ITEM 1. BUSINESS
Description of the Business
Vectren Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).
Indiana Gas provides energy delivery services to over 568,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to over 141,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 317,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.
Narrative Description of the Business
The Company has regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO’s natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment includes the operations of SIGECO’s electric transmission and distribution services, which provides electric distribution services primarily to southwestern Indiana, and the Company’s power generating and wholesale power operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers. The Utility Group’s other operations are not significant.
At December 31, 2008, the Company had $3.8 billion in total assets, with $2.2 billion (57 percent) attributed to Gas Utility Services, $1.4 billion (38 percent) attributed to Electric Utility Services, and $0.2 billion (5 percent) attributed to Other Operations. Net income for the year ended December 31, 2008, was $111.1 million, with $53.3 million attributed to the Gas Utility Services, $50.7 million attributed to Electric Utility Services, and $7.1 million attributed to Other Operations. Net income for the year ended December 31, 2007, was $106.5 million. For further information regarding the activities and assets of operating segments, refer to Note 11 in the Company’s consolidated financial statements included under “Item 8 Financial Statements and Supplementary Data.”
Following is a more detailed description of the Gas Utility Services and Electric Utility Services operating segments. The Company’s Other Operations are not significant.
Gas Utility Services
At December 31, 2008, the Company supplied natural gas service to approximately 996,300 Indiana and Ohio customers, including 910,000 residential, 84,700 commercial, and 1,600 industrial and other contract customers. Average gas utility customers served were approximately 986,700 in both 2008 and 2007; and 981,300 in 2006.
The Company’s service area contains diversified manufacturing and agriculture-related enterprises. The principal industries served include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, ethanol and coal mining. The largest Indiana communities served are Evansville, Bloomington, Terre Haute, and suburban areas surrounding Indianapolis and Indiana counties near Louisville, Kentucky. The largest community served outside of Indiana is Dayton, Ohio.
Revenues
For the year ended December 31, 2008, gas utility revenues were approximately $1,432.7 million, of which residential customers accounted for 67 percent and commercial 27 percent. Industrial and other contract customers account for the remaining 6 percent of revenues due to the high number of transportation customers in that customer class.
The Company receives gas revenues by selling gas directly to customers at approved rates or by transporting gas through its pipelines at approved rates to customers that have purchased gas directly from other producers, brokers, or marketers. Total volumes of gas delivered to both sales and transportation customers (throughput) were 206.3 MMDth for the year ended December 31, 2008. Gas sold and transported to residential and commercial customers was 114.8 MMDth representing 56 percent of throughput. Gas transported or sold to industrial and other contract customers was 91.5 MMDth representing 44 percent of throughput. Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs.
Availability of Natural Gas
The volume of gas sold is seasonal and affected by variations in weather conditions. To mitigate seasonal demand, the Company’s Indiana gas utilities have storage capacity at seven active underground gas storage fields and six liquefied petroleum air-gas manufacturing plants. Periodically, purchased natural gas is injected into storage. The injected gas is then available to supplement contracted and manufactured volumes during periods of peak requirements. The volumes of gas per day that can be delivered during peak demand periods for each utility are located in “Item 2 Properties.”
Natural Gas Purchasing Activity in Indiana
The Indiana utilities also contract with its affiliate, ProLiance Holdings, LLC (ProLiance), to ensure availability of gas. ProLiance is an unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens Energy Group (Citizens). (See the discussion of Energy Marketing & Services below and Note 3 in the Company’s Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” regarding transactions with ProLiance). The Company also prepays ProLiance for natural gas delivery services during the seven months prior to the peak heating season in lieu of maintaining gas storage. The Company received regulatory approval on April 25, 2006 from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities through March 2011.
Natural Gas Purchasing Activity in Ohio
As a result of a June 2005 PUCO order, the Company established an annual bidding process for VEDO’s gas supply and portfolio administration services. From November 1, 2005 through September 30, 2008, the Company used a third party provider for these services. Prior to October 31, 2005, ProLiance also supplied natural gas to Utility Holdings’ Ohio operations.
On April 30, 2008, the PUCO issued an Order adopting a stipulation involving the Company, the OCC and other interveners. The order involved the first two stages of a three stage plan to exit the merchant function in the Company’s Ohio service territory.
Stage one of the plan was implemented on October 1, 2008 and continues through March 31, 2010. As part of stage one, wholesale suppliers that were winning bidders in a PUCO approved auction provide the gas commodity to VEDO for resale to its customers at auction-determined standard pricing. This standard pricing is comprised of the monthly NYMEX settlement price plus a fixed adder. On October 1, 2008, the Company transferred its natural gas inventory at book value to the winning bidders, receiving proceeds of approximately $107 million, and now purchases natural gas from those suppliers, which include Vectren Source, a wholly owned subsidiary of Vectren, essentially on demand. This method of purchasing gas eliminates the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.
In the second stage of this process, the Company will no longer sell natural gas directly to customers; rather state- certified Competitive Retail Natural Gas Suppliers, which are successful bidders in a second regulatory-approved auction, will sell the gas commodity to specific customers at auction-determined standard pricing, and the Company will transport that gas supply to the customers. In the third stage, which was not part of the April 2008 order, it is contemplated that all of the Company’s Ohio customers will choose their commodity supplier from state-certified Competitive Retail Natural Gas Suppliers in a competitive market.
The PUCO has also provided for an Exit Transition Cost rider for the first two stages of the transition, which allows the Company to recover costs associated with the transition, and it is anticipated this rider will remain effective for the entire transition. Since the cost of gas is currently passed through to customers through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.
Total Natural Gas Purchased Volumes
In 2008, Utility Holdings purchased 109,059 MDth volumes of gas at an average cost of $9.61 per Dth, of which approximately 71 percent was purchased from ProLiance, 2 percent was purchased from Vectren Source, as discussed above, and 27 percent was purchased from third party providers. The average cost of gas per Dth purchased for the previous five years was $9.61 in 2008, $8.14 in 2007, $8.64 in 2006, $9.05 in 2005, and $6.92 in 2004.
Electric Utility Services
At December 31, 2008, the Company supplied electric service to approximately 141,300 Indiana customers, including approximately 122,800 residential, 18,400 commercial, and 100 industrial and other customers. Average electric utility customers served were approximately 141,100 in 2008; 140,800 in 2007; and 139,700 in 2006.
The principal industries served include polycarbonate resin (Lexan®) and plastic products, aluminum smelting and recycling, aluminum sheet products, automotive assembly, steel finishing, appliance manufacturing, pharmaceutical and nutritional products, automotive glass, gasoline and oil products, ethanol and coal mining.
Revenues
For the year ended December 31, 2008, retail electricity sales totaled 5,323.4 GWh, resulting in revenues of approximately $457.3 million. Residential customers accounted for 37 percent of 2008 revenues; commercial 28 percent; industrial 33 percent, and municipal and other 2 percent. In addition, in 2008 the Company sold 1,512.9 GWh through wholesale activities in 2008 principally to the MISO. Wholesale revenues, including transmission sales, totaled $66.9 million in 2008.
System Load
Total load for each of the years 2004 through 2008 at the time of the system summer peak, and the related reserve margin, is presented below in MW.
(1)
The total load at peak is increased 25 MW in 2007-2005 from the total load actually experienced. The additional 25 MW represents load that would have been incurred if the Summer Cycler program had not been activated. The 25 MW is also included in the interruptible contract portion of the Company’s total power supply capacity in those years. On the date of peak in 2008 and 2004, the Summer Cycler program was not activated.
The winter peak load for the 2007-2008 season of approximately 960 MW occurred on January 25, 2008. The prior year winter peak load was approximately 961 MW, occurring on December 7, 2006.
Generating Capability
Installed generating capacity as of December 31, 2008, was rated at 1,295 MW. Coal-fired generating units provide 1,000 MW of capacity, and natural gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW. Electric generation for 2008 was fueled by coal (98 percent) and natural gas (2 percent). Oil was used only for testing of gas/oil-fired peaking units. The Company generated approximately 6,653 GWh in 2008. Further information about the Company’s owned generation is included in Item 2 Properties.
There are substantial coal reserves in the southern Indiana area, and coal for coal-fired generating stations has been supplied from operators of nearby coal mines, including coal mines in Indiana owned by Vectren Fuels, Inc., a wholly owned subsidiary of the Company. Approximately 3.2 million tons were purchased for generating electricity during 2008, of which approximately 91 percent was supplied by Vectren Fuels, Inc. from its mines and third party purchases. The average cost of coal paid by the utility in generating electric energy for the years 2004 through 2008 follows:
On January 1, 2009, SIGECO began purchasing coal from Vectren Fuels, Inc. (Fuels) under new coal purchase agreements. The term of these coal purchase agreements continues to December 31, 2014, with prices specified ranging from two to four years. New pricing reflects current Illinois Basin market prices and will result in substantially higher costs in 2009, compared to prior years.
Firm Purchase Supply
The Company maintains a 1.5 percent interest in the Ohio Valley Electric Corporation (OVEC). OVEC is comprised of several electric utility companies, including SIGECO, and supplies power requirements to the United States Department of Energy’s (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating companies are entitled to receive from OVEC, and are obligated to pay for, any available power in excess of the DOE contract demand. At the present time, the DOE contract demand is essentially zero. Because of this decreased demand, the Company’s 1.5 percent interest in OVEC makes available approximately 30 MW of capacity for use in other operations. The Company purchased approximately 236 GWh from OVEC in 2008.
The Company has a capacity contract with Duke Energy Marketing America, LLC. to purchase as much as 100 MW at any time from a power plant located in Vermillion County, Indiana. The contract ends on December 31, 2009. The Company purchased insignificant amounts under this contract in 2008.
The Company executed a capacity contract with Benton County Wind Farm, LLC on April 15, 2008 to purchase as much as 30 MW from a wind farm located in Benton County, Indiana. The contract expires in 2029. At the time of peak in 2008 approximately 5 MW was available. The Company purchased approximately 59 GWh under this contract in 2008.
Other Power Purchases
The Company also purchases power as needed principally from the MISO to supplement its generation and firm purchase supply in periods of peak demand. Volumes purchased principally from the MISO in 2008 totaled 80 GWh.
Midwest Independent System Operator (MISO) Capacity Purchase
In May 2008, the Company executed a MISO capacity purchase from Sempra Energy Trading, LLC to purchase 100MW of name plate capacity from its generating facility in Dearborn, Michigan. The term of the contract begins January 1, 2010 and continues through December 31, 2012.
Interconnections
The Company has interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of Jasper, Indiana, providing the historic ability to simultaneously interchange approximately 500 MW. However, the ability of the Company to effectively utilize the electric transmission grid in order to achieve its desired import/export capability has been, and may continue to be, impacted as a result of the ongoing changes in the operation of the Midwestern transmission grid. The Company, as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets, like many other Midwestern electric utilities, to MISO. See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s participation in MISO.
Competition
The utility industry has undergone structural change for several years, resulting in increasing competitive pressures faced by electric and gas utility companies. Currently, several states have passed legislation allowing electricity customers to choose their electricity supplier in a competitive electricity market and several other states have considered such legislation. At the present time, Indiana has not adopted such legislation. Ohio regulation allows gas customers to choose their commodity supplier. The Company implemented a choice program for its gas customers in Ohio in January 2003. At December 31, 2008, over 80,000 customers in Vectren’s Ohio service territory purchase natural gas from a supplier other than the utility. Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs. Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting certain industrial and commercial large volume customers to choose their commodity supplier.
Regulatory and Environmental Matters
See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s regulatory environment and environmental matters.
Personnel
As of December 31, 2008, the Company and its consolidated subsidiaries had 1,600 employees, of which 800 are subject to collective bargaining arrangements.
In December 2008, the Company reached a three-year labor agreement, ending December 1, 2011 with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441.
In July 2007, the Company reached a three-year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 2010.
In November 2005, the Company reached a four-year agreement with Local 175 of the Utility Workers Union of America, ending October 2009. In September 2005, the Company reached a four-year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 2009.
ITEM 1A.
ITEM 1A. RISK FACTORS
Investors should consider carefully the following factors that could cause the Company’s operating results and financial condition to be materially adversely affected. New risks may emerge at any time, and the Company cannot predict those risks or estimate the extent to which they may affect the Company’s businesses or financial performance.
Utility Holdings is a holding company and its assets consist primarily of investments in its subsidiaries.
The ability of Utility Holdings to receive dividends and repay indebtedness depends on the earnings, financial condition, capital requirements and cash flow of its subsidiaries, SIGECO, Indiana Gas, and VEDO and the distribution or other payment of earnings from those entities to Utility Holdings. Should the earnings, financial condition, capital requirements or cash flow of, or legal requirements applicable to, them restrict their ability to pay dividends or make other payments to Utility Holdings, its ability to pay dividends to its parent could be limited. Utility Holdings’ results of operations, future growth and earnings and dividend goals also will depend on the performance of its subsidiaries. Additionally, certain of the Company’s lending arrangements contain restrictive covenants, including the maintenance of a total debt to total capitalization ratio, which could limit its ability to pay dividends.
Continued deterioration in general economic conditions may have adverse impacts.
The current economic environment is challenging and uncertain. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. Further, the risks associated with industries in which the Company operates and serves become more acute in periods of a slowing economy or slow growth. Economic declines may be accompanied by a decrease in demand for natural gas and electricity. The recent economic downturn may have some negative impact on both gas and electric large customers. This impact may include tempered growth, significant conservation measures, and perhaps even plant closures or bankruptcies. Deteriorating economic conditions may also lead to lower residential and commercial customer counts and thus lower Company revenues. It is also highly possible that a prolonged recession could result in increased costs including pension costs, interest costs, and bad debt expense in excess of historical levels. Further, Vectren’s nonutility businesses may also be negatively impacted, and those impacts could further adversely affect Utility Holdings ability to access the capital and credit markets.
