Item 1. Financial Statements (unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

ASSETS

Current assets:

Cash and cash equivalents

Restricted cash

Accounts receivable (less allowances for doubtful accounts of $38.0, $38.3 and $52.6, respectively)

Accrued utility revenues

Inventories

Deferred income taxes

Utility regulatory assets

Partnership collateral deposits

Derivative financial instruments

Prepaid expenses and other current assets

 

Total current assets

 

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,822.5, $1,788.8 and $1,640.7, respectively)

 

Goodwill

Intangible assets, net

Other assets

 

Total assets

 

 

LIABILITIES AND EQUITY

Current liabilities:

Current maturities of long-term debt

Bank loans

Accounts payable

Derivative financial instruments

Other current liabilities

 

Total current liabilities

 

Long-term debt

Deferred income taxes

Deferred investment tax credits

Other noncurrent liabilities

 

Total liabilities

 

Commitments and contingencies (note 9)

 

Equity:

UGI Corporation stockholders’ equity:

UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,261,294, 115,261,294 and 115,247,694 shares, respectively)

Retained earnings

Accumulated other comprehensive loss

Treasury stock, at cost

 

Total UGI Corporation stockholders’ equity

Noncontrolling interests

 

Total equity

 

 

Total liabilities and equity

 

Revenues

 

Costs and expenses:

Cost of sales

Operating and administrative expenses

Utility taxes other than income taxes

Depreciation

Amortization

Other income, net

 

 

 

 

Operating income

Loss from equity investees

Interest expense

 

Income before income taxes

Income taxes

 

Net income

Less: net income attributable to noncontrolling interests, principally AmeriGas Partners

 

Net income attributable to UGI Corporation

 

 

Earnings per common share attributable to UGI stockholders:

Basic

 

 

Diluted

 

 

Average common shares outstanding (millions):

Basic

 

 

Diluted

 

 

Dividends declared per common share

 

Net income

Reconcile to net cash from operating activities:

Depreciation and amortization

Gain on sale of Partnership California storage facility

Deferred income taxes, net

Provision for uncollectible accounts

Net change in settled accumulated other comprehensive income (loss)

Other, net

Net change in:

Accounts receivable and accrued utility revenues

Inventories

Utility deferred fuel costs

Accounts payable

Partnership collateral deposits

Other current assets

Other current liabilities

 

Net cash provided (used) by operating activities

 

 

Expenditures for property, plant and equipment

Acquisitions of businesses, net of cash acquired

Proceeds from sale of Partnership California storage facility

Net proceeds from disposals of assets

Increase in restricted cash

Other

 

Net cash used by investing activities

 

 

Dividends on UGI Common Stock

Distributions on AmeriGas Partners publicly held Common Units

Issuance of debt

Repayments of debt

Increase in bank loans

Issuances of UGI Common Stock

 

Net cash provided by financing activities

 

 

 

Cash and cash equivalents decrease

 

 

Cash and cash equivalents:

End of period

Beginning of period

 

Decrease

 

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes and markets energy products and related services. In the United States, we own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; (3) electricity generation facilities; and (4) energy marketing and services businesses. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in France, central and eastern Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the “Operating Partnerships”). AmeriGas Partners and the Operating Partnerships are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At December 31, 2009, the General Partner held a 1% general partner interest and 42.8% limited partner interest in AmeriGas Partners, and an effective 44.4% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,363,679 Common Units held by the general public as limited partner interests.

Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1) conducts an LPG distribution business in France (“Antargaz”); (2) conducts an LPG distribution business in central and eastern Europe (“Flaga”); and (3) participates in an LPG business in the Nantong region of China. We refer to our foreign operations collectively as “International Propane.” Through other subsidiaries, Enterprises also conducts an energy marketing and services business primarily in the Mid-Atlantic region of the United States (collectively, “Energy Services”). Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns interests in electricity generation facilities located in Pennsylvania.

Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary UGI Utilities, Inc. (“UGI Utilities”) and its subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities principally located in eastern, northeastern and central Pennsylvania. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s 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.”

Our condensed consolidated financial statements include the accounts of UGI and its controlled subsidiary companies, which, except for the Partnership, are majority owned. We eliminate all significant intercompany accounts and transactions when we consolidate. We report the public’s limited partner interests in the Partnership and the outside ownership interests in certain subsidiaries of Antargaz and Flaga as noncontrolling interests. Entities in which we own 50 percent or less and in which we exercise significant influence over operating and financial policies are accounted for by the equity method.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments which we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2009 condensed consolidated balance sheet data were derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2009 (“Company’s 2009 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

As discussed below, certain prior-period amounts have been adjusted to comply with recently adopted Financial Accounting Standards Board (“FASB”) accounting guidance for the presentation of noncontrolling interests in consolidated financial statements.

