | (82,275 | ) | ||||||||||||||
During the three and six months ended March 31, 2010 and 2009, the amount of IRPA net
losses included in AOCI that were reclassified into net income, and the impact on net income
from changes in the fair value of FTRs not accounted for under ASC 980 and gasoline futures
and swap contracts, were 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 electricity, and service contracts that require
the counterparty to provide commodity storage, transportation or capacity service to meet
our normal sales commitments. Although many of these contracts have the requisite elements
of a derivative instrument, these contracts qualify for normal purchase and normal sale
exception accounting under GAAP because they provide for the delivery of products or
services in quantities that are expected to be used in the normal course of operating our
business and the price in the contract is based on an underlying that is directly associated
with the price of the product or service being purchased or sold.
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UGI UTILITIES, INC. AND SUBSIDIARIES
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
Information contained in this Managements Discussion and Analysis of Financial Condition and
Results of Operations and elsewhere in this Quarterly Report 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 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 businesses, financial
condition or future results. We undertake no obligation to update publicly any forward-looking
statement whether as a result of new information or future events except as required by the federal
securities laws.
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UGI UTILITIES, INC. AND SUBSIDIARIES
ANALYSIS OF RESULTS OF OPERATIONS
The following analyses compare our results of operations for the three months ended March 31, 2010
(2010 three-month period) with the three months ended March 31, 2009 (2009 three-month period)
and the six months ended March 31, 2010 (2010 six-month period) with the six months ended March
31, 2009 (2009 six-month period). Our analyses of results of operations should be read in
conjunction with the segment information included in Note 4 to the condensed consolidated financial
statements.
2010 three-month period compared with 2009 three-month period
Increase | ||||||||||||||||
Three Months Ended March 31, | 2010 | 2009 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 445.4 | $ | 542.8 | $ | (97.4 | ) | (17.9 | )% | |||||||
Total margin (a) |
$ | 154.0 | $ | 150.0 | $ | 4.0 | 2.7 | % | ||||||||
Operating income |
$ | 91.1 | $ | 80.0 | $ | 11.1 | 13.9 | % | ||||||||
Income before income taxes |
$ | 80.9 | $ | 69.6 | $ | 11.3 | 16.2 | % | ||||||||
System throughput bcf |
54.6 | 56.5 | (1.9 | ) | (3.4 | )% | ||||||||||
Heating degree days % (warmer) colder
than normal (b) |
(2.8 | )% | 4.1 | % | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 31.6 | $ | 38.1 | $ | (6.5 | ) | (17.1 | )% | |||||||
Total margin (a) |
$ | 9.1 | $ | 11.9 | $ | (2.8 | ) | (23.5 | )% | |||||||
Operating income |
$ | 3.1 | $ | 5.4 | $ | (2.3 | ) | (42.6 | )% | |||||||
Income before income taxes |
$ | 2.6 | $ | 5.0 | $ | (2.4 | ) | (48.0 | )% | |||||||
Distribution sales gwh |
262.8 | 273.1 | (10.3 | ) | (3.8 | )% |
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 $1.7 million and $2.0 million during the
three-month periods ended March 31, 2010 and 2009, respectively. For financial statement
purposes, revenue-related taxes are included in Taxes other than income taxes in the
Condensed Consolidated Statements of Income. |
|
(b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (NOAA)
for airports located within Gas Utilitys service territory. |
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days
were 2.8% warmer than normal in the 2010 three-month period compared with temperatures that were
4.1% colder than normal in the prior-year period. Total distribution system throughput decreased
1.9 bcf in the 2010 three-month period principally reflecting the effects of the warmer weather on
core-market customers and the continuing effects of the economic recession. 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 $97.4 million during the 2010 three-month period principally
reflecting a decline in revenues from retail core-market customers partially offset by a $16.0
million increase in low-margin off-system sales. The decrease in retail core-market revenues
principally resulted from lower average purchased gas cost (PGC) rates and, to a much lesser
extent, lower retail core-market volumes partially offset by the effects of the PNG Gas and CPG Gas
base operating revenue increases that became effective August 28, 2009. Under Gas Utilitys PGC
recovery 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 $291.4 million in the 2010 three-month period compared with $392.9 million in the
prior-year period principally reflecting the lower average PGC rates and, to a much lesser extent,
the lower retail core-market sales partially offset by the previously mentioned increase in
off-system sales.
