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, 2005
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: 1-15467
(Exact name of registrant as specified in its charter)
INDIANA | | 35-2086905 |
| (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 |
Common - Without Par | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: 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□
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d0 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 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. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ý Accelerated filer □ Non-accelerated filer □
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes □ No ý
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, 2005, was $2,168,706,373.
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 | 76,186,504 | January 31, 2006 |
| Class | Number of Shares | Date |
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year, is incorporated by reference in Part III of this Form 10-K.
Definitions
AFUDC: allowance for funds used during construction | MMBTU: millions of British thermal units |
APB: Accounting Principles Board | MW: megawatts |
EITF: Emerging Issues Task Force | MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours) |
FASB: Financial Accounting Standards Board | NOx: nitrogen oxide |
FERC: Federal Energy Regulatory Commission | OUCC: Indiana Office of the Utility Consumer Counselor |
IDEM: Indiana Department of Environmental Management | PUCO: Public Utilities Commission of Ohio |
IURC: Indiana Utility Regulatory Commission | SFAS: Statement of Financial Accounting Standards |
MCF / BCF: thousands / billions of cubic feet | USEPA: United States Environmental Protection Agency |
MDth / MMDth: thousands / millions of dekatherms | Throughput: combined gas sales and gas transportation volumes |
| Item | | | Page |
| Number | | Number |
| Part I |
| | | | | | |
| | | | | | 4 |
| | | | | | 10 |
| | | | | | 14 |
| | | | | | 15 |
| | | | | | 16 |
| | | | | | 16 |
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| Part II |
| | | | | | |
| | | | | | 16 |
| | | | | | 18 |
| | | | | | 19 |
| | | | | | 45 |
| | | | | | 47 |
| | | | | | 90 |
| | | | | | 90 |
| | | | | | 90 |
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| Part III |
| | | | | | |
| | | | | | 90 |
| | | | | | 91 |
| | | | | | 91 |
| | | | | | 92 |
| | | | | | 92 |
| | | | | | |
| Part IV |
| | | | | | |
| | | | | | 92 |
| | | | | | 97 |
| | | | | | |
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports free of charge through its website at www.vectren.com, 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 |
| | | | | |
PART I
Description of the Business
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company organized on June 10, 1999, to effect the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, Indiana Energy merged with SIGCORP and into Vectren. The transaction involved a tax-free exchange of shares that was accounted for as a pooling-of-interests.
The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations. Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006, by the Energy Policy Act of 2005 (Energy Act). Both Vectren and Utility Holdings are holding companies as defined by the Energy Act.
Indiana Gas provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 140,000 electric customers and approximately 112,000 natural gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana.
The Ohio operations provide energy delivery services to approximately 318,000 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, (53% ownership) and Indiana Gas (47% ownership). The Ohio operations were acquired from The Dayton Power and Light Company on October 31, 2000. The Ohio operations generally do business as Vectren Energy Delivery of Ohio.
The Company, through Vectren Enterprises, Inc. (Enterprises), is also involved in nonregulated activities in three primary business areas: Energy Marketing and Services, Coal Mining and Utility Infrastructure Services. Energy Marketing and Services markets and supplies natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal and generates IRS Code Section 29 tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. In addition, there are other businesses that invest in broadband communication services, energy-related opportunities and services, real estate, and leveraged leases, among other investments. These operations are collectively referred to as the Nonregulated Group. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, utility infrastructure services, and other services.
Indiana Energy, incorporated under Indiana law on October 24, 1985, was engaged in natural gas distribution, gas portfolio administration services, and marketing of natural gas, electric power and related services. Prior to the merger, Indiana Energy had fourteen subsidiaries, including ten nonregulated direct or indirect subsidiaries, a not-for-profit foundation and three utility subsidiaries, as well as investments in four nonregulated joint ventures. SIGCORP, incorporated under Indiana law on October 19, 1994, was engaged in electric generation, transmission, and distribution, natural gas distribution, coal mining, and broadband communication services. Prior to the merger, SIGCORP had eleven wholly owned subsidiaries, including ten nonregulated subsidiaries.
Narrative Description of the Business
The Company segregates its operations into three groups: a Utility Group, a Nonregulated Group, and Corporate and Other. At December 31, 2005, the Company had $3.9 billion in total assets, with $3.4 billion (86%) attributed to the Utility Group, $0.5 billion (14%) attributed to the Nonregulated Group, and less than $0.1 billion attributed to Corporate and Other. Net income for the year ended December 31, 2005, was $136.8 million, or $1.81 per share of common stock, with $95.1 million attributed to the Utility Group, $48.2 million attributed to the Nonregulated Group, and a net loss of $6.5 million attributed to Corporate and Other. Net income for the year ended December 31, 2004, was $107.9 million, or $1.43 per share of common stock. For further information regarding the activities and assets of operating segments within these Groups, refer to Note 15 in the Company’s consolidated financial statements included under “Item 8 Financial Statements and Supplementary Data.”