Earnings Per Common Share. Basic earnings per share reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards.

Shares used in computing basic and diluted earnings per share are as follows:

Denominator (millions of shares):

Average common shares outstanding for basic computation

Incremental shares issuable for stock options and awards

 

Average common shares outstanding for diluted computation

 

Net income

Other comprehensive income (loss)

 

Comprehensive income (including noncontrolling interests)

Less: comprehensive income attributable to noncontrolling interests

 

Comprehensive income attributable to UGI Corporation

 

Noncontrolling Interests. Effective October 1, 2009, we adopted new guidance regarding the accounting for and presentation of noncontrolling interests in consolidated financial statements. The new guidance changed the accounting and reporting relating to noncontrolling interests in a consolidated subsidiary. Noncontrolling interests ($270.6, $225.4 and $137.4 at December 31, 2009, September 30, 2009 and December 31, 2008, respectively) are now classified within equity on the Condensed Consolidated Balance Sheets, a change from their prior classification between liabilities and stockholders’ equity. Earnings attributable to noncontrolling interests ($47.1 and $69.0 for the three months ended December 31, 2009 and 2008, respectively) is now included in net income and deducted from net income to determine net income attributable to UGI Corporation. In addition, changes in a parent’s ownership interest while retaining control are accounted for as equity transactions and any retained noncontrolling equity investments in a former subsidiary are initially measured at fair value. In accordance with the new guidance, previous periods have been adjusted to conform with the new presentation.

Business Combinations. Effective October 1, 2009, we adopted new guidance on the accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after the date of adoption. Among the more significant changes in accounting for acquisitions are (1) transaction costs will generally be expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, will generally be recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets will be recognized in operations (rather than decreases in goodwill). The new guidance did not have a material impact on our financial statements for the three months ended December 31, 2009.

Intangible Asset Useful Lives. On October 1, 2009, we adopted new accounting guidance which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under GAAP. The intent of the new guidance is to improve the consistency between the useful life of a recognized intangible asset under GAAP relating to intangible asset accounting and the period of expected cash flows used to measure the fair value of the asset under GAAP relating to business combinations and other applicable accounting literature. The new guidance must be applied prospectively to intangible assets acquired after the effective date. The adoption of the new guidance did not impact our financial statements.

Enhanced Disclosures of Postretirement Plan Assets. In December 2008, the FASB issued new guidance requiring more detailed disclosures about employers’ postretirement plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. The provisions of this annual disclosure guidance are effective for fiscal years ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to disclosures only, it will not impact the financial statements.

Transfers of Financial Assets. In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The new guidance is effective for financial asset transfers occurring after the beginning of an entity’s fiscal year that begins after November 15, 2009 (Fiscal 2011). We are currently evaluating the provisions of the new guidance.

The Company’s intangible assets comprise the following:

Goodwill (not subject to amortization)

 

 

Other intangible assets:

Customer relationships, noncompete agreements and other

Trademark (not subject to amortization)

 

Gross carrying amount

Accumulated amortization

 

Net carrying amount

 

The decrease in goodwill and other intangible assets during the three months ended December 31, 2009 principally reflects the effects of currency translation partially offset by acquisitions. Amortization expense of intangible assets was $4.9 and $4.4 for the three months ended December 31, 2009 and 2008, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. Our expected aggregate amortization expense of intangible assets for the next five fiscal years is as follows: Fiscal 2010 — $17.0; Fiscal 2011 — $16.5; Fiscal 2012 — $16.4; Fiscal 2013 — $15.9; Fiscal 2014 — $13.8.

We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) or regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment comprising Flaga and our international propane equity investments (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy Services. We refer to both international segments collectively as “International Propane.”

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2009 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Energy Services segments principally based upon their income before income taxes.