Notwithstanding the decrease in core-market volumes, Gas Utility total margin increased
$4.0 million in the 2010 three-month period. The increase reflects the impact of the previously
mentioned PNG Gas and CPG Gas base operating revenue increases.
Gas Utility operating income during the 2010 three-month period increased $11.1 million principally
reflecting lower operating and administrative costs and the previously mentioned increase in total
margin. The 2010 three-month period operating and administrative costs include, among other things,
lower provisions for uncollectible accounts and lower costs associated with environmental matters.
The $11.3 million increase in income before income taxes reflects the previously mentioned higher
operating income and slightly lower interest expense associated with bank loan borrowings.
Electric Utility. Electric Utilitys kilowatt-hour sales in the 2010 three-month period were 3.8%
lower than in the prior year. The decline in sales principally reflects the effects of warmer 2010
three-month period weather on heating-related sales volumes and the continuing effects of the
economic recession. Temperatures based upon heating degree days were approximately 4.8% warmer than
in the prior-year period. Electric Utility revenues decreased $6.5 million principally as a result
of lower default service revenue rates which became effective January 1, 2010 and, to a much lesser
extent, the lower sales. Electric Utility implemented its default service rates effective January
1, 2010 pursuant to a January 22, 2009 settlement of its default service rate filing with the PUC.
This reduced average costs to a residential general and residential heating customer by nearly 10%
and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and
industrial customers. Under default service 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
electric recovery 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 previous Provider of Last resort (POLR) rates in effect prior
to January 1, 2010. Electric Utility cost of sales declined to $20.7 million in the 2010
three-month period compared to $24.2 million in the 2009 three-month period principally reflecting
the effects of the new cost recovery mechanism on cost of sales and the lower sales volumes.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Electric Utility total margin declined $2.8 million in the 2010 three-month period reflecting the
reduction in margin resulting from implementation of default service rates effective January 1,
2010 and, to a much lesser extent, the effects of the lower 2010 three-month sales.
Electric Utility operating income and income before income taxes in the 2010 three-month period
were $2.3 million and $2.4 million lower, respectively, reflecting the lower total margin partially
offset by slightly lower operating and administrative costs including lower uncollectible accounts
expenses.
2010 six-month period compared with 2009 six-month period
Increase | ||||||||||||||||
Six Months Ended March 31, | 2010 | 2009 | (Decrease) | |||||||||||||
(Millions of dollars) | ||||||||||||||||
Gas Utility: |
||||||||||||||||
Revenues |
$ | 773.2 | $ | 953.2 | $ | (180.0 | ) | (18.9 | )% | |||||||
Total margin (a) |
$ | 272.0 | $ | 267.3 | $ | 4.7 | 1.8 | % | ||||||||
Operating income |
$ | 154.8 | $ | 136.9 | $ | 17.9 | 13.1 | % | ||||||||
Income before income taxes |
$ | 134.3 | $ | 115.5 | $ | 18.8 | 16.3 | % | ||||||||
System throughput bcf |
96.9 | 100.5 | (3.6 | ) | (3.6 | )% | ||||||||||
Heating degree days % (warmer) colder
than normal (b) |
(1.4 | )% | 5.4 | % | | | ||||||||||
Electric Utility: |
||||||||||||||||
Revenues |
$ | 65.6 | $ | 74.0 | $ | (8.4 | ) | (11.4 | )% | |||||||
Total margin (a) |
$ | 19.7 | $ | 22.6 | $ | (2.9 | ) | (12.8 | )% | |||||||
Operating income |
$ | 8.5 | $ | 10.5 | $ | (2.0 | ) | (19.0 | )% | |||||||
Income before income taxes |
$ | 7.6 | $ | 9.6 | $ | (2.0 | ) | (20.8 | )% | |||||||
Distribution sales gwh |
505.2 | 525.9 | (20.7 | ) | (3.9 | )% |
bcf billions of cubic feet. gwh millions of kilowatt-hours.
(a) | Gas Utilitys total margin represents total revenues less total cost of sales.