Following is a more detailed description of the Utility Group and Nonregulated Group. Corporate and Other operations are not significant.
Utility Group
The Utility Group is comprised of Utility Holdings’ operations. The operations of the Utility Group consist of the Company’s 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 includes the Company’s power generating and marketing operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers. The Utility Group’s other operations are generally not significant.
Gas Utility Services
At December 31, 2005, the Company supplied natural gas service to approximately 992,000 Indiana and Ohio customers, including 906,000 residential, 84,000 commercial, and 2,000 industrial and other contract customers. This represents customer base growth of 1.3% compared to 2004.
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, and coal mining. The largest Indiana communities served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington, Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, Richmond, and suburban areas surrounding Indianapolis. The largest community served outside of Indiana is Dayton, Ohio.
Revenues
For the year ended December 31, 2005, gas utility revenues were approximately $1,359.7 million, of which residential customers accounted for 66%, commercial 28%, and industrial and other contract customers 6%, respectively.
The Company receives gas revenues by selling gas directly to customers at approved rates or by transporting gas through its pipelines at approved rates to customers that have purchased gas directly from other producers, brokers, or marketers. Total volumes of gas provided to both sales and transportation customers (throughput) were 200.1 MMDth for the year ended December 31, 2005. Gas transported or sold to residential and commercial customers was 112.9 MMDth representing 56% of throughput. Gas transported or sold to industrial and other contract customers was 87.2 MMDth representing 44% of throughput. Rates for transporting gas provide for the same margins generally earned by selling gas under applicable sales tariffs.
The sale of gas is seasonal and strongly affected by variations in weather conditions. To mitigate seasonal demand, the Company has storage capacity at seven active underground gas storage fields, six liquefied petroleum air-gas manufacturing plants, and a propane cavern. The Company also contracts with its affiliate, ProLiance Energy, LLC (ProLiance), and with other third party gas service providers to ensure availability of gas. ProLiance is an unconsolidated, nonregulated, energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas). (See the discussion of Energy Marketing & Services below and Note 3 in the Company’s consolidated financial statements included in “Item 8 Financial Statements and Supplementary Data” regarding transactions with ProLiance). 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. In lieu of storage, the Company prepays ProLiance for natural gas delivery services during the seven months prior to the peak heating season. The volumes of gas per day that can be delivered during peak demand periods for each utility is located in “Item 2 Properties.”
Gas Purchases
In 2005, the Company purchased 106,449 MDth volumes of gas at an average cost of $9.05 per Dth, of which approximately 95% was purchased from ProLiance and 5% was purchased from other third party providers. As required by a June 2005, PUCO order, VEDO solicited bids for its gas supply/portfolio administration services and selected a third party provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. Prior to October 31, 2005, ProLiance supplied natural gas to all of the Company’s regulated gas utilities.
As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreements with Indiana Gas and SIGECO, were approved and extended through March 31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer representatives, including the OUCC, filed a settlement agreement with the IURC providing for ProLiance to be the continued supplier of gas supply services to the Company’s Indiana utilities through March 2011. The settlement is subject to approval by the IURC. The average cost of gas per Dth purchased for the last five years was: $9.05 in 2005; $6.92 in 2004; $6.36 in 2003; $4.57 in 2002; and $5.83 in 2001.
Electric Utility Services
At December 31, 2005, the Company supplied electric service to approximately 140,000 Indiana customers, including 121,000 residential, 19,000 commercial, and 150 industrial and other customers. This represents customer base growth of 0.6% compared to 2004. In addition, the Company has firm power commitments to four municipalities and has contingency reserve requirements consistent with Reliability First Corp. standards.
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, and coal mining.
Revenues
For the year ended December 31, 2005, retail and firm wholesale electricity sales totaled 6,199.0 GWh, resulting in revenues of approximately $383.4 million. Residential customers accounted for 35% of 2005 revenues; commercial 25%; industrial 31%; and municipal and other 9%. In addition, the Company sold 3,049.2 GWh through wholesale contracts in 2005, generating revenue, net of purchased power costs, of $38.0 million.