Revenues

 

Cost of sales

 

Segment profit:

Operating income

Loss from equity investees

Interest expense

 

Income before income taxes

 

 

Partnership EBITDA (c)

Noncontrolling interests’ net income

Depreciation and amortization

Capital expenditures

Total assets (at period end)

Bank loans (at period end)

Investments in equity investees (at period end)

Goodwill (at period end)

Revenues

 

Cost of sales

 

Segment profit:

Operating income

(Loss) income from equity investees

Interest expense

 

Income before income taxes

 

 

Partnership EBITDA (c)

Noncontrolling interests’ net income (loss)

Depreciation and amortization

Capital expenditures

Total assets (at period end)

Bank loans (at period end)

Investments in equity investees (at period end)

Goodwill (at period end)

Partnership EBITDA

Depreciation and amortization

Noncontrolling interests (i)

 

Operating income

 

Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in April 2010, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility back-up purchasers.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the FASB’s guidance for accounting for transfers and servicing of financial assets and extinguishments of liabilities. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.

During the three months ended December 31, 2009 and 2008, Energy Services sold trade receivables totaling $296.7 and $358.4, respectively, to ESFC. During the three months ended December 31, 2009 and 2008, ESFC sold an aggregate $120.2 and $169.3, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2009, the outstanding balance of ESFC trade receivables was $88.3 which is net of $27.6 that was sold to the commercial paper conduit and removed from the balance sheet. At December 31, 2008, the outstanding balance of ESFC trade receivables was $44.3 which is net of $87.9 that was sold to the commercial paper conduit.

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 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:

Regulatory assets:

Income taxes recoverable

Postretirement benefits

CPG Gas pension and postretirement plans

Environmental costs

Deferred fuel costs

Other

 

Total regulatory assets

 

Regulatory liabilities:

Postretirement benefits

Environmental overcollections

Deferred fuel refunds

 

Total regulatory liabilities

 

Deferred fuel costs and refunds. Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for differences between the total amount of purchased gas costs collected from customers and recoverable costs incurred. Net undercollected gas costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel refunds or costs. Unrealized losses on such contracts at December 31, 2009 and December 31, 2008 were $0.1 and $58.1, respectively. There were no such unrealized gains or losses at September 30, 2009.

We sponsor defined benefit pension plans for employees hired prior to January 1, 2009 of UGI, UGI Utilities, CPG, PNG, and certain of UGI’s other wholly owned domestic subsidiaries (“Pension Plans”). We also provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans.

Service cost

Interest cost

Expected return on assets

Amortization of:

Prior service benefit

Actuarial loss

 

Net benefit cost

Change in associated regulatory liabilities

 

Net expense

 

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 Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP relating to postretirement benefits other than pensions. The difference between the annual amount calculated and the amount included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2009, nor are they expected to be material for all of Fiscal 2010.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement income plans. We recorded pre-tax expense associated with these plans of $0.6 and $1.0 for the three months ended December 31, 2009 and 2008.

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 December 31, 2009, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material to UGI Utilities.

UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.

Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s 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 subsidiary’s MGP.

South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and paid $26 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14. Trial took place in March 2009 and the court’s 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 Frontier’s 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. Frontier’s third-party claims were stayed pending a resolution of the City’s suit against Frontier, which was tried in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup costs, which were estimated at $18. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7.6. Frontier subsequently filed the current action against the original third-party defendants, repeating its claims for contribution. On September 22, 2009, the court granted summary judgment in favor of co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has filed for summary judgment with respect to Frontier’s claims.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan believes that the cost could be as high as $20. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites could total approximately $215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. In a second phase of the trial scheduled for early 2010, the court will determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies estimate that remediation costs at Waterbury North could total $25.

AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership has communicated the results of its research to DEC and is awaiting a response before doing any additional investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

On May 27, 2009, the General Partner was named as a defendant in a purported class action lawsuit in the Superior Court of the State of California in which plaintiffs are challenging AmeriGas OLP’s weight disclosure with regard to its portable propane grill cylinders. The complaint purports to be brought on behalf of a class of all consumers in the state of California during the four years prior to the date of the California complaint, who exchanged an empty cylinder and were provided with what is alleged to be only a partially-filled cylinder. The plaintiffs seek restitution, injunctive relief, interest, costs, attorneys’ fees and other appropriate relief.

Since that initial suit, various AmeriGas entities have been named in more than a dozen similar suits that have been filed in various courts throughout the United States. These complaints purport to be brought on behalf of nationwide classes, which are loosely defined as including all purchasers of liquefied propane gas cylinders marketed or sold by AmeriGas OLP and another unaffiliated entity nationwide. The complaints claim that defendants’ conduct constituted unfair and deceptive practices that injured consumers and violated the consumer protection statutes of at least thirty-seven states and the District of Columbia, thereby entitling the class to damages, restitution, disgorgement, injunctive relief, costs and attorneys’ fees. Some of the complaints also allege violation of state “slack filling” laws. Additionally, the complaints allege that defendants were unjustly enriched by their conduct and they seek restitution of any unjust benefits received, punitive or treble damages, and pre-judgment and post-judgment interest. A motion to consolidate the purported class action lawsuits was heard by the Multidistrict Litigation Panel (“MDL Panel”) on September 24, 2009 in the United States District Court for the District of Kansas. By Order, dated October 6, 2009, the MDL Panel transferred the pending cases to the United States District Court for the Western District of Missouri.