Electric Utilitys total margin represents total revenues less total cost of sales and
revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $3.6 million and $4.1
million during the six-month periods ended March 31, 2010 and 2009, respectively. For
financial statement purposes, revenue-related taxes are included in Taxes other than
income taxes in the Condensed Consolidated Statements of Income. |
|
(b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (NOAA)
for airports located within Gas Utilitys service territory. |
Gas Utility. Temperatures in the Gas Utility service territory based upon heating degree days
were 1.4% warmer than normal in the 2010 six-month period compared with temperatures that were 5.4%
colder than normal in the prior-year period. Total distribution system throughput decreased 3.6
bcf in the 2010 six-month period principally reflecting the effects of the warmer weather on
core-market customers and the continuing effects of the economic recession.
Gas Utility revenues decreased $180.0 million during the 2010 six-month period principally
reflecting a decline in revenues from retail core-market customers. The decrease in retail
core-market revenues principally resulted from lower average PGC rates and the lower retail
core-market volumes partially offset by the effects of the PNG Gas and CPG Gas base operating
revenue
increases that became effective August 28, 2009. Gas Utilitys cost of gas was $501.2 million in
the 2010 six-month period compared with $685.8 million in the prior-year period principally
reflecting the lower average PGC rates and, to a much lesser extent, the lower retail core-market
sales.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Notwithstanding the decrease in distribution system volumes, Gas Utility total margin increased
$4.7 million in the 2009 six-month period. The increase is primarily the result of the PNG Gas and
CPG Gas base operating revenue increases.
Gas Utility operating income during the 2010 six-month period increased $17.9 million principally
reflecting lower operating and administrative costs and the previously mentioned increase in total
margin. The 2010 six-month period operating and administrative costs include, among other things,
lower provisions for uncollectible accounts, lower charges associated with environmental matters
and lower UGI corporate allocated expenses. These decreases in operating and administrative
expenses were partially offset by higher 2010 six-month period pension expense. The increase in
income before income taxes reflects the previously mentioned higher operating income and lower
interest expense due to lower average bank loan borrowings.
Electric Utility. Electric Utilitys kilowatt-hour sales in the 2010 six-month period were 3.9%
lower than in the prior year. The decline in sales principally reflects the effects of warmer 2010
six-month period weather on heating-related sales volumes and the continuing effects of the
economic recession. Temperatures based upon heating degree days were approximately 4.4% warmer than
in the prior-year period. Electric Utility revenues decreased $8.4 million principally as a result
of the previously mentioned lower default service revenue rates effective January 1, 2010 and the
lower sales. Electric Utility cost of sales declined to $42.2 million in the 2010 six-month period
compared to $47.4 million in the 2009 six-month period principally reflecting the effects of the
lower volume sales and the effects on cost of sales of the default service cost recovery mechanism
beginning January 1, 2010.
Electric Utility total margin declined $2.9 million in the 2010 six-month period reflecting the
reduction in margin resulting from the implementation of default service rates effective January 1,
2010 and, to a much lesser extent, the effects of the lower 2010 six-month period sales.
Electric Utility operating income and income before income taxes in the 2010 six-month period were
$2.0 million lower than the prior-year period reflecting the decline in total margin partially
offset by lower distribution system maintenance and uncollectible accounts expenses.
FINANCIAL CONDITION AND LIQUIDITY
Financial Condition
The Companys total debt outstanding at March 31, 2010 was $677 million compared to total debt
outstanding of $794 million at
September 30, 2009. The decrease in total debt reflects a decrease in bank loan borrowings.
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UGI UTILITIES, INC. AND SUBSIDIARIES
UGI Utilities has a $350 million Revolving Credit Agreement which expires in August 2011. At March
31, 2010 and 2009, UGI Utilities had $37 million and $178 million of borrowings outstanding under
its Revolving Credit Agreement, respectively. Borrowings under the Revolving Credit Agreement are
classified as bank loans on the Condensed Consolidated Balance Sheets. During the six months ended
March 31, 2010 and 2009, average daily bank loan borrowings were $136.8 million and $239.8 million,
respectively, and peak bank loan borrowings totaled $203 million and $312 million, respectively.
Peak bank loan borrowings typically occur during the peak heating season months of December and
January when UGI Utilities investment in working capital, principally accounts receivable and
inventories, is greatest. Revolving Credit Agreement borrowings were higher in the prior-year
period due in large part to higher margin deposits associated with natural gas futures
accounts as a result of declines in wholesale natural gas prices.
Cash Flows
Operating activities. Due to the seasonal nature of UGI Utilities businesses, cash flows from our
operating activities are generally strongest during the second and third fiscal quarters when
customers pay for natural gas and electricity consumed during the peak heating season months.