Utility Holdings’ gas and electric utility sales are concentrated in the Midwest.
The operations of the Company’s regulated utilities are concentrated in central and southern Indiana and west central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest. These industries include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, appliance manufacturing, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, ethanol and coal mining. While no one industrial customer comprises 10 percent of consolidated revenues, the top five industrial electric customers comprise approximately 17 percent of electric utility revenues, and therefore any significant decline in their collective revenues could adversely impact operating results.
Current financial market volatility could have adverse impacts.
The capital and credit markets have been experiencing volatility and disruption. If the current levels of market disruption and volatility worsen, there can be no assurance that the Company will not experience adverse effects, which may be material. These effects may include, but are not limited to, difficulties in accessing the debt capital markets and the commercial paper market, increased borrowing costs associated with current debt obligations, higher interest rates in future financings, and a smaller potential pool of investors and funding sources. Finally, there is no assurance the Company’s parent, Vectren, will have access to the equity capital markets to obtain financing when necessary or desirable.
A downgrade (or negative outlook) in or withdrawal of Utility Holdings’ credit ratings could negatively affect its ability to access capital and its cost.
The following table shows the current ratings assigned to certain outstanding debt by Moody’s and Standard & Poor’s:
The current outlook of both Standard and Poor’s and Moody’s is stable and both categorize the ratings of the above securities as investment grade. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.
Utility Holdings may be required to obtain additional permanent financing (1) to fund its capital expenditures, investments and debt security redemptions and maturities and (2) to further strengthen its capital structure and the capital structures of its subsidiaries. If the rating agencies downgrade the Company’s credit ratings, particularly below investment grade, or initiate negative outlooks thereon, or withdraw Utility Holdings’ ratings or, in each case, the ratings of its subsidiaries, it may significantly limit Utility Holdings’ access to the debt capital markets and the commercial paper market, and the Company’s borrowing costs would increase. In addition, Utility Holdings would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Finally, there is no assurance the Company’s parent, Vectren, will have access to the equity capital markets to obtain financing when necessary or desirable.
Utility Holdings operates in an increasingly competitive industry, which may affect its future earnings.
The utility industry has been undergoing structural change for several years, resulting in increasing competitive pressure faced by electric and gas utility companies. Increased competition may create greater risks to the stability of Utility Holdings' earnings generally and may in the future reduce its earnings from retail electric and gas sales. Currently, several states, including Ohio, have passed legislation that allows customers to choose their electricity supplier in a competitive market. Indiana has not enacted such legislation. Ohio regulation also provides for choice of commodity providers for all gas customers. In 2003, the Company implemented this choice for its gas customers in Ohio and is currently in the first of the three stage process to exit the merchant function in its Ohio service territory. The state of Indiana has not adopted any regulation requiring gas choice in the Company’s Indiana service territories; however, the Company operates under approved tariffs permitting certain industrial and commercial large volume customers to choose their commodity supplier. Utility Holdings cannot provide any assurance that increased competition or other changes in legislation, regulation or policies will not have a material adverse effect on its business, financial condition or results of operations.
A significant portion of Utility Holdings gas and electric utility sales are space heating and cooling. Accordingly, its operating results may fluctuate with variability of weather.
Utility Holdings’ gas and electric utility sales are sensitive to variations in weather conditions. The Company forecasts utility sales on the basis of normal weather. Since Utility Holdings does not have a weather-normalization mechanism for its electric operations, significant variations from normal weather could have a material impact on its earnings. However, the impact of weather on the gas operations in the Company’s Indiana territories has been significantly mitigated through the implementation in 2005 of a normal temperature adjustment mechanism. Additionally, the implementation of a straight fixed variable rate design over a two year period per a January 2009 PUCO order will significantly mitigate weather risk related to Ohio residential gas sales.
Risks related to the regulation of Utility Holdings’ utility businesses, including environmental regulation, could affect the rates the Company charges its customers, its costs and its profitability.
Utility Holdings’ businesses are subject to regulation by federal, state and local regulatory authorities and are exposed to public policy decisions that may negatively impact the Company’s earnings. In particular, Utility Holdings is subject to regulation by the FERC, the NERC (North American Electric Reliability Corporation), the IURC and the PUCO. These authorities regulate many aspects of its transmission and distribution operations, including construction and maintenance of facilities, operations, and safety, and its gas marketing operations involving title passage, reliability standards, and future adequacy. In addition, these regulatory agencies approve its utility-related debt and equity issuances, regulate the rates that the Company's utilities can charge customers, the rate of return that Utility Holdings’ utilities are authorized to earn, and its ability to timely recover gas and fuel costs. Further, there are consumer advocates and other parties which may intervene in regulatory proceedings and affect regulatory outcomes. The Company’s ability to obtain rate increases to maintain its current authorized rate of return depends upon regulatory discretion, and there can be no assurance that Utility Holdings will be able to obtain rate increases or rate supplements or earn its current authorized rate of return. As gas costs remain above historical levels and are more volatile, any future disallowance might be material to the Company’s operations or financial condition.
Utility Holdings’ operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. Such emissions from electric generating facilities include particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others.
Environmental legislation also requires that facilities, sites and other properties associated with the Company's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. The Company’s current costs to comply with these laws and regulations are significant to its results of operations and financial condition. In addition, claims against the Company under environmental laws and regulations could result in material costs and liabilities. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by Utility Holdings subject to environmental regulation, its investment in environmentally compliant equipment, and the costs associated with operating that equipment, have increased and are expected to increase in the future.
Climate Change
Further, there are proposals to address global climate change that would regulate carbon dioxide (CO2) and other greenhouse gases and other proposals that would mandate an investment in renewable energy sources. Any future legislative or regulatory actions taken to address global climate change or mandate renewable energy sources could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and possibly natural gas distribution businesses. Further, any legislation would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first to operating expenses for the purchase of allowances, and later to capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices. Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Approximately 22 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers. As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.
From time to time, Utility Holdings is subject to material litigation and regulatory proceedings.
From time to time, the Company may be subject to material litigation and regulatory proceedings including matters involving compliance with state and federal laws, regulations or other matters. There can be no assurance that the outcome of these matters will not have a material adverse effect on Utility Holdings’ business, prospects, results of operations, or financial condition.
Utility Holdings’ electric operations are subject to various risks.
The Company’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs. Such operational risks can arise from circumstances such as facility shutdowns due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; and natural disasters.
The impact of MISO participation is uncertain.
Since February 2002 and with the IURC’s approval, the Company has been a member of the MISO. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over SIGECO’s electric transmission facilities as well as that of other Midwest utilities.
As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where MISO provides bid-based regulation and contingency operating reserve markets which began on January 6, 2009, it is difficult to predict near term operational impacts. The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM.
The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant. The Company timely recovers its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.
Wholesale power marketing activities may add volatility to earnings.
Utility Holdings’ regulated electric utility engages in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO hourly and real time markets. As part of these strategies, the Company may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery. Margin earned from these activities above or below $10.5 million is shared evenly with customers. These earnings from wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity or purchased power available, beyond that needed to meet firm service requirements.
Catastrophic events could adversely affect Utility Holdings’ facilities and operations.
Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts or other similar occurrences could adversely affect Utility Holdings’ facilities, operations, financial condition and results of operations.
Workforce risks could affect Utility Holdings’ financial results.
The Company is subject to various workforce risks, including but not limited to, the risk that it will be unable to attract and retain qualified personnel; that it will be unable to effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; that it will be unable to react to a pandemic illness; and that it will be unable to reach collective bargaining arrangements with the unions that represent certain of its workers, which could result in work stoppages.
The performance of Vectren’s nonutility businesses may impact Utility Holdings.
Execution of gas marketing strategies by ProLiance and Vectren’s nonutility gas retail supply operations as well as the execution of Vectren’s coal mining and energy infrastructure services strategies, and the success of efforts to invest in and develop new opportunities in the nonutility business area is subject to a number of risks. These risks include, but are not limited to, the effects of weather; failure of installed performance contracting products to operate as planned; failure to properly estimate the cost to construct projects; storage field and mining property development; increased coal mining industry regulation; potential legislation that may limit CO2 and other greenhouse gas emissions; creditworthiness of customers and joint venture partners; factors associated with physical energy trading activities, including price, basis, credit, liquidity, volatility, capacity, and interest rate risks; changes in federal, state or local legal requirements, such as changes in tax laws or rates; and changing market conditions. Credit ratings of individual entities within a consolidated organization can be influenced by changes in business prospects and developments of other entities within that organization. Thus, material adverse developments affecting those other entities related to Vectren could result in a downgrade in Utility Holdings’ credit ratings or outlook, limit its ability to access the debt markets, bank financing and commercial paper markets and, thus, its liquidity.
Vectren’s nonutility businesses support Utility Holdings’ utilities pursuant to service contracts by providing natural gas supply services, coal, and energy infrastructure services. In most instances, Vectren’s ability to maintain these service contracts depends upon regulatory approval and negotiations with interveners, and there can be no assurance that it will be able to obtain future service contracts, or that existing arrangements will not be altered.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana covering 58,100 acres of land with an estimated ready delivery from storage capability of 6.0 BCF of gas with maximum peak day delivery capabilities of 151,000 MCF per day. Indiana Gas also owns and operates three liquefied petroleum (propane) air-gas manufacturing plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of manufactured gas per day. In addition to its company owned storage and propane capabilities, Indiana Gas has contracted with ProLiance for 17.9 BCF of prepaid delivery service with a maximum peak day delivery capability of 298,600 MMBTU per day. Indiana Gas’ gas delivery system includes 12,900 miles of distribution and transmission mains, all of which are in Indiana except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported by Indiana Gas to ultimate customers in Indiana.
SIGECO owns and operates three active underground gas storage fields located in Indiana covering 6,100 acres of land with an estimated ready delivery from storage capability of 6.3 BCF of gas with maximum peak day delivery capabilities of 108,500 MCF per day. In addition to its company owned storage delivery capabilities, SIGECO has contracted with ProLiance for 0.5 BCF of prepaid delivery service with a maximum peak day delivery capability of 19,200 MMBTU per day. SIGECO's gas delivery system includes 3,200 miles of distribution and transmission mains, all of which are located in Indiana.
The Ohio operations own and operate three liquefied petroleum (propane) air-gas manufacturing plants, all of which are located in Ohio. The plants can store 0.5 million gallons of propane, and the plants can manufacture for delivery 52,200 MCF of manufactured gas per day. In addition to its propane delivery capabilities, the Ohio operations have contracted for 11.8 BCF of delivery service with a maximum peak day delivery capability of 246,100 MMBTU per day. While the Company still has title to this delivery capability, it has released it to those now supplying the Ohio operations with natural gas, and those suppliers are responsible for the demand charges. The Ohio operations’ gas delivery system includes 5,500 miles of distribution and transmission mains, all of which are located in Ohio.
Electric Utility Services
SIGECO's installed generating capacity as of December 31, 2008, was rated at 1,295 MW. SIGECO's coal-fired generating facilities are the Brown Station with two units of 490 MW of combined capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the Culley Station with two units of 360 MW of combined capacity, and Warrick Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking units are: two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4) located at the Brown Station; two Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65 MW); and two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW. The Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil. Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally used only for reserve, peaking, or emergency purposes due to the higher per unit cost of generation.
SIGECO's transmission system consists of 924 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 32 substations with an installed capacity of 4,200 megavolt amperes (Mva). The electric distribution system includes 4,200 pole miles of lower voltage overhead lines and 349 trench miles of conduit containing 2,000 miles of underground distribution cable. The distribution system also includes 98 distribution substations with an installed capacity of 2,900 Mva and 54,000 distribution transformers with an installed capacity of 2,500 Mva.
SIGECO owns utility property outside of Indiana approximating nine miles of 138,000 volt electric transmission line which is located in Kentucky and which interconnects with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky.
Property Serving as Collateral
SIGECO's properties are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows. See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, rate and regulatory matters. The consolidated financial statements are included in “Item 8 Financial Statements and Supplementary Data.”
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter to a vote of security holders.
PART II
ITEM 5.
ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock Market Price
All of the outstanding shares of Utility Holdings’ common stock are owned by Vectren. Utility Holdings’ common stock is not traded. There are no outstanding options or warrants to purchase Utility Holdings’ common equity or securities convertible into Utility Holdings’ common equity. Additionally, Utility Holdings has no plans to publicly offer its common equity securities.
Dividends Paid to Parent
During 2008, Utility Holdings paid dividends to its parent company totaling $20.8 million in each quarter.
During 2007, Utility Holdings paid dividends to its parent company totaling $19.1 million in each quarter.
In the first quarter of 2009, the board of directors declared a $20.6 million dividend, payable to Vectren.
Dividends on shares of common stock are payable at the discretion of the board of directors out of legally available funds. Future payments of dividends, and the amounts of these dividends, will depend on the Company’s financial condition, results of operations, capital requirements, and other factors. Certain lending arrangements contain restrictive covenants, including the maintenance of a total debt to total capitalization ratio, which could limit the Company’s ability to pay dividends. These restrictive covenants are not expected to affect the Company’s ability to pay dividends in the near term.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data is derived from the Company’s audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Utility Holdings generates revenue primarily from the delivery of natural gas and electric service to its customers. Utility Holdings’ primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services.
Vectren has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of Utility Holdings’ SEC filings.
The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto.
Executive Summary of Consolidated Results of Operations
Results
In 2008, the Utility Holdings’ earnings were $111.1 million compared to $106.5 million in 2007. The 4 percent increase is due primarily to a full year of base rate changes in the Indiana service territories and increased earnings from wholesale power operations. Increases were offset somewhat by increased operating costs associated with maintenance and reliability programs contemplated in the base rate cases and favorable weather in 2007.