On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego have commenced an investigation into AmeriGas OLP’s cylinder labeling and filling practices in California and issued an administrative subpoena seeking documents and information relating to these practices. We are cooperating with these California governmental investigations and we are vigorously defending the lawsuits.

Samuel and Brenda Swiger and their son (the “Swigers”) sustained personal injuries and property damage as a result of a fire that occurred when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion to include customers acquired from Columbia Propane Corporation in August 2001 as additional potential class members and the plaintiffs amended their complaint to name additional parties pursuant to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a crossclaim against Columbia Energy Group, former owner of Columbia Propane Corporation, seeking indemnification for conduct undertaken by Columbia Propane Corporation prior to AmeriGas OLP’s acquisition. Class counsel has indicated that the class is seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys’ fees.

In 2005, the Swigers filed what purports to be a class action in the Circuit Court of Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers of UGI and the General Partner, and their insurance carriers and insurance adjusters. In the Harrison County lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative class for violations of the West Virginia Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil conspiracy. The Swigers have also requested that the Court rule that insurance coverage exists under the policies issued by the defendant insurance companies for damages sustained by the members of the class in the Monongalia County lawsuit. The Circuit Court of Harrison County has not certified the class in the Harrison County lawsuit at this time and, in October 2008, stayed that lawsuit pending resolution of the class action lawsuit in Monongalia County. We believe we have good defenses to the claims in both actions.

French tax authorities levy various taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of the entity’s tangible fixed assets. Antargaz has recorded liabilities for business taxes related to various classes of equipment. Changes in the French government’s interpretation of the tax laws or in the tax laws themselves could have either an adverse or a favorable effect on our results of operations.

Antargaz Competition Authority Matter. In June 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Antargaz did not have any further contact with the DGCCRF regarding this matter until February 2007, when it received a letter from the DGCCRF requesting documents and information relating to Antargaz’ pricing policies and practices. In March 2007, and again in August 2007, the DGCCRF requested additional information from Antargaz and three joint ventures in which it participates. In July 2008, France’s Autorité de la concurrence (“Competition Authority”) interviewed Mr. Varagne, as President of Antargaz and President of the industry association, Comité Français du Butane et du Propane, about competitive practices in the LPG cylinder market in France.

On July 21, 2009, Antargaz received a Statement of Objections from the Competition Authority with respect to the investigation of Antargaz by the DGCCRF. A Statement of Objections (“Statement”) is part of French competition proceedings and generally follows an investigation under French competition laws. The Statement sets forth the Competition Authority’s findings; it is not a judgment or final decision. The Statement alleges that Antargaz engaged in certain anti-competitive practices in violation of French and European Union civil competition laws related to the cylinder market during the period from 1999 through 2004. The alleged violations occurred principally during periods prior to March 31, 2004, when UGI first obtained a controlling interest in Antargaz.

We have completed our review of the Statement of Objections and the related evidence and filed our written response with the Competition Authority on October 21, 2009. The Competition Authority will undertake a review of Antargaz’ response and begin preparation of its final pleading on the claims. This process is anticipated to take several months and Antargaz will have the opportunity to prepare a response to the Competition Authority’s final pleading. Based on an assessment of the information contained in the Statement, during the quarter ended June 30, 2009 we recorded a provision of $10.0 (€7.1) related to this matter. The final resolution could result in payment of an amount significantly different from the amount we have recorded. We are unable to predict the timing of the final resolution of this matter.

We cannot predict with certainty the final results of any of the environmental or other pending claims or legal actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. While the results of these other pending claims and legal actions cannot be predicted with certainty, we believe, after consultation with counsel, the final outcome of such other matters will not have a significant effect on our consolidated financial position, results of operations or cash flows.

The following table sets forth changes in UGI’s equity and the equity of the noncontrolling interests for the three months ended December 31, 2009 and 2008:

 

Balance September 30, 2009

Net income

Net gains on derivative instruments

Reclassifications of net (gains) losses on derivative instruments

Benefit plans

Foreign currency translation adjustments

 

Comprehensive income

Dividends and distributions

Transactions with owners

Other

 

Balance December 31, 2009

 

 

Balance September 30, 2008

Net income

Net losses on derivative instruments

Reclassifications of net losses on derivative instruments

Benefit plans

Foreign currency translation adjustments

 

Comprehensive income

Dividends and distributions

Transactions with owners

Other

 

Balance December 31, 2008

 

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of December 31, 2009 and 2008:

Derivative financial instruments:

Assets

Liabilities

 

Derivative financial instruments:

Assets

Liabilities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk, (2) interest rate risk and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because our derivative instruments, other than FTRs and gasoline futures and swap contracts (as further described below), generally qualify as hedges under GAAP or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.

In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. Certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases.

Gas Utility’s 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 Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2009, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures contracts was not material. With respect to natural gas futures contracts associated with our Gas Utility, gains and losses on natural gas futures contracts are recorded in deferred fuel costs on the Condensed Consolidated Balance Sheets in accordance with FASB’s guidance in Accounting Standards Codification (“ASC”) 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Energy Services purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its default service costs commencing January 1, 2010 pursuant to a January 22, 2009 settlement of its default service filing with the PUC, Electric Utility FTRs associated with periods beginning January 1, 2010 are recorded at fair value with changes in fair value recorded as regulatory assets or liabilities in accordance with ASC 980 and will be reflected in cost of sales through the default service recovery mechanism. Electric Utility FTRs associated with periods prior to January 2010 were recorded at fair value with changes in fair value reflected in cost of sales. Energy Services’ FTRs are recorded at fair value with changes in fair value reflected in cost of sales.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. The volumes of gasoline under these contracts, the associated fair values and the effect on net income were not material for all periods presented.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Energy Services enters into NYMEX and over-the-counter natural gas and electricity futures contracts.

At December 31, 2009, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

LPG (millions of gallons)

Natural gas (millions of dekatherms)

Electricity (millions of kilowatt-hours)

The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 15 months with a weighted average of 3 months. The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 38 months with a weighted average of 8 months. The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with electricity price risk is 24 months with a weighted average of 8 months. The volume of electric transmission congestion that is subject to FTRs (excluding Electric Utility) at December 31, 2009 totaled 453.0 million kilowatt-hours. The maximum period over which we are economically hedging such electricity congestion with FTRs is 5 months.

We account for commodity price risk contracts (other than our Gas Utility natural gas futures contracts, gasoline futures and swap contracts and FTRs) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Consolidated Statements of Income. At December 31, 2009, the amount of net gains associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $15.6.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At December 31, 2009, the total notional amount of our unsettled IRPAs was $150. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of debt forecasted to occur in June 2010.

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial portion of its two term loans through their scheduled maturity dates in 2011 and 2014 through the use of pay-fixed, receive-variable interest rate swap agreements. As of December 31, 2009, the total notional amount of our interest rate swaps was €409.9.

We account for IRPAs and interest rate swaps as cash flow hedges. Changes in the fair values of IRPAs and interest rate swaps are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At December 31, 2009, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months based upon current fair values is $2.2.

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% — 20% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At December 31, 2009, we were hedging a total of $89.0 of U.S. dollar denominated LPG purchases. The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with the dollar denominated purchases of LPG is 24 months with a weighted average of 10 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investment. At December 31, 2009, we were hedging a total of €30.8 of our euro-denominated net investments. As of December 31, 2009, our foreign currency contracts extend through December 2011.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At December 31, 2009, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.3. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At December 31, 2009, restricted cash in brokerage accounts totaled $9.6. Although we have concentrations of credit risk associated with derivative financial instruments held by certain derivative financial instrument counterparties, the maximum amount of loss due to credit risk that, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties that make up the concentration failed to perform according to the terms of their contracts was not material at December 31, 2009. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the balance sheet location and fair value of derivative assets and liabilities existing as of December 31, 2009:

 

Commodity contracts:

LPG

Derivative financial instruments and Other assets

Derivative financial instruments

 

Natural gas

 

Derivative financial instruments

Derivative financial instruments and Other noncurrent liabilities

 

Electricity

 

Derivative financial instruments and Other noncurrent liabilities

 

Foreign currency contracts

 

Derivative financial instruments

Derivative financial instruments and Other noncurrent liabilities

Interest rate contracts

 

Derivative financial instruments

Derivative financial instruments and Other noncurrent liabilities