UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from __________________ to ________________________
Commission file number: 1-16739
| VECTREN UTILITY HOLDINGS, INC. |
(Exact name of registrant as specified in its charter)
| INDIANA | 35-2104850 | |
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | |
| One Vectren Square | 47708 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant's telephone number, including area code: 812-491-4000
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered | |
| Vectren Utility 6.10% SR NTS 12/1/2035 | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
| Title of each class | Name of each exchange on which registered | |
| Common – Without Par | None |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. *Yes ý No□
*Utility Holdings is a majority owned subsidiary of a well-known seasoned issuer, and well-known seasoned issuer status depends in part on the type of security being registered by the majority-owned subsidiary.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes □ No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No □
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
□ Yes □ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. □
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer □ Accelerated filer □
Non-accelerated filer ý Smaller reporting company □
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2009, was zero. All shares outstanding of the Registrant’s common stock were held by Vectren Corporation.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
| Common Stock - Without Par Value | 10 | February 28, 2010 |
| Class | Number of Shares | Date |
Omission of Information by Certain Wholly Owned Subsidiaries
The Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby.
Definitions
AFUDC: allowance for funds used during construction | MISO: Midwest Independent System Operator |
ASC: Accounting Standards Codification | MW: megawatts |
BTU / MMBTU: British thermal units / millions of BTU | MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours) |
FASB: Financial Accounting Standards Board | NERC: North American Electric Reliability Corporation |
FERC: Federal Energy Regulatory Commission | OCC: Ohio Office of the Consumer Counselor |
IDEM: Indiana Department of Environmental Management | OUCC: Indiana Office of the Utility Consumer Counselor |
IRC: Internal Revenue Code | PUCO: Public Utilities Commission of Ohio |
IURC: Indiana Utility Regulatory Commission | USEPA: United States Environmental Protection Agency |
MCF / BCF: thousands / billions of cubic feet | Throughput: combined gas sales and gas transportation volumes |
| MDth / MMDth: thousands / millions of dekatherms |
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports, including those of Vectren Utility Holdings, Inc., free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:
Mailing Address: One Vectren Square Evansville, Indiana 47708 | Phone Number: (812) 491-4000 | Investor Relations Contact: Steven M. Schein Vice President, Investor Relations sschein@vectren.com | ||
Table of Contents
| Item | Page | |||||
| Number | Number | |||||
| Part I | ||||||
| 4 | Reserved | 15 | ||||
| Part II | ||||||
| Part III | ||||||
| Part IV | ||||||
| (A) | – Omitted or amended as the Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby. |
PART I
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 567,000 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 assets 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 315,000 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, 2009, the Company had $3.8 billion in total assets, with $2.1 billion (55 percent) attributed to Gas Utility Services, $1.6 billion (42 percent) attributed to Electric Utility Services, and $0.1 billion (3 percent) attributed to Other Operations. Net income for the year ended December 31, 2009, was $107.4 million, with $50.2 million attributed to Gas Utility Services, $48.3 million attributed to Electric Utility Services, and $8.9 million attributed to Other Operations. Net income for the year ended December 31, 2008, was $111.1 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, 2009, the Company supplied natural gas service to approximately 993,100 Indiana and Ohio customers, including 907,500 residential, 84,000 commercial, and 1,600 industrial and other contract customers. Average gas utility customers served were approximately 981,300 in 2009 and 986,700 in both 2008 and 2007.
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
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 throughput was 184.5 MMDth for the year ended December 31, 2009. Gas sold and transported to residential and commercial customers was 106.5 MMDth representing 58 percent of throughput. Gas transported or sold to industrial and other contract customers was 78.0 MMDth representing 42 percent of throughput. Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs.
For the year ended December 31, 2009, gas utility revenues were approximately $1,066.0 million, of which residential customers accounted for 68 percent and commercial 26 percent. Industrial and other contract customers account for only 6 percent of revenues due to the high number of transportation customers in that customer class.
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 5 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. Vectren 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 approved the first two phases of a three phase plan to exit the merchant function in the Company’s Ohio service territory.
The initial phase of the plan was implemented on October 1, 2008 and continues through March 31, 2010. During the initial phase, wholesale suppliers that were winning bidders in a PUCO approved auction provide the gas commodity to VEDO for resale to its residential and general service 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 (one of which is Vectren Retail, LLC, a wholly owned subsidiary of Vectren) essentially on demand. This method of purchasing gas eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.
The second phase of the exit process begins on April 1, 2010, during which the Company will no longer sell natural gas directly to these customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that are successful bidders in a second regulatory-approved auction, will sell the gas commodity to specific customers for 12 months at auction-determined standard pricing. That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13. The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase. As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011. Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service.
In the last phase, which was not approved in the April 2008 order, it is contemplated that all of the Company’s Ohio residential and general service 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 phases of the transition, which allows the Company to recover costs associated with the transition, and it is anticipated this rider will remain in effect throughout the entire transition. Since the cost of gas is currently passed through to customers during phase one and two 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 2009, Utility Holdings purchased 97,682 MDth volumes of gas at an average cost of $5.97 per Dth, of which approximately 76 percent was purchased from ProLiance, 4 percent was purchased from Vectren Retail, LLC (d/b/a Vectren Source), as discussed above, and 20 percent was purchased from third party providers. The average cost of gas per Dth purchased for the previous four years was $9.61 in 2008, $8.14 in 2007, $8.64 in 2006, and $9.05 in 2005.
Electric Utility Services
At December 31, 2009, the Company supplied electric service to approximately 141,400 Indiana customers, including approximately 122,900 residential, 18,400 commercial, and 100 industrial and other customers. Average electric utility customers served were approximately 140,900 in 2009; 141,100 in 2008; and 140,800 in 2007.
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, 2009, retail electricity sales totaled 5,039.7 GWh, resulting in revenues of approximately $493.2 million. Residential customers accounted for 37 percent of 2009 revenues; commercial 28 percent; industrial 33 percent, and other 2 percent. In addition, in 2009 the Company sold 603.6 GWh through wholesale activities principally to the MISO. Wholesale revenues, including transmission-related revenue, totaled $35.4 million in 2009.
System Load
Total load for each of the years 2005 through 2009 at the time of the system summer peak, and the related reserve margin, is presented below in MW. The peak loads in 2009 reflect the current weak industrial demand and mild weather.
| Date of summer peak load | 6/22/2009 | 7/21/2008 | 8/08/2007 | 8/10/2006 | 7/25/2005 | |||||
Total load at peak (1) | 1,143 | 1,242 | 1,341 | 1,325 | 1,315 | |||||
| Generating capability | 1,295 | 1,295 | 1,295 | 1,351 | 1,351 | |||||
| Firm purchase supply | 136 | 135 | 130 | 107 | 107 | |||||
| Interruptible contracts & direct load control | 62 | 62 | 62 | 62 | 76 | |||||
| Total power supply capacity | 1,493 | 1,492 | 1,487 | 1,520 | 1,534 | |||||
| Reserve margin at peak | 31% | 20% | 11% | 15% | 17% | |||||
| (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 2009 the Summer Cycler program was not activated. |
The winter peak load for the 2008-2009 season of approximately 883 MW occurred on January 15, 2009. The prior year winter peak load was approximately 960 MW, occurring on January 25, 2008.
Generating Capability
Installed generating capacity as of December 31, 2009, was rated at 1,298 MW. Coal-fired generating units provide 1,000 MW of capacity, natural gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW, and in 2009 SIGECO purchased a landfill gas electric generation project which provides 3 MW. Electric generation for 2009 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 4,657 GWh in 2009. 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. (Vectren Fuels), a wholly owned subsidiary of the Company. Approximately 2.8 million tons were purchased for generating electricity during 2009, of which approximately 86 percent was supplied by Vectren Fuels from its mines and third party purchases. The average cost of coal paid by the utility in generating electric energy for the years 2005 through 2009 follows:
| Year Ended December 31, | ||||||||||||||||||||
| Average Delivered | 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||||||
Cost per Ton | $ | 61.67 | $ | 42.50 | $ | 40.23 | $ | 37.51 | $ | 30.27 | ||||||||||
Cost per MWh | 30.09 | 20.84 | 19.78 | 18.44 | 14.94 | |||||||||||||||
As of January 1, 2009, SIGECO purchases coal from Vectren Fuels under new coal purchase agreements. The term of these coal purchase agreements continues to December 31, 2014, with prices specified originally ranging from two to four years. New pricing reflects Illinois Basin market prices in effect when the contracts were executed and have resulted in higher costs compared to prior years.
The utility purchased approximately 13.3 percent less coal in 2009 compared to 2008. Due to contractual obligations, its year end coal inventory rose to approximately 1.1 million tons, compared to 0.5 million tons at the end of 2008.
Firm Purchase Supply
The Company has 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 can 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. The Company’s 1.5 percent interest in OVEC makes available approximately 30 MW of capacity. The Company purchased approximately 211 GWh from OVEC in 2009.
The Company had 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 expired on December 31, 2009 and was not renewed. The Company purchased insignificant amounts under this contract in 2009.
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, with the approval of the IURC. The contract expires in 2029. In 2009, the Company purchased approximately 91 GWh under this contract; however, none was purchased at the time of peak load on June 22, 2009.
In December 2009, the Company executed a 20 year power purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50 MW of energy from a wind farm located in Benton and Tippecanoe Counties in Indiana, with the approval of the IURC. The Company purchased insignificant amounts under this contract in 2009.
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 2009 totaled 855 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 600 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, 2009, over 117,000 customers in Vectren’s Ohio service territory purchase natural gas from a supplier other than VEDO. 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, 2009, the Company and its consolidated subsidiaries had 1,600 employees, of which 800 are subject to collective bargaining arrangements.
In October 2009, the Company’s existing agreement expired with Local 175 of the Utility Workers Union of America. Employees continue to work without a contractual agreement and continue the negotiation process.
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.
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 the recent recession, and despite the beginning recovery, may continue to result in 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 continue to be accompanied by a decrease in demand for natural gas and electricity. The recent recession may continue to have some negative impact on both gas and electric large customers and wholesale power sales. This impact may continue to include tempered growth, significant conservation measures, and perhaps even further plant closures or bankruptcies. Deteriorating economic conditions may also continue to lead to further reductions in residential and commercial customer counts, lower Company revenues, and increasing coal inventories. It is also possible that the recent recession could continue and further affect costs including pension costs, interest costs, and uncollectible accounts expense.
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 12 percent of electric utility margin, 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 level 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:
| Current Rating | ||
| Standard | ||
| Moody’s | & Poor’s | |
Utility Holdings and Indiana Gas senior unsecured debt | Baa1 | A- |
Utility Holdings commercial paper program | P-2 | A-2 |
SIGECO’s senior secured debt | A-2 | A |
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 that 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 Vectren’s 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 phase 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 electric utility sales are space heating and cooling. Accordingly, its operating results may fluctuate with variability of weather.
Utility Holdings’ electric utility sales are sensitive to variations in weather conditions. The Company forecasts utility sales on the basis of normal weather. Since Vectren 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 mitigates most 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, the USEPA, 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 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 rates of return depends upon regulatory discretion, and there can be no assurance that Vectren will be able to obtain rate increases or rate supplements or earn its current authorized rates of return.
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 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 regulation could negatively impact operations.
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 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 with regard to operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets.
Any additional expenses or capital incurred by the Company, as it relates to complying with greenhouse gas emissions regulation or other environmental regulations, are expected to be borne by the customers in its service territories through increased rates. Increased rates have an impact on the economic health of the communities served. New regulations could also negatively impact industries in the Company’s service territory.
The Company is exposed to physical and financial risks related to the uncertainty of climate change.
A changing climate creates uncertainty and could result in broad changes to the Company’s service territories. These impacts could include, but are not limited to, population shifts; changes in the level of annual rainfall; changes in the weather; and changes to the frequency and severity of weather events such as thunderstorms, wind, tornadoes, and ice storms that can damage infrastructure. Such changes could impact the Company in a number of ways including the number and/or type of customers in the Company’s service territories; the demand for energy resulting in the need for additional investment in generation assets or the need to retire current infrastructure that is no longer required; an increase to the cost of providing service; and an increase in the likelihood of capital expenditures to replace damaged infrastructure.
To the extent climate change impacts a region’s economic health, it may also impact the Company’s revenues, costs, and capital structure and thus the need for changes to rates charged to regulated customers. Rate changes themselves can impact the economic health of the communities served and may in turn adversely affect the Company’s operating results.
From time to time, Utility Holdings is subject to material litigation and regulatory proceedings.
From time to time, the Company, as well as its equity investees such as ProLiance, 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. Presently, 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. UNRESOLVED STAFF COMMENTS
None.
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 16.7 BCF of interstate pipeline storage service with a maximum peak day delivery capability of 252,600 MMBTU per day. Indiana Gas’ gas delivery system includes 13,000 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 interstate pipeline storage 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, 2009, was rated at 1,298 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. In 2009, SIGECO purchased a landfill gas electric generation project in Pike County, Indiana with a total capability of 3 MW.
SIGECO's transmission system consists of 932 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 34 substations with an installed capacity of 4,500 megavolt amperes (Mva). The electric distribution system includes 4,200 pole miles of lower voltage overhead lines and 358 trench miles of conduit containing 2,000 miles of underground distribution cable. The distribution system also includes 97 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. LEGAL PROCEEDINGS
The Company is party to various legal proceedings and audits and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits 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, and rate and regulatory matters. The consolidated condensed financial statements are included in “Item 8 Financial Statements and Supplementary Data.”
PART II
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 2009, Utility Holdings paid dividends to its parent company totaling $20.6 million in each quarter.
During 2008, Utility Holdings paid dividends to its parent company totaling $20.8 million in each quarter.
In the first quarter of 2010, the board of directors declared a $19.1 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. 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.
| Year Ended December 31, | ||||||||||||||||||||
| (In millions) | 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||||||
| Operating Data: | ||||||||||||||||||||
| Operating revenues | $ | 1,596.2 | $ | 1,958.7 | $ | 1,759.0 | $ | 1,656.5 | $ | 1,781.8 | ||||||||||
| Operating income | 238.0 | 254.6 | 244.4 | 209.0 | 216.6 | |||||||||||||||
| Net income | 107.4 | 111.1 | 106.5 | 91.4 | 95.1 | |||||||||||||||
| Balance Sheet Data: | ||||||||||||||||||||
| Total assets | $ | 3,823.1 | $ | 3,838.1 | $ | 3,643.7 | $ | 3,440.8 | $ | 3,391.2 | ||||||||||
| Long-term debt - net of current maturities | ||||||||||||||||||||
& debt subject to tender | 1,254.8 | 1,065.1 | 1,062.6 | 1,025.3 | 997.8 | |||||||||||||||
| Common shareholder's equity | 1,274.7 | 1,242.9 | 1,090.4 | 1,056.7 | 1,023.8 | |||||||||||||||
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 2009, Utility Holdings’ earnings were $107.4 million, compared to earnings of $111.1 million in 2008 and $106.5 million in 2007. The decrease in 2009 compared to 2008 reflects lower large customer usage and lower wholesale power sales, both due to the recession, mild cooling weather, and an increase in depreciation expense associated with rate base growth. Increased revenues associated with regulatory initiatives, lower operating expenses, and the return of market values associated with investments related benefit plans partially offset these declines.
In 2008 compared to 2007, Utility Holdings’ earnings increased due primarily to a full year of base rate increases 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 the Company’s electric and the Ohio natural gas service territory, which was not fully protected by straight fixed variable rate design in 2009, management estimates the margin impact of weather to be approximately $5.4 million unfavorable or $0.04 per share compared to normal temperatures. In 2008, management estimates a $1.2 million favorable impact on margin compared to normal or $0.01 per share, and in 2007 a $5.5 million favorable impact on margin compared to normal or $0.04 per share.
Results of Operations
Trends in Operations
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 sold. 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 and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.
Rate Design Strategies
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 been volatile. 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 2006. SIGECO’s natural gas territory has an NTA since 2005 and lost margin recovery since 2007. The Ohio service territory had lost margin recovery since 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 monthly service charge revenues and less dependent on volumetric revenues than previous rate designs. This new rate design, which will be fully implemented in February 2010, will mitigate most weather risk in Ohio. SIGECO’s electric service territory has neither NTA nor lost margin recovery mechanisms; however, rate designs proposed in a recently filed rate case requests a lost margin recovery mechanism that works in tandem with conservation initiatives, similar to rate designs undertaken in the Indiana gas service territories.
Tracked Operating Expenses
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 uncollectible accounts expense and percent of income payment plan expenses, costs associated with exiting the merchant function and to perform service riser replacement in Ohio, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, MISO transmission revenues and costs, as well as the gas cost component of uncollectible accounts expense based on historical experience and unaccounted for gas. Unaccounted for gas is also tracked in the Ohio service territory. Certain operating costs, including depreciation, associated with operating environmental compliance equipment at electric generation facilities and regional electric transmission investments are also tracked.
Recessionary Impacts
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 has had and may continue to have some negative impact on sales to and usage by both gas and electric large customers. This impact has included, and may continue to include, tempered growth, significant conservation measures, and increased plant closures and bankruptcies. While no one industrial customer comprises 10 percent of consolidated revenues, the top five industrial electric customers comprise approximately 12 percent of electric utility margin for the year ended December 31, 2009, and therefore any significant decline in their collective margin could adversely impact operating results. Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts. Further, resulting from the lower power prices, decreased demand for electricity and higher coal prices associated with contracts negotiated last year, the Company’s coal fired generation has been dispatched less often by the MISO. This has resulted in lower wholesale sales, more power being purchased from the MISO for native load requirements, and larger coal inventories.
Following is a discussion and analysis of margin generated from regulated utility operations.
Gas Utility Margin (Gas utility revenues less Cost of gas sold)
Gas utility margin and throughput by customer type follows:
| Year Ended December 31, | ||||||||||||
| (In millions) | 2009 | 2008 | 2007 | |||||||||
| Gas utility revenues | $ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
| Cost of gas sold | 618.1 | 983.1 | 847.2 | |||||||||
| Total gas utility margin | $ | 447.9 | $ | 449.6 | $ | 422.2 | ||||||
| Margin attributed to: | ||||||||||||
| Residential & commercial customers | $ | 388.8 | $ | 385.5 | $ | 360.9 | ||||||
| Industrial customers | 46.8 | 51.2 | 48.7 | |||||||||
| Other | 12.3 | 12.9 | 12.6 | |||||||||
| Sold & transported volumes in MMDth attributed to: | ||||||||||||
| Residential & commercial customers | 106.5 | 114.8 | 108.4 | |||||||||
| Industrial customers | 78.0 | 91.5 | 86.2 | |||||||||
| Total sold & transported volumes | 184.5 | 206.3 | 194.6 | |||||||||
For the year ended December 31, 2009, gas utility margins were $447.9 million, a slight decrease of $1.7 million, compared to 2008. Management estimates a $4.4 million year over year decrease in industrial customer margin associated with lower volumes sold, and slightly lower residential and commercial customer counts decreased margin approximately $1.7 million. These recessionary impacts were offset by margin associated with regulatory initiatives. Among all customer classes, margin increases associated with regulatory initiatives, including the full impact of the Vectren North base rate increase effective in February 2008 and the Vectren Ohio base rate increase effective February 2009, were $8.4 million year over year. The impact of operating costs, including revenue and usage taxes, recovered in margin was unfavorable $2.9 million year over year, reflecting lower revenue taxes offset by higher pass through operating expenses. The remaining decrease primarily relates to Ohio weather and lower miscellaneous revenues associated with reconnection fees. The lower fees as well as the lower revenue and usage taxes correlate with lower year over year gas costs. The average cost per dekatherm of gas purchased during 2009 was $5.97 compared to $9.61 in 2008 and $8.14 in 2007.
For the year ended December 31, 2008, gas utility margins increased $27.4 million compared to 2007. Regulatory initiatives, including the Vectren North base rate increase, effective February 2008 and the Vectren South base rate case effective August 2007, added $15.4 million in margin. 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, recovered in margin, increased gas margin $7.8 million.
Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)
Electric utility margin and volumes sold by customer type follows:
| Year Ended December 31, | ||||||||||||
| (In millions) | 2009 | 2008 | 2007 | |||||||||
| Electric utility revenues | $ | 528.6 | $ | 524.2 | $ | 487.9 | ||||||
| Cost of fuel & purchased power | 194.3 | 182.9 | 174.8 | |||||||||
| Total electric utility margin | $ | 334.3 | $ | 341.3 | $ | 313.1 | ||||||
| Margin attributed to: | ||||||||||||
| Residential & commercial customers | $ | 221.9 | $ | 218.6 | $ | 198.6 | ||||||
| Industrial customers | 84.5 | 82.9 | 78.3 | |||||||||
| Municipals & other customers | 7.2 | 7.3 | 15.3 | |||||||||
| Subtotal: Retail | $ | 313.6 | $ | 308.8 | $ | 292.2 | ||||||
| Wholesale margin | 20.7 | 32.5 | 20.9 | |||||||||
| Total electric utility margin | $ | 334.3 | $ | 341.3 | $ | 313.1 | ||||||
| Electric volumes sold in GWh attributed to: | ||||||||||||
| Residential & commercial customers | 2,760.8 | 2,850.5 | 3,042.9 | |||||||||
| Industrial customers | 2,258.9 | 2,409.1 | 2,538.5 | |||||||||
| Municipals & other | 20.0 | 63.8 | 635.1 | |||||||||
| Total retail & firm wholesale volumes sold | 5,039.7 | 5,323.4 | 6,216.5 | |||||||||
Retail
Electric retail utility margin was $313.6 million for the year ended December 31, 2009, and compared to 2008 increased $4.8 million. Increased margin among the customer classes associated with returns on pollution control equipment and other investments totaled $4.5 million year over year, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $10.3 million . Management estimates weather, driven primarily by cooling weather 10 percent milder than the prior year, decreased residential and commercial margin $5.2 million compared to 2008. Industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, decreased approximately $4.9 million due primarily to the weak economy. The industrial decreases are due primarily to lower usage; however, usage began to stabilize during the third and fourth quarters.
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.
Margin from Wholesale Electric 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:
| Year Ended December 31, | ||||||||||||
| (In millions) | 2009 | 2008 | 2007 | |||||||||
| Off-system sales | $ | 6.1 | $ | 23.2 | $ | 16.9 | ||||||
| Transmission system sales | 14.6 | 9.3 | 4.0 | |||||||||
| Total wholesale margin | $ | 20.7 | $ | 32.5 | $ | 20.9 | ||||||
For the year ended December 31, 2009, wholesale margin was $20.7 million, representing a decrease of $11.8 million, compared to 2008. Of the decrease, $17.1 million relates to lower margin retained by the Company from off-system sales. The Company experienced lower wholesale power marketing margins due primarily to lower demand and wholesale prices due to the recession, coupled with increased coal costs. During 2008, margin from off-system sales retained by the Company increased $6.3 million, compared to 2007, due to an increase in off peak volumes available for sale off system. This increase in volumes was driven primarily by expiring municipal contracts and increases in wholesale prices. Off-system sales totaled 603.6 GWh in 2009, compared to 1,512.9 GWh in 2008 and 921.3 GWh in 2007. The base rate increase effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August. Results in 2008 and 2009 reflect the impact of that sharing.
Beginning in June 2008, the Company began earning a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans. Margin associated with these projects and other transmission system operations increased $5.3 million in 2009 compared to 2008. These returns also primarily account for the $5.3 million increase in transmission system sales in 2008 compared to 2007.
Purchased Power
The Company’s mix of generated and purchased electricity changed during 2009 compared to prior years. For the years ended December 31, 2009, 2008, and 2007, respectively, the Company purchased approximately 1,159 GWh, 372 GWh, and 416 GWh of power from the MISO and other sources. The total cost associated with these volumes of purchased power is approximately $43 million, $26 million, and $26 million in 2009, 2008, and 2007 respectively, and is included in the Cost of fuel & purchased power.
Operating Expenses
Other Operating
For year ended December 31, 2009, other operating expenses were $304.6 million, increasing $4.3 million compared to 2008. Approximately $10.9 million of the change results from increased costs directly recovered through utility margin. Examples of such tracked costs include Ohio uncollectible accounts expense, Indiana gas pipeline integrity management costs, costs to fund Indiana energy efficiency programs, and MISO transmission revenues and costs, among others. Increases in other operating expenses in 2009, not directly recovered in margin, include an approximate $6.3 million increase for certain compensation costs and a $4.1 million increase associated with environmental matters. All other operating expenses were approximately $17.0 million lower than the prior year driven primarily by reductions in electric maintenance costs and lower chemical costs. Despite significantly lower gas costs due to the recession, Indiana uncollectible accounts expense was only slightly favorable compared to 2008.
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.
Depreciation & Amortization
In 2009, depreciation & amortization expense increased $15.4 million compared to 2008. The increase in depreciation is due largely to plant additions. Plant additions include the approximate $100 million SO2 scrubber placed into service January 1, 2009, for which depreciation totaling $5.6 million is directly recovered in electric utility margin. Depreciation expense increased $7.1 million in 2008 compared to 2007. Expense in 2008 includes $3.8 million of increased amortization associated with prior electric demand side management costs to be recovered 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 decreased $12.0 million in 2009 compared to 2008 and increased $4.2 million in 2008 compared to 2007. These taxes are primarily revenue-related taxes. The variations are primarily attributable to volatility in revenues, inclusive of changes in natural gas prices and gas volumes sold. These tax expenses are recovered through revenue.
Other Income-Net
Other income-net reflects income of $7.8 in 2009, compared to $4.0 million in 2008 and $9.4 million in 2007. The variations are primarily due to volatile market values associated with investments related to benefit plans.
Interest Expense
For the year ended December 31, 2009, interest expense was $79.2 million, which represents a slight decrease of $0.7 million compared to 2008. Lower short-term interest rates and lower average short-term debt balances have favorably affected interest expense year over year and are reflective of lower gas prices and the issuance of new long-term debt. Offsetting the favorable impacts of lower rates and short-term balances is the impact of two long-term financing transactions completed in 2009. The long-term financing transactions include a second quarter issuance by Utility Holdings of $100 million in unsecured eleven year notes with an interest rate of 6.28 percent and a third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.
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.
Income Taxes
Federal and state income taxes decreased $8.4 million in 2009 compared to 2008 and increased $0.9 million in 2008 compared to 2007. The changes are impacted primarily by fluctuations in pre-tax income and lower effective tax rates.
Environmental Matters
Clean Air Act
The Clean Air Interstate Rule (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. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009 and is also in compliance with SO2 reductions effective January 1, 2010. It is possible that a revised CAIR will require further reductions in NOx and SO2 from SIGECO’s generating units. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised; however, most of these allowances were granted to the Company at zero cost, so these changes will not impact the carrying value.
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. In response to the court decision, USEPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2010. It is uncertain what emission limit the USEPA is considering, and whether they will address hazardous pollutants in addition to mercury. It is also possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress.
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. The Company has invested approximately $100 million in this project. The scrubber was placed into service on January 1, 2009. Recovery through a rider mechanism of associated operating expenses including depreciation expense associated with the scrubber also began on January 1, 2009. The SO2 scrubber is in 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
Vectren is committed to responsible environmental stewardship and conservation efforts. While scientific uncertainties exist and the debate surrounding global climate change is ongoing, current information suggests a potential for adverse economic and social consequences should world-wide carbon dioxide (CO2) and other greenhouse gas emissions continue at present levels.
The Company emits greenhouse gases (GHG) primarily from its fossil fuel electric generation plants. The Company uses methodology described in the Acid Rain Program (under Title IV of the Clean Air Act) to calculate its level of direct CO2 emissions from its fossil fuel electric generating plants. The Company’s direct CO2 emissions from its plants over the past 5 years are represented below:
| (in thousands) | 2009 | 2008 | 2007 | 2006 | 2005 | |||||
Direct CO2 Emissions (tons) | 5,500 | 1/ | 8,029 | 7,995 | 7,827 | 8,242 | ||||
| 1/ | The decline in emissions from 2008 to 2009 is primarily due to recessionary impacts that resulted in a 30 percent decrease in generation. It is not clear to what extent this recent reduction may continue. |
Based on 2005 data made available through the Emissions and Generation Resource Integrated Database (eGRID) maintained by the USEPA, the Company’s direct CO2 emissions from its fossil fuel electric generation that report under the Acid Rain Program were less than one half of one percent of all emissions in the United States from similar sources.
Emissions from other Company operations, including those from its natural gas distribution operations, are monitored internally using the Department of Energy 1605(b) Standard, and the Company is currently assessing how to effectively report these emissions in relation to the new mandatory reporting regulations set forth by the USEPA.
The need to reduce CO2 and other greenhouse gas emissions, yet provide affordable energy, requires thoughtful balance. For these reasons, Vectren supports a national climate change policy with the following elements:
| · | 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; |
| · | 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; |
| · | 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; |
| · | Inclusion of incentives for investment in advanced clean coal technology and support for research and development; |
| · | 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; and |
| · | The allocation of zero cost allowances to natural gas distribution companies if those companies are required to hold allowances for the benefit of the end use customer. |
Current Initiatives to Increase Conservation & Reduce Emissions
The Company is committed to a policy that reduces greenhouse gas emissions and conserves energy usage. Evidence of this commitment includes:
| · | Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs; |
| · | Building a renewable energy portfolio to complement base load coal-fired generation in advance of mandated renewable energy portfolio standards; |
| · | Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories; |
| · | Participation in an electric conservation and demand side management collaborative with the OUCC and other customer advocate groups; |
| · | 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; and |
Legislative Actions & Other Climate Change Initiatives
The U.S. House of Representatives has passed a comprehensive energy bill that includes a carbon cap and trade program in which there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases, a federal renewable portfolio standard, and utility energy efficiency targets. Current proposed legislation also requires local natural gas distribution companies to hold allowances for the benefit of their customers. As of the date of this filing, the Senate has not passed a bill, and the House bill is not law.
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 Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord.
In advance of a federal or state renewable portfolio standard, SIGECO received IURC approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly interconnected to the Company’s distribution system. In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy. These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008. At December 31, 2009, the Company’s renewable portfolio is approximately 5 percent of total generation sources.
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 motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the USEPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December of 2009, and is the first step toward USEPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases. The USEPA has recently finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010). The USEPA has also recently proposed a revision to the PSD (Prevention of Significant Deterioration) and Title V permitting rules which would require facilities that emit 25,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. If these proposed rules were adopted, they would apply to SIGECO’s generating facilities.
Impact of Legislative Actions & 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 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 with regard operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets. Costs to purchase allowances that cap greenhouse gas emissions should be considered a cost of providing electricity and gas, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Approximately 20 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers. As such, reductions in these volumes in 2009 coupled with the flexibility to further modify the level of these transactions in future periods may help with compliance since emission targets are expected to be based on pre-2008 levels.
Ash Ponds & Coal Ash Disposal Regulations
The USEPA is considering additional regulatory measures affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. Additional laws and regulations under consideration more stringently regulate these byproducts, including the potential for coal ash to be considered a hazardous waste in certain circumstances. The USEPA has indicated that it intends to propose a rule during 2010. At this time, the Company is unable to predict the outcome any such revised regulations might have on operating results, financial position, or liquidity.
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 Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels. At this time, it is anticipated that the USEPA may request only additional soil testing at some future date.
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 $23.2 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 limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent.
With respect to insurance coverage, Indiana Gas has settled with all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.8 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 waste disposal site subject to potential environmental remediation efforts. With respect to that lawsuit, in an October 2009 court decision, SIGECO was found to be a PRP at the site. However, the Court must still determine whether such costs should be allocated among a number of PRPs, including the former owners of the site. 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.
SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters totaling approximately $11.1 million. However, given the uncertainty surrounding the allocation of PRP responsibility associated with the May 2007 lawsuit and other matters, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time. With respect to insurance coverage, SIGECO has settled with certain of its known insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.1 million; negotiations are ongoing with others.
Total costs expected to be incurred 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, 2009 and December 31, 2008, approximately $6.5 million of accrued, but not yet spent, remediation costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.
Rate & 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 PUCO has completed all audits of periods prior to October 2008, and no issues or findings are outstanding. After October 1, 2008, the Company is no longer the supplier, and the GCR is no longer necessary.
Vectren South Electric Base Rate Filing
On December 11, 2009, the Company filed a request with the IURC to adjust its electric base rates in its South service territory. The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between the Company and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers. In total the request approximated $54 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service. Most of the remainder of the request is to account for the now lower overall sales levels resulting from the recession. A portion of the request reflects a slight increase in annual operating and maintenance costs since the last rate case, nearly four years ago. The rate design proposed in the filing would break the link between customers’ consumption and the utility’s rate of return, thereby aligning the utility’s and customers’ interests in using less energy. The request assumes an overall rate of return of 7.62 percent on rate base of approximately $1,294 million and an allowed return on equity (ROE) of 10.7 percent. Based upon timelines prescribed by the IURC at the start of these proceedings, a decision is expected to be issued at the end of 2010.
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 adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers. The order allows for the phased movement toward a straight fixed variable rate design which places substantially all of the fixed cost recovery in the customer service charge. A straight fixed variable design mitigates most 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 on February 22, 2009. In 2008, annual results include approximately $4.3 million of revenue from a lost margin recovery mechanism that did not continue once this base rate increase went into effect. After year one, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge. 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. The Ohio Supreme Court has yet to act on the OCC’s request in this instance, but in two similar cases, the Court denied such requests.
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 uncollectible accounts 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. The straight fixed variable rate design will be fully phased in by February 2010.
VEDO Continues the 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 eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. In October 2008, VEDO’s entire natural gas inventory was transferred, receiving proceeds of approximately $107 million.
The second phase of the exit process begins on April 1, 2010, during which the Company will no longer sell natural gas directly to these customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that are successful bidders in a second regulatory-approved auction, will sell the gas commodity to specific customers for 12 months at auction-determined standard pricing. That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13. The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase. As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011. Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service.
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 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 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 uncollectible accounts expense level based on historical experience and unaccounted for gas through the existing GCA mechanism, and tracking of pipeline integrity management expense.
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 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 uncollectible accounts 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 Electric Base Rate Order Received
In August 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 Vectren 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.
MISO
Since 2002 and with the IURC’s approval, the Company has been a member of the 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.
Historically, the Company has typically been in a net sales position with MISO as generation capacity is in excess of that needed to serve native load and is from time to time 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 & 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. The Company also has municipal customers served through the MISO and for which the Company transmits power to the MISO for delivery to those customers. Net revenues from wholesale activities, inclusive of revenues associated with these municipal contracts, totaled $20.8 million in 2009, $57.6 million in 2008, and $35.0 million in 2007. The base rate case effective August 17, 2007, requires that wholesale margin (net revenues less the cost of fuel & purchased power) inclusive of this MISO wholesale activity earned above or below $10.5 million be shared equally with retail customers as measured on a fiscal year ending in August.
Recently, MISO market prices have fallen and the Company has more frequently been a net purchaser. In addition, the Company also receives power through the MISO associated with its wind and other power purchase agreements. Including these power purchase agreements, the Company purchased energy from the MISO totaling $34.2 million in 2009, $16.6 million in 2008, and $18.2 million in 2007. To the extent these power purchases are used for retail load, they are subject to FAC filings.
The Company also receives transmission revenue that results from other MISO 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 from / refunded to retail customers 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 recover costs associated with ASM. To date impacts from the ASM have been minor.
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. Beginning in June 2008, the Company began timely recovering its investment in certain new electric transmission projects that benefit the MISO regional infrastructure at a FERC approved rate of return. Such revenues recorded in Electric utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $9.1 million in 2009 and $4.8 million in 2008.
One such project currently under construction is an interstate 345 kilovolt transmission line that will connect Vectren’s A.B. Brown Generating 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 updated annually for estimated costs to be incurred. Of the total investment, which is expected to approximate $75 million, as of December 31, 2009, the Company has invested approximately $21.3 million. The Company expects this project to be fully 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
Business Combinations
On January 1, 2009, the Company adopted new FASB guidance related to business combinations. This guidance 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. The guidance applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities. To date, the adoption of this standard has not had a material impact.
Subsequent Events
The Company adopted new FASB guidance related to management’s review of subsequent events on June 30, 2009. In the instance of a public registrant such as the Company, this guidance establishes the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are “issued”, as that term is defined in the guidance. Such disclosure is included in Note 2 to these consolidated financial statements.
Accounting Standards Codification
The Company adopted FASB guidance related to the FASB Accounting Standards Codification (ASC) and the Hierarchy of GAAP. This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States. This statement replaces prior guidance related to the hierarchy of GAAP and establishes the FASB ASC as the source of authoritative accounting principles recognized by the FASB. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for all SEC registrants. The adoption of this guidance did not have any impact on amounts recorded on the financial statements.
Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement
On January 1, 2009, the Company adopted FASB guidance related to issuer’s accounting for liabilities measured at fair value with a third-party credit enhancement. This guidance states that companies should not include the effect of third-party credit enhancements in the fair value measurement of the related liabilities. The guidance also requires companies with outstanding liabilities measured or disclosed at fair value to disclose the existence of credit enhancements, to disclose valuation techniques used to measure liabilities and to include a discussion of changes, if any, from the valuation techniques used to measure liabilities in prior periods.
As of December 31, 2009, the Company has approximately $250.0 million of debt instruments that are supported by a third party credit enhancement feature such as insurance from a monoline insurer or a letter of credit posted by third party that supports the Company’s credit facilities. The Company’s valuation techniques did not materially change as a result of the adoption of this guidance.
Variable Interest Entities
In June 2009, the FASB issued new accounting guidance regarding variable interest entities (VIE’s). This new guidance is effective for annual reporting periods beginning after November 15, 2009. This guidance requires a qualitative analysis of which holder of a variable interest controls the VIE and if that interest holder must consolidate a VIE. Additionally, it requires additional disclosures and an ongoing reassessment of who must consolidate a VIE. The Company adopted this guidance on January 1, 2010. The Company does not expect the adoption will have a material impact on the consolidated financial statements.
Fair Value Measurements & Disclosures
In January 2010, the FASB issued new accounting guidance on improving disclosures about fair market value. This guidance amends prior disclosure requirements involving fair value measurements to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The guidance also clarifies existing fair value disclosures in regard to the level of disaggregation and about inputs and valuation techniques used to measure fair value. The guidance also amends prior disclosure requirements regarding postretirement benefit plan assets to require that disclosures be provided by classes of assets instead of major categories of assets. This guidance is effective for the first reporting period beginning after December 15, 2009. The Company will adopt this guidance in its first quarter 2010 reporting. The Company does not expect the adoption will have a material impact on the consolidated financial statements.
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 and other asset impairments tests and to determine pension and postretirement benefit obligations. The Company makes other estimates in the course of accounting for unbilled revenue and the effects of regulation 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 and coal reserves, 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 and other market based information 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 has been substantially in excess of the carrying amount in each of the last three years 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, comprised of only service cost and interest on that service cost by subsidiary, is determined 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. 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 obtains 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 2009 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. These key assumptions were unchanged from the assumptions utilized in 2008. To estimate 2010 costs, the discount rate, expected return on plan assets, rate of compensation increase, and inflation assumption were 6.0 percent, 8.0 percent, 3.5 percent, and 3.0 percent respectively. Management currently estimates a pension and postretirement cost of approximately $13 million in 2010, compared to approximately $15 million in 2009, $11 million in 2008, and $14 million in 2007. 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 used to estimate 2010 projected costs would generally increase periodic benefit cost by approximately $1.6 million. A 50 basis point decrease in the discount rate used to estimate 2009 periodic cost would have increased costs 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 FASB guidance related to accounting for the effects of certain types of regulation. 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, 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, 2009, approximated $920 million and $16 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. SIGECO will also occasionally issue tax exempt debt to fund qualifying pollution control capital expenditures. 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, 2009, 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/A2. 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. During the third quarter of 2009, Moody’s raised its credit rating on SIGECO’s secured debt from A3 to A2; otherwise, these ratings and outlooks did not change during 2009. 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 45-60 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 49 percent and 52 percent of long-term capitalization at December 31, 2009 and 2008, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.
As of December 31, 2009, the Company was in compliance with all financial covenants.
Available Liquidity in Current Credit Conditions
The Company’s A-/Baa1 investment grade credit ratings have allowed it to access the capital markets as needed during this period of financial market volatility. Over the last twelve to twenty four months, the Company has significantly enhanced its short-term borrowing capacity with the completion of several long-term financing transactions including the issuance of long-term debt in both 2008 and 2009 and the receipt of a $125 million capital contribution from Vectren in 2008. The liquidity provided by these transactions, when coupled with existing cash and expected internally generated funds, is expected to be sufficient over the near term to fund anticipated capital expenditures, investments, debt security redemptions, and other working capital requirements.
Regarding debt redemptions, there are none in 2010 and $250 million in 2011. The Company is currently considering whether to prefund a portion of the $250 million debt redemption with a long-term debt issuance in 2010. In addition, investors have the one-time option to put $10 million in May of 2010 and a one time option to put $30 million in 2011.
Long-term debt transactions completed in 2009 include a $100 million issuance by Utility Holdings. SIGECO also recently remarketed $41.3 million of long-term debt, supported by letters of credit issued under Utility Holdings' credit facility and completed a $22.3 million tax-exempt first mortgage bond issuance. These transactions, along with financing transactions completed in 2008 and 2007, are more fully described below.
Consolidated Short-Term Borrowing Arrangements
At December 31, 2009, the Company had $520 million of short-term borrowing capacity. As reduced by letters of credit and borrowings currently outstanding, approximately $462 million was available. Of the $520 million in capacity, $5 million is available through June, 2010 and $515 million is available through November, 2010.
Historically, the Company uses short-term borrowings to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis. The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market. In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the turmoil and volatility in the financial markets. As a result, the Company met short-term financing needs through a combination of A2/P2 commercial paper issuances and draws on Utility Holdings’ $515 million commercial paper back-up credit facilities. Throughout 2009, the Company has been able to place commercial paper without any significant issues. However, the level of required short-term borrowings is significantly lower compared to historical trends due to the recently completed long-term financing transactions.
Compared to historical trends, the Company anticipates over the next several years a greater use of the long-term capital markets to more timely finance capital investments and other growth as well as debt security redemptions. This change comes as short-term borrowing arrangements have become less certain, more volatile, and the cost of unutilized capacity is expected to increase significantly. Thus, while the Company expects to renew these facilities in 2010, the Company anticipates that borrowing levels will be lower due to the reduced requirements for short-term borrowings described above. Under current market conditions, this change is expected to yield greater certainty to financing business operations at the expense of some increase in interest costs.
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 $5.8 million in 2009 and $5.3 million in 2007. In 2010, new issuances required to meet these various plan requirements are estimated to be approximately $6 million, and such amount is expected to be consistent with issuances in 2009.
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 2010 - 2014 are estimated as follows (in millions): $245 in 2010, $230 in 2011, $210 in 2012, $195 in 2013, and $215 in 2014.
Pension and Postretirement Funding Obligations
As of December 31, 2009, Vectren’s pension plan asset values were approximately 82 percent of the projected benefit obligation. In order to increase the funded status, Vectren’s management currently estimates the qualified pension plans require contributions of $12 million in 2010. Under current market conditions, Vectren estimates similar funding in 2011, a portion which may be funded by Utility Holdings. During 2009, Vectren made contributions of approximately $34 million to qualified pension plans, of which approximately $30 million was funded by Utility Holdings. In addition to the qualified plan funding, Vectren anticipates payments totaling $20 million in 2010 associated with its other retirement and deferred compensation plans, of which the majority is expected to be funded by Utility Holdings.
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2009:
| Total | 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter | ||||||||||||||||||||||
Long-term debt (1) | $ | 1,306.1 | $ | - | $ | 250.0 | $ | - | $ | 105.0 | $ | - | $ | 951.1 | ||||||||||||||
| Short-term debt | 16.4 | 16.4 | - | - | - | - | - | |||||||||||||||||||||
| Long-term debt interest commitments | 1,072.7 | 77.5 | 76.2 | 61.0 | 58.6 | 55.4 | 744.0 | |||||||||||||||||||||
| Plant & commodity purchase commitments | 16.5 | - | - | 5.3 | 5.5 | 5.7 | - | |||||||||||||||||||||
| Operating leases | 1.7 | 0.5 | 0.4 | 0.3 | 0.3 | 0.2 | - | |||||||||||||||||||||
Total (2) | $ | 2,413.4 | $ | 94.4 | $ | 326.6 | $ | 66.6 | $ | 169.4 | $ | 61.3 | $ | 1,695.1 | ||||||||||||||
(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 2009 (in millions) is $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter. |
| (2) | The Company has other long-term liabilities that total approximately $91 million. This amount is comprised of the following: deferred compensation and share-based compensation $28 million, asset retirement obligations $30 million, pension and postretirement obligations $11 million, investment tax credits $6 million, environmental remediation $6 million, and other obligations including unrecognized tax benefits totaling $10 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, they have not been included in the listing of contractual obligations.
Off Balance Sheet Arrangements
As of December 31, 2009, other than the letters of credit discussed above, the Company does not have any material off balance sheet arrangements.
Comparison of Historical Sources & Uses of Liquidity
The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $356.8 million in 2009, compared to $435.0 million in 2008 and $232.2 million in 2007.
The $78.2 million decrease occurring in 2009 compared to 2008 was primarily due to changes in working capital, which reduced operating cash flow approximately $60.1 million. This decrease is caused by the timing of intercompany tax transactions and the timing of natural gas inventory sales and purchases due to exiting the merchant function in the Ohio service territory in October of 2008. In addition, the Company made increased contributions to Vectren’s pension and other retirement plans during 2009. These impacts have been partially offset by a $31.8 million increase in net income before the impacts of depreciation, deferred taxes, and other non-cash charges. Tax payments in both 2009 and 2008 were favorably impacted by federal stimulus plans authorizing bonus depreciation and IRS approval in 2009 to change its tax method for recognizing repair and maintenance activities.
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.
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.
During 2009 and 2008, net cash flow associated with financing activities is reflective of management’s ongoing effort to rely less on short-term borrowing arrangements. The Company’s 2009 and 2008 operating cash flow funded over 90 percent of capital expenditures and dividends in those years. Recently completed long-term financing transactions have allowed for the repayment of nearly $370 million in short term borrowings over the past two years. In addition, these long-term financing transactions have financed other capital expenditures on a long-term basis. During the first quarter of 2008, the Company mitigated its exposure to auction rate debt markets. These transactions are more fully described below.
Utility Holdings 2009 Debt Issuance
On April 7, 2009, Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million.
The 2020 Notes have no sinking fund requirements, and interest payments are due semi-annually. The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in the Utility Holdings’ $515 million short-term credit facility.
SIGECO 2009 Debt Issuance
On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity. The bonds mature in 2040. The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 million.
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, 2009, 2008,and 2007, the Company has cumulatively received additional capital of $12.2 million from Vectren, 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.
On March 26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations, receiving proceeds, net of issuance costs of approximately $40.6 million. The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit backed by Utility Holdings’ $515 million short-term credit facility. The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025. The initial interest rate paid to investors was 0.55 percent. The equivalent rate of the debt at inception, inclusive of interest, weekly remarketing fees, and letter of credit fees, approximated 1 percent. Since Utility Holdings’ short-term facility has a remaining term of less than one year, these obligations are classified as Long-term debt subject to tender in current liabilities.
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 2009 and 2008, the Company repaid approximately $3.0 million and $1.6 million, respectively, related to death puts. In 2007, 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 2009 (in millions) is $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter.
Investing Cash Flow
Cash flow required for investing activities was $310.3 million in 2009, $308.3 million in 2008, and $303.3 million in 2007. Capital expenditures are the primary component of investing activities and totaled $306.9 million in 2009, compared to $306.3 million in 2008 and $302.5 million in 2007. Capital expenditures in 2009 include the impact of the January 2009 ice storm that resulted in approximately $20 million in capital expenditures. The year ended December 31, 2008 includes increased capital expenditures for environmental compliance equipment, compared to 2007. Both 2009 and 2008 include increased capital expenditures for bare steel cast iron replacement programs and other expenditures qualifying for federal bonus deprecation.
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”, “likely”, 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. |
| · | Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts or other similar occurrences could adversely affect Vectren’s facilities, operations, financial condition and results of operations. |
| · | 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 recent 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. QUALITATIVE & 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 state 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 Vectren’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered.
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 future periods. 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, 2009 and 2008.
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 as needed and occasionally from other third parties in advance of usage. In the past, the Company also used derivative financial instruments to hedge this risk, but no such derivative instruments were outstanding at December 31, 2009 or 2008.
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 2009 and 2008, the weighted average combined borrowings under these arrangements approximated $60 million and $278 million, respectively. At December 31, 2009 and 2008, combined borrowings under these arrangements were $58 million and $192 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2009 and 2008, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $0.6 million and $2.8 million, respectively.
Other Risks
By using financial instruments to manage risk, the Company creates exposure 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 uncollectible accounts expense in Ohio and the gas cost portion of uncollectible accounts expense in Indiana based on historical experience.
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, 2009. Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2009 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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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
March 5, 2010
VECTREN UTILITY HOLDINGS. INC. AND SUBSIDIARY COMPANIES
| CONSOLIDATED BALANCE SHEETS |
(In millions)
| At December 31, | ||||||||
| 2009 | 2008 | |||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash & cash equivalents | $ | 6.2 | $ | 52.5 | ||||
| Accounts receivable - less reserves of $4.0 & | ||||||||
| $4.5, respectively | 108.1 | 164.0 | ||||||
| Receivables due from other Vectren companies | 0.7 | 4.7 | ||||||
| Accrued unbilled revenues | 115.4 | 167.2 | ||||||
| Inventories | 127.9 | 84.6 | ||||||
| Recoverable fuel & natural gas costs | - | 3.1 | ||||||
| Prepayments & other current assets | 69.2 | 103.1 | ||||||
| Total current assets | 427.5 | 579.2 | ||||||
| Utility Plant | ||||||||
| Original cost | 4,601.4 | 4,335.3 | ||||||
| Less: accumulated depreciation & amortization | 1,722.6 | 1,615.0 | ||||||
| Net utility plant | 2,878.8 | 2,720.3 | ||||||
| Investments in unconsolidated affiliates | 0.2 | 0.2 | ||||||
| Other investments | 31.4 | 24.1 | ||||||
| Nonutility plant - net | 171.8 | 182.4 | ||||||
| Goodwill - net | 205.0 | 205.0 | ||||||
| Regulatory assets | 104.1 | 115.7 | ||||||
| Other assets | 4.3 | 11.2 | ||||||
| TOTAL ASSETS | $ | 3,823.1 | $ | 3,838.1 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
| At December 31, | ||||||||
| 2009 | 2008 | |||||||
| LIABILITIES & SHAREHOLDER'S EQUITY | ||||||||
| Current Liabilities | ||||||||
| Accounts payable | $ | 133.1 | $ | 212.5 | ||||
| Accounts payable to affiliated companies | 54.1 | 72.8 | ||||||
| Payables to other Vectren companies | 53.6 | 69.0 | ||||||
| Refundable fuel & natural gas costs | 22.3 | 4.1 | ||||||
| Accrued liabilities | 131.4 | 147.7 | ||||||
| Short-term borrowings | 16.4 | 191.9 | ||||||
| Long-term debt subject to tender | 51.3 | 80.0 | ||||||
| Total current liabilities | 462.2 | 778.0 | ||||||
| Long-Term Debt - Net of Current Maturities & | ||||||||
| Debt Subject to Tender | 1,254.8 | 1,065.1 | ||||||
| Deferred Income Taxes & Other Liabilities | ||||||||
| Deferred income taxes | 418.0 | 332.1 | ||||||
| Regulatory liabilities | 322.2 | 315.1 | ||||||
| Deferred credits & other liabilities | 91.2 | 104.9 | ||||||
| Total deferred credits & other liabilities | 831.4 | 752.1 | ||||||
| Commitments & Contingencies (Notes 10 - 12) | ||||||||
| Common Shareholder's Equity | ||||||||
| Common stock (no par value) | 769.9 | 763.0 | ||||||
| Retained earnings | 504.7 | 479.8 | ||||||
| Accumulated other comprehensive income | 0.1 | 0.1 | ||||||
| Total common shareholder's equity | 1,274.7 | 1,242.9 | ||||||
| TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 3,823.1 | $ | 3,838.1 | ||||
| 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)
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| OPERATING REVENUES | ||||||||||||
| Gas utility | $ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
| Electric utility | 528.6 | 524.2 | 487.9 | |||||||||
| Other | 1.6 | 1.8 | 1.7 | |||||||||
| Total operating revenues | 1,596.2 | 1,958.7 | 1,759.0 | |||||||||
| OPERATING EXPENSES | ||||||||||||
| Cost of gas sold | 618.1 | 983.1 | 847.2 | |||||||||
| Cost of fuel & purchased power | 194.3 | 182.9 | 174.8 | |||||||||
| Other operating | 304.6 | 300.3 | 266.1 | |||||||||
| Depreciation & amortization | 180.9 | 165.5 | 158.4 | |||||||||
| Taxes other than income taxes | 60.3 | 72.3 | 68.1 | |||||||||
| Total operating expenses | 1,358.2 | 1,704.1 | 1,514.6 | |||||||||
| OPERATING INCOME | 238.0 | 254.6 | 244.4 | |||||||||
| Other income - net | 7.8 | 4.0 | 9.4 | |||||||||
| Interest expense | 79.2 | 79.9 | 80.6 | |||||||||
| INCOME BEFORE INCOME TAXES | 166.6 | 178.7 | 173.2 | |||||||||
| Income taxes | 59.2 | 67.6 | 66.7 | |||||||||
| NET INCOME | $ | 107.4 | $ | 111.1 | $ | 106.5 | ||||||
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)
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net income | $ 107.4 | $ 111.1 | $ 106.5 | |||||||||
| Adjustments to reconcile net income to cash from operating activities: | ||||||||||||
| Depreciation & amortization | 180.9 | 165.5 | 158.4 | |||||||||
| Deferred income taxes & investment tax credits | 76.2 | 54.7 | 14.4 | |||||||||
| Expense portion of pension & postretirement periodic benefit cost | 4.1 | 2.6 | 4.1 | |||||||||
| Provision for uncollectible accounts | 14.6 | 15.8 | 15.0 | |||||||||
| Other non-cash expense - net | 14.0 | 15.7 | 7.6 | |||||||||
| Changes in working capital accounts: | ||||||||||||
| Accounts receivable, including to Vectren companies | ||||||||||||
| & accrued unbilled revenue | 93.1 | (56.1 | ) | (54.1 | ) | |||||||
| Inventories | (43.2 | ) | 46.8 | 7.0 | ||||||||
| Recoverable/refundable fuel & natural gas costs | 21.3 | (26.2 | ) | (6.3 | ) | |||||||
| Prepayments & other current assets | 48.1 | (13.4 | ) | 4.0 | ||||||||
| Accounts payable, including to Vectren companies | ||||||||||||
| & affiliated companies | (95.9 | ) | 96.2 | 14.6 | ||||||||
| Accrued liabilities | (12.0 | ) | 24.2 | 1.1 | ||||||||
| Changes in noncurrent assets | 1.7 | 20.6 | (22.3 | ) | ||||||||
| Changes in noncurrent liabilities | (53.5 | ) | (22.5 | ) | (17.8 | ) | ||||||
| Net cash flows from operating activities | 356.8 | 435.0 | 232.2 | |||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Proceeds from: | ||||||||||||
| Long-term debt - net of issuance costs & hedging proceeds | 161.3 | 171.1 | 16.3 | |||||||||
| Additional capital contribution | 6.9 | 124.8 | 5.3 | |||||||||
| Requirements for: | ||||||||||||
| Dividends to parent | (82.5 | ) | (83.2 | ) | (76.6 | ) | ||||||
| Retirement of long-term debt | (3.0 | ) | (104.6 | ) | (6.5 | ) | ||||||
| Net change in short-term borrowings, including from other | ||||||||||||
| Vectren companies | (175.5 | ) | (194.0 | ) | 115.8 | |||||||
| Net cash flows from financing activities | (92.8 | ) | (85.9 | ) | 54.3 | |||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Proceeds from other investing activities | 0.2 | 2.5 | 1.0 | |||||||||
| Requirements for: | ||||||||||||
| Capital expenditures, excluding AFUDC equity | (306.9 | ) | (306.3 | ) | (302.5 | ) | ||||||
| Other investments | (3.6 | ) | (4.5 | ) | (1.8 | ) | ||||||
| Net cash flows from investing activities | (310.3 | ) | (308.3 | ) | (303.3 | ) | ||||||
| Net change in cash & cash equivalents | (46.3 | ) | 40.8 | (16.8 | ) | |||||||
| Cash & cash equivalents at beginning of period | 52.5 | 11.7 | 28.5 | |||||||||
| Cash & cash equivalents at end of period | $ | 6.2 | $ | 52.5 | $ | 11.7 | ||||||
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)
| Accumulated | ||||||||||||||||
| Other | ||||||||||||||||
| Common | Retained | Comprehensive | ||||||||||||||
| Stock | Earnings | Income | Total | |||||||||||||
| Balance at January 1, 2007 | $ | 632.9 | $ | 422.9 | $ | 0.9 | $ | 1,056.7 | ||||||||
| Comprehensive income: | ||||||||||||||||
| Net income | 106.5 | 106.5 | ||||||||||||||
| Cash flow hedge | ||||||||||||||||
| Unrealized losses - net of $0.1 million in tax | 0.1 | 0.1 | ||||||||||||||
| Reclassification to net income - net of $0.4 million in tax | (0.7 | ) | (0.7 | ) | ||||||||||||
| Total comprehensive income | 105.9 | |||||||||||||||
| Adoption of FIN 48 | (0.9 | ) | (0.9 | ) | ||||||||||||
| Common stock: | ||||||||||||||||
| Additional capital contribution | 5.3 | 5.3 | ||||||||||||||
| Dividends | (76.6 | ) | (76.6 | ) | ||||||||||||
| Balance at December 31, 2007 | 638.2 | 451.9 | 0.3 | 1,090.4 | ||||||||||||
| Comprehensive income: | ||||||||||||||||
| Net income | 111.1 | 111.1 | ||||||||||||||
| Cash flow hedge | ||||||||||||||||
| Reclassification to net income - net of $0.2 million in tax | (0.2 | ) | (0.2 | ) | ||||||||||||
| Total comprehensive income | 110.9 | |||||||||||||||
| Common stock: | ||||||||||||||||
| Additional capital contribution | 124.8 | 124.8 | ||||||||||||||
| Dividends | (83.2 | ) | (83.2 | ) | ||||||||||||
| Balance at December 31, 2008 | 763.0 | 479.8 | 0.1 | 1,242.9 | ||||||||||||
| Comprehensive income: | ||||||||||||||||
| Net income & total comprehensive income | 107.4 | 107.4 | ||||||||||||||
| Common stock: | ||||||||||||||||
| Additional capital contribution | 6.9 | 6.9 | ||||||||||||||
| Dividends | (82.5 | ) | (82.5 | ) | ||||||||||||
| Balance at December 31, 2009 | $ | 769.9 | $ | 504.7 | $ | 0.1 | $ | 1,274.7 | ||||||||
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 & 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 567,000 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 assets 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 315,000 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 |
In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing pension and postretirement benefit obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, and derivatives and other financial instruments. Estimates also impact the depreciation of utility and nonutility plant and the testing goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of significant intercompany transactions.
Subsequent Events Review
Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued.
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. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.
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.
Excise & 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 $36.2 million in 2009, $44.9 million in 2008, and $41.8 million in 2007. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.
Inventories
Inventories consist of the following:
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Gas in storage – at LIFO cost | $ | 24.4 | $ | 22.2 | ||||
| Gas in storage – at average cost | - | 0.4 | ||||||
| Total Gas in storage | 24.4 | 22.6 | ||||||
| Materials & supplies | 35.0 | 31.9 | ||||||
| Fuel (coal & oil) for electric generation | 66.8 | 28.4 | ||||||
| Other | 1.7 | 1.7 | ||||||
| Total inventories | $ | 127.9 | $ | 84.6 | ||||
Based on the average cost of gas purchased during December, the cost of replacing gas in stoarge carried at LIFO cost exceeded that carrying value at December 31, 2009, and 2008, by approximately $19 million and $35 million, respectively. All other inventories are carried at average cost.
Plant, Property, & Equipment
Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.
Impairment Reviews
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the 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.
Utility Plant & Related Depreciation
Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other – net in the Consolidated Statements of Income.
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, resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.
The Company’s portion of jointly owned Utility Plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.
Nonutility Plant & Related Depreciation
The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. 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, typically impacting operating expenses.
Goodwill
Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is 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, 2009, no goodwill impairments have been recorded. All of the Company’s goodwill is included in the Gas Utility Services operating segment.
Intangible Assets
The Company has emission allowances relating to its wholesale power marketing operations totaling $1.3 million and $1.6 million at December 31, 2009 and 2008, respectively. The value of the emission allowances are recognized as they are consumed or sold.
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 ratemaking and accounting practices authorized by these agencies.
Refundable or Recoverable Gas Costs & 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 and purchased power for electric generation is charged to operating expense when consumed.
Regulatory Assets & 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 continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate.
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.
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). The Company records 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 Company 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, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.
ARO’s included in Other liabilities total $29.9 million and $24.7 million at December 31, 2009 and 2008, respectively. ARO’s included in Accrued liabilities total $2.7 million and $7.2 million at December 31, 2009 and 2008, respectively. During 2009, the Company recorded accretion of $1.4 million and decreases in estimates, net of cash payments of $0.4 million. During 2008, the Company recorded accretion of $0.9 million and increases in estimates, net of cash payments of $5.1 million.
Fair Value Measurements
Certain financial assets and liabilities as well as certain nonfinancial assets and liabilities, such as the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets and long-lived assets impairment tests, are valued and/or disclosed at fair value. The Company describes its fair value measurements using a hierarchy of inputs based primarily on the level of public data used. 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 using internal models, which reflect what a market participant would use to determine fair value.
Earnings Per Share
Earnings per share are not presented as Utility Holdings’ common stock is wholly owned by Vectren.
Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 5).
| 3. | Utility & Nonutility Plant |
The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:
| At and For the Year Ended December 31, | ||||||||||||||||
| (In millions) | 2009 | 2008 | ||||||||||||||
| Original Cost | Depreciation Rates as a Percent of Original Cost | Original Cost | Depreciation Rates as a Percent of Original Cost | |||||||||||||
| Gas utility plant | $ | 2,299.1 | 3.5 | % | $ | 2,157.6 | 3.5 | % | ||||||||
| Electric utility plant | 2,113.3 | 3.4 | % | 1,884.3 | 3.3 | % | ||||||||||
| Common utility plant | 48.7 | 2.9 | % | 47.9 | 2.9 | % | ||||||||||
| Construction work in progress | 140.3 | - | 245.5 | - | ||||||||||||
| Total original cost | $ | 4,601.4 | $ | 4,335.3 | ||||||||||||
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, 2009, is $178.1 million with accumulated depreciation totaling $53.4 million. The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $0.7 million at December 31, 2009. 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.
Nonutility plant, net of accumulated depreciation and amortization follows:
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Computer hardware & software | $ | 117.9 | $ | 127.5 | ||||
| Land & buildings | 39.3 | 40.5 | ||||||
| All other | 14.6 | 14.4 | ||||||
| Nonutility plant - net | $ | 171.8 | $ | 182.4 | ||||
Nonutility plant is presented net of accumulated depreciation and amortization totaling $160.2 million and $133.5 million as of December 31, 2009 and 2008, respectively. For the years ended December 31, 2009, 2008, and 2007, the Company capitalized interest totaling $0.2 million, $2.0 million, and $1.3 million, respectively, on nonutility plant construction projects.
| 4. | Regulatory Assets & Liabilities |
Regulatory Assets
Regulatory assets consist of the following:
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Future amounts recoverable from ratepayers related to: | ||||||||
| Deferred income taxes | $ | 14.7 | $ | 11.4 | ||||
| Asset retirement obligations & other | 4.3 | 8.5 | ||||||
| 19.0 | 19.9 | |||||||
| Amounts deferred for future recovery related to: | ||||||||
| Cost recovery riders & other | 1.0 | 1.7 | ||||||
| 1.0 | 1.7 | |||||||
| Amounts currently recovered in customer rates related to: | ||||||||
| Demand side management programs | 15.3 | 21.5 | ||||||
| Unamortized debt issue costs & hedging proceeds | 38.1 | 38.4 | ||||||
| Indiana authorized trackers | 15.6 | 13.8 | ||||||
| Ohio authorized trackers | 8.2 | 11.6 | ||||||
| Premiums paid to reacquire debt & other | 6.9 | 8.8 | ||||||
| 84.1 | 94.1 | |||||||
| Total regulatory assets | $ | 104.1 | $ | 115.7 | ||||
Of the $84.1 million currently being recovered in customer rates, $15.3 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 11 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, 2009 and 2008, the Company has approximately $322.1 million and $315.1 million, respectively, in Regulatory liabilities. Of these amounts, $294.4 million and $292.4 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs.
| 5. | 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, 2009, 2008 and 2007, totaled $152.9 million, $119.8 million, and $115.9 million, respectively. Amounts owed to Vectren Fuels at December 31, 2009 and 2008 are included in Payables to other Vectren companies.
Miller Pipeline Corporation
Miller Pipeline Corporation (Miller), a wholly owned subsidiary of Vectren, 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 $40.4 million in 2009, $39.9 million in 2008, and $46.9 million in 2007. Amounts owed to Miller at December 31, 2009 and 2008 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 189,000 equivalent residential and commercial customers. This customer base reflects approximately 62,000 of VEDO’s customers that have voluntarily opted to choose their natural gas supplier and the supply of natural gas to nearly 33,000 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 to 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. The Company purchased natural gas from Vectren Source totaling approximately $27.0 million in 2009 and $14.5 million in 2008, which represented approximately 4 percent and 2 percent of the Company’s total gas purchased during 2009 and 2008, respectively. 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, 2009 are included in Payables to other Vectren companies.
Support Services & 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 $48.4 million, $45.8 million, and $47.1 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Retirement Plans & Other Postretirement Benefits
Vectren has multiple defined benefit pension plans and postretirement plans that require accounting in accordance with FASB guidance related to employers’ accounting for defined benefit pension and other postretirement plans. 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 FASB guidance related to “multiemployer” benefit accounting.
For the years ended December 31, 2009, 2008 and 2007, periodic pension costs totaling $5.4 million, $3.2 million and $5.2 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2009, 2008 and 2007, other periodic postretirement benefit costs totaling $0.5 million, $0.3 million and $0.5 million, respectively, were directly charged by Vectren to the Company. As of December 31, 2009 and 2008, $10.9 million and $38.5 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 & Deferred Compensation Plans
Utility Holdings does not have share-based compensation plans separate from Vectren. The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to Utility Holdings. As of December 31, 2009 and 2008, $28.5 million and $26.6 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are 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.
Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.
Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Consolidated Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities.
Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property in accordance with the regulatory treatment. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.
Significant components of the net deferred tax liability follow:
| At December 31, | |||||||||||
| (In millions) | 2009 | 2008 | |||||||||
| Noncurrent deferred tax liabilities (assets): | |||||||||||
| Depreciation & cost recovery timing differences | $ | 431.8 | $ | 330.9 | |||||||
| Regulatory assets recoverable through future rates | 25.6 | 27.8 | |||||||||
| Other comprehensive income | - | 0.1 | |||||||||
| Alternative minimum tax carryforward | (21.5 | ) | - | ||||||||
| Employee benefit obligations | (7.8 | ) | (22.1 | ) | |||||||
| Regulatory liabilities to be settled through future rates | (11.7 | ) | (15.7 | ) | |||||||
| Other – net | 1.6 | 11.1 | |||||||||
| Net noncurrent deferred tax liability | 418.0 | 332.1 | |||||||||
| Current deferred tax liabilities (assets): | |||||||||||
| Deferred fuel costs - net | 1.2 | 2.6 | |||||||||
| Alternative minimum tax carryforward | (15.8 | ) | (11.2 | ) | |||||||
| Demand side management programs | 5.2 | 8.8 | |||||||||
| Other – net | (7.7 | ) | (3.3 | ) | |||||||
| Net current deferred tax liability | (17.1 | ) | 340.1 | ||||||||
| Net deferred tax liability | $ | 400.9 | $ | 329.0 | |||||||
At December 31, 2009 and 2008, investment tax credits totaling $5.8 million and $6.9 million, respectively, are included in Deferred credits & other liabilities. At December 31, 2009, the Company has alternative minimum tax carryforwards of $37.3 million, which do not expire.
A reconciliation of the federal statutory rate to the effective income tax rate follows:
| Year Ended December 31, | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| Statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | ||||
| State and local taxes-net of federal benefit | 2.9 | 3.4 | 3.9 | |||||||
| Amortization of investment tax credit | (0.6) | (0.7) | (1.0) | |||||||
| Tax law changes and other adjustments to income tax accruals | (1.7) | (1.3) | 0.2 | |||||||
| All other - net | - | 1.4 | 0.4 | |||||||
| Effective tax rate | 35.6 | % | 37.8 | % | 38.5 | % | ||||
The components of income tax expense and utilization of investment tax credits follow:
| Year Ended December 31, | ||||||||||||
| (In millions) | 2009 | 2008 | 2007 | |||||||||
| Current: | ||||||||||||
| Federal | $ | (18.2 | ) | $ | 3.7 | $ | 43.7 | |||||
| State | 1.2 | 9.2 | 8.6 | |||||||||
| Total current taxes | (17.0 | ) | 12.9 | 52.3 | ||||||||
| Deferred: | ||||||||||||
| Federal | 70.3 | 52.7 | 11.9 | |||||||||
| State | 7.0 | 3.3 | 4.2 | |||||||||
| Total deferred taxes | 77.3 | 56.0 | 16.1 | |||||||||
| Amortization of investment tax credits | (1.1 | ) | (1.3 | ) | (1.7 | ) | ||||||
| Total income tax expense | $ | 59.2 | $ | 67.6 | $ | 66.7 | ||||||
Uncertain Tax Positions
Following is a roll forward of the total amount of unrecognized tax benefits for the three years ended December 31, 2009 and 2008:
| (in millions) | 2009 | 2008 | 2007 | |||||||||
| Unrecognized tax benefits at January 1 | $ | 0.5 | $ | 3.8 | $ | 7.0 | ||||||
Gross increases - tax positions in prior periods | 1.0 | 0.3 | 0.3 | |||||||||
Gross decreases - tax positions in prior periods | (1.9 | ) | (3.6 | ) | (3.5 | ) | ||||||
Gross increases - current period tax positions | 9.0 | - | - | |||||||||
Settlements | 0.3 | - | - | |||||||||
Lapse of statute of limitations | 0.6 | - | - | |||||||||
Unrecognized tax benefits at December 31 | $ | 9.5 | $ | 0.5 | $ | 3.8 | ||||||
Of the change in unrecognized tax benefits during 2009 and 2008 almost none impacted the effective rate of the change in unrecognized tax benefits during 2007, $0.3 million impacted the effective tax rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.2 million at December 31, 2009 and almost none at December 31, 2008 and 2007.
As of December 31, 2009, the 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 recognized expense related to interest and penalties totaling approximately $0.1 million in 2009, less than $0.1 million in 2008, and $0.5 million in 2007. The Company had approximately $0.2 million for the payment of interest and penalties accrued as of December 31, 2009 and 2008.
The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes, totaled $8.9 million and $0.7 million, respectively, at December 31, 2009 and 2008.
From time to time, the Company may consider changes to filed positions that could impact its 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.
As the result of adopting changes to the accounting guidance for uncertain tax positions on January 1, 2007, the Company recognized an approximate $0.3 million increase in the liability for unrecognized tax benefits, of which $0.1 million was accounted for as a reduction to the January 1, 2007 balance of Retained earnings and $0.2 million was recorded as an increase to Goodwill.
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. Subsequent to the year ended December 31, 2009, Vectren received a notice from the IRS that year ended December 31, 2008 is under audit. The State of Indiana, Vectren’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2007. The statutes of limitations for assessment of federal and Indiana income tax have expired with respect to tax years through 2002.
| 6. | 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, 2009, 2008 and 2007 totaled $436.2 million, $739.3 million, and $602.2 million, respectively. Amounts owed to ProLiance at December 31, 2009 and 2008, for those purchases were $54.1 million and $72.8 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. The Company purchased approximately 76 percent of its gas through ProLiance in 2009 and 71 percent in 2008 and 2007. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.
| 7. | Borrowing Arrangements |
Long-Term Debt
Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Utility Holdings | ||||||||
Fixed Rate Senior Unsecured Notes | ||||||||
| 2011, 6.625% | $ | 250.0 | $ | 250.0 | ||||
| 2013, 5.25% | 100.0 | 100.0 | ||||||
| 2015, 5.45% | 75.0 | 75.0 | ||||||
| 2018, 5.75% | 100.0 | 100.0 | ||||||
| 2020, 6.28% | 100.0 | - | ||||||
| 2035, 6.10% | 75.0 | 75.0 | ||||||
| 2036, 5.95% | 97.8 | 99.1 | ||||||
| 2039, 6.25% | 122.5 | 124.3 | ||||||
| Total Utility Holdings | 920.3 | 823.4 | ||||||
| SIGECO | ||||||||
First Mortgage Bonds | ||||||||
| 2015, 1985 Pollution Control Series A, current adjustable rate 0.9%, | ||||||||
| tax exempt, 2008 weighted average: 0.37% | 9.8 | 9.8 | ||||||
| 2016, 1986 Series, 8.875% | 13.0 | 13.0 | ||||||
| 2020, 1998 Pollution Control Series B, 4.50%, tax exempt | 4.6 | 4.6 | ||||||
| 2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt | 22.6 | 22.6 | ||||||
| 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt | 22.5 | 22.5 | ||||||
| 2025, 1998 Pollution Control Series A, current adjustable rate 1.2%, | ||||||||
| tax exempt, 2008 weighted average: 0.44% | 31.5 | 31.5 | ||||||
| 2029, 1999 Senior Notes, 6.72% | 80.0 | 80.0 | ||||||
| 2030, 1998 Pollution Control Series B, 5.00%, tax exempt | 22.0 | 22.0 | ||||||
| 2030, 1998 Pollution Control Series C, 5.35%, tax exempt | 22.2 | 22.2 | ||||||
| 2040, 2009 Environmental Improvement Series, 5.40%, tax exempt | 22.3 | - | ||||||
| 2041, 2007 Pollution Control Series, 5.45%, tax exempt | 17.0 | 17.0 | ||||||
| Total SIGECO | 267.5 | 245.2 | ||||||
| Indiana Gas | ||||||||
Senior Unsecured Notes | ||||||||
| 2013, Series E, 6.69% | 5.0 | 5.0 | ||||||
| 2015, Series E, 7.15% | 5.0 | 5.0 | ||||||
| 2015, Series E, 6.69% | 5.0 | 5.0 | ||||||
| 2015, Series E, 6.69% | 10.0 | 10.0 | ||||||
| 2025, Series E, 6.53% | 10.0 | 10.0 | ||||||
| 2027, Series E, 6.42% | 5.0 | 5.0 | ||||||
| 2027, Series E, 6.68% | 1.0 | 1.0 | ||||||
| 2027, Series F, 6.34% | 20.0 | 20.0 | ||||||
| 2028, Series F, 6.36% | 10.0 | 10.0 | ||||||
| 2028, Series F, 6.55% | 20.0 | 20.0 | ||||||
| 2029, Series G, 7.08% | 30.0 | 30.0 | ||||||
| Total Indiana Gas | 121.0 | 121.0 | ||||||
| Total long-term debt outstanding | 1,308.8 | 1,189.6 | ||||||
Current maturities of long-term debt | - | - | ||||||
Debt subject to tender | (51.3 | ) | (80.0 | ) | ||||
Unamortized debt premium & discount - net | (2.7 | ) | (3.2 | ) | ||||
Treasury debt | - | (41.3 | ) | |||||
| Total long-term debt-net | $ | 1,254.8 | $ | 1,065.1 | ||||
Utility Holdings 2009 Debt Issuance
On April 7, 2009, Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million.
The 2020 Notes have no sinking fund requirements, and interest payments are due semi-annually. The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in the Utility Holdings’ $515 million short-term credit facility.
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.
SIGECO 2009 Debt Issuance
On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity. The bonds mature in 2040. The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 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 2009 and 2008, the Company repaid approximately $3.0 million and $1.6 million, respectively, related to death puts. In 2007, 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 2009 (in millions) is $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter. Debt that may be put to the Company within one year or debt that is supported by lines of credit that expire within one year are 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.
On March 26, 2009, SIGECO remarketed the remaining $41.3 million of long-term debt held in treasury at December 31, 2008, receiving proceeds, net of issuance costs of approximately $40.6 million. The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit backed by Utility Holdings’ $515 million short-term credit facility. The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025. The initial interest rate paid to investors was 0.55 percent. The equivalent rate of the debt at inception, inclusive of interest, weekly remarketing fees, and letter of credit fees, approximated 1 percent. Because these notes are supported by Utility Holdings’ short term credit facility and that facility expires within one year, such debt is classified as Long-term debt subject to tender in current liabilities.
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 2010 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2010 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2009, $1.2 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 $2.5 billion at December 31, 2009.
Consolidated maturities of long-term debt during the five years following 2009 (in millions) are zero in 2010, $250.0 in 2011, zero in 2012, $105.0 in 2013, and zero in 2014.
Short-Term Borrowings
At December 31, 2009, the Company had $520 million of short-term borrowing capacity, of which approximately $462 million was available. Interest rates and outstanding balances associated with short-term borrowing arrangements follows.
| Year Ended December 31, | |||||||||||||||
| (In millions) | 2009 | 2008 | 2007 | ||||||||||||
| Weighted average commercial paper and bank loans | |||||||||||||||
| outstanding during the year | $ | 28.7 | $ | 178.2 | $ | 253.6 | |||||||||
| Weighted average interest rates during the year | |||||||||||||||
| Commercial paper | 1.29 | % | 3.76 | % | 5.54 | % | |||||||||
| Bank loans | 1.26 | % | 3.42 | % | N/A | ||||||||||
| At December 31, | |||||||||||||||
| (In millions) | 2009 | 2008 | |||||||||||||
| Commercial paper | $ | 16.4 | $ | 91.5 | |||||||||||
| Bank loans | - | 100.4 | |||||||||||||
| Total short-term borrowings | $ | 16.4 | $ | 191.9 | |||||||||||
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, 2009, the Company was in compliance with all financial covenants.
| 8. | 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, 2009, 2008, and 2007, the Company has cumulatively received additional capital of $12.2 million from Vectren which was funded by new share issues from Vectren’s dividend reinvestment plan.
| 9. | Accumulated Other 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:
| 2007 | 2008 | 2009 | ||||||||||||||||||||||||||
| Beginning | Changes | End | Changes | End | Changes | End | ||||||||||||||||||||||
| of Year | During | of Year | During | of Year | During | of Year | ||||||||||||||||||||||
| (In millions) | Balance | Year | Balance | Year | Balance | Year | Balance | |||||||||||||||||||||
| Cash flow hedges | $ | 1.4 | $ | (0.9 | ) | $ | 0.5 | $ | (0.4 | ) | $ | 0.1 | $ | - | $ | 0.1 | ||||||||||||
| Deferred income taxes | (0.5 | ) | 0.3 | (0.2 | ) | 0.2 | - | - | - | |||||||||||||||||||
| Accumulated other comprehensive income | $ | 0.9 | $ | (0.6 | ) | $ | 0.3 | $ | (0.2 | ) | $ | 0.1 | $ | - | $ | 0.1 | ||||||||||||
10. | 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 2009 and thereafter (in millions) are $0.5 in 2010, $0.4 in 2011, $0.3 in 2012, $0.3 in 2013, $0.2 in 2014, and zero thereafter. Total lease expense (in millions) was $0.9 in 2009, $1.6 in 2008, and $1.3 in 2007. Firm purchase commitments for commodities and utility plant total zero in 2010 and 2011, $5.3 million in 2012, $5.5 million in 2013, $5.7 million in 2014, and zero thereafter.
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, they have not been included in the listing of contractual obligations.
Legal Proceedings
The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.
| 11. | Environmental Matters |
Clean Air Act
The Clean Air Interstate Rule (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 and is positioned to comply with SO2 reductions effective January 1, 2010. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised; however, most of 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. In response to the court decision, USEPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2010. It is uncertain what emission limit the USEPA is considering, and whether they will address hazardous pollutants in addition to mercury. It is also possible that the vacatur of the CAMR regulations will lead to increased support for the passage of a multi-pollutant bill in Congress.
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. The Company has invested approximately $100 million in this project. The scrubber was placed into service on January 1, 2009. 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 U.S. House of Representatives has passed a comprehensive energy bill that includes a carbon cap and trade program in which there is a progressive cap on greenhouse gas emissions and an auctioning and subsequent trading of allowances among those that emit greenhouse gases, a federal renewable portfolio standard, and utility energy efficiency targets. Current proposed legislation also requires local natural gas distribution companies to hold allowances for the benefit of their customers. As of the date of this filing, the Senate has not passed a bill, and the House bill is not law. The U.S. Senate is currently debating a cap and trade proposal that is similar in structure to the House bill.
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 Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord, and in its completed 2009 session, the state’s legislature debated, but did not pass, a renewable energy portfolio standard.
In advance of a federal or state renewable portfolio standard, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly interconnected to the Company’s distribution system. In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy. These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008.
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 motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the USEPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December of 2009, and is the first step toward USEPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases. The USEPA has recently finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010). The USEPA has also recently proposed a revision to the PSD (Prevention of Significant Deterioration) and Title V permitting rules which would require facilities that emit 25,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility. If these proposed rules were adopted, they would apply to SIGECO’s generating facilities.
Impact of Legislative Actions & 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 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 with regard operating expenses for the purchase of allowances, and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices and energy efficiency targets. 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 20 percent of electric volumes sold in 2008 were delivered to municipal and other wholesale customers. As such, reductions in these volumes in 2009 coupled with the flexibility to further modify the level of these transactions in future periods may help with compliance if emission targets are based on pre-2008 levels.
Ash Ponds & Coal Ash Disposal Regulations
The USEPA is considering additional regulatory measures affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. Additional laws and regulations under consideration more stringently regulate these byproducts, including the potential for coal ash to be considered a hazardous waste in certain circumstances. The USEPA has indicated that it intends to propose a rule during 2010. At this time, the Company is unable to predict the outcome any such revised regulations might have on operating results, financial position, or liquidity.
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 Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels. At this time, it is anticipated that the USEPA may request only additional soil testing at some future date.
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 $23.2 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 limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent.
With respect to insurance coverage, Indiana Gas has settled with all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.8 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 waste disposal site subject to potential environmental remediation efforts. With respect to that lawsuit, in an October 2009 court decision, SIGECO was found to be a PRP at the site. However, the Court must still determine whether such costs should be allocated among a number of PRPs, including the former owners of the site. 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.
SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters totaling approximately $11.1 million. However, given the uncertainty surrounding the allocation of PRP responsibility associated with the May 2007 lawsuit and other matters, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time. With respect to insurance coverage, SIGECO has settled with certain of its known insurance carriers under insurance policies in effect when these sites were in operation in an aggregate amount of $8.1 million; negotiations are ongoing with others. SIGECO has undertaken significant remediation efforts at two MGP sites.
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, 2009 and December 31, 2008, approximately $6.5 million of accrued, but not yet spent, remediation costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.
| 12. | Rate & Regulatory Matters |
Vectren South Electric Base Rate Filings
On December 11, 2009, the Company filed a request with the IURC to adjust its electric base rates in its South service territory. The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between the Company and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers. In total the request approximated $54 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service. Most of the remainder of the request is to account for the now lower overall sales levels resulting from the recession. A portion of the request reflects a slight increase in annual operating and maintenance costs since the last rate case, nearly four years ago. The rate design proposed in the filing would break the link between customers’ consumption and the utility’s rate of return, thereby aligning the utility’s and customers’ interests in using less energy. The request assumes an overall rate of return of 7.62 percent on rate base of approximately $1,294 million and an allowed return on equity (ROE) of 10.7 percent. Based upon timelines prescribed by the IURC at the start of these proceedings, a decision is expected to be issued at the end of 2010.
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 adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers. The order allows for the phased movement toward a straight fixed variable rate design which places substantially all of the fixed cost recovery in the customer service charge. A straight fixed variable design mitigates most 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 on February 22, 2009. In 2008, annual results include approximately $4.3 million of revenue from a lost margin recovery mechanism that did not continue once this base rate increase went into effect. After year one, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge. 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. The Ohio Supreme Court has yet to act on the OCC’s request in this instance, but in two similar cases, the Court denied such requests.
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 uncollectible accounts 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. The straight fixed variable rate design will be fully phased in by February 2010.
VEDO Continues the 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 eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. On October 1, 2008, VEDO’s entire natural gas inventory was transferred, receiving proceeds of approximately $107 million.
The second phase of the exit process begins on April 1, 2010, during which the Company will no longer sell natural gas directly to these customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that are successful bidders in a second regulatory-approved auction, will sell the gas commodity to specific customers for 12 months at auction-determined standard pricing. That auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13. The plan approved by the PUCO requires that the Company conduct at least two auctions during this phase. As such, the Company will conduct another auction in advance of the second 12-month term, which will commence on April 1, 2011. Consistent with current practice, customers will continue to receive one bill for the delivery of natural gas service.
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 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 uncollectible accounts 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 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 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 uncollectible accounts 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
In August 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 Vectren 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.
MISO
Since 2002 and with the IURC’s approval, the Company has been a member of the 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.
MISO-related purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.
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. The Company also has municipal customers served through the MISO and for which the Company transmits power to the MISO for delivery to those customers. Net revenues from wholesale activities, inclusive of revenues associated with these municipal contracts, totaled $20.8 million in 2009, $57.6 million in 2008, and $35.0 million in 2007 and are recorded in Electric utility revenues. The base rate case effective August 17, 2007, requires that wholesale margin (net revenues less the cost of fuel and purchased power) inclusive of this MISO wholesale activity earned above or below $10.5 million be shared equally with retail customers as measured on a fiscal year ending in August.
Recently, MISO market prices have fallen and the Company has more frequently been a net purchaser. In addition, the Company also receives power through the MISO associated with its wind and other power purchase agreements. Including these power purchase agreements, the Company purchased energy from the MISO totaling $34.2 million in 2009, $16.6 million in 2008, and $18.2 million in 2007. To the extent these power purchases are used for retail load, they are included in FAC filings.
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 from / refunded to retail customers 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 recover costs associated with ASM. To date impacts from the ASM have been minor.
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. Beginning in June 2008, the Company began timely recovering its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return. Such revenues recorded in Electric utility revenues associated with projects meeting the criteria of MISO’s transmission expansion plans totaled $9.1 million in 2009 and $4.8 million in 2008.
| 13. | Fair Value Measurements |
The carrying values and estimated fair values of the Company's other financial instruments follow:
| At December 31, | ||||||||||||||||
| 2009 | 2008 | |||||||||||||||
| (In millions) | Carrying Amount | Est. Fair Value | Carrying Amount | Est. Fair Value | ||||||||||||
| Long-term debt | $ | 1,308.8 | $ | 1,366.4 | $ | 1,189.6 | $ | 1,068.3 | ||||||||
| Short-term borrowings | 16.4 | 16.4 | 191.9 | 191.9 | ||||||||||||
| Cash & cash equivalents | 6.2 | 6.2 | 52.5 | 52.5 | ||||||||||||
For the balance sheet dates presented in these financial statements, other than $40 million invested in money market funds and included in Cash and cash equivalents as of December 31, 2008, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs. The money market investments were valued using Level 1 inputs.
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 and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.
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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.
| 14. | 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:
| Year Ended December 31, | ||||||||||||
| (In millions) | 2009 | 2008 | 2007 | |||||||||
| Revenues | ||||||||||||
| Gas Utility Services | $ | 1,066.0 | $ | 1,432.7 | $ | 1,269.4 | ||||||
| Electric Utility Services | 528.6 | 524.2 | 487.9 | |||||||||
| Other Operations | 42.8 | 36.8 | 40.4 | |||||||||
| Eliminations | (41.2 | ) | (35.0 | ) | (38.7 | ) | ||||||
| Total revenues | $ | 1,596.2 | $ | 1,958.7 | $ | 1,759.0 | ||||||
| Profitability Measure - Net Income | ||||||||||||
| Gas Utility Services | $ | 50.2 | $ | 53.3 | $ | 41.7 | ||||||
| Electric Utility Services | 48.3 | 50.7 | 52.6 | |||||||||
| Other Operations | 8.9 | 7.1 | 12.2 | |||||||||
| Total net income | $ | 107.4 | $ | 111.1 | $ | 106.5 | ||||||
| Amounts Included in Profitability Measures | ||||||||||||
| Depreciation & Amortization | ||||||||||||
| Gas Utility Services | $ | 76.9 | $ | 74.1 | $ | 70.6 | ||||||
| Electric Utility Services | 77.5 | 68.5 | 66.0 | |||||||||
| Other Operations | 26.5 | 22.9 | 21.8 | |||||||||
| Total depreciation & amortization | $ | 180.9 | $ | 165.5 | $ | 158.4 | ||||||
| Interest Expense | ||||||||||||
| Gas Utility Services | $ | 38.8 | $ | 42.0 | $ | 39.8 | ||||||
| Electric Utility Services | 34.8 | 32.0 | 29.6 | |||||||||
| Other Operations | 5.6 | 5.9 | 11.2 | |||||||||
| Total interest expense | $ | 79.2 | $ | 79.9 | $ | 80.6 | ||||||
| Income Taxes | ||||||||||||
| Gas Utility Services | $ | 31.3 | $ | 35.5 | $ | 33.2 | ||||||
| Electric Utility Services | 27.4 | 32.0 | 38.0 | |||||||||
| Other Operations | 0.5 | 0.1 | (4.5 | ) | ||||||||
| Total income taxes | $ | 59.2 | $ | 67.6 | $ | 66.7 | ||||||
| Capital Expenditures | ||||||||||||
| Gas Utility Services | $ | 121.1 | $ | 110.4 | $ | 128.9 | ||||||
| Electric Utility Services | 154.1 | 172.0 | 134.7 | |||||||||
| Other Operations | 16.7 | 29.6 | 36.4 | |||||||||
| Non-cash costs & changes in accruals | 15.0 | (5.7 | ) | 2.5 | ||||||||
| Total capital expenditures | $ | 306.9 | $ | 306.3 | $ | 302.5 | ||||||
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Assets | ||||||||
| Utility Group | ||||||||
| Gas Utility Services | $ | 2,102.4 | $ | 2,204.7 | ||||
| Electric Utility Services | 1,592.4 | 1,462.1 | ||||||
| Other Operations, net of eliminations | 128.3 | 171.3 | ||||||
| Total assets | $ | 3,823.1 | $ | 3,838.1 | ||||
| 15. | Additional Balance Sheet & Operational Information |
Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Prepaid gas delivery service | $ | 38.7 | $ | 75.0 | ||||
| Prepaid taxes | 11.4 | 19.3 | ||||||
| Deferred income taxes | 17.1 | 3.1 | ||||||
| Other prepayments & current assets | 2.0 | 5.7 | ||||||
| Total prepayments & other current assets | $ | 69.2 | $ | 103.1 | ||||
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Refunds to customers & customer deposits | $ | 51.0 | $ | 45.5 | ||||
| Accrued taxes | 36.9 | 45.2 | ||||||
| Accrued interest | 19.6 | 18.0 | ||||||
| Asset retirement obligation | 2.7 | 7.2 | ||||||
| Accrued salaries & other | 21.2 | 31.8 | ||||||
| Total accrued liabilities | $ | 131.4 | $ | 147.7 | ||||
Other investments in the Consolidated Balance Sheets consist of the following:
| At December 31, | ||||||||
| (In millions) | 2009 | 2008 | ||||||
| Cash surrender value of life insurance policies | $ | 23.1 | $ | 18.5 | ||||
| Municipal bond | 4.3 | 4.5 | ||||||
| Restricted cash | 2.8 | - | ||||||
| Other investments | 1.2 | 1.2 | ||||||
| Total other investments | $ | 31.4 | $ | 24.1 | ||||
Other – net in the Consolidated Statements of Income consists of the following:
| Year Ended December 31, | |||||||||||||||
| (In millions) | 2009 | 2008 | 2007 | ||||||||||||
| AFUDC - borrowed funds | $ | 1.3 | $ | 2.2 | $ | 3.5 | |||||||||
| AFUDC - equity funds | 0.7 | 0.3 | 0.5 | ||||||||||||
| Nonutility plant capitalized interest | 0.2 | 2.0 | 1.3 | ||||||||||||
| Interest income | 0.7 | 1.0 | 2.3 | ||||||||||||
| Cash surrender value of life insurance policies | 3.9 | (2.6 | ) | 0.5 | |||||||||||
| Other income | 1.0 | 1.1 | 1.3 | ||||||||||||
| Total other – net | $ | 7.8 | $ | 4.0 | $ | 9.4 | |||||||||
Supplemental Cash Flow Information:
| Year Ended December 31, | |||||||
| (In millions) | 2009 | 2008 | 2007 | ||||
| Cash paid for: | |||||||
Interest | 77.6 | 74.9 | 77.1 | ||||
Income taxes | (26.1) | 14.8 | 44.9 | ||||
As of December 31, 2009 and 2008, the Company has accruals related to utility and nonutility plant purchases totaling approximately $8.8 million and $30.3 million, respectively.
| 16. | Impact of Recently Issued Accounting Guidance |
Variable Interest Entities
In June 2009, the FASB issued new accounting guidance regarding variable interest entities (VIE’s). This new guidance is effective for annual reporting periods beginning after November 15, 2009. This guidance requires a qualitative analysis of which holder of a variable interest controls the VIE and if that interest holder must consolidate a VIE. Additionally, it requires additional disclosures and an ongoing reassessment of who must consolidate a VIE. The Company adopted this guidance on January 1, 2010. The Company does not expect the adoption will have a material impact on the consolidated financial statements.
In January 2010, the FASB issued new accounting guidance on improving disclosures about fair market value. This guidance amends prior disclosure requirements involving fair value measurements to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The guidance also clarifies existing fair value disclosures in regard to the level of disaggregation and about inputs and valuation techniques used to measure fair value. The guidance also amends prior disclosure requirements regarding postretirement benefit plan assets to require that disclosures be provided by classes of assets instead of major categories of assets. This guidance is effective for the first reporting period beginning after December 15, 2009. The Company will adopt this guidance in its first quarter 2010 reporting. The Company does not expect the adoption will have a material impact on the consolidated financial statements.
| 17. | Subsidiary Guarantor & 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 $16 million is outstanding at December 31, 2009, and Utility Holdings’ $920 million unsecured senior notes outstanding at December 31, 2009. 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, which are 100 percent owned, 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, 2009 (in millions):
| Subsidiary | Parent | |||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| OPERATING REVENUES | ||||||||||||||||
| Gas utility | $ | 1,066.0 | $ | - | $ | - | $ | 1,066.0 | ||||||||
| Electric utility | 528.6 | - | - | 528.6 | ||||||||||||
| Other | - | 42.8 | (41.2 | ) | 1.6 | |||||||||||
| Total operating revenues | 1,594.6 | 42.8 | (41.2 | ) | 1,596.2 | |||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Cost of gas sold | 618.1 | - | - | 618.1 | ||||||||||||
| Cost of fuel & purchased power | 194.3 | - | - | 194.3 | ||||||||||||
| Other operating | 345.3 | 0.1 | (40.8 | ) | 304.6 | |||||||||||
| Depreciation & amortization | 154.1 | 26.5 | 0.3 | 180.9 | ||||||||||||
| Taxes other than income taxes | 58.6 | 1.6 | 0.1 | 60.3 | ||||||||||||
| Total operating expenses | 1,370.4 | 28.2 | (40.4 | ) | 1,358.2 | |||||||||||
| OPERATING INCOME | 224.2 | 14.6 | (0.8 | ) | 238.0 | |||||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||
| Equity in earnings of consolidated companies | - | 98.5 | (98.5 | ) | - | |||||||||||
| Other – net | 6.6 | 50.9 | (49.7 | ) | 7.8 | |||||||||||
| Total other income (expense) | 6.6 | �� | 149.4 | (148.2 | ) | 7.8 | ||||||||||
| Interest expense | 73.6 | 56.1 | (50.5 | ) | 79.2 | |||||||||||
| INCOME BEFORE INCOME TAXES | 157.2 | 107.9 | (98.5 | ) | 166.6 | |||||||||||
| Income taxes | 58.7 | 0.5 | - | 59.2 | ||||||||||||
| NET INCOME | $ | 98.5 | $ | 107.4 | $ | (98.5 | ) | $ | 107.4 | |||||||
Consolidating Statement of Income for the year ended December 31, 2008 (in millions):
| Subsidiary | Parent | |||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| OPERATING REVENUES | ||||||||||||||||
| Gas utility | $ | 1,432.7 | $ | - | $ | - | $ | 1,432.7 | ||||||||
| Electric utility | 524.2 | - | - | $ | 524.2 | |||||||||||
| Other | - | 36.8 | (35.0 | ) | $ | 1.8 | ||||||||||
| Total operating revenues | 1,956.9 | 36.8 | (35.0 | ) | 1,958.7 | |||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Cost of gas sold | 983.1 | - | - | 983.1 | ||||||||||||
| Cost of fuel & purchased power | 182.9 | - | - | 182.9 | ||||||||||||
| Other operating | 334.2 | - | (33.9 | ) | 300.3 | |||||||||||
| Depreciation & amortization | 142.3 | 22.9 | 0.3 | 165.5 | ||||||||||||
| Taxes other than income taxes | 70.5 | 1.7 | 0.1 | 72.3 | ||||||||||||
| Total operating expenses | 1,713.0 | 24.6 | (33.5 | ) | 1,704.1 | |||||||||||
| OPERATING INCOME | 243.9 | 12.2 | (1.5 | ) | 254.6 | |||||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||
| Equity in earnings of consolidated companies | - | 104.0 | (104.0 | ) | - | |||||||||||
| Other – net | 1.6 | 52.4 | (50.0 | ) | 4.0 | |||||||||||
| Total other income (expense) | 1.6 | 156.4 | (154.0 | ) | 4.0 | |||||||||||
| Interest expense | 74.0 | 57.4 | (51.5 | ) | 79.9 | |||||||||||
| INCOME BEFORE INCOME TAXES | 171.5 | 111.2 | (104.0 | ) | 178.7 | |||||||||||
| Income taxes | 67.5 | 0.1 | - | 67.6 | ||||||||||||
| NET INCOME | $ | 104.0 | $ | 111.1 | $ | (104.0 | ) | $ | 111.1 | |||||||
Consolidating Statement of Income for the year ended December 31, 2007 (in millions):
| Subsidiary | Parent | |||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| OPERATING REVENUES | ||||||||||||||||
| Gas utility | $ | 1,269.4 | $ | - | $ | - | $ | 1,269.4 | ||||||||
| Electric utility | 487.9 | - | - | 487.9 | ||||||||||||
| Other | - | 40.4 | (38.7 | ) | 1.7 | |||||||||||
| Total operating revenues | 1,757.3 | 40.4 | (38.7 | ) | 1,759.0 | |||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Cost of gas sold | 847.2 | - | - | 847.2 | ||||||||||||
| Cost of fuel & purchased power | 174.8 | - | - | 174.8 | ||||||||||||
| Other operating | 301.5 | - | (35.4 | ) | 266.1 | |||||||||||
| Depreciation & amortization | 136.6 | 21.5 | 0.3 | 158.4 | ||||||||||||
| Taxes other than income taxes | 66.0 | 2.1 | - | 68.1 | ||||||||||||
| Total operating expenses | 1,526.1 | 23.6 | (35.1 | ) | 1,514.6 | |||||||||||
| OPERATING INCOME | 231.2 | 16.8 | (3.6 | ) | 244.4 | |||||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||
| Equity in earnings of consolidated companies | - | 94.3 | (94.3 | ) | - | |||||||||||
| Other – net | 3.7 | 48.3 | (42.6 | ) | 9.4 | |||||||||||
| Total other income (expense) | 3.7 | 142.6 | (136.9 | ) | 9.4 | |||||||||||
| Interest expense | 69.4 | 57.4 | (46.2 | ) | 80.6 | |||||||||||
| INCOME BEFORE INCOME TAXES | 165.5 | 102.0 | (94.3 | ) | 173.2 | |||||||||||
| Income taxes | 71.2 | (4.5 | ) | - | 66.7 | |||||||||||
| NET INCOME | $ | 94.3 | $ | 106.5 | $ | (94.3 | ) | $ | 106.5 | |||||||
Consolidating Statement of Cash Flows for the year ended December 31, 2009 (in millions):
| Subsidiary | Parent | |||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| NET CASH FLOWS FROM OPERATING ACTIVITIES | $ | 350.6 | $ | 6.2 | $ | - | $ | 356.8 | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
| Proceeds from | ||||||||||||||||
Additional capital contribution from parent | 6.9 | 6.9 | (6.9 | ) | 6.9 | |||||||||||
Long-term debt - net of issuance costs & hedging proceeds | 136.3 | 99.5 | (74.5 | ) | 161.3 | |||||||||||
| Requirements for: | ||||||||||||||||
Dividends to parent | (82.5 | ) | (82.5 | ) | 82.5 | (82.5 | ) | |||||||||
Retirement of long-term debt, including premiums paid | (3.0 | ) | (3.0 | ) | 3.0 | (3.0 | ) | |||||||||
Net change in intercompany short-term borrowings | (152.5 | ) | (35.1 | ) | 187.6 | - | ||||||||||
Net change in short-term borrowings | (0.4 | ) | (175.1 | ) | - | (175.5 | ) | |||||||||
| Net cash flows from financing activities | (95.2 | ) | (189.3 | ) | 191.7 | (92.8 | ) | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
| Proceeds from | ||||||||||||||||
Consolidated subsidiary distributions | - | 82.5 | (82.5 | ) | - | |||||||||||
Other investing activities | - | 0.2 | - | 0.2 | ||||||||||||
| Requirements for: | ||||||||||||||||
Capital expenditures, excluding AFUDC equity | (291.0 | ) | (15.9 | ) | - | (306.9 | ) | |||||||||
Consolidated subsidiary investments | - | (6.9 | ) | 6.9 | - | |||||||||||
Other investing activities | (3.6 | ) | - | - | (3.6 | ) | ||||||||||
Net change in long-term intercompany notes receivable | - | (71.5 | ) | 71.5 | - | |||||||||||
Net change in short-term intercompany notes receivable | 35.1 | 152.5 | (187.6 | ) | - | |||||||||||
| Net cash flows from investing activities | (259.5 | ) | 140.9 | (191.7 | ) | (310.3 | ) | |||||||||
| Net change in cash & cash equivalents | (4.1 | ) | (42.2 | ) | - | (46.3 | ) | |||||||||
| Cash & cash equivalents at beginning of period | 9.7 | 42.8 | - | 52.5 | ||||||||||||
| Cash & cash equivalents at end of period | $ | 5.6 | $ | 0.6 | $ | - | $ | 6.2 | ||||||||
Consolidating Statement of Cash Flows for the year ended December 31, 2008 (in millions):
| Subsidiary | Parent | |||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| NET CASH FLOWS FROM OPERATING ACTIVITIES | $ | 379.6 | $ | 55.4 | $ | - | $ | 435.0 | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
| Proceeds from: | ||||||||||||||||
Long-term debt - net of issuance costs & hedging proceeds | 171.1 | 111.1 | (111.1 | ) | 171.1 | |||||||||||
Issuance of common stock | - | 124.8 | - | 124.8 | ||||||||||||
| Requirements for: | ||||||||||||||||
Dividends to parent | (83.2 | ) | (83.2 | ) | 83.2 | (83.2 | ) | |||||||||
Retirement of long-term debt, including premiums paid | (104.6 | ) | (1.6 | ) | 1.6 | (104.6 | ) | |||||||||
Net change in intercompany short-term borrowings | (80.9 | ) | 103.9 | (23.0 | ) | - | ||||||||||
Net change in short-term borrowings | 0.4 | (194.4 | ) | - | (194.0 | ) | ||||||||||
| Net cash flows from financing activities | (97.2 | ) | 60.6 | (49.3 | ) | (85.9 | ) | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
| Proceeds from: | ||||||||||||||||
Consolidated subsidiary distributions | - | 83.2 | (83.2 | ) | - | |||||||||||
Other investing activities | 2.3 | 0.2 | - | 2.5 | ||||||||||||
| Requirements for: | ||||||||||||||||
Capital expenditures, excluding AFUDC equity | (277.0 | ) | (29.3 | ) | - | (306.3 | ) | |||||||||
Other investing activities | (4.5 | ) | - | - | (4.5 | ) | ||||||||||
Net change in long-term intercompany notes receivable | - | (109.5 | ) | 109.5 | - | |||||||||||
Net change in short-term intercompany notes receivable | - | (23.0 | ) | 23.0 | - | |||||||||||
| Net cash flows from investing activities | (279.2 | ) | (78.4 | ) | 49.3 | (308.3 | ) | |||||||||
| Net change in cash & cash equivalents | 3.2 | 37.6 | - | 40.8 | ||||||||||||
| Cash & cash equivalents at beginning of period | 6.5 | 5.2 | - | 11.7 | ||||||||||||
| Cash & cash equivalents at end of period | $ | 9.7 | $ | 42.8 | $ | - | $ | 52.5 | ||||||||
Consolidating Statement of Cash Flows for the year ended December 31, 2007 (in millions):
| Subsidiary | Parent | |||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| NET CASH FLOWS FROM OPERATING ACTIVITIES | $ | 211.2 | $ | 21.0 | $ | - | $ | 232.2 | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
| Proceeds from: | ||||||||||||||||
Long-term debt - net of issuance costs & hedging proceeds | 30.3 | - | (14.0 | ) | 16.3 | |||||||||||
Additional capital contribution | - | 5.3 | - | 5.3 | ||||||||||||
| Requirements for: | ||||||||||||||||
Dividends to parent | (76.4 | ) | (76.6 | ) | 76.4 | (76.6 | ) | |||||||||
Retirement of long-term debt, including premiums paid | (6.5 | ) | - | - | (6.5 | ) | ||||||||||
Net change in short-term borrowings, including from other | ||||||||||||||||
| Vectren companies | 110.3 | 115.8 | (110.3 | ) | 115.8 | |||||||||||
| Net cash flows from financing activities | 57.7 | 44.5 | (47.9 | ) | 54.3 | |||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
| Proceeds from: | ||||||||||||||||
Consolidated subsidiary distributions | - | 76.4 | (76.4 | ) | - | |||||||||||
Other investing activities | 0.7 | 0.3 | - | 1.0 | ||||||||||||
| Requirements for: | ||||||||||||||||
Capital expenditures, excluding AFUDC equity | (267.0 | ) | (35.5 | ) | - | (302.5 | ) | |||||||||
Consolidated subsidiary investments | - | (14.0 | ) | 14.0 | - | |||||||||||
Unconsolidated affiliate & other investments | (1.8 | ) | - | - | (1.8 | ) | ||||||||||
Net change in notes receivable from other Vectren companies | - | (110.3 | ) | 110.3 | - | |||||||||||
| Net cash flows from investing activities | (268.1 | ) | (83.1 | ) | 47.9 | (303.3 | ) | |||||||||
| Net change in cash & cash equivalents | 0.8 | (17.6 | ) | - | (16.8 | ) | ||||||||||
| Cash & cash equivalents at beginning of period | 5.7 | 22.8 | - | 28.5 | ||||||||||||
| Cash & cash equivalents at end of period | $ | 6.5 | $ | 5.2 | $ | - | $ | 11.7 | ||||||||
Consolidating Balance Sheet as of December 31, 2009 (in millions):
| ASSETS | Subsidiary | Parent | ||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| Current Assets | ||||||||||||||||
| Cash & cash equivalents | $ | 5.6 | $ | 0.6 | - | $ | 6.2 | |||||||||
| Accounts receivable - less reserves | 108.1 | - | - | 108.1 | ||||||||||||
| Intercompany receivables | 68.2 | 132.7 | (200.9 | ) | - | |||||||||||
| Receivables due from other Vectren companies | 0.7 | - | - | 0.7 | ||||||||||||
| Accrued unbilled revenues | 115.4 | - | - | 115.4 | ||||||||||||
| Inventories | 124.6 | 3.3 | - | 127.9 | ||||||||||||
| Recoverable fuel & natural gas costs | - | - | - | - | ||||||||||||
| Prepayments & other current assets | 63.4 | 16.4 | (10.6 | ) | 69.2 | |||||||||||
| Total current assets | 486.0 | 153.0 | (211.5 | ) | 427.5 | |||||||||||
| Utility Plant | ||||||||||||||||
| Original cost | 4,601.4 | - | - | 4,601.4 | ||||||||||||
| Less: accumulated depreciation & amortization | 1,722.6 | - | - | 1,722.6 | ||||||||||||
| Net utility plant | 2,878.8 | - | - | 2,878.8 | ||||||||||||
| Investments in consolidated subsidiaries | - | 1,190.3 | (1,190.3 | ) | - | |||||||||||
| Notes receivable from consolidated subsidiaries | - | 770.4 | (770.4 | ) | - | |||||||||||
| Investments in unconsolidated affiliates | 0.2 | - | - | 0.2 | ||||||||||||
| Other investments | 26.0 | 5.4 | - | 31.4 | ||||||||||||
| Nonutility property - net | 4.1 | 167.7 | - | 171.8 | ||||||||||||
| Goodwill - net | 205.0 | - | - | 205.0 | ||||||||||||
| Regulatory assets | 79.6 | 24.5 | - | 104.1 | ||||||||||||
| Other assets | 15.2 | - | (10.9 | ) | 4.3 | |||||||||||
| TOTAL ASSETS | $ | 3,694.9 | $ | 2,311.3 | $ | (2,183.1 | ) | $ | 3,823.1 | |||||||
| LIABILITIES & SHAREHOLDER'S EQUITY | Subsidiary | Parent | ||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| Current Liabilities | ||||||||||||||||
| Accounts payable | $ | 127.5 | $ | 5.6 | $ | - | $ | 133.1 | ||||||||
| Accounts payable to affiliated companies | 54.1 | - | - | 54.1 | ||||||||||||