In 2007 compared to 2006, the increase in earnings primarily resulted from base rate increases in the Vectren South service territory, the combined impact of residential and commercial usage and lost margin recovery, favorable weather, and increased wholesale power margins. The increase was offset somewhat by increased operating costs including depreciation expense in 2007 and a lower effective tax rate in 2006.
In the Company’s electric and Ohio natural gas service territories which are not protected by weather normalization mechanisms, management estimates the margin impact of weather to be approximately $1.2 million favorable or $0.7 million after tax compared to 30-year normal temperatures in 2008. In 2007 management estimates a $5.5 million favorable impact on margin compared to normal or $3.3 million after tax, and in 2006 an $8.3 million unfavorable impact on margin compared to normal or $4.9 million after tax.
Ice Storm
On January 27, 2009, a major ice storm in the Company’s southern Indiana territory resulted in an extended disruption of electricity to approximately 75,000 of the Company’s 141,000 electric customers. Electricity was restored to substantially all customers within one week. Management estimates the total cost of restoration could approximate $15 to $20 million, the majority of which is expected to be capitalized as utility plant.
Results of Operations
Significant Fluctuations
Margin
Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.
Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather. Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas has increased. Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. Indiana Gas’ territory has both an NTA since 2005 and lost margin recovery since December 2006. SIGECO’s natural gas territory has an NTA since 2005, and lost margin recovery began when new base rates went into effect August 1, 2007. The Ohio service territory had lost margin recovery since October 2006. The Ohio lost margin recovery mechanism ended when new base rates went into effect in February 2009. This mechanism was replaced by a rate design, commonly referred to as a straight fixed variable rate design, which is more dependent on service charge revenues and less dependent on volumetric revenues than previous rate designs. This new rate design, which will be phased in over a two year period, also prospectively mitigates some weather risk in Ohio. SIGECO’s electric service territory has neither NTA nor lost margin recovery mechanisms.
Gas and electric margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products. The recent recession may have some negative impact on both gas and electric large customers. This impact may include tempered growth, significant conservation measures, and perhaps even plant closures or bankruptcies. While no one industrial customer comprises 10 percent of consolidated revenues, the top five industrial electric customers comprise approximately 17 percent of electric utility revenues, and therefore any significant decline in their collective revenues could adversely impact operating results. Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts.
Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas and fuel costs, as well as other tracked expenses. Expenses subject to tracking mechanisms include Ohio bad debts and percent of income payment plan expenses, Indiana gas pipeline integrity management costs, and costs to fund Indiana energy efficiency programs. Certain operating costs associated with operating environmental compliance equipment were also tracked prior to their recovery in base rates that went into effect on August 15, 2007. The latest Indiana service territory rate cases, implemented in 2007 and 2008 also provide for the tracking of MISO revenues and costs, as well as the gas cost component of bad debt expense based on historical experience and unaccounted for gas. Unaccounted for gas is also tracked in the Ohio service territory.
Electric wholesale activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations.
Gas Utility Margin (Gas utility revenues less Cost of gas)
Gas Utility margin and throughput by customer type follows:
For the year ended December 31, 2008, gas utility margins were $449.6 million, an increase of $27.4 million compared to 2007. The Vectren North base rate increase, effective February 14, 2008 added $11.8 million in margin. Also impacting year over year results was the Vectren South base rate increase, effective August 1, 2007, increasing margin for the full 2008 year approximately $3.6 million. In 2008, Ohio weather was 8 percent colder than the prior year and resulted in an estimated increase in margin of approximately $3.2 million compared to 2007. Operating costs, including revenue and usage taxes, directly recovered in margin, increased gas margin $7.8 million. The average cost per dekatherm of gas purchased for the year ended December 31, 2008, was $9.61 compared to $8.14 in 2007 and $8.64 in 2006.
Gas Utility margins increased $31.2 million in 2007 compared to 2006. Residential and commercial customer usage, including lost margin recovery, increased margin $13.3 million year over year. For all of 2007, Ohio weather was 6 percent warmer than normal, but approximately 6 percent colder than the prior year and resulted in an estimated increase in margin of approximately $2.0 million compared to 2006. Margin increases associated with the Vectren South base rate increase, effective August 1, 2007, were $3.3 million. Recovery of gas storage carrying costs in Ohio was $2.3 million. Lastly, operating costs, including revenue and usage taxes, directly recovered in margin increased gas margin $10.3 million year over year. During 2007, the Company resolved all remaining issues related to a 2005 disallowance by the PUCO of gas costs incurred by the Ohio utility operations, resulting in an additional charge of $1.1 million.
Electric Utility Margin (Electric Utility revenues less Cost of fuel and purchased power)
Electric Utility margin and volumes sold by customer type follows:
Retail
Electric retail utility margin was $308.8 million for the year ended December 31, 2008, an increase of approximately $16.6 million compared to 2007. The base rate increase that went into effect on August 15, 2007, produced incremental margin of $27.0 million year over year when netted with municipal contracts that were allowed to expire. Management estimates the year over year decreases in usage by residential and commercial customers due to weather, which was very warm the prior summer, to be $7.5 million. Other usage declines due in part to a weakening economy and conservation measures were the primary reason for the remaining decrease.
In 2007, electric retail utility margins increased $35.1 million when compared to 2006. Management estimates the year over year increases in usage by residential and commercial customers due to weather to be $11.8 million. The base rate increase that went into effect on August 15, 2007, produced incremental margin of $17.9 million. During 2007, cooling degree days were 33 percent above normal compared to 5 percent below normal in 2006. Recovery of pollution control investments and expenses increased margin $5.5 million year over year.
Margin from Wholesale Activities
Periodically, generation capacity is in excess of native load. The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets. A majority of the margin generated from these activities is associated with wholesale off-system sales, and substantially all off-system sales occur into the MISO Day Ahead and Real Time markets.
Further detail of Wholesale activity follows:
For the year ended December 31, 2008, wholesale margins were $32.5 million, representing an increase of $11.6 million, compared to 2007.
During 2008, margin from off-system sales retained by the Company increased $6.3 million. The Company experienced higher wholesale power marketing margins due to the increase in off peak volumes available for sale off system, driven primarily by expiring municipal contracts, and increases in wholesale prices. The base rate case effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers, and 2008 results reflect the impact of that sharing. Off-system sales totaled 1,512.9 GWh in 2008, compared to 921.3 GWh in 2007 and 889.4 GWh in 2006.
Beginning in June 2008, the Company began earning a return on electric transmission projects constructed by the Company in its service territory that benefit reliability throughout the region. These returns primarily account for the year over year increase of $4.8 million in transmission system sales.
For the year ended December 31, 2007, wholesale margins were $20.9 million, which represents an increase of $7.3 million, compared to 2006. The increase is primarily due to losses on financial contracts experienced in 2006 and higher fourth quarter wholesale prices. In 2006, the availability of excess capacity was reduced by scheduled outages associated with the installation of environmental compliance equipment.
Operating Expenses
Other Operating
For the year ended December 31, 2008, other operating expenses were $300.3 million, which represents an increase of $34.2 million, compared to 2007. Costs in 2008 resulting from increased maintenance and other reliability activities, including amortization of prior deferred costs contemplated in base rate increases, increased approximately $35.3 million year over year. Operating costs that are directly recovered in utility margin increased $4.2 million year over year. Costs associated with lower performance compensation and share based compensation and other cost reductions partially offset these increases.
In 2007, other operating expenses increased $27.1 million compared to 2006. Operating costs that are directly recovered in utility margin, including costs funding Indiana energy efficiency programs, increased $9.5 million year over year. Increases in operating costs associated with lost margin recovery and conservation initiatives that are not directly recovered in margin increased $1.3 million year over year. Costs directly attributable to the Vectren South rate cases, including amortization of prior deferred costs, totaled $3.6 million in 2007. Expenses in 2006 are offset by the gain on the sale of a storage asset of approximately $4.4 million. The remaining increases are primarily due to increased wage and benefit costs.
Depreciation & Amortization
Depreciation expense increased $7.1 million in 2008 compared to 2007 as well as in 2007 compared to 2006. Expense in 2008 and 2007 includes $3.8 million and $1.8 million, respectively of increased amortization associated with prior electric demand side management costs pursuant to the August 15, 2007 electric base rate order. The remaining increases are also attributable to increased utility plant in service.
.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $4.2 million in 2008 compared to 2007 and increased $3.9 million in 2007 compared 2006. The increases are primarily attributable to higher utility receipts, excise, and usage taxes. These variations resulted primarily from volatility in revenues and gas volumes sold.
Other Income-Net
Other-net reflects income of $4.0 million in 2008 compared to $9.4 million in 2007 and $7.6 million in 2006. The decrease in 2008 compared to 2007 is primarily due to lower returns associated with investments that fund deferred compensation arrangements and lower interest income. The increase in 2007 compared to 2006 relates primarily to increased AFUDC due to increased capital spending and higher interest income.
Interest Expense
For the year ended December 31, 2008, interest expense was $79.9 million, a decrease of $0.7 million compared to 2007, as lower average short-term debt levels and lower average short-term interest rates were partially offset by higher long-term balances and interest rates.
In 2007, interest expense increased $3.1 million compared to 2006. The increase is primarily driven by rising interest rates during the period and is also impacted by higher levels of short-term borrowings. The 2007 increase was mitigated somewhat by the full impact of financing transactions completed in October 2006. Interest costs in 2006 reflect permanent financing transactions completed in the fourth quarter of 2005 in which $150 million in debt-related proceeds were received and used to retire short-term borrowings and other long-term debt.
Income Taxes
Federal and state income taxes increased $0.9 million in 2008 compared to 2007 and $19.0 million in 2007 compared to 2006. The changes are impacted primarily by fluctuations in pre-tax income and a lower effective tax rate in 2008 and 2006.
Environmental Matters
The Company is subject to federal, state, and local regulations with respect to environmental matters, principally air, solid waste, and water quality. Pursuant to environmental regulations, the Company is required to obtain operating permits for the electric generating plants that it owns or operates and construction permits for any new plants it might propose to build. Regulations concerning air quality establish standards with respect to both ambient air quality and emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury. Regulations concerning water quality establish standards relating to intake and discharge of water from electric generating facilities, including water used for cooling purposes in electric generating facilities. Because of the scope and complexity of these regulations, the Company is unable to predict the ultimate effect of such regulations on its future operations.
Clean Air Act Initiatives
In March of 2005, the USEPA finalized the Clean Air Interstate Rule (CAIR). CAIR is an allowance cap and trade program requiring further reductions from coal-burning power plants in NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations. Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the USEPA for promulgation of revisions in accordance with the Court’s July 11, 2008 Order. Thus, the original version of CAIR promulgated in March of 2005 remains effective while USEPA revises it per the Court’s guidance. It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised; however, most of the these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.
Similarly, in March of 2005, USEPA promulgated the Clean Air Mercury Rule (CAMR). CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008. It is quite possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress. It is also possible that the USEPA will promulgate a revised mercury regulation in 2009.
To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2 reductions, SIGECO has IURC authority to invest in clean coal technology. Using this authorization, SIGECO has invested approximately $307 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems and fabric filters. SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007. Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.
Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). The order allows SIGECO to recover an approximate 8 percent return on capital investments through a rider mechanism which is periodically updated for actual costs incurred less post in-service depreciation expense. Through December 31, 2008, the Company has invested approximately $97.6 million in this project. The scrubber was placed into service on January 1, 2009, and the Company expects the total project investment to approximate $100 million once all post in-service investments are completed. Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009. With the SO2 scrubber fully operational, SIGECO is positioned for compliance with the additional SO2 reductions required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA.
Climate Change
The Company is committed to responsible environmental stewardship and conservation efforts as demonstrated by its proactive approach to balancing environmental and customer needs. While scientific uncertainties exist and the debate surrounding global climate change is ongoing, the growing understanding of the science of climate change would suggest a strong potential for adverse economic and social consequences should world-wide carbon dioxide (CO2) and other greenhouse gas emissions continue at present levels.
The need to reduce CO2 and other greenhouse gas emissions, yet provide affordable energy requires thoughtful balance. For these reasons, the Company supports a national climate change policy with the following elements:
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An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions;
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Provisions for enhanced use of renewable energy sources as a supplement to base load coal generation including effective energy conservation, demand side management and generation efficiency measures;
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A flexible market-based cap and trade approach with zero cost allowance allocations to coal-fired electric generators. The approach should have a properly designed economic safety valve in order to reduce or eliminate extreme price spikes and potential price volatility. A long lead time must be included to align nearer-term technology capabilities and expanded generation efficiency and other enhanced renewable strategies, ensuring that generation sources will rely less on natural gas to meet short term carbon reduction requirements. This new regime should allow for adequate resource and generation planning and remove existing impediments to efficiency enhancements posed by the current New Source Review provisions of the Clean Air Act;
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Inclusion of incentives for investment in advanced clean coal technology and support for research and development; and
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A strategy supporting alternative energy technologies and biofuels and increasing the domestic supply of natural gas to reduce dependence on foreign oil and imported natural gas.
Current Initiatives to Increase Conservation and Reduce Emissions
The Company is committed to its policy on climate change and conservation. Evidence of this commitment includes:
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Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs;
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Recently executing a 20 year contract to purchase 30MW of wind energy generated by a wind farm in Benton County, Indiana;
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Evaluating other renewable energy projects to complement base load coal fired generation in advance of mandated renewable energy portfolio standards;
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Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories;
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Participation in an electric conservation and demand side management collaborative with the OUCC and other customer advocate groups;
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Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;
·
Reducing the Company’s carbon footprint by measures such as purchasing hybrid vehicles, and optimizing generation efficiencies;
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Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group.
Legislative Actions and Other Climate Change Initiatives
There are currently several forms of legislation being circulated at the federal level addressing the climate change issue. These proposals generally involve either: 1) a “cap and trade” approach where there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases or 2) a carbon tax. Currently no legislation has passed either house of Congress.