Conversely, operating cash flows are generally at their lowest levels during the first and fourth
fiscal quarters when the Companys investment in working capital, principally accounts receivable
and inventories, is generally greatest. UGI Utilities uses borrowings under its Revolving Credit
Agreement to manage seasonal cash flow needs.
Cash flow provided by operating activities was $187.2 million in the 2010 six-month period compared
to $184.0 million in the prior-year six-month period. Cash flow from operating activities before
changes in operating working capital increased to $154.8 million in the 2010 six-month period from
$108.3 million in the prior-year six-month period. The increase principally reflects higher net
income and greater noncash charges for deferred income taxes. Changes in operating working capital
provided $32.4 million of operating cash flow during the 2010 six-month period compared with $75.7
million used during the prior-year six-month period. Cash flow provided by changes in operating
working capital in the 2010 six-month period includes lower cash from changes in deferred fuel
cost recoveries and storage agreement security deposits.
Investing activities. Cash used by investing activities was $40.0 million in the 2010 six-month
period compared to $362.8 million in the 2009 six-month period. The 2009 six-month period reflects
net cash paid in conjunction with the acquisition of CPG (CPG Acquisition) of $298.7 million less
$32.3 million of net cash received from the sale of the propane assets of a CPG subsidiary to
AmeriGas Propane, L.P., an affiliate of UGI. In addition, changes in restricted cash associated
with our commodity futures brokerage accounts required $12.6 million of cash in the 2010 six-month
period compared with $58.6 million of such cash required in the prior-year period. The
significantly higher cash required in the prior-year six-month period reflects the effects of
declining natural gas prices on margin deposit requirements during that period. Capital
expenditures were lower in the 2010 six-month period due in large part to lower 2010 six-month
period Gas Utility growth capital expenditures.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Financing activities. Cash used by financing activities was $153.3 million in the 2010 six-month
period compared with cash provided by financing activities of $197.8 million in the 2009 six-month
period. Financing activity cash flows are primarily the result of issuances and repayments of
long-term debt, net borrowings and repayments under our Revolving Credit Agreement, cash dividends
paid to UGI, and capital contributions from UGI. We paid cash dividends to UGI totaling
$36.3 million and $31.2 million during the 2010 and 2009 six-month periods, respectively. During
the 2010 six-month period, net bank loan repayments totaled $117 million compared with net bank
loan borrowings of $121 million in the prior-year six-month period. The significantly higher net
cash from bank loan borrowings in the prior-year six-month period was due in large part to the
timing and use of cash contributions made by UGI on September 25, 2008 to fund the CPG Acquisition
on October 1, 2008. A $120 million cash contribution made by UGI on September 25, 2008 was
temporarily used by UGI Utilities in September 2008 to reduce bank loan borrowings. This amount was
then reborrowed on October 1, 2008, along with additional bank loan borrowings, to fund a portion
of the CPG Acquisition. The greater 2009 six-month period bank loan borrowings also reflect, in
part, greater cash needed to fund the higher natural gas futures margin deposits. During the 2009
six-month period, UGI Utilities issued $108 million of 6.375% Senior Notes due 2013 the proceeds of
which were used to fund a portion of the CPG Acquisition. There were no long-term debt transactions
during the 2010 six-month period.
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 fair value of natural gas futures contracts at March 31, 2010 was a loss of $7.6
million. The cost of natural gas derivative financial instruments, net of any associated gains or
losses, is included in Gas Utilitys PGC recovery mechanism. The change in market value of natural
gas futures contracts can require daily deposits of cash in futures accounts. At March 31, 2010 Gas
Utility had $12.6 million of restricted cash associated with natural gas and other
futures accounts with brokers.