| Intercompany payables | 18.2 | - | (18.2 | ) | - | |||||||||||
| Payables to other Vectren companies | 53.6 | - | - | 53.6 | ||||||||||||
| Refundable fuel & natural gas costs | 22.3 | - | - | 22.3 | ||||||||||||
| Accrued liabilities | 120.8 | 21.2 | (10.6 | ) | 131.4 | |||||||||||
| Short-term borrowings | - | 16.4 | - | 16.4 | ||||||||||||
| Intercompany short-term borrowings | 113.8 | 68.9 | (182.7 | ) | - | |||||||||||
| Long-term debt subject to tender | 51.3 | - | - | 51.3 | ||||||||||||
| Total current liabilities | 561.6 | 112.1 | (211.5 | ) | 462.2 | |||||||||||
| Long-Term Debt | ||||||||||||||||
| Long-term debt - net of current maturities & | ||||||||||||||||
| debt subject to tender | 335.6 | 919.2 | - | 1,254.8 | ||||||||||||
| Long-term debt due to VUHI | 770.4 | - | (770.4 | ) | - | |||||||||||
| Total long-term debt - net | 1,106.0 | 919.2 | (770.4 | ) | 1,254.8 | |||||||||||
| Deferred Income Taxes & Other Liabilities | ||||||||||||||||
| Deferred income taxes | 417.8 | 0.2 | - | 418.0 | ||||||||||||
| Regulatory liabilities | 318.2 | 4.0 | - | 322.2 | ||||||||||||
| Deferred credits & other liabilities | 101.0 | 1.1 | (10.9 | ) | 91.2 | |||||||||||
| Total deferred credits & other liabilities | 837.0 | 5.3 | (10.9 | ) | 831.4 | |||||||||||
| Common Shareholder's Equity | ||||||||||||||||
| Common stock (no par value) | 783.1 | 769.9 | (783.1 | ) | 769.9 | |||||||||||
| Retained earnings | 407.1 | 504.7 | (407.1 | ) | 504.7 | |||||||||||
| Accumulated other comprehensive income | 0.1 | 0.1 | (0.1 | ) | 0.1 | |||||||||||
| Total common shareholder's equity | 1,190.3 | 1,274.7 | (1,190.3 | ) | 1,274.7 | |||||||||||
| TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 3,694.9 | $ | 2,311.3 | $ | (2,183.1 | ) | $ | 3,823.1 | |||||||
Consolidating Balance Sheet as of December 31, 2008 (in millions):
ASSETS | Subsidiary | Parent | ||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| Current Assets | ||||||||||||||||
| Cash & cash equivalents | $ | 9.7 | $ | 42.8 | $ | - | $ | 52.5 | ||||||||
| Accounts receivable - less reserves | 163.5 | 0.5 | - | 164.0 | ||||||||||||
| Intercompany receivables | 104.2 | 275.9 | (380.1 | ) | - | |||||||||||
| Receivables due from other Vectren companies | 4.5 | 0.2 | - | 4.7 | ||||||||||||
| Accrued unbilled revenues | 167.2 | - | - | 167.2 | ||||||||||||
| Inventories | 78.7 | 5.9 | - | 84.6 | ||||||||||||
| Recoverable fuel & natural gas costs | 3.1 | - | - | 3.1 | ||||||||||||
| Prepayments & other current assets | 82.9 | 38.5 | (18.3 | ) | 103.1 | |||||||||||
| Total current assets | 613.8 | 363.8 | (398.4 | ) | 579.2 | |||||||||||
| Utility Plant | ||||||||||||||||
| Original cost | 4,335.3 | - | - | 4,335.3 | ||||||||||||
| Less: accumulated depreciation & amortization | 1,615.0 | - | - | 1,615.0 | ||||||||||||
| Net utility plant | 2,720.3 | - | - | 2,720.3 | ||||||||||||
| Investments in consolidated subsidiaries | - | 1,167.4 | (1,167.4 | ) | - | |||||||||||
| Notes receivable from consolidated subsidiaries | - | 698.9 | (698.9 | ) | - | |||||||||||
| Investments in unconsolidated affiliates | 0.2 | - | - | 0.2 | ||||||||||||
| Other investments | 18.5 | 5.6 | - | 24.1 | ||||||||||||
| Nonutility property - net | 4.3 | 178.1 | - | 182.4 | ||||||||||||
| Goodwill - net | 205.0 | - | - | 205.0 | ||||||||||||
| Regulatory assets | 90.5 | 25.2 | - | 115.7 | ||||||||||||
| Other assets | 14.2 | 0.2 | (3.2 | ) | 11.2 | |||||||||||
| TOTAL ASSETS | $ | 3,666.8 | $ | 2,439.2 | $ | (2,267.9 | ) | $ | 3,838.1 | |||||||
| LIABILITIES & SHAREHOLDER'S EQUITY | Subsidiary | Parent | ||||||||||||||
| Guarantors | Company | Eliminations | Consolidated | |||||||||||||
| Current Liabilities | ||||||||||||||||
| Accounts payable | $ | 205.5 | $ | 7.0 | $ | - | $ | 212.5 | ||||||||
| Accounts payable to affiliated companies | 72.8 | - | - | 72.8 | ||||||||||||
| Intercompany payables | 9.5 | 0.4 | (9.9 | ) | - | |||||||||||
| Payables to other Vectren companies | 53.6 | 15.4 | - | 69.0 | ||||||||||||
| Refundable fuel & natural gas costs | 4.1 | - | - | 4.1 | ||||||||||||
| Accrued liabilities | 146.4 | 19.6 | (18.3 | ) | 147.7 | |||||||||||
| Short-term borrowings | 0.4 | 191.5 | - | 191.9 | ||||||||||||
| Intercompany short-term borrowings | 266.3 | 103.9 | (370.2 | ) | - | |||||||||||
| Long-term debt subject to tender | 80.0 | - | - | 80.0 | ||||||||||||
| Total current liabilities | 838.6 | 337.8 | (398.4 | ) | 778.0 | |||||||||||
| Long-Term Debt | ||||||||||||||||
| Long-term debt - net of current maturities & | ||||||||||||||||
| debt subject to tender | 243.1 | 822.0 | - | 1,065.1 | ||||||||||||
| Long-term debt due to VUHI | 698.9 | - | (698.9 | ) | - | |||||||||||
| Total long-term debt - net | 942.0 | 822.0 | (698.9 | ) | 1,065.1 | |||||||||||
| Deferred Income Taxes & Other Liabilities | ||||||||||||||||
| Deferred income taxes | 308.9 | 23.2 | - | 332.1 | ||||||||||||
| Regulatory liabilities | 310.4 | 4.7 | - | 315.1 | ||||||||||||
| Deferred credits & other liabilities | 99.5 | 8.6 | (3.2 | ) | 104.9 | |||||||||||
| Total deferred credits & other liabilities | 718.8 | 36.5 | (3.2 | ) | 752.1 | |||||||||||
| Common Shareholder's Equity | ||||||||||||||||
| Common stock (no par value) | 776.3 | 763.0 | (776.3 | ) | 763.0 | |||||||||||
| Retained earnings | 391.0 | 479.8 | (391.0 | ) | 479.8 | |||||||||||
| Accumulated other comprehensive income | 0.1 | 0.1 | (0.1 | ) | 0.1 | |||||||||||
| Total common shareholder's equity | 1,167.4 | 1,242.9 | (1,167.4 | ) | 1,242.9 | |||||||||||
| TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 3,666.8 | $ | 2,439.2 | $ | (2,267.9 | ) | $ | 3,838.1 | |||||||
| 18. | 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 2009 and 2008 follows:
| (In millions) | Q1 | Q2 | Q3 | Q4 | ||||||||||||
| 2009 | ||||||||||||||||
| Results of Operations: | ||||||||||||||||
| Operating revenues | $ | 652.8 | $ | 272.2 | $ | 236.8 | $ | 434.4 | ||||||||
| Operating income | 105.2 | 27.6 | 32.1 | 73.1 | ||||||||||||
| Net income | 56.2 | 6.6 | 8.7 | 35.9 | ||||||||||||
| 2008 | ||||||||||||||||
| Results of Operations: | ||||||||||||||||
| Operating revenues | $ | 761.4 | $ | 352.7 | $ | 292.4 | $ | 552.2 | ||||||||
| Operating income | 112.5 | 31.1 | 41.0 | 70.0 | ||||||||||||
| Net income | 58.0 | 8.8 | 13.6 | 30.7 | ||||||||||||
ITEM 9. CHANGE IN & DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING & FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS & PROCEDURES
Changes in Internal Controls over Financial Reporting
During the quarter ended December 31, 2009, 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, 2009, 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, 2009, 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, 2009.
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. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS & 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 Corporate Code of Conduct that covers the Company’s directors, officers and employees are available in the Corporate Governance section of the Company’s website, www.vectren.com. The Corporate Code of Conduct (titled “Corp Code of Conduct”) contains specific codes of ethics pertaining to the CEO and senior financial officers and the Board of Directors in Exhibits D and E, respectively. A copy will be mailed upon request to Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708. The Company intends to disclose any amendments to the Corporate Code of Conduct or waivers of the Corporate Code of Conduct on behalf of the Company’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions on the Company’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. EXECUTIVE COMPENSATION
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS & MANAGEMENT & RELATED
STOCKHOLDER MATTERS
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
ITEM 13. CERTAIN RELATIONSHIPS & RELATED TRANSACTIONS & DIRECTOR INDEPENDENCE
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
ITEM 14. PRINCIPAL ACCOUNTANT FEES & 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, 2009 and 2008. The fees presented below represent total Vectren fees, the majority of which are allocated to Utility Holdings.
| 2009 | 2008 | |||||||
Audit Fees(1) | $ | 1,374,906 | $ | 1,378,911 | ||||
Audit-Related Fees(2) | 283,413 | 235,449 | ||||||
Tax Fees(3) | 122,145 | 162,073 | ||||||
Total Fees Paid to Deloitte(4) | $ | 1,780,464 | $ | 1,776,433 | ||||
| (1) | Aggregate fees incurred and payable to Deloitte for professional services rendered for the audits of Vectren’s and Utility Holdings’ 2009 and 2008 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 2009 and 2008 fiscal years. The amount includes fees related to the attestation to the Company’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 $104,406 and $69,911 in 2009 and 2008, 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 audits of two of the Company’s consolidated subsidiaries. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $15,013 and $5,949 in 2009 and 2008, respectively. |
| (3) | Tax fees consisted of fees paid to Deloitte for the review of tax returns and consultation on other tax matters of the Company and of its consolidated subsidiaries. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $13,205 and $17,548 in 2009 and 2008, respectively. |
| (4) | Pursuant to its charter, the Audit Committee 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 the Company, 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 in accordance with this policy. |
PART IV
ITEM 15. EXHIBITS & 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, 2009, 2008, and 2007, 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
| Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
| Additions | ||||||||||||||||||||
| Balance at | Charged | Charged | Deductions | Balance at | ||||||||||||||||
| Beginning | to | to Other | from | End of | ||||||||||||||||
| Description | Of Year | Expenses | Accounts | Reserves, Net | Year | |||||||||||||||
| (In millions) | ||||||||||||||||||||
| VALUATION AND QUALIFYING ACCOUNTS: | ||||||||||||||||||||
| Year 2009 – Accumulated provision for | ||||||||||||||||||||
| uncollectible accounts | $ | 4.5 | $ | 14.6 | $ | - | $ | 15.1 | $ | 4.0 | ||||||||||
| Year 2008 – Accumulated provision for | ||||||||||||||||||||
| uncollectible accounts | $ | 2.7 | $ | 15.8 | $ | - | $ | 14.0 | $ | 4.5 | ||||||||||
| Year 2007 – Accumulated provision for | ||||||||||||||||||||
| uncollectible accounts | $ | 2.5 | $ | 15.0 | $ | - | $ | 14.8 | $ | 2.7 | ||||||||||
| OTHER RESERVES: | ||||||||||||||||||||
| Year 2009 – Restructuring costs | $ | 0.6 | $ | - | $ | - | $ | 0.1 | $ | 0.5 | ||||||||||
| Year 2008 – Restructuring costs | $ | 0.6 | $ | - | $ | - | $ | - | $ | 0.6 | ||||||||||
| Year 2007 – Restructuring costs | $ | 1.7 | $ | - | $ | - | $ | 1.1 | $ | 0.6 | ||||||||||
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. |
| 32 | 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 |
| 12 | 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. as most recently amended and restated as of June 24, 2009 (Filed and designated in Current Report on Form 8-K filed June 26, 2009, File No. 1-15467, as Exhibit 3.1.) |
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) August 1, 2009 (Filed and designated in Form 10-K for the year ended December 31, 2009, File No 1-15467, as Exhibit 4.1) |
| 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) |
| 4.4 | Note Purchase Agreement, dated April 7, 2009, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. and the purchasers named therein. (Filed and designated in Form 8-K dated April 7, 2009 File No. 1-15467, as Exhibit 4.5) |
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 unit award agreement for officers, effective January 1, 2010. (Filed and designated in Form 8-K, dated January 7, 2010, File No. 1-15467, as Exhibit 10.1.) |
| 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 At Risk Compensation Plan stock unit award agreement for non-employee directors, effective May 1, 2009. (Filed and designation in Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit 10.1) |
| 10.16 | 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. |
| 10.17 | 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 | Amendment to F.B. Culley and A.B. Brown Coal Supply Agreements dated December 21, 2009. (Filed and designated in Form 10-K, for the year ended December 31, 2009, File No. 1-15467, as exhibit 10.1) |
| 10.22 | 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.) |
| 10.23 | 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.) |
| 10.24 | 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.) |
| 10.25 | 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-Q, for the period ended September 30, 2009, File No. 1-15467, as Exhibit 10.24.) |
| 10.26 | Niel C. Ellerbrook Retirement Agreement, dated February 3, 2010. (Filed and designated in Form 8-K dated February 4, 2010 File No. 1-15467, as Exhibit 99.2) |
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 2002
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 2002
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 March 3, 2010. (Filed and designated in Current Report on Form 8-K filed March 4, 2010, File No. 1-15467, as Exhibit 3.1.)
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 5, 2010 /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 5, 2010 | ||
Niel C. Ellerbrook | (Principal Executive Officer) | |||
/s/ Jerome A. Benkert, Jr. | Executive Vice President and Chief Financial Officer | March 5, 2010 | ||
Jerome A. Benkert, Jr. | (Principal Financial Officer) | |||
/s/ M. Susan Hardwick | Vice President, Controller and Assistant Treasurer | March 5, 2010 | ||
M. Susan Hardwick | (Principal Accounting Officer) | |||
/s/ Ronald E. Christian | Director | March 5, 2010 | ||
Ronald E. Christian | ||||
/s/ William S. Doty | Director | March 5, 2010 | ||
William S. Doty | -82- |