In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs. While no climate change legislation is pending in the State of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas Reduction Accord, and its legislature has in the recent past debated, but did not pass, renewable energy portfolio standards. It is expected that the Indiana State legislature will address a renewable energy portfolio standard again in 2009.
In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the USEPA to determine whether greenhouse gas emissions from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. Should the USEPA find such endangerment, it is likely that major stationary sources will be subject to regulation under the Act. In 2008, the USEPA published its Advanced Notice of Proposed Rulemaking in which the agency solicited comment as to whether it is appropriate or effective to regulate greenhouse gas emissions under the Act. The Obama administration has asserted that it will act on the endangerment finding in the absence of comprehensive federal legislation within the next 18 months.
Impact of Legislative Actions and Other Initiatives is Unknown
If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and possibly natural gas distribution businesses. Further, any legislation would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first to operating expenses for the purchase of allowances, and later to capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices. Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Approximately 22 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers. As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.
Environmental Remediation Efforts
In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.
Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.
Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $21.6 million. The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20 percent and 50 percent.
With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.5 million.
In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM in February 2004. SIGECO is also named in a lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.
SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the May 2007 lawsuit. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded cumulative costs that it reasonably expects to incur totaling approximately $8.7 million. With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.0 million.
Environmental remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate PRP and insurance settlement recoveries. Such cumulative costs are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2008, approximately $6.5 million is included in Other Liabilities related to the remediation of these sites.
Jacobsville Superfund Site
On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including the Company's Wagner Operations Center. The Company’s property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the property contains lead contaminated soils. The Company's own soil testing, completed during the construction of the Operations Center, did not indicate that the property contains lead contaminated soils. At this time, the Company anticipates only additional soil testing could be requested by the USEPA at some future date.
Rate and Regulatory Matters
Gas and electric operations with regard to retail rates and charges, terms of service, accounting matters, issuance of securities, and certain other operational matters specific to its Indiana customers are regulated by the IURC. The retail gas operations of the Ohio operations are subject to regulation by the PUCO.
Gas rates in Indiana contain a gas cost adjustment (GCA) clause. The GCA clause allows the Company to charge for changes in the cost of purchased gas. Electric rates contain a fuel adjustment clause (FAC) that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The IURC approved agreement authorizing this recovery expires in April 2010, and is subject to automatic annual renewals.
GCA and FAC procedures involve periodic filings and IURC hearings to establish the amount of price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between the estimated cost of gas, cost of fuel, and net energy cost of purchased power and actual costs incurred. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in margin. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers.
The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. These earnings tests have not had any material impact to the Company’s recent operating results.
Prior to October 1, 2008, gas costs were recovered in Ohio through a gas cost recovery (GCR) clause. The GCR clause operated similar to the GCA clause in Indiana. The PUCO periodically audited the GCR rates. The period from November 2005 to September 2008, the final GCR period subject to audit, is currently under audit by the PUCO. After October 1st, the Company is no longer the supplier, and the GCR is no longer necessary.
Vectren Energy Delivery Ohio, Inc. (VEDO) Gas Base Rate Order Received
On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case. The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.
The order also adjusts the rate design that will be used to collect the agreed-upon revenue from VEDO's residential customers. The order authorizes the use of a straight fixed variable rate design which places all, or most, of the fixed cost recovery in the customer service charge. Using a phased in approach, revenues based on volumes sold will be entirely replaced with a fixed charge after one year. A straight fixed variable design mitigates some weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism, which expired when this new rate design went into effect in February 2009. In 2008, results include approximately $4.3 million of revenue from the existing lost margin recovery mechanism that will not continue once this base rate increase is in effect. The OCC has filed a request for rehearing on the rate design finding by the PUCO. The rehearing request mirrors similar requests filed by the OCC in each case where the PUCO has approved similar rate designs, and all such requests have been denied.
With this rate order the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of bad debt and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.
Vectren Energy Delivery Ohio, Inc. Begins Process to Exit the Merchant Function
On August 20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing. This standard pricing is comprised of the monthly NYMEX settlement price plus a fixed adder. This auction, which is effective from October 1, 2008 through March 31, 2010, is the initial step in exiting the merchant function in the Company’s Ohio service territory. The approach eliminates the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. On October 1st, VEDO’s entire natural gas inventory was transferred, receiving proceeds of approximately $107 million. The PUCO has also provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition. As the cost of gas is currently passed through to customers through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.
Vectren North (Indiana Gas Company, Inc.) Gas Base Rate Order Received
On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case. The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million. The order also provides for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.
Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The regulatory accounting treatment allows for the continuation of the accrual for allowance for funds used during construction (AFUDC) and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years on each project.
With this order, the Company has in place for its North gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a bad debt expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense.
Vectren South (SIGECO) Electric Base Rate Order Received
On August 15, 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s electric rate case. The order provided for an approximate $60.8 million electric rate increase to cover the Company’s cost of system growth, maintenance, safety and reliability. The order provided for, among other things: recovery of ongoing costs and deferred costs associated with the MISO; operations and maintenance (O&M) expense increases related to managing the aging workforce, including the development of expanded apprenticeship programs and the creation of defined training programs to ensure proper knowledge transfer, safety and system stability; increased O&M expense necessary to maintain and improve system reliability; benefit to customers from the sale of wholesale power by sharing equally with customers any profit earned above or below $10.5 million of wholesale power margin; recovery of and return on the investment in past demand side management programs to help encourage conservation during peak load periods; timely recovery of the Company’s investment in certain new electric transmission projects that benefit the MISO infrastructure; an overall rate of return of 7.32 percent on rate base of approximately $1,044 million and an allowed ROE of 10.4 percent.
Vectren South Gas Base Rate Order Received
On August 1, 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s gas rate case. The order provided for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an overall rate of return of 7.2 percent on rate base of approximately $122 million. The order also provided for the recovery of $2.6 million of costs through separate cost recovery mechanisms rather than base rates.
Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The regulatory accounting treatment allows for the continuation of the accrual for allowance for funds used during construction (AFUDC) and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $3 million and the treatment cannot extend beyond three years on each project.
With this order, the Company now has in place for its South gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a bad debt expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense.
MISO
Since February 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
The Company is typically in a net sales position with MISO as generation capacity is in excess of that needed to serve native load and is only occasionally in a net purchase position. When the Company is a net seller such net revenues are included in Electric Utility revenues and when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased power. Net positions are determined on an hourly basis. Since the Company became an active MISO member, its generation optimization strategies primarily involve the sale of excess generation into the MISO day ahead and real-time markets. Net revenues from wholesale activities included in Electric Utility revenues totaled $57.6 million in 2008, $39.8 million in 2007 and $29.8 million in 2006.
The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric Utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered/refunded through tracking mechanisms.
As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where MISO began providing a bid-based regulation and contingency operating reserve markets on January 6, 2009, it is difficult to predict near term operational impacts. The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM.
The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant. The Company timely recovers its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.
One such project is an interstate 345 kilovolt transmission line that will connect the Company’s A B Brown Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south. Throughout the project, SIGECO is to recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is periodically updated for actual costs incurred. Of the total investment, which is expected to approximate $70 million, as of December 31, 2008, the Company has invested approximately $3.1 million. The Company expects this project to be operational in 2011. At that time, any operating expenses including depreciation expense are also expected to be recovered through a FERC approved rider mechanism. Further, the approval allows for recovery of expenditures made even in the event currently unforeseen difficulties delay or permanently halt the project.
Impact of Recently Issued Accounting Guidance
SFAS
On January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (SFAS 157), except as it applies to nonfinancial assets and nonfinancial liabilities. FSP FAS 157-2 delayed the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value on a recurring basis (at least annually). This FSP deferred the effective date of Statement 157 for those items to fiscal years beginning after November 15, 2008.
SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement does not require any new fair value measurements; however, the standard impacts how other fair value based GAAP is applied. The partial adoption of SFAS 157 did not have a material impact on the Company’s financial position, results of operations or cash flows. Disclosures impacted by SFAS 157 are included in Note 10 to the consolidated financial statements. The adoption of the remaining components of SFAS 157 on January 1, 2009 is also not expected to be material on the Company’s financial position, results of operations or cash flows.
SFAS
Also on January 1, 2008, the Company adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS 159). SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The Company did not choose to apply the option provided in SFAS 159 to any of its eligible items; therefore, its adoption did not have any impact on the Company’s financial statements or results of operations.
SFAS 141 (Revised 2007)
In December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS 141R). SFAS 141R establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination. SFAS 141R applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities. SFAS 141R applies prospectively to business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption is not permitted. The Company will adopt SFAS 141R on January 1, 2009, and because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.
SFAS
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an Amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 enhances the current disclosures under SFAS 133 and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation in order to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Tabular disclosure of fair value amounts and gains and losses on derivative instruments and related hedged items is required. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption encouraged. The Company will adopt SFAS 161 on January 1, 2009, and the impact is not expected to be material to the Company’s financial position or results of operations.
SFAS
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of accounting principles and the framework for selecting principles used in the preparation of financial statements. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles”. The implementation of this standard will not have a material impact on its financial position and results of operations.
Critical Accounting Policies
Management is required to make judgments, assumptions, and estimates that affect the amounts reported in the consolidated financial statements and the related disclosures that conform to accounting principles generally accepted in the United States. The consolidated financial statement footnotes describe the significant accounting policies and methods used in the preparation of the consolidated financial statements. Certain estimates used in the financial statements are subjective and use variables that require judgment. These include the estimates to perform goodwill impairments tests. The Company makes other estimates, in the course of accounting for unbilled revenue and the effects of regulation and intercompany allocations that are critical to the Company’s financial results but that are less likely to be impacted by near term changes. Other estimates that significantly affect the Company’s results, but are not necessarily critical to operations, include depreciating utility and nonutility plant, valuing reclamation liabilities, valuing derivative contracts, and estimating uncollectible accounts, among others. Actual results could differ from these estimates.
Goodwill
The Company performs an annual impairment analysis of its goodwill, all of which resides in the Gas Utility Services operating segment, at the beginning of each year, and more frequently if events or circumstances indicate that an impairment loss may have been incurred. Impairment tests are performed at the reporting unit level. The Company has determined its Gas Utility Services operating segment as identified in Note 11 to the consolidated financial statements to be the reporting unit. An impairment test requires that a reporting unit’s fair value be estimated. The Company used a discounted cash flow model to estimate the fair value of its Gas Utility Services operating segment, and that estimated fair value was compared to its carrying amount, including goodwill. The estimated fair value was in excess of the carrying amount in 2008, 2007, and 2006 and therefore resulted in no impairment.
Estimating fair value using a discounted cash flow model is subjective and requires significant judgment in applying a discount rate, growth assumptions, company expense allocations, and longevity of cash flows. A 100 basis point increase in the discount rate utilized to calculate the Gas Utility Services segment’s fair value also would have resulted in no impairment charge.
Intercompany Allocations
Support Services
Vectren provides corporate, general, and administrative services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers, and/or the level of payroll, revenue contribution, and capital expenditures. Allocations are at cost. Management believes that the allocation methodology is reasonable and approximates the costs that would have been incurred had the Company secured those services on a stand-alone basis. The allocation methodology is not subject to near term changes.
Pension and Other Postretirement Obligations
Vectren satisfies the future funding requirements of its pension and other postretirement plans and the payment of benefits from general corporate assets. An allocation of expense is determined, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. Vectren has historically measured its obligations annually on September 30. However, in 2008, Vectren measured these obligations on December 31 in accordance with 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). These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Management believes these direct charges when combined with benefit-related corporate charges discussed in “support services” above approximate costs that would have been incurred if the Company accounted for benefit plans on a stand-alone basis.
Vectren estimates the expected return on plan assets, discount rate, rate of compensation increase, and future health care costs, among other inputs, and relies on actuarial estimates to assess the future potential liability and funding requirements of pension and postretirement plans. Vectren used the following weighted average assumptions to develop 2008 periodic benefit cost: a discount rate of 6.25 percent, an expected return on plan assets of 8.25 percent, a rate of compensation increase of 3.75 percent, and an inflation assumption of 3.5 percent. In 2008, the Company increased the discount rate from 5.85 percent, which was used to measure 2007 periodic cost due to an increase in benchmark interest rates. Due to the recent and significant decline in asset values, retirement plan costs are expected to be higher in 2009 and in subsequent years. Management currently estimates a pension and postretirement cost of approximately $14 to $16 million in 2009 depending on funding levels, compared to approximately $11 million in 2008. Future changes in health care costs, work force demographics, interest rates, asset values or plan changes could significantly affect the estimated cost of these future benefits. Management estimates that a 50 basis point decrease in the discount rate would generally increase periodic benefit cost by approximately $1.7 million.
Unbilled Revenues
To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period. The Company uses actual units billed during the month to allocate unbilled units by customer class. Those allocated units are multiplied by rates in effect during the month to calculate unbilled revenue at balance sheet dates.
Regulation
At each reporting date, the Company reviews current regulatory trends in the markets in which it operates. This review involves judgment and is critical in assessing the recoverability of regulatory assets as well as the ability to continue to account for its activities based on the criteria set forth in SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Based on the Company’s current review, it believes its regulatory assets are probable of recovery. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets and liabilities. In the unlikely event of a change in the current regulatory environment, such write-offs and impairment charges could be significant.
Financial Condition
Utility Holdings funds the short-term and long-term financing needs of utility operations. Vectren does not guarantee Utility Holdings’ debt. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. Information about the subsidiary guarantors as a group is included in Note 14 to the consolidated financial statements. Utility Holdings’ long-term and short-term obligations outstanding at December 31, 2008, approximated $823 million and $192 million, respectively. Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations. Utility Holdings’ operations have historically been the primary source for Vectren’s common stock dividends.
The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at December 31, 2008, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. The credit ratings on SIGECO's secured debt are A/A3. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s is stable. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.