Electric Utility purchases its electric power needs from electricity suppliers under fixed-price
energy contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity
can be volatile especially during periods of high demand or tight supply. Electric Utility has
diversified its purchases across several suppliers and entered into bilateral collateral
arrangements with certain of them. Changes in electricity prices could require Electric Utility to
provide cash collateral to its supply counterparties. Electric Utility obtains financial
transmission rights (FTRs) through an annual PJM Interconnection (PJM) auction process and, to
a lesser extent, by purchases at monthly PJM auctions. FTRs are financial instruments that entitle
the holder to receive
compensation for electricity transmission congestion charges that result when there is insufficient
electricity transmission capacity on the electricity transmission grid. PJM is a regional
transmission organization that coordinates the movement of wholesale electricity in all or parts of
14 eastern and midwestern states. At March 31, 2010, the fair value of FTRs was a gain of $0.3
million. Beginning January 1, 2010, Electric Utilitys default service tariffs contain clauses
which permit recovery of all prudently incurred power costs through the application of generation
service (GS) rates. The clauses provide for periodic adjustments to GS 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 FTRs, associated with our Electric Utility operations.
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UGI UTILITIES, INC. AND SUBSIDIARIES
Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and
swap contracts for a portion of gasoline volumes expected to be used in their operations. These
gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected
in other income. The amount of unrealized gains on these contracts and associated volumes under
contract at March 31, 2010 were not material.
Our variable-rate debt includes our bank loan borrowings. These agreements provide for interest
rates on borrowings that are indexed to short-term market interest rates. Our long-term debt is
typically issued at fixed rates of interest based upon market rates for debt having similar terms
and credit ratings. As these long-term debt issues mature, we expect to refinance such debt with
new debt having interest rates reflecting then-current market conditions. 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.
Our unsettled derivative instruments at March 31, 2010 comprise Gas Utilitys exchange-traded
natural gas futures and options contracts, which are included in Gas Utilitys PGC recovery
mechanism, Electric Utilitys FTRs, which are included in Electric Utilitys GS recovery mechanism,
and exchange-traded gasoline futures and swap contracts.
ITEM 4T. CONTROLS AND PROCEDURES
(a) | Evaluation of Disclosure Controls and Procedures |
|
The Companys management, with the participation of the Companys Chief Executive Officer
and Chief Financial Officer, evaluated the effectiveness of the Companys disclosure
controls and procedures as of the end of the period covered by this report. Based on that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the
Companys disclosure controls and procedures as of the end of the period covered by this
report were designed and functioning effectively to provide reasonable assurance that the
information required to be disclosed by the Company in reports filed under the Securities
Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commissions rules and forms, and
(ii) accumulated and communicated to our management, including the Chief Executive Officer
and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. |
||
(b) | Change in Internal Control over Financial Reporting |
|
No change in the Companys internal control over financial reporting occurred during the
Companys most recent fiscal quarter that has materially affected, or is reasonably likely
to materially affect, the Companys internal control over financial reporting. |
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UGI 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, 2009, which could materially affect our business, financial
condition or future results. The risks described in our Annual Report on Form 10-K are not the
only risks facing the Company. Other unknown or unpredictable factors could also have material
adverse effects on future results.
ITEM 6. EXHIBITS
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are
set forth with the name of the registrant, the type of report and last date of the period for which
it was filed, and the exhibit number in such filing):
Incorporation by Reference
Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
12.1 | Computation of
ratio of earnings
to fixed charges
|
|||||||||
31.1 | Certification by
the Chief Executive
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended March 31,
2010, pursuant to
Section 302 of the
Sarbanes-Oxley Act
of 2002 |
|||||||||
31.2 | Certification by
the Chief Financial
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended March 31,
2010, pursuant to
Section 302 of the
Sarbanes-Oxley Act
of 2002 |
|||||||||
32 | Certification by
the Chief Executive
Officer and the
Chief Financial
Officer relating to
the Registrants
Report on Form 10-Q
for the quarter
ended March 31,
2010, pursuant to
Section 906 of the
Sarbanes-Oxley Act
of 2002 |
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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: May 7, 2010 | By: | /s/ John C. Barney | ||
John C. Barney | ||||
Senior Vice President Finance and Chief Financial Officer |
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Table of Contents
UGI UTILITIES, INC. AND SUBSIDIARIES
EXHIBIT INDEX
12.1 | Computation of ratio of earnings to fixed charges |
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31.1 | Certification by the Chief Executive Officer relating to the Registrants
Report on Form 10-Q for the quarter ended March 31, 2010, pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 |
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31.2 | Certification by the Chief Financial Officer relating to the Registrants
Report on Form 10-Q for the quarter ended March 31, 2010, pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 |
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32 | Certification by the Chief Executive Officer and the Chief Financial Officer
relating to the Registrants Report on Form 10-Q for the quarter ended March 31, 2010,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |