ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
With the exception of the matters set forth below, no material legal proceedings are pending involving UGI Utilities, or any of its properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of the Company’s business.
Environmental Matters - Manufactured Gas Plants
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, UGI Utilities divested all of its utility operations other than those which now constitute UGI Gas and Electric Utility by the early 1950s.
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 Utilities (excluding UGIPNG) is currently permitted to include in rates, through future base rate proceedings, prudently incurred remediation costs associated with such sites.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly owned subsidiary, UGIPNG, UGIPNG became party to a Multi-site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of activities associated with environmental investigation and remediation work at 11 currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, environmental expenditures, including costs to perform work on the Properties, are capped at $1.1 million in any calendar year. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates at the end of 15 years but may be terminated by either party at the end of any two-year period beginning with the effective date. In accordance with existing regulatory practices of the PUC, UGIPNG currently amortizes as removal cost over a five-year period site-specific environmental investigation and remediation costs.
UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities 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 four claims against it relating to out-of-state sites.
City of Bangor, Maine v. Citizens Communications Co. In April 2003, Citizens Communications Company (“Citizens”) 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 plaintiff, City of Bangor, Maine (“City”), sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizens’ third-party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March of 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. The court has stayed further proceedings while Citizens and the City discuss settlement. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs.
Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70 million.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order, which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, UGI Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On October 2, 2006, the United States Supreme Court entered an order inviting the Solicitor General to file a brief expressing the views of the United States in this case.
Atlanta Gas Light Company v. UGI Utilities, Inc. By letter dated July 29, 2003, Atlanta Gas Light Company (“AGL”) served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. On March 22, 2005, the trial court granted UGI Utilities’ motion for summary judgment. AGL appealed, and on September 6, 2006, the Eleventh Circuit Court of Appeals affirmed the trial court’s entry of summary judgment, effectively terminating the case.
Savannah, Georgia Matter. AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55 million. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million 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 million. KeySpan believes that the cost could be as high as $20 million. 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. The Northeast Companies estimate that remediation costs for all of the sites would total approximately $215 million and assert that UGI Utilities is responsible for approximately $103 million of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23 million. UGI Utilities believes that it has good defenses to the claim.
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 United States District Court for the District 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 UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site and estimates that future remediation costs could be as high as $2.5 million. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities believes that it has good defenses to the claim.
PART II:
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
All of the outstanding shares of the Company’s Common Stock are owned by UGI and are not publicly traded.
Dividends
Cash dividends declared on the Company’s Common Stock totaled $37.6 million in fiscal year 2006, $38.5 million in fiscal year 2005 and $45.0 million in fiscal year 2004.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Business Overview
UGI Utilities, a wholly owned subsidiary of UGI Corporation, owns and operates two natural gas distribution utilities located in parts of eastern and northeastern Pennsylvania, and an electricity distribution utility in northeastern Pennsylvania. UGI Utilities is regulated by the Pennsylvania Public Utility Commission (“PUC”). UGI Gas’ rate of customer growth exceeds the national averages for local gas distribution companies (“LDCs”), and its proximity to major population centers and its extensive transportation infrastructure makes its service area a desired location for homes and businesses. Because many customers use natural gas and electricity for heating purposes, Gas Utility’s and to a lesser extent Electric Utility’s results are seasonal with the peak-heating season comprising the months of November through March.
On August 24, 2006, UGI Utilities, through its subsidiary, UGIPNG, acquired certain assets and assumed certain liabilities of Southern Union Company’s (“SU’s”) PG Energy Division, a natural gas LDC located in northeastern Pennsylvania (“PG Energy Acquisition”). The PG Energy LDC serves approximately 158,000 customers. The results of the acquired LDC are included in our consolidated results beginning August 24, 2006. We expect to obtain operating and financial synergies as we integrate the acquired businesses with our existing operations over time.
In conducting its business operations, the Company’s management focuses its attention on those factors it believes have a significant effect on the successful operation of its businesses. These factors include, among others, regulation by the PUC, pursuing customer growth in its service territories and controlling operating costs in order to maintain competitive prices. Year-to-year weather variations can have a significant impact on the Company’s results. To a lesser extent, customer behavior in response to increases and volatility in energy costs can also affect the Company’s results. Gas Utility’s tariffs contain purchased gas cost rates that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. These tariffs provide for annual increases or decreases in rates that Gas Utility charges for natural gas sold by it to reflect projected costs of purchased gas. These rates may be adjusted quarterly or, under certain conditions monthly, to reflect the actual cost of gas. Because of this ratemaking process, there is limited commodity price risk associated with Gas Utility operations. Electric Utility is subject to commodity price risk for electricity as its rates for electric generation under Provider of Last Resort (“POLR”) settlements contain rate caps which provide limited protection against electricity price increases. Management attempts to reduce natural gas product cost volatility through the use of call options, natural gas futures contracts, fixed-price forward contracts and storage services. Management attempts to reduce electric price volatility by entering into price swap agreements and fixed-price forward contracts. Because a number of Gas Utility’s customers have the ability to switch to an alternate fuel at any time and are therefore served on an interruptible basis, profitability for these customers is affected by the difference between the delivered cost of gas and the delivered cost of the alternate fuel in addition to the frequency and duration of service interruptions.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) compares the results of the Company’s operations covering the three-year period ended September 30, 2006. The MD&A should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the business segment information in Note 11. The operations of UGIPNG are referred to as PNG Gas and the operations of PNG Gas and UGI Gas are collectively referred to as “Gas Utility.”
Fiscal 2006 Compared with Fiscal 2005
bcf - billions of cubic feet. gwh - millions of kilowatt hours.
(a) Gas Utility’s total margin represents total revenues less cost of sales. Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $5.3 million in Fiscal 2006 and $5.2 million in Fiscal 2005. For financial statement purposes, revenue-related taxes are included in “Taxes other than income taxes” on the Consolidated Statements of Income.
(b) Deviation from average heating degree days based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for four airports located within UGI Gas’ service territory. Fiscal 2005 degree day statistics have been restated to reflect the current-year, four-location average from the previous single location statistic. PNG Gas’ degree days for the period from August 24, 2006 through September 30, 2006 were not material and have been excluded.
Gas Utility. Temperatures in Gas Utility’s service territory based upon heating degree days were 8.7% warmer than normal in Fiscal 2006 compared with temperatures that were 2.0% warmer than normal in Fiscal 2005. Total distribution system throughput declined 2.1 bcf in Fiscal 2006 despite 2.7 bcf of throughput contributed by PNG Gas’ operations during the period from August 24, 2006 through September 30, 2006. Notwithstanding year-over-year growth in the number of UGI Gas’ firm- residential, commercial and industrial (“retail core-market”) customers, its Fiscal 2006 throughput was approximately 6% lower than in Fiscal 2005 primarily due to a reduction in retail core-market customer usage largely resulting from warmer weather and customer conservation in response to the pass through of higher natural gas costs.
The increase in Gas Utility revenues during Fiscal 2006 is principally the result of an $86.6 million increase in UGI Gas’ retail core-market revenues reflecting higher average purchased gas cost (“PGC”) rates, $43.0 million of higher revenues from UGI Gas’ low-margin off-system sales and, to a much lesser extent, revenues from PNG Gas subsequent to the PG Energy Acquisition. Increases or decreases in retail core-market customer revenues and cost of sales results principally from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, 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 amount 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 the pass through nature of the PGC recovery mechanism, increases or decreases in the gas costs associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $522.9 million in Fiscal 2006 compared to $390.1 million in Fiscal 2005 largely reflecting the effects of the higher PGC rates, the higher low-margin off-system sales and, to a much lesser extent, cost of gas associated with PNG Gas’ operations subsequent to the PG Energy Acquisition.
The $6.2 million increase in Gas Utility total margin in Fiscal 2006 principally reflects greater margin generated from higher average interruptible delivery service unit margins and margin from PNG Gas partially offset by lower retail core-market margin. The increase in average interruptible delivery service unit margins reflects an increase in the spread between delivered prices for natural gas and alternative fuels, principally oil. The lower gross margin from retail core-market customers largely reflects the previously mentioned lower average usage per customer.
Gas Utility operating income increased $2.6 million in Fiscal 2006 as the $6.2 million increase in total margin was partially offset by a $2.6 million increase in depreciation and amortization expense, including depreciation expense associated with PNG Gas, and slightly higher operating and administrative expenses. Fiscal 2006 operating and administrative expenses were slightly higher than in Fiscal 2005 reflecting operating and administrative expenses from PNG Gas and higher uncollectible accounts and customer assistance expense, partially offset by lower distribution system expenses resulting in large part from the mild heating-season weather and lower stock-based compensation expense.
The decrease in Gas Utility income before income taxes in Fiscal 2006 reflects the increase in operating income which was more than offset by higher interest expense. The higher interest expense resulted from higher average short-term debt outstanding, higher short-term interest rates and interest on long-term debt associated with the PG Energy Acquisition.
Electric Utility. Electric Utility’s Fiscal 2006 kilowatt-hour sales decreased 1.6% principally reflecting the effects of warmer heating-season weather. Electric Utility revenues increased 2.0% principally reflecting the effects of a 3.0% increase in its Provider of Last Resort (“POLR”) electric generation rates effective January 1, 2006 partially offset by the lower kilowatt-hour sales. Electric Utility’s cost of sales increased to $51.0 million in Fiscal 2006 from $47.8 million in Fiscal 2005 as a result of higher per-unit purchased power costs partially offset by the lower kilowatt-hour sales. Electric Utility total margin in Fiscal 2006 decreased $1.4
million principally as a result of the lower kilowatt-hour sales and the increase in per-unit purchased power costs. In accordance with the terms of its POLR settlement which became effective in June 2006, Electric Utility expects to increase its POLR rates effective January 1, 2007 which will affect all metered customers. This increase is expected to raise the average cost to residential customers by approximately 35% over the costs in effect during calendar year 2006.
Electric Utility operating income decreased $0.9 million reflecting the decrease in total margin and slightly higher depreciation and amortization expense slightly offset by lower operating and administrative expenses. The decrease in Electric Utility income before income taxes in Fiscal 2006 reflects the decrease in operating income and higher interest expense resulting from higher average short-term debt outstanding and higher short-term interest rates.
Fiscal 2005 Compared with Fiscal 2004
bcf - billions of cubic feet. gwh - millions of kilowatt hours.
(a) Electric Utility’s total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes of $5.2 million in Fiscal 2005 and $4.8 million in Fiscal 2004.
Gas Utility. Weather in Gas Utility’s service territory based upon heating degree days was 2.0% warmer than normal in Fiscal 2005 compared with weather that was 2.9% warmer than normal in Fiscal 2004. Total distribution system throughput increased in Fiscal 2005 due primarily to greater interruptible delivery service volumes. Notwithstanding the volume effects of the slightly colder weather and an increase in the number of retail core-market customers, Fiscal 2005 retail core-market throughput was substantially equal to Fiscal 2004 primarily due to a reduction in customer usage per degree day. We believe that the lower usage per degree day was primarily the result of conservation in response to higher natural gas prices.
The increase in Gas Utility revenues during Fiscal 2005 is principally the result of a $53.4 million increase in retail core-market revenues reflecting higher average PGC rates and, to a lesser extent, the increase in throughput and higher revenues from interruptible customers. These increases were partially offset by a $37.2 million decrease in revenues from low-margin off-system sales. Gas Utility’s cost of gas was $390.1 million in Fiscal 2005 compared to $368.9 million in Fiscal 2004 reflecting the effects of the higher PGC rates partially offset by lower cost of sales associated with lower off-system sales.
The $3.5 million increase in Gas Utility total margin in Fiscal 2005 principally reflects greater margin generated from higher interruptible delivery service volumes and higher average interruptible delivery service unit margins. The increase in average interruptible delivery service unit margins reflects an increase in the spread between delivered prices for natural gas and alternative fuels, principally oil. Gross margin from retail core-market customers was relatively stable as lower usage per degree day was offset by an increase in the number of customers.
Gas Utility operating income increased $1.5 million in Fiscal 2005 as the $3.5 million increase in total margin and a $1.9 million increase in other income were partially offset by higher operating and administrative expenses and a $1.2 million increase in depreciation and amortization. The increase in other income is due in large part to the absence of costs recorded in Fiscal 2004 related to a regulatory claim resulting from the discontinuance of natural gas service to certain customers. Fiscal 2005 operating and administrative expenses were slightly higher than in Fiscal 2004 as a $1.9 million increase in uncollectible accounts and customer assistance expenses, the absence of environmental insurance settlements received in the prior year and higher professional services expenses were partially offset by lower injuries and damages and distribution system expenses. The increase in depreciation expense reflects the normal effects of yearly capital expenditures. The increase in Gas Utility income before income taxes in Fiscal 2005 reflects the increase in operating income partially offset by higher interest expense resulting from higher average short-term debt outstanding and higher short-term interest rates.
Electric Utility. Electric Utility’s Fiscal 2005 kilowatt-hour sales increased principally reflecting slightly colder Fiscal 2005 heating-season weather and warmer Fiscal 2005 cooling-season weather which increased sales for air conditioning. The increase in Electric Utility revenues principally reflects the effects of a 4.5% increase in its POLR electric generation rates effective January 1, 2005 and the higher kilowatt-hour sales. Electric Utility’s cost of sales increased to $47.8 million in Fiscal 2005 from $43.3 million in Fiscal 2004 as a result of higher per-unit purchased power costs and the higher sales.
Electric Utility total margin in Fiscal 2005 increased $1.6 million principally as a result of the previously mentioned increase in POLR rates and the higher kilowatt-hour sales partially offset by the increase in per-unit purchased power costs. Operating income and income before income taxes in Fiscal 2005 were higher than the prior year as the increase in total margin was partially offset by higher operating and administrative costs, principally higher incentive compensation and distribution system maintenance expenses.
PG Energy Acquisition
On January 26, 2006, UGI signed a definitive agreement to acquire the natural gas utility business of PG Energy from Southern Union Company for approximately $580 million in cash, subject to certain adjustments associated with the working capital of the acquired business. UGI assigned its rights under the Purchase and Sale Agreement to UGIPNG. The transaction was approved by the PUC and effective August 24, 2006, our wholly-owned subsidiary, UGIPNG acquired the assets and liabilities of the PG Energy business. The PG Energy business serves approximately 158,000 customers in thirteen counties in northeastern Pennsylvania. The cash payment of $580 million was funded by UGI Utilities with net proceeds from the issuance of $275 million of UGI Utilities’ bank loans under a Credit Agreement dated as of August 18, 2006 (the “Bridge Loan”), cash capital contributions from UGI of $265 million and $40 million under its revolving credit agreement for working capital. In September 2006, UGI Utilities repaid the Bridge Loan with proceeds from the issuance of $175 million of 5.753% Senior Notes due 2016 and $100 million of 6.206% Senior Notes due 2036.
FINANCIAL CONDITION AND LIQUIDITY
Capitalization and Liquidity
UGI Utilities’ total debt outstanding was $728.0 million at September 30, 2006. Included in this amount is $216.0 million of bank loans outstanding. In September 2006, UGI Utilities issued $175 million of 5.753% Senior Notes due 2016 and $100 million of 6.206% Senior Notes due 2036 and used the proceeds to fund a portion of the $580 million PG Energy Acquisition purchase price.
UGI Utilities has a revolving credit agreement under which it may borrow up to a total of $350 million. This agreement is currently scheduled to expire in August 2007 but may be automatically extended by UGI Utilities to August 2011. At September 30, 2006, there was $216.0 million outstanding under our revolving credit agreement. In the past, UGI Utilities also entered into short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs. Amounts outstanding under the revolving credit agreement and the uncommitted arrangements are classified as bank loans on the Consolidated Balance Sheets. The revolving credit agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. During Fiscal 2006 and Fiscal 2005, peak bank loan borrowings totaled $219.0 million and $91.4 million, respectively. Peak bank loan borrowings have typically occurred during the peak heating season months of December and January. Average daily bank loan borrowings were $118.4 million in Fiscal 2006 and $52.9 million in Fiscal 2005. The increase in average and peak bank loan borrowings during Fiscal 2006 reflects in large part borrowings to fund increased working capital primarily resulting from higher natural gas prices and borrowings related to the working capital of PNG Gas.
UGI Utilities has a shelf registration statement with the U.S. Securities and Exchange Commission under which it may issue up to $75 million of Medium-Term Notes or other debt securities.
Based upon cash expected to be generated from our operations, borrowings under our revolving credit agreement and the Company’s ability to issue debt under its Medium-Term Note program, management believes the Company will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2007. For additional discussion of UGI Utilities’ long-term debt and revolving credit agreement, see Note 4 to Consolidated Financial Statements.
Cash Flows
Operating activities. Due to the seasonal nature of UGI Utilities’ businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for 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 Company’s investment in working capital, principally accounts receivable and inventories, is generally greatest. UGI Utilities uses short-term borrowings, primarily borrowings under its revolving credit agreement as well as borrowings under uncommitted arrangements, to manage these seasonal cash flow needs.
Cash flow from operating activities was $10.7 million in Fiscal 2006, $68.3 million in Fiscal 2005 and $67.0 million in Fiscal 2004. Cash flow from operating activities before changes in operating working capital was $93.8 million in Fiscal 2006, $86.3 million in Fiscal 2005 and $92.9 million in Fiscal 2004. Changes in operating working capital used $83.1 million in Fiscal 2006, $18.0 million Fiscal 2005 and $26.0 million in Fiscal 2004 of operating cash flow. The significant decrease in cash flow from operating activities reflects a $65.1 million decrease in cash flow from changes in operating working capital, principally greater cash required to fund natural gas storage inventories and changes in accounts payable, a decrease in cash flow as a result of changes in deferred fuel costs during the period and the refund of $13.5 million in electricity supplier collateral deposits compared to the receipt of $11.0 million of such deposits in Fiscal 2005. The greater cash requirements to fund working capital principally reflect the effects of higher natural gas costs in Fiscal 2006 and higher natural gas storage inventory volumes at the end of Fiscal 2006.
Investing activities. Cash used by investing activities was $647.8 million in Fiscal 2006, $47.5 million in Fiscal 2005 and $42.4 million in Fiscal 2004. The increase in cash used by investing activities reflects the preliminary purchase price of the PG Energy Acquisition and, to a lesser extent, increased capital expenditures. Fiscal 2006 capital expenditures principally reflect (1) greater UGI Gas capital expenditures, (2) capital expenditures made by PNG Gas subsequent to its acquisition on August 24, 2006, and (3) greater Electric Utility capital expenditures principally associated with substation improvements.
Financing activities. Cash provided by financing activities was $637.4 million in Fiscal 2006 compared with cash used by financing activities of $18.2 million in Fiscal 2005 and $24.8 million in Fiscal 2004. Financing activity cash flows are primarily the result of issuances and repayments of long-term debt, net short-term borrowings including borrowings under revolving credit agreements and other uncommitted arrangements, cash dividends to UGI, and capital contributions from UGI. As previously mentioned, we issued $175 million of 5.753% Senior Notes due 2016 and $100 million of 6.206% Senior Notes due 2036 and received $265 million in capital contributions from UGI, all of which were used to fund the PG Energy Acquisition. During Fiscal 2006, net bank loan borrowings totaled $134.8 million compared with $20.3 million in the prior-year. Included in Fiscal 2006 net bank loan borrowings are repayments of two $35 million borrowings with maturities greater than three months and a $20 million borrowing made on June 1, 2006, which was repaid in September 2006. The increase in short-term borrowings in Fiscal 2006 reflects borrowings needed to finance the higher working capital requirements, including working capital related to PNG Gas.
In December 2005, we refinanced $50 million of 7.14% maturing Medium-Term Notes through the issuance of $50 million of 5.64% Medium-Term Notes due in 2015. During Fiscal 2006, 2005 and 2004, we paid dividends to UGI totaling $37.6 million, $38.5 million and $45.0 million, respectively.
UGI Utilities Pension Plan
UGI Utilities sponsors two defined benefit pension plans (“Pension Plan”) for employees of UGI Utilities, UGIPNG, UGI, and certain of UGI’s other subsidiaries. As a result of the PG Energy Acquisition, we acquired the pension assets and assumed the pension liabilities related to the Employees’ Retirement Plan of Southern Union Company Pennsylvania Division (the “Division Plan”). The fair value of Pension Plan assets was $274.6 million and $211.7 million at September 30, 2006 and 2005, respectively. The increase in the fair value of Pension Plan assets substantially reflects the fair value of the Division Plan assets acquired. At September 30, 2006 and 2005, the Pension Plan’s assets exceeded accumulated benefit obligations by $5.9 million and $7.4 million, respectively. The Company is in full compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations, and does not anticipate it will be required to make a contribution to the Pension Plan in Fiscal 2007. Pre-tax pension expense reflected in Fiscal 2006, 2005 and 2004 results was $2.2 million, $2.5 million and $1.0 million, respectively. The increase in pension expense over this period principally reflects changes in the market value of Pension Plan assets, decreases in the discount rate assumption, and beginning October 2004, the expiration of the Pension Plan’s transition asset amortization. Pension expense in Fiscal 2007 is expected to be approximately $2.4 million.
Capital Expenditures
In the following table, we present capital expenditures by business segment for Fiscal 2006, Fiscal 2005 and Fiscal 2004. We also provide amounts we expect to spend in Fiscal 2007. We expect to finance a substantial portion of Fiscal 2007 capital expenditures from cash generated by operations and the remainder from borrowings under our revolving credit agreement.
Contractual Cash Obligations and Commitments
UGI Utilities has contractual cash obligations that extend beyond Fiscal 2006 including scheduled repayments of long-term debt and interest, operating lease obligations, unconditional purchase obligations for pipeline transportation and natural gas storage services, and commitments to purchase natural gas and electricity. The following table presents significant contractual cash obligations under agreements existing as of September 30, 2006 (in millions of dollars).
RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct corporate expenses and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. These billed expenses totaled $10.7 million in Fiscal 2006, $12.9 million in Fiscal 2005 and $11.2 million in Fiscal 2004 and are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries, principally payroll related services. Amounts billed to these entities by UGI Utilities were not material.
Effective December 1, 2004, following a competitive bidding process, UGI Utilities entered into a Storage Contract Administration Agreement (“Storage Agreement”) with UGI Energy Services, Inc. (“Energy Services”), a wholly owned, indirect subsidiary of UGI. The Storage Agreement was initially scheduled to expire on October 31, 2005, but effective November 1, 2005, UGI Utilities and Energy Services agreed to extend the Storage Agreement through October 31, 2008. Under the Storage Agreement, UGI Utilities released certain gas transportation and storage contracts through October 31, 2008 and transferred associated gas storage inventories to Energy Services. UGI Utilities may recall such released transportation and storage contracts without penalty if recalled to meet operational requirements, and if not recalled, the releases will terminate at the end of the term of the Storage Agreement. In the event that released contracts are recalled or at the expiration of the Storage Agreement, Energy Services is required to transfer associated gas storage inventories to UGI Utilities. In exchange for the ability to utilize these assets, Energy Services pays a monthly fee to UGI Utilities and provides a firm natural gas delivery service to UGI Utilities. During 2006 and 2005, UGI Utilities incurred costs associated with purchases of natural gas storage inventories from Energy Services and incurred associated pipeline transportation and storage capacity charges pursuant to the Storage Agreement totaling $85.8 million and $80.7 million, respectively.
UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (for any amounts of gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at September 30, 2006, comprising 8.4 billion cubic feet of natural gas, was $71.3 million. The carrying value of these gas storage inventories at September 30, 2005, comprising approximately 8.1 billion cubic feet of natural gas, was $63.0 million.
UGI Utilities has a Gas Supply and Delivery Service Agreement with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the peak heating-season months of November to 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 Storage Agreement transactions) during Fiscal 2006, 2005 and 2004 totaled $15.1 million, $8.5 million and $6.3 million, respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During Fiscal 2006, 2005 and 2004, revenues associated with sales to Energy Services totaled $14.1 million, $4.2 million, and $1.7 million, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements that are expected to have an effect on the Company’s financial condition, revenues and expenses, results of operations, liquidity, capital expenditures or capital resources.
REGULATORY MATTERS
As a result of Pennsylvania’s Natural Gas Choice and Competition Act (the “Gas Competition Act”), since July 1, 1999, all natural gas consumers in Pennsylvania, including residential and smaller commercial and industrial customers (“core-market customers”), have been able to purchase gas supplies from entities other than natural gas distribution companies (“NGDCs”). Gas Utility’s gross margin is not negatively affected by customers who use its transportation service and purchase natural gas from another supplier because its tariff is designed so that no profit is earned on the commodity portion of sales to firm customers. Under the Gas Competition Act, NGDCs, like UGI Gas and PNG Gas, continue to serve as the suppliers of last resort for all core-market customers, and such sales of gas, as well as the distribution service provided by NGDCs, continue to be subject to rate regulation by the PUC. As of September 30, 2006, less than two percent of UGI Gas’ core-market customers purchase their gas from alternate suppliers. Currently, none of PNG Gas’ core-market customers purchase their gas from alternate suppliers.
Prior to the PG Energy Acquisition, on April 13, 2006, an application was filed with the PUC seeking an increase in base rates. In an order entered on November 30, 2006, the PUC approved a settlement of the base rate proceeding of PG Energy (PNG Gas). The settlement provides for an increase in natural gas distribution base rates of approximately $12.5 million annually or approximately 4%, effective December 2, 2006. In addition, the settlement provides PNG Gas the ability to recover up to $1.0 million of additional corporate franchise tax through the state tax adjustment surcharge mechanism.
As a result of the Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers have the ability to acquire their electricity from entities other than Electric Utility. As of September 30, 2006, none of Electric Utility’s customers have chosen an alternative electricity generation supplier. Electric Utility remains the provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established in a series of PUC approved settlements, the latest of which became effective in June 2006 (collectively, the “POLR Settlement”).
Electric Utility’s POLR service rules provide for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier. Customers who do not select an alternate supplier will be obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service must remain on POLR service until the date of the second open shopping period after returning. Commercial and industrial customers who return to POLR service must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges. In October 2005, Electric Utility was notified by the only alternative electric generation provider supplying electricity in its service territory that it would cease providing electric generation service during the first quarter of Fiscal 2006.
Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates increased 4.5% on January 1, 2005 and 3% on January 1, 2006 (a total of 7.5% above the total rates in effect on December 31, 2004). Electric Utility is permitted to further increase its POLR rates in January of 2007, 2008 and 2009. Electric Utility expects to increase its POLR rates effective January 1, 2007 which will affect all metered customers. This increase is expected to raise the average cost to residential customers by approximately 35% over the costs in effect during calendar year 2006. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers. The PUC is currently developing post-rate-cap POLR regulations that are expected to further define POLR service obligations and pricing.
We account for the operations of Gas Utility and Electric Utility in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable.
MANUFACTURED GAS PLANTS
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, UGI Utilities divested all of its utility operations other than 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, prudently incurred remediation costs associated with such sites. In accordance with existing regulatory practices of the PUC, PNG Gas amortizes as removal costs over a five-year period site-specific environmental investigation and remediation costs.
As a result of the PG Energy Acquisition by our wholly-owned subsidiary, UGIPNG, UGIPNG became a party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform a specified level of activities associated with environmental investigation and remediation work at eleven currently owned properties on which MGP-related facilities were operated (“Properties”). UGIPNG is not required to spend more than $1.1 million in any calendar year for such expenditures, including costs to perform work on the Properties. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates at the end of fifteen years but may be terminated by either party at the end of any two-year period beginning with the effective date.
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 four claims against it relating to out-of-state sites. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
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.
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 UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site and estimates that future remediation costs could be as high as $2.5 million. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizens’ third party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. The court has stayed further proceedings while the City and Citizens discuss settlement. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.
By letter dated July 29, 2003, Atlanta Gas Light Company (“AGL”) served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8 million incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. On March 22, 2005, the trial court granted UGI Utilities’ motion for summary judgment. AGL appealed and on September 6, 2006, the Eleventh Circuit Court of Appeals affirmed the trial court’s entry of summary judgment, effectively terminating the case.
AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55 million. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70 million.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order, which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, UGI Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On October 2, 2006, the Supreme Court entered an order inviting the Solicitor General to file a brief expressing the views of the United States in this case.
By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11.0 million 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 million. KeySpan believes that the cost could be as high as $20 million. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
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. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 million and asserted that UGI Utilities is responsible for approximately $103 million of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23 million. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
MARKET RISK DISCLOSURES
Gas Utility’s tariffs contain clauses that permit recovery of substantially 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 our Gas Utility operations. Gas Utility uses exchange-traded natural gas call option and futures contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these call option and futures contracts, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism.
Electric Utility purchases its power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Prices for electricity can be volatile especially during periods of high demand or tight supply. Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates increased 4.5% on January 1, 2005 and 3% on January 1, 2006 (a total of 7.5% above the total rates in effect on December 31, 2004). Electric Utility is permitted, but not required, to further increase its POLR rates annually in January of 2007, 2008 and 2009. Pursuant to its POLR settlement in June 2006, Electric Utility expects to increase its POLR rates effective January 1, 2007 which will affect all metered customers. This increase is expected to raise the average cost to residential customers by approximately 35% over the costs in effect during calendar year 2006. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers. The PUC is currently developing post-rate-cap POLR regulations that are expected to further define POLR service obligations and pricing. Currently, Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2009. However, should any of the suppliers under these contracts fail to provide electric power under the terms of the power and capacity contracts, any increases in the cost of replacement power or capacity could negatively impact Electric Utility results. In order to reduce this non-performance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them.
Electric Utility has and may enter into electric price swap agreements to reduce the volatility in the cost of a portion of its anticipated electricity requirements. Electric Utility has an electric price swap agreement associated with purchases of a portion of electricity anticipated to occur in 2007. At September 30, 2006, the fair value of our electric price swap was a gain of $5.2 million. Fair value reflects the estimated amount that we would expect to receive or pay to terminate the contract based upon quoted market prices of comparable contracts at September 30, 2006. An adverse change in electricity prices of ten percent would result in a $1.4 million decrease in the fair value of the swap.
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact its fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
Our variable-rate debt includes our short-term borrowings. These debt agreements provide for interest rates on borrowings that are indexed to short-term market interest rates. Based upon the average level of borrowings outstanding under these agreements in Fiscal 2006 and Fiscal 2005, an increase in short-term interest rates of 100 basis points (1%) would have increased annual interest expense by $1.2 million and $0.5 million, respectively.
The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $43.8 million and $16.4 million at September 30, 2006 and 2005, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $50.6 million and $18.7 million at September 30, 2006 and 2005, respectively.
In order to reduce interest rate risk associated with near or medium term issuances of fixed-rate debt, we may enter into interest rate protection agreements. The fair value of our unsettled interest rate protection agreement, which has been designated and qualifies as a cash flow hedge, was a gain of $0.4 million at September 30, 2006. An adverse change in interest rates of ten percent on ten-year U.S. treasury notes would result in a $0.4 million decrease in the fair value of this interest rate protection agreement.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in compliance with accounting principles generally accepted in the United States of America requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Company’s operations and the use of estimates made by management. The Company has identified the following critical accounting policies and estimates that are most important to the portrayal of the Company’s financial condition and results of operations. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies and estimates with the Audit Committee.
Accounting for Business Combinations. In the event that the Company enters into a material business combination, in accordance with SFAS No. 141, “Business Combinations” (“SFAS 141”), the purchase price is allocated to the various assets and liabilities acquired at their estimated fair value. Fair values of assets are based upon available information. Estimating fair values can be a complex and judgmental area and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. In 2006, our preliminary allocation of the purchase price of the PG Energy Acquisition resulted in the Company recording
goodwill. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), our reporting unit with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform such impairment tests, management must determine the reporting unit’s fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill which would adversely impact our results of operations. As of September 30, 2006, our goodwill, based on our preliminary purchase price allocation, totaled $182.9 million.
Litigation accruals and environmental remediation liabilities. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and UGIPNG owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with accounting principles generally accepted in the United States of America, we establish reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability, and such reserves may change materially as more information becomes available and estimated reserves are adjusted.
Depreciation of property, plant and equipment. We compute depreciation on UGI Utilities property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property. Changes in the estimated useful lives of property, plant and equipment could have a material effect on our results of operations. As of September 30, 2006, UGI Utilities net property, plant and equipment totaled $1,050.8 million and we recorded depreciation expense of $25.5 million during Fiscal 2006.
Regulatory assets and liabilities. Gas Utility and Electric Utility’s distribution businesses are subject to regulation by the PUC. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2006, our regulatory assets totaled $72.9 million. See Note 3 to the Consolidated Financial Statements.
Defined Benefit Pension Plans. The costs of providing benefits under our Pension Plan is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including, the discount rate applied to benefit obligations,
the expected rate of return on plan assets and the rate of compensation increase, among others. Pension Plan assets are held in trust and consist principally of equity and fixed income mutual funds. Changes in plan assumptions as well as fluctuations in actual equity or bond market returns could have a material impact on future pension costs. We believe the two most critical assumptions are the expected rate of return on plan assets and the discount rate. An unfavorable change in the expected rate of return on plan assets of 50 basis points would result in an increase in pre-tax pension expense of approximately $1.2 million in Fiscal 2007. An unfavorable change in the discount rate of 50 basis points would result in an increase in pre-tax pension expense of approximately $1.4 million in Fiscal 2007.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Below is a listing of recently issued accounting pronouncements or guidance by the Financial Accounting Standards Board or SEC. See Note 1 to the Consolidated Financial Statements for additional discussion of such pronouncements.
FORWARD-LOOKING STATEMENTS
Information contained above in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this Report on Form 10-K 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) competitive pressures from the same and alternative energy sources; (5) liability for environmental claims; (6) customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (7) adverse labor relations; (8) large customer, counterparty or supplier defaults; (9) increased uncollectible accounts expense; (10) 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; (11) political, regulatory and economic conditions in the United States; and (12) reduced access to capital markets and interest rate fluctuations.
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 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.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
“Quantitative and Qualitative Disclosures About Market Risk” are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated here by reference.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the financial statement schedule referred to in the Index contained on page of this Report are incorporated herein by reference.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
(a)
The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s 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 Company’s disclosure controls and procedures as of September 30, 2006 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 SEC’s 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)
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting using the criteria in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”). The scope of that assessment excluded the PG Energy business acquired on August 24, 2006 by UGI Penn Natural Gas, Inc. (“UGIPNG”), a wholly owned subsidiary of the Company. As of September 30, 2006, UGIPNG’s total assets represented approximately 42% of the Company’s consolidated total assets and less than 2% of its revenues. Such exclusion is permitted based upon current guidance of the U.S. Securities and Exchange Commission.
Internal control over financial reporting refers to the process designed by, and under the supervision of, our Chief Executive Officer and Chief Financial Officer to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States and includes policies and procedures that, among other things, provide reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management’s authorization and are properly recorded to permit the preparation of reliable financial information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2006, based on the COSO Framework. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2006, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report.
For the related report of PricewaterhouseCoopers LLP, our Independent Registered Public Accounting Firm, see Item 8 of this Report (which information is incorporated herein by reference).
(c)
As a result of the August 24, 2006 acquisition by UGIPNG of PG Energy from Southern Union Company, we are integrating UGIPNG into our disclosure controls and procedures and our internal controls over financial reporting. For an interim period, Southern Union Company is providing certain information technology services to UGIPNG and is assisting in migrating transaction-based processes to the Company’s systems, as well as transferring historical UGIPNG data to the Company’s systems. The migration plan is expected to be completed during fiscal year 2007. We have extended internal control procedures over quarterly financial reporting to include UGIPNG. Other than changes arising out of the PG Energy acquisition, there has been no change in our internal control over financial reporting that occurred during the fiscal quarter and year ended September 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Not applicable.
PART III:
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The aggregate fees billed by PricewaterhouseCoopers LLP, the Company’s independent registered public accountants, in fiscal years 2006 and 2005 were as follows:
Audit Fees were for audit services, including (i) the annual audit of the consolidated financial statements of the Company, (ii) the audit of management’s assessment of the effectiveness of internal control over financial statements, (iii) review of the interim financial statements included in the Quarterly Reports on Form 10-Q of the Company, and (iv) services that only the independent public accounting firm can reasonably be expected to provide, such as services associated with SEC registration statements, and documents issued in connection with securities offerings.
Consistent with SEC policies regarding auditor independence, the Audit Committee has responsibility for appointing, setting compensation and overseeing the work of the Company’s independent accountants. In recognition of this responsibility, the Audit Committee has a policy of pre-approving all audit and permissible non-audit services provided by the independent accountants.
Prior to engagement of the Company’s independent accountants for the next year’s audit, management submits a list of services and related fees expected to be rendered during that year within each of the four categories of services noted above to the Audit Committee for approval.
PART IV:
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Documents filed as part of this report:
(1)
Financial Statements:
Included under Item 8 are the following financial statements and supplementary data:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of September 30, 2006 and 2005
Consolidated Statements of Income for the fiscal years ended September 30, 2006, 2005 and 2004
Consolidated Statements of Cash Flows for the fiscal years ended September 30, 2006, 2005 and 2004
Consolidated Statements of Stockholder’s Equity for the fiscal years ended September 30, 2006, 2005 and 2004
Notes to Consolidated Financial Statements
II - Valuation and Qualifying Accounts
We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or notes thereto contained in this report.
(3)
List of Exhibits:
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
*
Filed herewith.
**
As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 5, 2006 by the following persons on behalf of the Registrant in the capacities indicated.
Signature
Title
/s/ David W. Trego
David W. Trego
President and Chief Executive Officer
(Principal Executive Officer) and Director
/s/ Lon R. Greenberg
Lon R. Greenberg
Chairman and Director
/s/ John L. Walsh
John L. Walsh
Vice Chairman and Director
/s/ John C. Barney
John C. Barney
Sr. Vice President - Finance and Chief Financial Officer
(Principal Financial Officer and Principal Accounting Officer)
/s/ Stephen D. Ban
Stephen D. Ban
Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on December 5, 2006 by the following persons on behalf of the Registrant in the capacities indicated.
Signature
Title
/s/ Richard C. Gozon
Richard C. Gozon
Director
/s/ Ernest E. Jones
Ernest E. Jones
Director
/s/ Anne Pol
Anne Pol
Director
/s/ Marvin O. Schlanger
Marvin O. Schlanger
Director
/s/ James W. Stratton
James W. Stratton
Director
/s/ Roger B. Vincent
Roger B. Vincent
Director
Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:
No annual report or proxy material was sent to security holders in fiscal year 2006.
UGI UTILITIES, INC.
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2006
UGI UTILITIES, INC.
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULE
We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of UGI Utilities, Inc.:
We have completed integrated audits of UGI Utilities, Inc.’s 2006 and 2005 consolidated financial statements and of its internal control over financial reporting as of September 30, 2006 and an audit of its 2004 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1), present fairly, in all material respects, the financial position of UGI Utilities, Inc. and its subsidiaries at September 30, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, effective October 1, 2005, the Company adopted Statement of Financial Accounting Standards 123(R) “Share-Based Payment (revised 2004)”.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of September 30, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded the PG Energy business from its assessment of internal control over financial reporting as of September 30, 2006 because it was acquired by the Company in a purchase business combination on August 24, 2006. We have also excluded the PG Energy business from our audit of internal control over financial reporting. The PG Energy business is a wholly-owned subsidiary whose total assets represent approximately 42% of total consolidated assets and total revenues represent less than 2% of total consolidated revenues as of and for the year ended September 30, 2006.
/s/ PricewaterhouseCoopers
Philadelphia, Pennsylvania
December 8, 2006
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars, except per share)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(Thousands of dollars)
See accompanying notes to consolidated financial statements.
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Thousands of dollars, except per share amounts)
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Consolidation Principles
UGI Utilities, Inc., a wholly owned subsidiary of UGI Corporation (“UGI”), and its wholly-owned subsidiary UGI Penn Natural Gas, Inc. (“UGIPNG”) own and operate (1) a natural gas distribution utility in parts of eastern Pennsylvania (“UGI Gas”), (2) a natural gas distribution utility in northeastern Pennsylvania (“PNG Gas”) and (3) an electricity distribution utility in northeastern Pennsylvania (“Electric Utility”). On August 24, 2006, UGI Utilities, Inc.’s subsidiary, UGIPNG, acquired certain assets and assumed certain liabilities of Southern Union Company’s (“SU’s”) PG Energy Division and all of the issued and outstanding stock of SU’s wholly owned subsidiary PG Energy Services, Inc. (collectively, the “PG Energy Acquisition”). See Note 2.
We refer to UGI Gas and PNG Gas collectively as “Gas Utility.” The term “UGI Utilities” is used sometimes as an abbreviated reference to UGI Utilities, Inc. or UGI Utilities, Inc. and UGIPNG. We refer to Gas Utility and Electric Utility collectively as “the Company” or “we.” Our consolidated financial statements include the accounts of UGI Utilities and its subsidiaries. We eliminate all significant intercompany accounts when we consolidate. Our Gas Utility and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”).
Use of Estimates
We make estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. 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.
Regulated Utility Operations
We account for the operations of Gas Utility and Electric Utility in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable. See Note 3.
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Consolidated Statements of Cash Flows
We define cash equivalents as all highly liquid investments with maturities of three months or less when purchased. We record cash equivalents at cost plus accrued interest, which approximates market value. Restricted cash represents the cash deposited in our natural gas futures brokerage account.
We paid interest totaling $22,131 in 2006, $17,509 in 2005 and $18,143 in 2004. We paid income taxes totaling $24,939 in 2006, $36,348 in 2005 and $19,910 in 2004.
Revenue Recognition
We record regulated revenues for service provided to the end of each month which includes an accrual for certain unbilled amounts based upon estimated usage. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Nonregulated revenues are recognized as services are performed or products are delivered.
Inventories
Our inventories are stated at the lower of cost or market. Substantially all of our inventory is determined on an average cost method.
Income Taxes
We record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated depreciation methods based upon amounts recognized for ratemaking purposes. We also record a deferred tax liability for tax benefits that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to the Company’s plant additions over the service lives of the related property. The Company reduces its deferred income tax liability for the future tax benefits that will occur when the deferred investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize.
We join with UGI and its subsidiaries in filing a consolidated federal income tax return. We are charged or credited for our share of current taxes resulting from the effects of our transactions in the UGI consolidated federal income tax return including giving effect to intercompany transactions. The result of this allocation is generally consistent with income taxes calculated on a separate return basis.
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at cost. When Gas Utility and Electric Utility retire depreciable utility plant and equipment, we charge the original cost, net of removal costs and salvage value, to accumulated depreciation for financial accounting purposes.
We record depreciation expense for plant and equipment on a straight-line method over the estimated average remaining lives of the various classes of depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.5% in 2006, 2.4% in 2005 and 2.3% in 2004. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.8% in 2006, 2.9% in 2005 and 2.8% in 2004. Depreciation expense was $25,501 in 2006, $23,046 in 2005, and $21,860 in 2004.
We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets.
Intangible Assets
In accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), goodwill resulting from the PG Energy Acquisition is subject to tests for impairment at least annually. SFAS 142 requires that we perform impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill might be impaired. The goodwill recorded on our Consolidated Balance Sheet at September 30, 2006 is based upon our preliminary purchase price allocation, see Note 2. We use valuation techniques which use discounted estimates of future cash flows to be generated in the absence of quoted market prices to perform our impairment tests. No provision for goodwill impairment was recorded during 2006.
Computer Software Costs
We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.
Deferred Fuel Costs
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 the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with SFAS 71, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers. The balance sheet caption “deferred fuel costs” reflects amounts related to this PGC recovery mechanism.
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Employee Retirement Plans
The Company sponsors two defined benefit pension plans (“Pension Plan”). The Company uses a market related value of plan assets and expected long-term rates of return on plan assets to determine the expected return on plan assets associated with the Pension Plan. The market related value of plan assets other than equities in the Pension Plan is based upon the market price of the plan assets or similar assets. The market related value of equities in the Pension Plan is calculated by rolling forward the prior-year’s market related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market related value. See Note 6.
Stock-Based Compensation
Under UGI’s 2004 Omnibus Equity Compensation Plan (“OECP”), certain key employees of UGI Utilities may be granted stock options and other equity-based awards (“Units”) of UGI Common Stock. Such awards typically vest ratably over a period of three years. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or eliminate further service requirements. Stock options for UGI Common Stock generally can be exercised no later than ten years from the grant date. Effective October 1, 2005, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”). Prior to October 1, 2005, as permitted, we applied the provisions of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), in recording compensation expense for grants of stock, stock options and other equity instruments to employees. Under APB 25, the Company did not record any compensation expense for stock options, but provided the required pro forma disclosures as if we had determined compensation expense under the fair value method prescribed by the provisions of SFAS No. 123. Under SFAS 123R, all equity-based compensation cost is measured on the grant date or at period end based on the fair value of that award and is recognized in the income statement over the requisite service period.
As permitted by SFAS 123R, under the modified prospective approach, effective October 1, 2005, we began recording compensation expense for awards that were not vested as of that date and did not restate any prior periods. For the periods prior to and subsequent to the adoption of SFAS 123R, we used the Black-Scholes option-pricing model to estimate the fair value of each option. The adoption of SFAS 123R resulted in pre-tax compensation expense associated with stock options of $371 ($217 after-tax) during 2006. As of September 30, 2006, there was $438 of unrecognized compensation cost related to non-vested stock options that is expected to be recognized over a weighted average period of 1.8 years. Assuming no significant change in the level of future stock option grants to the Company’s employees, we do not believe that compensation expense associated with stock options will have a material impact on our financial position, results of operations or cash flows.
Both prior to and subsequent to the adoption of SFAS 123R, we measured and recorded compensation cost of Units awarded to employees prior to January 1, 2006 (that can be settled at UGI’s option in cash or shares of Common Stock, or a combination of both) based upon their fair value as of the end of each period. The fair value of Units is generally dependent upon UGI’s stock price and its performance in comparison to a group of peer companies. The fair value of these awards is expensed over requisite service periods.
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Effective in June 2006, UGI modified the settlement terms of those Units awarded to employees having an original grant date of January 1, 2006 which did not impact the number of awards to employees. For these Unit awards, we used the Monte Carlo valuation model to estimate their fair value. Compensation costs associated with these modified awards are measured based upon the fair value on the date of modification and as of the end of each period, as appropriate. Compensation costs are recorded over requisite service periods. The Company did not incur any incremental compensation expense as a result of this modification.
We recorded total net pre-tax equity-based compensation expense associated with both Units and stock options of $367 ($215 after-tax) during the twelve months ended September 30, 2006. The following table illustrates the effects on net income as if we had applied the provisions of SFAS 123R to all equity-based compensation awards for the comparable periods prior to the adoption of SFAS 123R.
During the year ended September 30, 2006, a portion of vested Unit awards were settled in shares of UGI Common Stock and $384 in cash. As of September 30, 2006, there was a total of $704 of unrecognized compensation expense associated with 66,234 Unit awards that are expected to be recognized over a weighted average period of 1.7 years. At September 30, 2006, total liabilities of $1,118 associated with Unit awards are reflected in other current liabilities and other noncurrent liabilities in the Condensed Balance Sheet.
The following table illustrates the number of unvested Unit awards:
Environmental and Other Legal Matters
We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Amounts accrued generally reflect our best estimate of costs expected to be incurred or the minimum liability associated with a
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
range of expected environmental response costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of any incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred removal costs. In accordance with existing regulatory practice at the PUC, site-specific environmental investigation and remediation costs associated with PNG Gas are amortized as removal costs over a five-year period. At September 30, 2006, neither the Company’s undiscounted amount nor its accrued liability for environmental investigation and cleanup costs was material.
Similar to environmental issues, we accrue investigation and other legal costs for other matters when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated (see Note 9).
Derivative Instruments
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. For a detailed description of the derivative instruments we use, our objectives for using them, and related supplemental information required by SFAS 133, see Note 10.
Comprehensive Income
Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) of $(4,037), $1,698 and $594 for the years ended September 30, 2006, 2005 and 2004, respectively, is the result of gains or losses on interest rate protection agreements (“IRPAs”) and changes in the fair value of an electric price swap agreement qualifying as cash flow hedges, net of reclassifications to net income.
Recently Issued Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R),” (“SFAS 158”). SFAS 158 requires an employer to recognize the funded status of each of its defined pension and postretirement benefit plans as a net asset or liability in its balance sheet with an offsetting amount in accumulated other comprehensive income, and to recognize changes in that funded status in the year in which changes occur through comprehensive income. SFAS 158 is effective as of the end of our fiscal year ending September 30, 2007. Had SFAS 158 been applied to our
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
September 30, 2006 Consolidated Balance Sheet, we estimate that the impact would have resulted in a reduction of long-term assets of $19,300, an increase of long-term liabilities of $23,900, a net reduction of deferred tax liabilities of $17,900 and a reduction of stockholder’s equity of $25,300. However, the effect at any future date could significantly differ depending on the measurement of our pension and other postretirement benefit plan assets and obligations at that date.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. The provisions of this standard apply to other accounting pronouncements that require or permit fair value measurements. The provisions of SFAS 157 are effective for our fiscal year beginning October 1, 2008. We are currently evaluating the impact, if any, of the provisions of SFAS 157.
In September 2006, the U.S. Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 “Considering the Effects of Prior Year Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered when quantifying a current year misstatement. The provisions of SAB 108 are effective for the end of our fiscal year ending September 30, 2007.
In June 2006, the FASB issued Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes,” which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures, and transition. FIN 48 is effective for our fiscal year beginning October 1, 2007. We are currently evaluating the impact that this standard will have on our Consolidated Financial Statements.
2. ACQUISITION OF PG ENERGY
On August 24, 2006, UGI Utilities acquired certain assets and assumed certain liabilities of SU’s PG Energy Division, a natural gas distribution business located in northeastern Pennsylvania, and all of the issued and outstanding stock of SU’s wholly-owned subsidiary, PG Energy Services, Inc. pursuant to a Purchase and Sale Agreement, as amended, between SU and UGI dated as of January 26, 2006 (the “Agreement”). Immediately prior to the PG Energy Acquisition, UGI assigned its rights and obligations under the Agreement to UGI Utilities’ newly formed subsidiary, UGIPNG. The PG Energy Acquisition increased UGI Utilities’ presence in northeastern Pennsylvania by adding approximately 158,000 natural gas customers. We expect to obtain operating and financial synergies as we integrate PNG Gas with our existing operations over time.
Under the terms of the Agreement, on August 24, 2006, the Company paid SU the acquisition price of $580,000 (excluding transaction fees and expenses) which amount is subject to working capital adjustments. The cash payment of $580,000 was funded with the net proceeds from the
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
issuance of $275,000 of UGI Utilities’ bank loans under a Credit Agreement dated as of August 18, 2006 (the “Bridge Loan”), cash capital contributions from UGI of $265,000 and $40,000 from borrowings under UGI Utilities’ revolving credit agreement. In September 2006, UGI Utilities repaid amounts outstanding under the Bridge Loan with the proceeds from the issuance of $175,000 of 5.753% Senior Notes due 2016 and $100,000 of 6.206% Senior Notes due 2036.
The assets and liabilities of the PG Energy Acquisition are included in our Consolidated Balance Sheet at September 30, 2006. The operating results of PNG Gas are included in our consolidated results beginning August 24, 2006. The preliminary purchase price allocation has not been finalized because we are still in the process of reviewing and determining the fair value of certain of PNG Gas’ assets acquired and liabilities assumed, principally working capital adjustments and amounts associated with environmental related liabilities. The purchase price is subject to a working capital adjustment, pursuant to the Agreement, equal to the difference between an estimated $68,100 and the actual working capital as of the closing date agreed to by both UGIPNG and SU.
The preliminary purchase price of PNG Gas, including estimated transaction fees and expenses of $9,800, has been allocated to the assets acquired and liabilities assumed, as follows:
Substantially all of the estimated goodwill is expected to be deductible for income tax purposes over a fifteen-year period.
The following table presents unaudited pro forma income statement data for the years ended September 30, 2006 and 2005 as if the acquisition of PNG Gas had occurred as of the beginning of those periods:
The pro forma results of operations reflect PNG Gas’ historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the PG Energy Acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results. The unaudited pro forma net income for the twelve months ended September 30, 2006 includes a writedown of goodwill of $98,000 recorded by SU during the three months ended December 31, 2005.
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Pursuant to the Agreement, SU and UGIPNG entered into a Transition Services Agreement (“TSA”) whereby each party will be a provider and receiver of certain services to the other. The principal services include general business continuity, information technology, accounting and tax services. Services under the TSA will be provided through the expiration of the term relating to each service or until such time as mutually agreed by UGIPNG and SU.
3. REGULATORY ASSETS AND LIABILITIES AND REGULATORY MATTERS
The following regulatory assets and liabilities are included in our accompanying balance sheets at September 30:
The Company’s regulatory liabilities relating to postretirement benefits are included in “other noncurrent liabilities” on the Consolidated Balance Sheets. The Company does not recover a rate of return on its regulatory assets.
Prior to the PG Energy Acquisition, on April 13, 2006, an application was filed with the PUC seeking an increase in base rates. In an order entered on November 30, 2006, the PUC approved a settlement of the base rate proceeding of PG Energy (PNG Gas). The settlement provides for an increase in natural gas distribution base rates of $12,500 annually or approximately 4%, effective December 2, 2006. In addition, the settlement provides PNG Gas the ability to recover up to $1,000 of additional corporate franchise tax through the state tax adjustment surcharge mechanism.
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
4. DEBT
Long-term debt comprises the following at September 30:
The only principal repayment of long-term debt due during the next five fiscal years ending September 30 is $20,000 of 7.17% Medium-Term Notes due June 2007.
UGI Utilities has a revolving credit agreement (“Credit Agreement”) with banks providing for borrowings of up to $350,000. This agreement is currently scheduled to expire in August 2007, but may be automatically extended by UGI Utilities to August 2011. Under this agreement, UGI Utilities may borrow at various prevailing interest rates, including LIBOR and the banks’ prime rate. UGI Utilities pays quarterly facility fees on this credit line. UGI Utilities had revolving credit agreement borrowings totaling $216,000 at September 30, 2006 and $11,200 at September 30, 2005 which we classify as bank loans. UGI Utilities from time to time has entered into short-term borrowings under uncommitted arrangements with major banks in order to meet liquidity needs. Such borrowings are also classified as bank loans. At September 30, 2005, we had two separate $35,000 borrowings outstanding under uncommitted arrangements with major banks. Scheduled repayments of these borrowings were made in February and March 2006. The weighted-average interest rates on our bank loans outstanding were 5.58% at September 30, 2006 and 4.41% at September 30, 2005.
UGI Utilities’ Credit Agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
5. INCOME TAXES
The provisions for income taxes consist of the following:
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Deferred tax liabilities (assets) comprise the following at September 30:
The Company had recorded deferred tax liabilities of approximately $40,445 as of September 30, 2006 and $37,270 as of September 30, 2005 pertaining to utility temporary differences, principally a result of accelerated tax depreciation for state income tax purposes, the tax benefits of which previously were or will be flowed through to ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $2,823 at September 30, 2006 and $2,985 at September 30, 2005, pertaining to utility deferred investment tax credits. We had recorded regulatory income tax assets related to these net deferred taxes of $64,304 at September 30, 2006 and $58,601 at September 30, 2005. These regulatory income tax assets represent future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred.
6. EMPLOYEE RETIREMENT PLANS
Defined Benefit Pension and Other Postretirement Plans
The Company sponsors two defined benefit pension plans for employees of UGI Utilities, UGIPNG, UGI, and certain of UGI’s other wholly owned subsidiaries. In addition, we provide postretirement health care benefits to certain of our retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all active and retired employees. As a result of the PG Energy Acquisition, we acquired the pension assets and assumed the pension liabilities related to the Employees’ Retirement Plan of Southern Union Company Pennsylvania Division (the “Division Plan”).
UGI UTILITIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following provides a reconciliation of projected benefit obligations, plan assets and funded status of the plans as of September 30:
Net pension expense is determined using assumptions as of the beginning of each fiscal year and, in the case of UGIPNG’s pension and postretirement benefits, as of August 31, 2006. Funded status is determined using assumptions as of the end of each fiscal year. The expected rate of return on assets assumption is based on the rates of return for certain asset classes and the allocation of plan assets among those asset classes as well as actual historic long-term rates of return on our plan assets.
Included in the end of year pension benefit obligations above are $26,384 at September 30, 2006 and $26,223 at September 30, 2005 relating to employees of UGI and certain of its other subsidiaries. Included in the end of year other postretirement obligations above are $763 at September 30, 2006 and $751 at September 30, 2005 relating to employees of UGI and certain of its other subsidiaries.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Net periodic pension expense and other postretirement benefit costs relating to the Company’s employees include the following components:
Pension plan assets associated with our two defined benefit pension plans are held in trust. Although the projected benefit obligations of these plans exceeded plan assets at September 30, 2006 and 2005, plan assets exceeded accumulated benefit obligations by $5,928 and $7,404, respectively. The Company did not make any contributions to its pension plans in 2006, 2005 or 2004 and does not believe that it will be required to make any contributions during the year ending September 30, 2007 for ERISA funding purposes.
Pursuant to orders issued by the PUC, UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to fund the UGI Utilities’ postretirement benefit obligations and to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS No. 106, “Employers Accounting for Postretirement Benefits Other than Pensions” (“SFAS 106”). The difference between such amounts calculated under SFAS 106 and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Effective July 1, 2005, substantially all retirees and their beneficiaries participating in the UGI Utilities’ postretirement benefit program were enrolled in insured Medicare Advantage plans. As a result of this change, net benefit cost declined for periods subsequent to July 1, 2005. The Company’s estimated required contribution to the VEBA during the year ending September 30, 2007 is not expected to be material.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Expected payments for pension benefits and other postretirement welfare benefits are as follows:
In accordance with our investment strategy to obtain long-term growth, our target asset allocations are to maintain a mix of 60% equities and the remainder in fixed income funds or cash equivalents. The target and actual allocations for our defined benefit pension plans and VEBA trust assets at September 30 are as follows:
UGI Common Stock comprised approximately 7% and 11% of pension plan trust assets at September 30, 2006 and 2005, respectively.
The assumed health care cost trend rates are 10% for fiscal 2007, decreasing to 5.5% in fiscal 2012. A one percentage point change in the assumed health care cost trend rate would increase (decrease) the 2006 postretirement benefit cost and obligation as follows:
We also sponsor an unfunded and non-qualified supplemental executive retirement income plan. At September 30, 2006 and 2005, the projected benefit obligations of this plan were $3,250 and $2,700, respectively. We recorded expense for this plan of $522 in 2006, $439 in 2005 and $460 in 2004.
Defined Contribution Plans
We sponsor a 401(k) savings plan for eligible employees (“Utilities Savings Plan”). Generally, participants in the Utilities Savings Plan may contribute a portion of their compensation on a before-tax and after-tax basis. We may, at our discretion, match a portion of participants’ contributions. The cost of benefits under the savings plan totaled $918 in 2006, $931 in 2005, and $915 in 2004.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
7. INVENTORIES
Inventories comprise the following at September 30:
Included in utility fuel and gases inventories are amounts associated with the UGI Gas’ Storage Contract Administration Agreement (“Storage Agreement”) with Energy Services, Inc. (“Energy Services”), a wholly owned subsidiary of UGI. For a detailed description of the Storage Agreement and the accounting for such inventories, see Note 13.
8. SERIES PREFERRED STOCK
We have 2,000,000 shares of Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, authorized for issuance. We had no shares of Series Preferred Stock outstanding at September 30, 2006.
On October 1, 2004, we redeemed all 200,000 shares of our $7.75 Series Preferred Stock at a price of $100 per share together with full cumulative dividends. The redemption on October 1, 2004 was funded with proceeds from the October 2004 issuance of $20,000 of 6.13% Medium-Term Notes due October 2034.
9. COMMITMENTS AND CONTINGENCIES
We lease various buildings and transportation, computer and office equipment and other facilities under operating leases. Certain of our leases contain renewal and purchase options and also contain escalation clauses. Our aggregate rental expense for such leases was $5,025 in 2006, $4,703 in 2005, and $4,431 in 2004.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year for the fiscal years ending September 30 are as follows: 2007 - $4,247; 2008 - $3,215; 2009 - $2,054; 2010 - $1,542; 2011 - $1,135; after 2011-$2,459.
Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage service which Gas Utility may terminate at various dates through 2017. Gas Utility’s costs associated with transportation and storage service agreements are included in its annual PGC filing with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Electric Utility purchases its capacity requirements and electric energy needs under contracts with various suppliers and on the spot market. Contracts with producers for capacity and energy needs expire at various dates through fiscal 2011.
Future contractual cash obligations under Gas Utility and Electric Utility supply, storage and service agreements existing at September 30, 2006 are as follows: 2007 - $367,174; 2008 - $157,125; 2009 - $144,524; 2010 - $83,989; 2011 - $46,445; after 2011 - $86,891.
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, UGI Utilities divested all of its utility operations other than 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, prudently incurred remediation costs associated with such sites. In accordance with existing regulatory practices of the PUC, PNG Gas amortizes as removal costs over a five-year period site-specific environmental investigation and remediation costs.
As a result of the PG Energy Acquisition by our wholly-owned subsidiary, UGIPNG, UGIPNG became a party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform a specified level of activities associated with environmental investigation and remediation work at eleven currently owned properties on which MGP-related facilities were operated (“Properties”). UGIPNG is not required to spend more than $1,100 in any calendar year for such expenditures, including costs to perform work on the Properties. Costs related to investigation and remediation of one property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates at the end of fifteen years but may be terminated by either party at the end of any two-year period beginning with the effective date.
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 four claims against it relating to out-of-state sites. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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.
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 UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G assets that it has spent approximately $22,000 in remediation costs and $26,000 in third-party claims relating to the site and estimates that future remediation costs could be as high as $2,500. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it could cost up to $18,000 to clean up the river. Citizens’ third party claims have been stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. The amount of Citizens’ liability has not been finally determined. The court has stayed further proceedings while the City and Citizens discuss settlement. UGI Utilities believes that it has good defenses to Citizens’ claim and to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.
By letter dated July 29, 2003, Atlanta Gas Light Company (“AGL”) served UGI Utilities with a complaint filed in the United States District Court for the Middle District of Florida in which AGL alleges that UGI Utilities is responsible for 20% of approximately $8,000 incurred by AGL in the investigation and remediation of a former MGP site in St. Augustine, Florida. UGI Utilities formerly owned stock of the St. Augustine Gas Company, the owner and operator of the MGP. On March 22, 2005, the trial court granted UGI Utilities’ motion for summary judgment. AGL appealed and on September 6, 2006, the Eleventh Circuit Court of Appeals affirmed the trial court’s entry of summary judgment, effectively terminating the case.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
AGL previously informed UGI Utilities that it was investigating contamination that appeared to be related to MGP operations at a site owned by AGL in Savannah, Georgia. A former subsidiary of UGI Utilities operated the MGP in the early 1900s. AGL has informed UGI Utilities that it has begun remediation of MGP wastes at the site and believes that the total cost of remediation could be as high as $55,000. AGL has not filed suit against UGI Utilities for a share of these costs. UGI Utilities believes that it will have good defenses to any action that may arise out of this site.
On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at former MGP sites in Westchester County, New York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a declaration that UGI Utilities is responsible for an allocated percentage of future investigative and remedial costs at the sites. ConEd believes that the cost of remediation for all of the sites could exceed $70,000.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in part the decision of the trial court. The appellate panel affirmed the trial court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under lease. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order which was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, UGI Utilities filed a petition requesting that the United States Supreme Court review the decision of the Second Circuit Court of Appeals. On October 2, 2006, the Supreme Court entered an order inviting the Solicitor General to file a brief expressing the views of the United States in this case.
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.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
plants from 1883 to 1941. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215,000 and asserted that UGI Utilities is responsible for approximately $103,000 of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23,000. UGI Utilities believes that it has good defenses to this claim and is defending the suit.
In addition to these environmental matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. 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.
10. FINANCIAL INSTRUMENTS
In accordance with its commodity hedging policy, the Company has entered into (1) natural gas call option and futures contracts to reduce volatility in the cost of gas it purchases for its firm- residential, commercial and industrial (“retail core-market”) customers and (2) an electric price swap agreement to reduce the volatility in the cost of anticipated electricity requirements. Because costs of the natural gas call option and futures contracts and associated gains and losses resulting from these contracts are included in our PGC recovery mechanism, as these contracts are recorded at fair value in accordance with SFAS 133, any gains or losses are deferred for future refund to or recovery from Gas Utility’s ratepayers through the PGC recovery mechanism. We have designated the electric price swap as a cash flow hedge under SFAS 133.
We are 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 are not subject to the accounting requirements of SFAS 133, as amended, 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 or the value of the contract is directly associated with the price or value of a service.
We enter into IRPAs in order to manage interest rate risk associated with planned issuances of fixed-rate long-term debt. We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are included in other comprehensive income and are reclassified to interest expense as the interest expense on the associated debt affects earnings.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
During 2006, 2005 and 2004, there were no gains or losses recognized in earnings as a result of hedge ineffectiveness or as a result of excluding a portion of a derivative instrument’s gain or loss from the assessment of hedge effectiveness, and there were no gains or losses recognized in earnings as a result of a hedged firm commitment no longer qualifying as a fair value hedge. At September 30, 2006, our unsettled derivative contracts included in accumulated other comprehensive income include our electric price swap agreement and one IRPA.
Gains and losses included in accumulated other comprehensive income (loss) at September 30, 2006 relating to cash flow hedges will be reclassified into (1) interest expense when interest on hedged issuances of fixed-rate long-term debt is reflected in net income and (2) cost of sales when the forecasted purchases of electricity subject to the hedge impact net income. Included in accumulated other comprehensive income at September 30, 2006 are net after-tax losses of approximately $6,838 associated with settled IRPAs and an unsettled IRPA associated with a forecasted issuance of long-term debt anticipated to occur during fiscal year 2007. The amount of net loss on IRPAs expected to be reclassified into net income during the next twelve months is approximately $460. Also included in accumulated other comprehensive income at September 30, 2006 is an after-tax gain of $3,043 associated with our unsettled electric price swap agreement for purchases of electricity anticipated to occur during 2007. The actual amount of gains or losses on unsettled derivative instruments that ultimately is reclassified into net income will depend upon the value of such derivative contracts when settled. The fair value of derivative instruments is included in other current assets, other assets and other current liabilities in the Consolidated Balance Sheets.
The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivatives and current maturities of long-term debt) approximate their fair values because of their short-term nature.
The carrying amounts and estimated fair values of our remaining financial instruments (including unsettled derivative instruments) at September 30 are as follows:
We estimate the fair value of long-term debt by using current market prices and by discounting future cash flows using rates available for similar type debt.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
We have financial instruments such as trade accounts receivable which could expose us to concentrations of credit risk. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different markets. At September 30, 2006 and 2005, we had no significant concentrations of credit risk.
11. SEGMENT INFORMATION
We have determined that we have two reportable segments: (1) Gas Utility and (2) Electric Utility. Gas Utility revenues are derived principally from the sale and distribution of natural gas to customers in eastern and northeastern Pennsylvania. Electric Utility derives its revenues principally from the sale and distribution of electricity in two northeastern Pennsylvania counties.
The accounting policies of our reportable segments are the same as those described in Note 1. We evaluate the performance of our Gas Utility and Electric Utility segments principally based upon their income before income taxes.
No single customer represents more than ten percent of our consolidated revenues and there are no significant intersegment transactions. In addition, all of our reportable segments’ revenues are derived from sources within the United States, and all of our reportable segments’ long-lived assets are located in the United States.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Financial information by business segment follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
12. OTHER INCOME, NET
Other income, net, comprises the following:
13. RELATED PARTY TRANSACTIONS
UGI provides certain financial and administrative services to UGI Utilities. UGI bills UGI Utilities monthly for all direct and for an allocated share of indirect corporate expenses incurred or paid on behalf of UGI Utilities. These billed expenses are classified as operating and administrative expenses - related parties in the Consolidated Statements of Income. In addition, UGI Utilities provides limited administrative services to UGI and certain of UGI’s subsidiaries, principally payroll related services. Amounts billed to these entities by UGI Utilities for all periods presented were not material.
Effective December 1, 2004, following a competitive bidding process, UGI Utilities entered into a Storage Contract Administrative Agreement (“Storage Agreement”) with UGI Energy Services, Inc., a second-tier wholly owned subsidiary of UGI (“Energy Services”). The Storage Agreement was initially scheduled to expire on October 31, 2005, but effective November 1, 2005, UGI Utilities and Energy Services agreed to extend the Storage Agreement through October 31, 2008. Under the Storage Agreement, Energy Services provides a firm natural gas delivery service to UGI Utilities. UGI Utilities has released certain gas transportation and storage contracts through October 31, 2008 and transferred associated gas storage inventories to Energy Services. UGI Utilities may recall such released transportation and storage contracts without penalty if recalled to meet operational requirements, and if not recalled, the releases will terminate at the end of the term of the Storage Agreement. In the event that released contracts are recalled or at the expiration of the Storage Agreement, Energy Services is required to transfer associated gas storage inventories to UGI Utilities. In exchange for the ability to utilize these assets, Energy Services pays a monthly fee to UGI Utilities and provides a firm natural gas delivery service to UGI Utilities. During 2006 and 2005, UGI Utilities incurred costs associated with purchases of natural gas storage inventories from Energy Services and incurred associated pipeline transportation and storage capacity charges pursuant to the Storage Agreement totaling $85,839 and $80,745, respectively.
UGI Utilities reflects the historical cost of the gas storage inventories and any exchange receivable from Energy Services (representing amounts of natural gas inventories used but not yet replenished by Energy Services) on its balance sheet under the caption “Inventories.” The carrying value of these gas storage inventories at September 30, 2006, comprising approximately 8.4 billion cubic feet of natural gas, was $71,290. The carrying value of these gas storage inventories at September 30, 2005, comprising approximately 8.1 billion cubic feet of natural gas, was $63,004.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
UGI Utilities has a Gas Supply and Delivery Service Agreement with Energy Services pursuant to which Energy Services provides certain gas supply and related delivery service to Gas Utility during the peak heating-season months of November to 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 Storage Agreement transactions) during 2006, 2005 and 2004 totaled $15,114, $8,491 and $6,257, respectively.
From time to time, the Company sells natural gas or pipeline capacity to Energy Services. During 2006, 2005 and 2004, revenues associated with sales to Energy Services totaled $14,080, $4,249, and $1,698, respectively. These transactions did not have a material effect on the Company’s financial position, results of operations or cash flows.
14. QUARTERLY DATA (unaudited)
The following quarterly information includes all adjustments (consisting only of normal recurring adjustments), which we consider necessary for a fair presentation of such information. Quarterly results fluctuate because of the seasonal nature of the Company’s businesses.
UGI UTILITIES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of dollars)
(1)
Uncollectible accounts written off, net of recoveries.
(2)
Acquisition
(3)
Payments, net
(4)
Includes reserves for self-insured property and casualty liability, insured property and casualty liability, environmental, litigation and other.
S-1
EXHIBIT INDEX