The Company’s consolidated equity capitalization objective is 45-55 percent of long-term capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans and seasonal factors that affect the Company’s operations. The Company’s equity component was 52 percent and 51 percent of long-term capitalization at December 31, 2008 and 2007, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholder’s equity.
As of December 31, 2008, the Company was in compliance with all financial covenants.
Available Liquidity in Current Credit Conditions
As noted below, in 2008 the Company completed permanent financing transactions, including the issuance of $125 million in long-term debt; receiving a $125 million capital contribution from Vectren. These transactions have increased the level of unutilized short-term borrowing capacity. This unutilized short-term debt capacity, when coupled with expected internally generated funds and any additional long-term financings undertaken, should provide sufficient liquidity over the next twelve to twenty four months to fund anticipated capital expenditures, investments, and debt security redemptions.
Regarding debt redemptions, there are none in 2009 and 2010. However, holders of certain debt instruments have the one-time option to put them to the Company. Debt subject to these put provisions total $80 million in 2009 and $10 million in 2010.
The Company continues to develop plans to issue additional long-term debt over the next twelve to twenty four months, assuming its A-/Baa1 investment grade credit ratings will allow it to access the capital markets, as the need arises. However, while debt markets have improved somewhat, such long-term debt issued during this period could be more expensive than in recent history. This permanent financing would reduce reliance on unutilized short-term capacity.
Consolidated Short-Term Borrowing Arrangements
At December 31, 2008, the Company had $520 million of short-term borrowing capacity, of which approximately $328 million was available. Of the $520 million in capacity, $515 million is available through November, 2010.
Historically, the Company has funded its short-term borrowing needs through the commercial paper market. In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the continued turmoil and volatility in the financial markets. As a result, the Company has met working capital requirements through a combination of A2/P2 commercial paper issuances and draws on its $515 million commercial paper back-up credit facilities. In addition, the Company increased its cash investments by approximately $40 million during the fourth quarter of 2008. This cash position was liquidated in January 2009 based upon improvements in the short-term debt and commercial paper markets; and therefore, resulted in an increase to the available short-term debt capacity.
Proceeds from Stock Plans
Vectren may periodically issue new common shares to satisfy dividend reinvestment plan, stock option plan, and other employee benefit plan requirements and contribute those proceeds to Utility Holdings. New issuances contributed to Utility Holdings added additional liquidity of $5.3 million in 2007. In 2009, new issuances required to meet these various plan requirements are estimated to be approximately $6 million, and such amount is expected to be contributed to Utility Holdings.
Potential Uses of Liquidity
Planned Capital Expenditures
The timing and amount of planned capital expenditures, including contractual purchase commitments discussed below, for the five-year period 2009 - 2013 are estimated as follows (in millions): $250 in 2009, $265 in 2010, $255 in 2011, $270 in 2012, and $245 in 2013.
Pension and Postretirement Funding Obligations
Vectren’s pension plan asset values were approximately $151 million at December 31, 2008, compared to asset values as of December 31, 2007 of approximately $212 million, and since December 31, 2008, market values have remained volatile and have experienced further declines. Asset values for qualified plans as of December 31, 2008 are approximately 61 percent of the projected benefit obligation. Vectren management currently estimates that the qualified pension plans may require Company contributions of approximately $25 to $30 million in 2009 and a lesser level in 2010, a portion of which may be funded by Utility Holdings. During 2008, Vectren made contributions of approximately $12 million, none of which were funded by Utility Holdings.
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2008:
(1)
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. These provisions allow holders the one-time option to put debt back to the Company at face value or the Company to call debt at face value or at a premium. Long-term debt subject to tender during the years following 2008 (in millions) is $80.0 in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter.
(2)
The settlement period of these utility and nonutility plant obligations is estimated.
(3)
The Company has other long-term liabilities that total approximately $105 million. This amount is comprised of the following: deferred compensation and share-based compensation $27 million, asset retirement obligations $25 million, pension obligations $19 million, postretirement obligations $19 million, investment tax credits $7 million, environmental remediation $6 million, and other obligations including unrecognized tax benefits totaling $2 million. Based on the nature of these items their expected settlement dates cannot be estimated.
The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Because of the pass through nature of these costs and their insignificant impact to earnings, they have not been included in the listing of contractual obligations.
Off Balance Sheet Arrangements
As of December 31, 2008, the Company does not have any material off balance sheet arrangements.
Comparison of Historical Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $435.0 million in 2008, compared to $232.2 million in 2007 and $286.1 million in 2006.
In 2008 cash flow from operating activities increased $202.8 million compared to 2007. Working capital changes generated cash of $71.5 million in 2008 compared to cash used of $33.7 million in 2007. The increase in cash from working capital results primarily from the permanent reduction of natural gas inventory associated with VEDO’s exit of the merchant function, offset by growth in recoverable fuel balances. Higher levels of deferred taxes due primarily to federal stimulus plans authorizing bonus depreciation on qualifying capital expenditures increased cash flow approximately $40.3 million. The remaining increase in operating cash flow is primarily due to the cash collection of previously deferred regulatory assets and higher earnings and depreciation.
While net income increased substantially in 2007 compared to 2006, cash flow from operating activities decreased $53.9 million. The decrease was primarily a result of changes in working capital accounts. Working capital changes used cash of $33.7 million in 2007 compared to cash generated of $68.7 million in 2006. These decreases were partially offset by the higher earnings in 2007 as well as increased deferred taxes and depreciation.
Financing Cash Flow
Although working capital requirements are generally funded by cash flow from operations, the Company uses short-term borrowings to supplement working capital needs when accounts receivable balances are at their highest and gas storage is refilled. Additionally, short-term borrowings are required for capital projects and investments until they are financed on a long-term basis.
Net cash flow used for financing activities was $85.9 million in 2008. The increased cash used for financing activities during 2008 compared to 2007 is reflective the increased operating cash flows used to repay short-term borrowings and is also reflective of the impact of completed long-term financing transactions, including the issuance of long term debt and a capital contribution from Vectren. In 2007 compared to 2006, financing activities reflect short-term and long-term debt proceeds and stock option proceeds offset by debt payments and dividends.
In 2008, Utility Holdings issued $125 million of senior unsecured securities and received a $124.8 million capital contribution from Vectren. Those proceeds were used to refinance certain capital projects originally financed with short-term borrowings. Also, during the first quarter of 2008, the Company mitigated its exposure to auction rate debt markets. In 2006, Utility Holdings issued $100 million of senior unsecured securities and used those proceeds to retire higher coupon long-term debt. These transactions are more fully described below.
Capital Contribution from Vectren
On June 27, 2008, Vectren physically settled an equity forward agreement associated with a 2007 public offering of its common stock. Vectren transferred net proceeds of approximately $124.8 million to Utility Holdings, and Utility Holdings used the proceeds to repay short-term debt obligations incurred primarily to fund its capital expenditure program. The proceeds received were recorded as an increase to Common Stock in Common Shareholder’s Equity and are presented in the Statement of Cash Flows as a financing activity.
Additional Capital Contributions
In addition to the $124.8 million capital contribution above, during the years ended December 31, 2008, 2007 and 2006, the Company has cumulatively received additional capital of $25.3 million from Vectren. Of that total, $20 million was funded by Vectren’s nonutility operations, and $5.3 million was funded by new share issues from Vectren’s dividend reinvestment plan.
Utility Holdings 2008 Debt Issuance
In March 2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes) at par. The 2039 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several.
The 2039 Notes have no sinking fund requirements, and interest payments are due monthly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest. During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue. The proceeds from the sale of the 2039 Notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million.
Auction Rate Securities
On December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt long-term debt. The debt had a life of 33 years, maturing on January 1, 2041. The initial interest rate was set at 4.50 percent but the rate was to reset every 7 days through an auction process that began December 13, 2007. This new debt was collateralized through the issuance of first mortgage bonds and the payment of interest and principal was insured through Ambac Assurance Corporation (Ambac).
In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt, including the $17 million issued in December 2007, of its plans to convert that debt from its current auction rate mode into a daily interest rate mode. In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest. During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million. The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041. The remaining $41.3 million continues to be held in treasury and is expected to be remarketed in 2009.
Utility Holdings 2006 Debt Issuance
In October 2006, Utility Holdings issued $100 million in 5.95 percent senior unsecured notes due October 1, 2036 (2036 Notes). The 30-year notes were priced at par. The 2036 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. These notes, as well as the timely payment of principal and interest, are insured by a financial guaranty insurance policy by Financial Guaranty Insurance Company (FGIC).
The 2036 Notes have no sinking fund requirements, and interest payments are due quarterly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after October 1, 2011, at 100 percent of principal amount plus accrued interest. During the first and second quarters of 2006, Utility Holdings entered into several interest rate hedges with a $100 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $3.3 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue maturing October 2036.
The net proceeds from the sale of the 2036 Notes and settlement of the hedging arrangements totaled approximately $92.8 million.
Utility Holdings and Indiana Gas Debt Calls
In 2006, the Company called at par $100.0 million of Utility Holdings senior unsecured notes originally due in 2031. The note had a stated interest rate of 7.25 percent.
Other Financing Transactions
Other Company debt totaling $6.5 million in 2007 was retired as scheduled.
Long-Term Debt Put and Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. Other than certain instruments that can be put to the company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. During 2008, the Company repaid approximately $1.6 million related to death puts. In 2007 and 2006, no debt was put to the Company. Debt which may be put to the Company for reasons other than a death during the years following 2008 (in millions) is $80.0 in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.
Investing Cash Flow
Cash flow required for investing activities was $308.3 million in 2008, $303.3 million in 2007, and $249.9 million in 2006. Capital expenditures are the primary component of investing activities and totaled $306.3 million in 2008, compared to $302.5 million in 2007 and $250.0 million in 2006. The year ended December 31, 2008 includes increased capital expenditures for environmental compliance equipment, compared to 2007. The year ended December 31, 2007 also includes expenditures for environmental compliance equipment as well as increased spending for electric transmission and a new gas line serving a Honda plant in the Vectren North service territory, compared to 2006.
Forward-Looking Information
A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements. Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:
·
Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas transportation and storage costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints.
·
Increased competition in the energy industry, including the effects of industry restructuring and unbundling.
·
Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases.
·
Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.
·
Economic conditions including the effects of an economic downturn, inflation rates, commodity prices, and monetary fluctuations.
·
Economic conditions surrounding the current recession, which may be more prolonged and more severe than cyclical downturns, including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; decreases in demand for natural gas, and electricity; impacts on both gas and electric large customers; lower residential and commercial customer counts; and higher operating expenses.
·
Increased natural gas and coal commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense.
·
Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks.
·
Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries.
·
Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, work stoppages, or pandemic illness.
·
Legal and regulatory delays and other obstacles associated with mergers, acquisitions and investments in joint ventures.
·
Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving compliance with state and federal laws and interpretations of these laws.
·
Changes in or additions to federal, state or local legislative requirements, such as changes in or additions to tax laws or rates, environmental laws, including laws governing greenhouse gases, mandates of sources of renewable energy, and other regulations.
·
The performance of projects undertaken by Vectren’s nonutility businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the Company’s coal mining, gas marketing, and energy infrastructure strategies.
The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.
ITEM 7A.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company’s risk management program includes, among other things, the use of derivatives. The Company may also execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and optimizing its generation assets.
The Company has in place a risk management committee that consists of senior management as well as financial and operational management. The committee is actively involved in identifying risks as well as reviewing and authorizing risk mitigation strategies.
Commodity Price Risk
Regulated Operations
The Company’s regulated operations have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal and purchased power for the benefit of retail customers due to current Indiana and Ohio regulations, which subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. Constructive regulatory orders, such as those authorizing lost margin recovery, other innovative rate designs, and recovery of unaccounted for gas and other gas related expenses, also mitigate the effect volatile gas costs may have on the Company’s financial condition.
Although the Company’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices have other effects such as higher working capital requirements, higher interest costs, and some level of price-sensitivity in volumes sold or delivered. The Company manages these risks by executing derivative contracts that hedge the price of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. Therefore, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings.
Wholesale Power Marketing
The Company’s wholesale power marketing activities undertake strategies to optimize electric generating capacity beyond that needed for native load. In recent years, the primary strategy involves the sale of excess generation into the MISO Day Ahead and Real-time markets. As part of these strategies, the Company may also from time to time execute energy contracts that commit the Company to purchase and sell electricity in the future. Commodity price risk results from forward positions that commit the Company to deliver electricity. The Company mitigates price risk exposure with planned unutilized generation capability and occasionally offsetting forward purchase contracts. The Company accounts for any energy contracts that are derivatives at fair value with the offset marked to market through earnings. No market sensitive derivative positions were outstanding on December 31, 2008 and 2007.
For retail sales of electricity, the Company receives the majority of its NOx and SO2 allowances at zero cost through an allocation process. Based on arrangements with regulators, wholesale operations can purchase allowances from retail operations at current market values, the value of which is distributed back to retail customers through a MISO cost recovery tracking mechanism. Wholesale operations are therefore at risk for the cost of allowances, which for the recent past have been volatile. The Company manages this risk by purchasing allowances from retail operations and other third parties in advance of usage creating an intangible asset. In the past, the Company has also used derivative financial instruments to hedge this risk, but no such derivative instruments were outstanding at December 31, 2008 or 2007.
Interest Rate Risk
The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company manages this risk by allowing an annual average of 20 percent and 30 percent of its total debt to be exposed to variable rate volatility. However, this targeted range may be exceeded during the seasonal increases in short-term borrowing. To manage this exposure, the Company may use derivative financial instruments.
Market risk is estimated as the potential impact resulting from fluctuations in interest rates on adjustable rate borrowing arrangements exposed to short-term interest rate volatility. During 2008 and 2007, the weighted average combined borrowings under these arrangements approximated $278 million and $340 million, respectively. At December 31, 2008 and 2007, combined borrowings under these arrangements were $192 million and $489 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2008 and 2007, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $2.8 million and $3.4 million, respectively.
Other Risks
By using financial instruments to manage risk, the Company exposes itself to counter-party credit risk and market risk. The Company manages exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract. Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk. Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk. Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices or interest rates. The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by establishing parameters and monitoring those parameters that limit the types and degree of market risk that may be undertaken.
The Company’s customer receivables from gas and electric sales and gas transportation services are primarily derived from residential, commercial, and industrial customers located in Indiana and west central Ohio. The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits or refunds cash deposits based on that review. Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral. In addition, credit risk is mitigated by regulatory orders that allow recovery of all bad debt expense in Ohio and the gas cost portion of bad debt expense in Indiana based on historical experience.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Vectren Utility Holdings, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Those control procedures underlie the preparation of the consolidated balance sheets, statements of income, cash flows, and common shareholder’s equity, and related footnotes contained herein.
These consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of these consolidated financial statements, including required estimates and judgments, is the responsibility of management.
These consolidated financial statements are also subject to an evaluation of internal control over financial reporting conducted under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, conducted under the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, the Company concluded that its internal control over financial reporting was effective as of December 31, 2008. Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2008 Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholder and Board of Directors of Vectren Utility Holdings, Inc.:
We have audited the accompanying consolidated balance sheets of Vectren Utility Holdings, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, common shareholder’s equity and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule included in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Vectren Utility Holdings, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 18, 2009
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
(In millions)
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS INC. AND SUBSIDIARY COMPANIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1.
Organization and Nature of Operations
Vectren Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).
Indiana Gas provides energy delivery services to over 568,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to over 141,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 317,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.
2.
Summary of Significant Accounting Policies
A.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned and majority owned subsidiaries, after elimination of intercompany transactions.
B.
Cash & Cash Equivalents
All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.
C.
Revenues
Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period.
D.
Excise and Utility Receipts Taxes
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $44.9 million in 2008, $41.8 million in 2007, and $39.7 million in 2006. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.
E.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
F.
Inventories
Inventories consist of the following:
Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2008, and 2007, by approximately $35 million and $73 million, respectively. Gas in storage of the Indiana regulated operations is stated at LIFO. All other inventories are carried at average cost.
G.
Utility Plant & Depreciation
Utility plant is stated at historical cost, including AFUDC. Depreciation rates are established through regulatory proceedings and are applied to all in-service utility plant. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2008 is $63.5 million with accumulated depreciation totaling $48.9 million. The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $111.5 million at December 31, 2008. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.
Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.
AFUDC represents the cost of borrowed and equity funds which are used for construction purposes, and charged to construction work in progress during the construction period. AFUDC is included in Other - net in the Consolidated Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:
H.
Nonutility Property
Nonutility property, net of accumulated depreciation and amortization follows:
The depreciation of nonutility property is recorded over its estimated useful life, using the straight-line method of depreciation. Repairs and maintenance, which are not considered improvements and do not extend the useful life of the nonutility property, are charged to expense as incurred. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income. Nonutility property is presented net of accumulated depreciation and amortization totaling $133.5 million and $135.2 million as of December 31, 2008, and 2007, respectively. For the years ended December 31, 2008, 2007, and 2006, the Company capitalized interest totaling $2.0 million, $1.3 million, and $0.7 million, respectively, on nonutility plant construction projects.
I.
Goodwill
Goodwill arising from business combinations is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 requires a portion of goodwill be charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Through December 31, 2008, no goodwill impairments have been recorded. All of the Company’s goodwill is included in the Gas Utility Services operating segment.
J.
Intangible Assets
The Company has emission allowances relating to its wholesale power marketing operations totaling $1.6 million and $2.6 million at December 31, 2008 and 2007, respectively. The value of the emission allowances are recognized as they are consumed or sold on the open market.
K.
Regulation
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).
Refundable or Recoverable Gas Costs and Cost of Fuel & Purchased Power
All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel for electric generation is charged to operating expense when consumed.
Regulatory Assets and Liabilities
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets.
Regulatory Assets consist of the following:
Of the $94.1 million currently being recovered in customer rates charged to customers, $21.5 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 13 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.
Regulatory Liabilities
At December 31, 2008 and 2007, the Company has approximately $315.1 million and $307.2 million, respectively, in regulatory liabilities. Of these amounts, $292.4 million and $288.3 million relate to cost of removal obligations.
The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation as defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its related interpretations (SFAS 143).
L.
Asset Retirement Obligations
A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). SFAS 143 requires entities to record the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred.
ARO’s included in Other liabilities total $24.7 million and $16.4 million at December 31, 2008 and 2007, respectively. ARO’s included in Accrued liabilities total $7.2 million and $9.5 million at December 31, 2008 and 2007, respectively. During 2008, the Company recorded accretion of $0.9 million and increases in estimates, net of cash payments of $5.1 million. During 2007, the Company recorded accretion of $1.0 million and increases in estimates, net of cash payments of $6.6 million.
M.
Impairment Review of Long-Lived Assets
Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires that the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows that the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.
N.
Comprehensive Income
Comprehensive income is a measure of all changes in equity that result from the non-shareholder transactions. This information is reported in the Consolidated Statements of Common Shareholder’s Equity. A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
O.
Earnings Per Share
Earnings per share are not presented as Utility Holdings’ common stock is wholly owned by Vectren.
P.
Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 3) and derivatives (Note 10)
3.
Transactions with Other Vectren Companies
Vectren Fuels, Inc.
Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases coal used for electric generation. The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with IURC. Amounts paid for such purchases for the years ended December 31, 2008, 2007 and 2006, totaled $119.8 million, $115.9 million, and $116.8 million, respectively. Amounts owed to Vectren Fuels at December 31, 2008 and 2007 are included in Payables to other Vectren companies.
Miller Pipeline Corporation
Effective July 1, 2006, Vectren purchased the remaining 50 percent ownership in Miller Pipeline Corporation (Miller), making Miller a wholly owned subsidiary of Vectren. Prior to the transaction, Miller was 50 percent owned by Vectren and was accounted for by Vectren using the equity method of accounting. Miller performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. Miller’s customers include Utility Holdings’ utilities. Fees paid by Utility Holdings and its subsidiaries totaled $39.9 million in 2008, $46.9 million in 2007, and $20.6 million in 2006. Amounts owed to Miller at December 31, 2008 and 2007 are included in Payables to other Vectren companies.
Vectren Source
Vectren Source, a nonutility wholly owned subsidiary of Vectren, provides natural gas and other related products and services in the Midwest and Northeast United States to over 170,000 residential and commercial customers. This customer base reflects approximately 50,000 of VEDO’s customers that have voluntarily opted to choose their natural gas supplier and the supply of natural gas to nearly 40,000 equivalent customers in VEDO’s service territory as part of VEDO’s process of exiting the merchant function, which began October 1, 2008. As part of VEDO’s exiting process on October 1, 2008, it transferred its natural gas inventory at book value its new suppliers, and now purchases natural gas from those suppliers, which include Vectren Source, essentially on demand.
The cost of natural gas inventory purchased by Vectren Source on October 1, 2008 totaled approximately $31.6 million. From October 1, 2008 to December 31, 2008, the Company purchased natural gas from Vectren Source totaling approximately $14.5 million, which represented approximately 2 percent of the Company’s total gas purchased during 2008. Amounts charged by Vectren Source for gas supply services is comprised of the monthly NYMEX settlement price plus a fixed adder, as authorized by the PUCO. Amounts owed to Vectren Source at December 31, 2008 are included in Payables to other Vectren companies.
Support Services and Purchases
Vectren provides corporate and general and administrative services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. Utility Holdings received corporate allocations totaling $45.8 million, $47.1 million, and $43.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Retirement Plans and Other Postretirement Benefits
Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in 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), which it adopted on December 31, 2006. An allocation of cost is determined, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with “multiemployer” benefit accounting as described in SFAS 87 and 106.
For the years ended December 31, 2008, 2007 and 2006, periodic pension costs totaling $3.2 million, $5.2 million and $5.3 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2008, 2007 and 2006, other periodic postretirement benefit costs totaling $0.3 million, $0.5 million and $0.6 million, respectively, were directly charged by Vectren to the Company. As of December 31, 2008 and 2007, $38.5 million and $37.4 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.
Cash Management Arrangements
The Company participates in Vectren’s centralized cash management program.
Share-Based Incentive Plans and Deferred Compensation Plans
Utility Holdings does not have share-based compensation plans separate from Vectren. An insignificant number of Utility Holdings’ employees participate in Vectren’s share-based compensation plans. The Company recognizes its allocated portion of expenses in accordance with FASB Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R). As of December 31, 2008 and 2007, $26.6 million and $29.1 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.
Income Taxes
Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Utility Holdings’ current and deferred tax expense is computed on a separate company basis. Current taxes payable/receivable are settled with Vectren in cash. The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:
At December 31, 2008 and 2007, investment tax credits totaling $6.9 million and $8.2 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. At December 31, 2008, the Company has alternative minimum tax carryforwards of $11.2 million, which do not expire.
A reconciliation of the federal statutory rate to the effective income tax rate follows:
The components of income tax expense and utilization of investment tax credits follow:
Accounting for Uncertainty in Income Taxes
On January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return. FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition.
As a result of the implementation of FIN 48, the Company recognized an approximate $0.9 million increase in the liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of Retained earnings. At adoption, the total amount of gross unrecognized tax benefits was $7.0 million.
Following is a roll forward of the total amount of unrecognized tax benefits for the years ended December 31, 2008 and 2007:
The change in unrecognized tax benefits during 2008 totaled $3.3 million, almost none of which impacted the effective rate. During 2007 the change in unrecognized tax benefits totaled $3.2 million, of which $0.3 million impacted the effective tax rate. The amount of unrecognized tax benefits, which, if recognized, that would impact the effective tax rate as of December 31, 2008 and 2007 was insignificant.
As of December 31, 2008, the remaining unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority.
The Company accrues interest and penalties associated with unrecognized tax benefits in Income taxes. The Company recognized expense related to interest and penalties totaling less than $0.1 million in 2008 and approximately $0.5 million in 2007. Prior to the adoption of FIN 48, activity related to interest and penalties was recorded at the Vectren level. As of December 31, 2008 and 2007, the Company had approximately $0.2 million and $0.5 million, respectively, accrued for the payment of interest and penalties.
The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and secondary impacts which are a component of the Deferred taxes, totaled $0.7 million and $4.3 million, respectively, at December 31, 2008 and 2007.
From time to time, Vectren may consider changes to filed positions that could impact the Company's unrecognized tax benefits. However, it is not expected that such changes would have a significant impact on earnings and would only affect the timing of payments to taxing authorities.
Utility Holdings does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file returns in various states. The Internal Revenue Service (IRS) has conducted examinations of Vectren’s U.S. federal income tax returns for tax years through December 31, 2005. The State of Indiana, Vectren’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2002. The statutes of limitations for assessment of federal and Indiana income tax have expired with respect to tax years through 2002.
4.
Transactions with Affiliated Vectren Companies
ProLiance Holdings, LLC (ProLiance)
ProLiance Holdings, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2008, 2007 and 2006 totaled $739.3 million, $602.2 million, and $610.2 million, respectively. Amounts owed to ProLiance at December 31, 2008 and 2007, for those purchases were $72.8 million and $66.9 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. The Company purchased approximately 71 percent of its gas through ProLiance in 2008 and 2007 and 72 percent in 2006. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.
Other Affiliate Transactions
Vectren has an ownership interest in Reliant Services LLC (Reliant) that is accounted for using the equity method of accounting. Reliant performed facilities locating and meter reading services for the Company in 2006. For the year ended December 31, 2006, fees for these services paid by the Company to Reliant were approximately $7.4 million. Amounts charged were market based.
5.
Borrowing Arrangements
Long-Term Debt
Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
Utility Holdings 2008 Debt Issuance
In March 2008, Utility Holdings issued at par $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes). The 2039 Notes are guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several.
The 2039 Notes have no sinking fund requirements, and interest payments are due monthly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest. During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue. The proceeds from the sale of the 2039 Notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million.
Utility Holdings 2006 Debt Issuance
In October 2006, Utility Holdings issued $100 million in 5.95 percent senior unsecured notes due October 1, 2036 (2036 Notes). The 30-year notes were priced at par. The 2036 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. These notes, as well as the timely payment of principal and interest, are insured by a financial guaranty insurance policy by Financial Guaranty Insurance Company (FGIC).
The 2036 Notes have no sinking fund requirements, and interest payments are due quarterly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after October 1, 2011, at 100 percent of principal amount plus accrued interest. During the first and second quarters of 2006, Utility Holdings entered into several interest rate hedges with a $100 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $3.3 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue. The proceeds from the sale of the 2036 Notes, settlement of the hedging arrangements, and payments of issuance costs totaled approximately $92.8 million.
Long-Term Debt Put and Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. Other than certain instruments that can be put to the Company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. During 2008 the Company repaid approximately $1.6 million related to death puts. In 2007 and 2006, no debt was put to the Company. Debt which may be put to the Company for reasons other than a death during the years following 2008 (in millions) is $80.0 in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.
Auction Rate Securities
On December 6, 2007, SIGECO closed on $17 million of auction rate tax-exempt long-term debt. The debt had a life of 33 years, maturing on January 1, 2041. The initial interest rate was set at 4.50 percent but the rate was to reset every 7 days through an auction process that began December 13, 2007. This new debt was collateralized through the issuance of first mortgage bonds and the payment of interest and principal was insured through Ambac Assurance Corporation (Ambac).
In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt, including the $17 million issued in December 2007, of its plans to convert that debt from its current auction rate mode into a daily interest rate mode. In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest. During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million. The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041. The remaining $41.3 million continues to be held in treasury and is expected to be remarketed in 2009.
Utility Holdings and Indiana Gas Debt Calls
In 2006, the Company called at par $100.0 million of Utility Holdings senior unsecured notes originally due in 2031. The note had a stated interest rate of 7.25 percent.
Other Financing Transactions
Other Company debt totaling $6.5 million in 2007 was retired as scheduled.
Future Long-Term Debt Sinking Fund Requirements and Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2009 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2009 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2008, $1.0 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.3 billion at December 31, 2008.
Consolidated maturities of long-term debt during the five years following 2008 (in millions) are zero in 2009 and 2010, $250.0 in 2011, zero in 2012, and $105.0 in 2013.
Short-Term Borrowings
At December 31, 2008, the Company had $520 million of short-term borrowing capacity, of which approximately $328 million was available. Interest rates and outstanding balances associated with short-term borrowing arrangements follows.
Impacts on Short-Term Borrowings from Recent Events in Credit Markets
Historically, the Company has funded its short-term borrowing needs through the commercial paper market. In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the continued turmoil and volatility in the financial markets. As a result, the Company has met working capital requirements through a combination of A2/P2 commercial paper issuances and draws on its $515 million commercial paper back-up credit facilities. In addition, the Company increased its cash investments by approximately $40 million during the fourth quarter of 2008. This cash position was liquidated in January 2009 based upon improvements in the short-term debt and commercial paper markets; and therefore, resulted in an increase to the available short-term debt capacity.
Covenants
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As an example, the Utility Holdings’ short-term debt agreement expiring in 2010 contains a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2008, the Company was in compliance with all financial covenants.
6.
Common Shareholder’s Equity
On June 27, 2008, Vectren physically settled an equity forward agreement associated with a 2007 public offering of its common stock. Vectren transferred net proceeds of approximately $124.8 million to Utility Holdings. The proceeds received were recorded as an increase to Common Stock in Common Shareholder’s Equity and are presented in the Statement of Cash Flows as a financing activity.
In addition to the $124.8 million capital contribution above, during the years ended December 31, 2008, 2007 and 2006, the Company has cumulatively received additional capital of $25.3 million from Vectren. Of that total, $20.0 million was funded by Vectren’s nonregulated operations, and $5.3 million was funded by new share issues from Vectren’s dividend reinvestment plan.
7.
Commitments & Contingencies
Commitments
Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2008 and thereafter (in millions) are $1.0 in 2009, $0.6 in 2010, $0.3 in 2011, $0.2 in 2012, $0.2 in 2013, and zero thereafter. Total lease expense (in millions) was $1.6 in 2008, $1.3 in 2007, and $2.4 in 2006. Firm purchase commitments for commodities and utility plant total $6.8 million in 2009.
The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.
8.
Environmental Matters
Clean Air Act
In March of 2005, the USEPA finalized the Clean Air Interstate Rule (CAIR). CAIR is an allowance cap and trade program requiring further reductions from coal-burning power plants in NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations. Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the USEPA for promulgation of revisions in accordance with the Court’s July 11, 2008 Order. Thus, the original version of CAIR promulgated in March of 2005 remains effective while USEPA revises it per the Court’s guidance. It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised; however, most of the these allowances were granted to the Company at zero cost, so a reduction in carrying value is not expected.
Similarly, in March of 2005, USEPA promulgated the Clean Air Mercury Rule (CAMR). CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008. It is quite possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress. It is also possible that the USEPA will promulgate a revised mercury regulation in 2009.
To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2 reductions, SIGECO has IURC authority to invest in clean coal technology. Using this authorization, SIGECO has invested approximately $307 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems and fabric filters. SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. These investments were included in rate base for purposes of determining new base rates that went into effect on August 15, 2007. Prior to being included in base rates, return on investments made and recovery of related operating expenses were recovered through a rider mechanism.
Further, the IURC granted SIGECO authority to invest in an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). The order allows SIGECO to recover an approximate 8 percent return on capital investments through a rider mechanism which is periodically updated for actual costs incurred less post in-service depreciation expense. Through December 31, 2008, the Company has invested approximately $97.6 million in this project. The scrubber was placed into service on January 1, 2009, and the Company expects the total project investment to approximate $100 million once all post in-service investments are completed. Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009. With the SO2 scrubber fully operational, SIGECO is positioned for compliance with the additional SO2 reductions required by Phase I CAIR commencing on January 1, 2010.
SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. SIGECO's investments in scrubber, SCR and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable pollution control legislation, if and when, reductions in mercury and further reductions in NOx and SO2 are promulgated by USEPA.
Climate Change
There are currently several forms of legislation being circulated at the federal level addressing the climate change issue. These proposals generally involve either: 1) a “cap and trade” approach where there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases or 2) a carbon tax. Currently no legislation has passed either house of Congress.
In the absence of federal legislation, several regional initiatives throughout the United States are in the process of establishing regional cap and trade programs. While no climate change legislation is pending in the State of Indiana, the State is an observer of the Midwestern Regional Greenhouse Gas Reduction Accord, and its legislature has in the recent past debated, but did not pass, renewable energy portfolio standards. It is expected that the Indiana State legislature will address a renewable energy portfolio standard again in 2009.
In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the USEPA to determine whether greenhouse gas emissions from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. Should the USEPA find such endangerment, it is likely that major stationary sources will be subject to regulation under the Act. In 2008, the USEPA published its Advanced Notice of Proposed Rulemaking in which the agency solicited comment as to whether it is appropriate or effective to regulate greenhouse gas emissions under the Act. The Obama administration has asserted that it will act on the endangerment finding in the absence of comprehensive federal legislation within the next 18 months.
Impact of Legislative Actions and Other Initiatives is Unknown
If legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and possibly natural gas distribution businesses. Further, any legislation would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to comply with a cap and trade approach to controlling greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first to operating expenses for the purchase of allowances, and later to capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are very sensitive to highly uncertain assumptions, including allowance prices. Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Approximately 22 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers. As such, the Company has some flexibility to modify the level of these transactions to reduce overall emissions and reduce costs associated with complying with new environmental regulations.
Environmental Remediation Efforts
In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.
Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.
Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $21.6 million. The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20 percent and 50 percent.
With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.5 million.
In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM in February 2004. SIGECO is also named in a lawsuit filed in federal district court in May 2007, involving another site subject to potential environmental remediation efforts.
SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the May 2007 lawsuit. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, SIGECO has recorded cumulative costs that it reasonably expects to incur totaling approximately $8.7 million. With respect to insurance coverage, SIGECO has received and recorded settlements from insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.0 million.
Environmental remediation costs related to Indiana Gas’ and SIGECO’s manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate PRP and insurance settlement recoveries. Such cumulative costs are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2008, approximately $6.5 million is included in Other Liabilities related to the remediation of these sites.
Jacobsville Superfund Site
On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including the Company’s Wagner Operations Center. The Company's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the property contains lead contaminated soils. The Company's own soil testing, completed during the construction of the Operations Center, did not indicate that the property contains lead contaminated soils. At this time, the Company anticipates only additional soil testing could be requested by the USEPA at some future date.
9.
Rate & Regulatory Matters
Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Order Received
On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case. The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.
The order also adjusts the rate design that will be used to collect the agreed-upon revenue from VEDO's residential customers. The order authorizes the use of a straight fixed variable rate design which places all, or most, of the fixed cost recovery in the customer service charge. Using a phased in approach, revenues based on volumes sold will be entirely replaced with a fixed charge after one year. A straight fixed variable design mitigates some weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism, which expired when this new rate design went into effect in February 2009. In 2008, results include approximately $4.3 million of revenue from the existing lost margin recovery mechanism that will not continue once this base rate increase is in effect. The OCC has filed a request for rehearing on the rate design finding by the PUCO. The rehearing request mirrors similar requests filed by the OCC in each case where the PUCO has approved similar rate designs, and all such requests have been denied.
With this rate order the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of bad debt and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.
Vectren Energy Delivery of Ohio, Inc. Begins Process to Exit the Merchant Function
On August 20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing. This standard pricing is comprised of the monthly NYMEX settlement price plus a fixed adder. This auction, which is effective from October 1, 2008 through March 31, 2010, is the initial step in exiting the merchant function in the Company’s Ohio service territory. The approach eliminates the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. On October 1st, VEDO’s entire natural gas inventory was transferred, receiving proceeds of approximately $107 million. The PUCO has also provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition. As the cost of gas is currently passed through to customers through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.
Vectren North (Indiana Gas Company, Inc.) Gas Base Rate Order Received
On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case. The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million. The order also provides for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.
Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The accounting treatment allows for the continuation of the accrual for allowance for funds used during construction (AFUDC) and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years on each project.
With this order, the Company has in place for its North gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a bad debt expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense.
Vectren South (SIGECO) Electric Base Rate Order Received
On August 15, 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s electric rate case. The order provided for an approximate $60.8 million electric rate increase to cover the Company’s cost of system growth, maintenance, safety and reliability. The order provided for, among other things: recovery of ongoing costs and deferred costs associated with the MISO; operations and maintenance (O&M) expense increases related to managing the aging workforce, including the development of expanded apprenticeship programs and the creation of defined training programs to ensure proper knowledge transfer, safety and system stability; increased O&M expense necessary to maintain and improve system reliability; benefit to customers from the sale of wholesale power by sharing equally with customers any profit earned above or below $10.5 million of wholesale power margin; recovery of and return on the investment in past demand side management programs to help encourage conservation during peak load periods; timely recovery of the Company’s investment in certain new electric transmission projects that benefit the MISO infrastructure; an overall rate of return of 7.32 percent on rate base of approximately $1,044 million and an allowed ROE of 10.4 percent.
Vectren South Gas Base Rate Order Received
On August 1, 2007, the Company received an order from the IURC which approved the settlement reached in Vectren South’s gas rate case. The order provided for a base rate increase of $5.1 million and a ROE of 10.15 percent, with an overall rate of return of 7.2 percent on rate base of approximately $122 million. The order also provided for the recovery of $2.6 million of costs through separate cost recovery mechanisms rather than base rates.
Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The accounting treatment allows for the continuation of the accrual for allowance for funds used during construction (AFUDC) and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $3 million and the treatment cannot extend beyond three years on each project.
With this order, the Company now has in place for its South gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a bad debt expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense.
MISO
Since February 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
The Company is typically in a net sales position with MISO as generation capacity is in excess of that needed to serve native load and is only occasionally in a net purchase position. When the Company is a net seller such net revenues are included in Electric Utility revenues and when the Company is a net purchaser such net purchases are included in Cost of fuel and purchased power. Net positions are determined on an hourly basis. Since the Company became an active MISO member, its generation optimization strategies primarily involve the sale of excess generation into the MISO day ahead and real-time markets. Net revenues from wholesale activities included in Electric Utility revenues totaled $57.6 million in 2008, $39.8 million in 2007 and $29.8 million in 2006.
The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric Utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered/refunded through tracking mechanisms.
As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO’s policies regarding use of transmission facilities, as well as ongoing FERC initiatives, and a Day 3 ancillary services market (ASM), where MISO began providing a bid-based regulation and contingency operating reserve markets on January 6, 2009, it is difficult to predict near term operational impacts. The IURC has approved the Company’s participation in the ASM and has granted authority to defer costs associated with ASM
The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant. The Company timely recovers its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.
10.
Derivatives & Other Financial Instruments
Accounting Policy for Derivatives
The Company periodically executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, “Accounting for Derivatives” and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met.
When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked-to-market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting in three primary areas: SO2 emission allowance risk management, natural gas procurement, and interest rate risk management.
SO2 Emission Allowance Risk Management
The Company’s wholesale power marketing operations are exposed to price risk associated with SO2 emission allowances. To mitigate this risk, the Company executed call options to hedge wholesale emission allowance utilization in future periods. The Company designated and documented these derivatives as cash flow hedges. At December 31, 2008, a deferred gain of approximately $0.2 million remains in accumulated comprehensive income related to these call options which will be recognized in earnings as emission allowances are utilized. Hedge ineffectiveness totaled $0.2 million of expense in 2006. No SO2 emission allowance hedges are outstanding as of December 31, 2008.
Natural Gas Procurement Activity
The Company’s regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Although regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price-sensitive reduction in volumes sold. The Company may mitigate these risks by using derivative contracts. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. At December 31, 2008 and 2007, the market values of these contracts were not significant.
Interest Rate Management
The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company has used interest rate swaps and treasury locks to hedge forecasted debt issuances and other interest rate swaps to manage interest rate exposure.
As of December 31, 2008, no interest rate swaps were outstanding. At December 31, 2007, the fair value liability associated with interest rate swaps was $8.9 million. Related to derivative instruments associated with completed debts issuances, an approximate $7.7 million net regulatory asset remains at December 31, 2008. In 2008, $0.3 million was reclassified as a decrease to interest expense, $0.6 million reduced interest expense in 2007, and $0.7 million reduced interest expense in 2006. The Company estimates a $0.3 million reduction to interest expense will occur in 2009 related to the amortization of this net position.
Fair Value Measurements
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 (GAAP), and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied. Subsequently, the FASB issued FSP FAS 157-2 which delayed the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) to fiscal years beginning after November 15, 2008. The Company adopted SFAS 157 on January 1, 2008, except as it applies to those nonfinancial assets and nonfinancial liabilities as described in FSP FAS 157-2. The partial adoption of SFAS 157 did not materially impact the Company’s financial position, results of operations or cash flows. The potential impact of applying SFAS 157 to its nonfinancial assets and liabilities is not expected to have a material impact on the Company’s consolidated financial statements.
The Company measures certain financial instruments, primarily derivatives, at fair value on a recurring basis. SFAS 157 defines a hierarchy for disclosing fair value measurements based primarily on the level of public data used in determining fair value. Level 1 inputs include quoted market prices in active markets for identical assets or liabilities; Level 2 inputs include inputs other than Level 1 inputs that are directly or indirectly observable; and Level 3 inputs include unobservable inputs using estimates and assumptions developed in-house, which reflect what a market participant would use to determine fair value. At December 31, 2008, other than $40 million invested in money market funds and included in Cash and cash equivalents, the Company had no material assets or liabilities recorded at fair value outstanding and none outstanding valued using Level 3 inputs. The money market investments are valued using Level 1 inputs. As of December 31, 2007, the Company had derivatives in Prepayments and other current assets totaling $2.6 million. In addition, as of December 31, 2007 there was $8.9 million in Accrued liabilities related to derivatives managing interest rate risk.
SFAS
Also on January 1, 2008, the Company adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (SFAS 159). SFAS 159 permitted entities to choose to measure many financial instruments and certain other items at fair value. The Company did not choose to apply the option provided in SFAS 159 to any of its eligible items; therefore, its adoption did not have any impact on the Company’s financial statements or results of operations.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial instruments follow:
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.
Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.
11.
Segment Reporting
The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. The Company manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and wholesale power operations. In total, regulated operations supply natural gas and /or electricity to over one million customers. Net income is the measure of profitability used by management for all operations.
Information related to the Company’s business segments is summarized below:
12.
Additional Balance Sheet & Statement of Income Information
Prepayments and other current assets in the Consolidated Balance Sheets consist of the following:
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
Other Investments in the Consolidated Balance Sheets consist of the following:
Other - net in the Consolidated Statements of Income consists of the following:
13.
Impact of Recently Issued Accounting Guidance
SFAS 141 (Revised 2007)
In December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS 141R). SFAS 141R establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination. SFAS 141R applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities. SFAS 141R applies prospectively to business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption is not permitted. The Company will adopt SFAS 141R on January 1, 2009, and because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.
SFAS 161
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities - an Amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 enhances the current disclosures under SFAS 133 and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation in order to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Tabular disclosure of fair value amounts and gains and losses on derivative instruments and related hedged items is required. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption encouraged. The Company will adopt SFAS 161 on January 1, 2009, and the impact is not expected to be material to the Company’s financial position or results of operations.
SFAS 162
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of accounting principles and the framework for selecting principles used in the preparation of financial statements. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles”. The implementation of this standard will not have a material impact on its financial position and results of operations.
14.
Subsidiary Guarantor and Consolidating Information
The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of Utility Holdings’ $515 million in short-term credit facilities, of which $192 million is outstanding at December 31, 2008, and Utility Holdings’ $823 million unsecured senior notes outstanding at December 31, 2008. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. However, Utility Holdings does have operations other than those of the subsidiary guarantors. Pursuant to Item 3 - 10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level.
Consolidating Statement of Income for the year ended December 31, 2008 (in millions):
Consolidating Statement of Income for the year ended December 31, 2007 (in millions):
Consolidating Statement of Income for the year ended December 31, 2006 (in millions):
Consolidating Statement of Cash Flows for the year ended December 31, 2008 (in millions)
Consolidating Statement of Cash Flows for the year ended December 31, 2007 (in millions):
Consolidating Statement of Cash Flows for the year ended December 31, 2006 (in millions):
Consolidating Balance Sheet as of December 31, 2008 (in millions)
Consolidating Balance Sheet as of December 31, 2007 (in millions):
15.
Quarterly Financial Data (Unaudited)
Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company’s utility operations. Summarized quarterly financial data for 2008 and 2007 follows:
ITEM 9.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Changes in Internal Controls over Financial Reporting
During the quarter ended December 31, 2008, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2008, the Company conducted an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective as of December 31, 2008, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:
1)
recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and
2)
accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Vectren Utility Holdings, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation under the framework in Internal Control - Integrated Framework, the Company concluded that its internal control over financial reporting was effective as of December 31, 2008.
This annual report does not include an attestation report of Utility Holdings’ registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by Utility Holdings’ registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit Utility Holdings to provide only management's report in this annual report.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
Vectren’s Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Benefits and Nominating and Corporate Governance Committees, and its Code of Ethics covering the Company’s directors, officers and employees are available on the Company’s website, www.vectren.com, and a copy will be mailed upon request to Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708. Vectren intends to disclose any amendments to the Code of Ethics or waivers of the Code of Ethics on behalf of the Vectren’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer or controller and persons performing similar functions on Vectren’s website at the internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to the address listed above.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following tabulation shows the audit and non-audit fees incurred and payable to Deloitte & Touche LLP (Deloitte) for the years ending December 31, 2008 and 2007. The fees presented below represent total Vectren fees, the majority of which are allocated to Utility Holdings.
(1)
Aggregate fees incurred and payable to Deloitte for professional services rendered for the audits of Vectren’s and Utility Holdings’ 2008 and 2007 fiscal year annual financial statements and the review of financial statements included in their Forms 10-K or 10-Q filed during the Company’s 2008 and 2007 fiscal years. The amount includes fees related to the attestation to Vectren’s assertion pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $69,911 and $83,989 in 2008 and 2007, respectively.
(2)
Audit-related fees consisted principally of reviews related to various financing transactions, regulatory filings, consultation on various accounting issues, and audit fees related to the stand-alone audit of one of Vectren’s consolidated subsidiaries.
(3)
Tax fees consisted of fees paid to Deloitte for the review of tax returns, consultation on other tax matters of Vectren and of its consolidated subsidiaries, and tax technical training. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $17,548 and $20,426 in 2008 and 2007, respectively.
(4)
Pursuant to its charter, the Audit committee of Vectren Corporation is responsible for selecting, approving professional fees and overseeing the independence, qualifications and performance of the independent registered public accounting firm. The Audit committee has adopted a formal policy with respect to the pre-approval of audit and permissible non-audit services provided by the independent registered public accounting firm. Pre-approval is assessed on a case-by-case basis. In assessing requests for services to be provided by the independent registered public accounting firm, the Audit committee considers whether such services are consistent with the auditors’ independence, whether the independent registered public accounting firm is likely to provide the most effective and efficient service based upon the firm’s familiarity with Vectren and Utility Holdings, and whether the service could enhance the Company’s ability to manage or control risk or improve audit quality. The audit-related, tax and other services provided by Deloitte in the last year and related fees were approved by the Audit committee of Vectren Corporation in accordance with this policy.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
List of Documents Filed as Part of This Report
Consolidated Financial Statements
The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and Supplementary Data” of this Form 10-K.
Supplemental Schedules
For the years ended December 31, 2008, 2007, and 2006, the Company’s Schedule II -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein. The report of Deloitte & Touche LLP on the schedule may be found in Item 8. All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8.
SCHEDULE II
Vectren Utility Holdings, Inc. and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified below pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company attached to this filing filed electronically with the SEC are listed below.
Vectren Utility Holdings, Inc.
Form 10-K
Attached Exhibits
The following Exhibits are included in this Annual Report on Form 10-K.
Exhibit
Number
Document
31.1
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
The following Exhibits, as well as the Exhibits listed above, were filed electronically with the SEC with this filing.
Exhibit
Number
Document
Ratio of Earnings to Fixed Charges
21.1
List of Company’s Significant Subsidiaries
23.1
Consent of Independent Registered Public Accounting Firm
INDEX TO EXHIBITS
3. Articles of Incorporation and By-Laws
3.1
Articles of Incorporation of Vectren Utility Holdings, Inc. (Filed and designated in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit 3.1)
3.2
Bylaws of Vectren Utility Holdings, Inc. (Filed and designated in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit 3.2)
4. Instruments Defining the Rights of Security Holders, Including Indentures
4.1
Mortgage and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1, 1993. (Filed and designated in Form 8-K, dated April 13, 1993, File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit 4.) May 1, 1993. (Filed and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit 4(a).) March 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.) August 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.) April 1, 2005 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.1) March 1, 2006 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.2) December 1, 2007 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.3)
4.2
Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National Association (formerly know as First Trust National Association, which was formerly know as Bank of America Illinois, which was formerly know as Continental Bank, National Association. Inc.'s. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494.); First Supplemental Indenture thereto dated as of February 15, 1991. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture thereto dated as of September 15, 1991, (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(b).); Third supplemental Indenture thereto dated as of September 15, 1991 (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture thereto dated as of December 2, 1992, (Filed and designated in Current Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000, (Filed and designated in Current Report on Form 8-K filed December 27, 2000, File No. 1-6494, as Exhibit 4.)
4.3
Indenture dated October 19, 2001, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit 4.1); Fourth Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated November 18, 2005, File No. 1-16739, as Exhibit 4.1). Form of Fifth Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas & Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 16, 2006, File No. 1-16739, as Exhibit 4.1). Sixth Supplemental Indenture, dated March 10, 2008, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank National Association (Filed and designated in Form 8-K, dated March 10, 2008, File No. 1-16739, as Exhibit 4.1)
10. Material Contracts
10.1
Summary description of Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.).
10.2
Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and designated in Southern Indiana Gas and Electric Company's Proxy Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)
10.3
Vectren Corporation At Risk Compensation Plan effective May 1, 2001,(as amended and restated s of May 1, 2006). (Filed and designated in Vectren Corporation’s Proxy Statement dated March 15, 2006, File No. 1-15467, as Appendix H.)
10.4
Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.)
10.5
Vectren Corporation Nonqualified Deferred Compensation Plan, effective January 1, 2005. (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.3.)
10.6
Vectren Corporation Unfunded Supplemental Retirement Plan for a Select Group of Management Employees (As Amended and Restated Effective January 1, 2005).(Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.1.)
10.7
Vectren Corporation Nonqualified Defined Benefit Restoration Plan (As Amended and Restated Effective January 1, 2005). (Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.2.)
10.8
Vectren Corporation Change in Control Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 1, 2005. (Filed and designated in Form 8-K dated March 1, 2005, File No. 1-15467, as Exhibit 99.1.). Amendment Number One to the Vectren Corporation Change in Control Agreement, effective as of March 1, 2005 between Vectren Corporation and Niel C. Ellerbrook (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.1.)
10.9
Vectren Corporation At Risk Compensation Plan specimen stock unit award agreement for non-employee members of the Board of Directors, effective January 1, 2009. (Filed and designated in Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit 10.1.)
10.10
Vectren Corporation At Risk Compensation Plan specimen restricted stock grant agreement for officers, effective January 1, 2006. (Filed and designated in Form 8-K, dated February 27, 2006, File No. 1-15467, as Exhibit 99.1.)
10.11
Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2009. (Filed and designated in Form 8-K, dated February 17, 2009, File No. 1-15467, as Exhibit 10.1.)
10.12
Vectren Corporation At Risk Compensation Plan specimen restricted stock grant agreement for officers, effective January 1, 2008. (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.1.)
10.13
Vectren Corporation At Risk Compensation Plan specimen restricted stock units agreement for officers, effective January 1, 2008. (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.2.)
10.14
Vectren Corporation At Risk Compensation Plan specimen Stock Option Grant Agreement for officers, effective January 1, 2005. (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99.2.)
10.15
Vectren Corporation specimen employment agreement dated February 1, 2005. (Filed and designated in Form 8-K, dated February 1, 2005, File No. 1-15467, as Exhibit 99.1.) Amendment Number One to the Specimen Vectren Corporation Employment Agreement between Vectren Corporation and Executive Officers (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.2.) The specimen agreements and related amendments differ among named executive officers only to the extent severance and change in control benefits are provided in the amount of three times base salary and bonus for Messrs. Benkert, Chapman, and Christian and two times for Mr. Doty.
10.16
Life Insurance Replacement Agreement between Vectren Corporation and certain named officers, effective December 31, 2006. (Filed and designated in Form 8-K, dated December 31, 2006, File No. 1-15467 as Exhibit 99.1.)
10.17
Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.1.)
10.18
Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.2.)
10.19
Coal Supply Agreement for A.B. Brown Generating Station for 410,000 tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.3.)
10.20
Coal Supply Agreement for A.B. Brown Generating Station for 1 million tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.4.)
10.21
Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.15.)
10.22
Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective September 1, 2002. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.16.)
10.23
Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Energy Group, Citizens Energy Services Corporation and ProLiance Energy, LLC, effective March 15, 1996. (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)
10.24
Revolving Credit Agreement (5 year facility), dated November 10, 2005, among Vectren Utility Holdings, Inc., and each of the purchasers named therein. (Filed and designated in Form 10-K, for the year ended December 31, 2005, File No. 1-15467, as Exhibit 10.24.)
21. Subsidiaries of the Company
The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1. (Filed herewith.)
23. Consent of Experts and Counsel
The consent of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 (Filed herewith.)
31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1 (Filed herewith.)
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2 (Filed herewith.)
32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32 (Filed herewith.)
99. Additional Exhibits
99.1
Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31, 2000. (Filed and designated in Current Report on Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
99.2
Amended and Restated Code of By-Laws of Vectren Corporation as of February 27, 2008. (Filed and designated in Current Report on Form 8-K filed February 27, 2008, File No. 1-15467, as Exhibit 3.1.)
99.3
Shareholders Rights Agreement dated as of October 21, 1999 between Vectren Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No. 1-15467, as Exhibit 4.)
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.
VECTREN UTILITY HOLDINGS, INC.
Dated: March 2, /s/ Niel C. Ellerbrook
Niel C. Ellerbrook,
Chairman, Chief Executive Officer and Director
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in capacities and on the dates indicated.
Signature
Title
Date
/s/ Niel C. Ellerbrook
Chairman, Chief Executive Officer and Director
March 2, 2009
Niel C. Ellerbrook
(Principal Executive Officer)
/s/ Jerome A. Benkert, Jr.
Executive Vice President and Chief Financial Officer
March 2, 2009
Jerome A. Benkert, Jr.
(Principal Financial Officer)
/s/ M. Susan Hardwick
Vice President, Controller and Assistant Treasurer
March 2, 2009
M. Susan Hardwick
(Principal Accounting Officer)
/s/ Ronald E. Christian
Director
March 2, 2009
Ronald E. Christian
/s/ William S. Doty
Director
March 2, 2009
William S. Doty