Generating Capacity
Installed generating capacity as of December 31, 2005, was rated at 1,351 MW. Coal-fired generating units provide 1,056 MW of capacity, and natural gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW.
In addition to its generating capacity, in 2005, the Company had 34 MW available under firm contracts and 61 MW available under interruptible contracts. The Company also had a firm purchase supply contract for a maximum of 73 MW for the peak cooling season months during 2005.
The Company has interconnections with Louisville Gas and Electric Company, Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of Jasper, Indiana, providing the historic ability to simultaneously interchange approximately 500 MW. Vectren also had an interconnection agreement with Wabash Valley Power Association, which was cancelled effective August 31, 2005. However, the ability of the Company to effectively utilize the electric transmission grid in order to achieve import/export capability has been, and may continue to be, impacted. The Company, as a member of the Midwest Independent System Operator (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.
Total load for each of the years 2001 through 2005 at the time of the system summer peak, and the related reserve margin, is presented below in MW.
| | | | | | | | | | | |
| Date of summer peak load | | 7/25/2005 | | 7/13/2004 | | 8/27/2003 | | 8/5/2002 | | 7/31/2001 |
Total load at peak (1) | | 1,315 | | 1,222 | | 1,272 | | 1,258 | | 1,234 |
| | | | | | | | | | | |
| Generating capability | | 1,351 | | 1,351 | | 1,351 | | 1,351 | | 1,271 |
| Firm purchase supply | | 107 | | 105 | | 32 | | 82 | | 82 |
| Interruptible contracts | | 76 | | 51 | | 95 | | 95 | | 95 |
| Total power supply capacity | | 1,534 | | 1,507 | | 1,478 | | 1,528 | | 1,448 |
| | | | | | | | | | | |
| Reserve margin at peak | | 17% | | 23% | | 16% | | 21% | | 17% |
| | | | | | | | | | | |
| (1) | The total load at peak is increased 25 MW in 2005, 2003, 2002, and 2001 from the total load actually experienced. The additional 25 MW represents load that would have been incurred if summer cycler programs 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 2004, summer cycler programs were not activated. |
The winter peak load for the 2004-2005 season of approximately 932 MW occurred on January 18, 2005. The prior year winter peak load was approximately 928 MW, occurring on January 20, 2004.
The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation (OVEC). The OVEC is comprised of several electric utility companies, including SIGECO, and supplies power requirements to the United States Department of Energy’s (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating companies are entitled to receive from OVEC, and are obligated to pay for, any available power in excess of the DOE contract demand. At the present time, the DOE contract demand is essentially zero. Because of this decreased demand, the Company’s 1.5% interest in the OVEC makes available approximately 34 MW of capacity, in addition to its generating capacity, for use in other operations. Such generating capacity is included in firm purchase supply in the chart above.
Fuel Costs and Purchased Power
Electric generation for 2005 was fueled by coal (98.3%) and natural gas (1.7%). Oil was used only for testing of gas/oil-fired peaking units.
There are substantial coal reserves in the southern Indiana area, and coal for coal-fired generating stations has been supplied from operators of nearby Indiana coal mines, including those owned by Vectren Fuels, Inc., a wholly owned subsidiary of the Company. Approximately 3.6 million tons of coal were purchased for generating electricity during 2005, of which substantially all was supplied by Vectren Fuels, Inc. from its mines and third party purchases.
The average cost of coal consumed in generating electric energy for the years 2001 through 2005 follows:
| | | | | | | | | | | |
| | | Year Ended December 31, |
| Avg. Cost Per | | 2005 | | 2004 | | 2003 | | 2002 | | 2001 |
Ton | | $ 30.27 | | $ 27.06 | | $ 24.91 | | $ 23.50 | | $ 22.48 |
MWh | | 14.94 | | 13.06 | | 11.93 | | 11.00 | | 10.53 |
The Company also purchases power as needed from the wholesale market to supplement its generation capabilities in periods of peak demand; however, the majority of power purchased through the wholesale market is used to optimize and hedge the Company’s sales to other wholesale customers. Volumes purchased in 2005 totaled 2,253,502 MWh.
Competition
The utility industry has undergone dramatic structural change for several years, resulting in increasing competitive pressures faced by electric and gas utility companies. Currently, several states, including Ohio, have passed legislation allowing electricity customers to choose their electricity supplier in a competitive electricity market and several other states are considering 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, 2005, approximately 71,000 customers in Vectren’s Ohio service territory purchase natural gas from a supplier other than the regulated utility. Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs. Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting 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 regulated environment and other environmental matters.
Nonregulated Group
The Company is involved in nonregulated activities in three primary business areas: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services.
Energy Marketing and Services
The Energy Marketing and Services group relies heavily upon a customer focused, value added strategy in three areas: gas marketing, performance contracting, and retail gas supply.
Proliance
ProLiance is a nonregulated energy marketing affiliate of Vectren and Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. ProLiance provides these services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s primary customers include Vectren’s utilities and nonregulated gas supply operations as well as Citizens Gas. The Company, including its retail gas supply operations, contracted for 95% of its natural gas purchases through ProLiance in 2005.
In 2002, the Company integrated a wholly owned subsidiary, SIGCORP Energy Services, LLC (SES), with ProLiance. SES provided natural gas and related services to SIGECO and others prior to the transaction. In exchange for the contribution of SES’ net assets totaling $19.2 million, Vectren’s allocable share of ProLiance’s profits and losses increased from 52.5% to 61%, consistent with Vectren’s current ownership percentage. In March 2001, Vectren’s allocable share of profits and losses increased from 50% to 52.5% when ProLiance began managing the Ohio operations’ gas portfolio. Governance and voting rights remain at 50% for each member; and therefore, Vectren continues to account for its investment in ProLiance using the equity method of accounting.
For the year ended December 31, 2005, ProLiance’s revenues, including sales to Vectren companies, exceeded $3.2 billion.
At December 31, 2005, the pre-tax earnings of ProLiance exceeded 20% of Vectren’s pre-tax earnings and, as a result, ProLiance is a “significant subsidiary” within the meaning of Regulation S-X, paragraph 3-09. As such, ProLiance’s audited financial statements as of and for its fiscal years ending September 30, 2005 and 2004, as well as unaudited information for the fiscal year ended September 30, 2003, are included in this Form 10-K.
Energy Systems Group
Performance-based energy contracting operations are performed through Energy Systems Group, LLC (ESG). ESG assists schools, hospitals, governmental facilities, and other private institutions to reduce energy and maintenance costs by upgrading their facilities with energy-efficient equipment. ESG’s customer base is located throughout the Midwest and Southeast United States. Prior to April 2003, ESG was a consolidated venture between the Company and Citizens Gas with the Company owning two-thirds. In April 2003, the Company purchased the remaining interest in ESG.
Vectren Source
Vectren Retail, LLC (d/b/a Vectren Source) provides natural gas and other related products and services in the Midwest and Southeast United States to nearly 130,000 residential and commercial customers opting for choice among energy providers. Vectren Source generated approximately $129.2 million in revenues in 2005, up from $81.1 million in 2004. Gas sold in 2005 approximated 12,411 MDth, up from 9,386 MDth in 2004.
Coal Mining
The Coal Mining group mines and sells coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. The Company’s two coal mines produced 4.4 million tons in 2005, up from 3.6 million tons in 2004. The Coal Mining group also generates IRS Code Section 29 tax credits relating to the production of coal-based synthetic fuels through its 8.3% ownership in Pace Carbon Synfuels, LP (Pace Carbon). Pace Carbon developed, owns, and operates four projects to produce and sell coal-based synthetic fuel (synfuel) utilizing Covol technology. Vectren accounts for its investment in Pace Carbon using the equity method. In addition, Fuels receives synfuel-related fees from a synfuel producer unrelated to Pace Carbon for a portion of its coal production.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair of utility infrastructure services to the Company and to other gas, water, and telecommunications companies as well as facilities locating and meter reading services through its investment in Reliant Services, LLC (Reliant) and Reliant’s 100% ownership in Miller Pipeline, which was purchased by Reliant in 2000. Reliant is a 50% owned strategic alliance with an affiliate of Cinergy Corporation and is accounted for using the equity method of accounting.
Other Businesses
The Other Businesses group includes a variety of wholly owned operations and investments that invest in broadband communication services, energy-related opportunities and services, real estate, and leveraged leases, among other investments. Major investments at December 31, 2005, include Haddington Energy Partnerships, two partnerships both approximately 40% owned; the Company’s Utilicom-related investments; and the wholly owned subsidiaries, Southern Indiana Properties, Inc., Energy Realty, Inc.
The Company has an approximate 2% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom) that if converted would bring the Company’s ownership interest up to 16%. The Company also has an approximate 19% equity interest in SIGECOM Holdings, Inc., which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services, such as cable television, high-speed internet, and advanced local and long distance phone services, to the greater Evansville, Indiana area. At December 31, 2005, SIGECOM had approximately 27,000 residential customers yielding over 63,000 revenue generating units indicating multiple services, not including long distance service, being utilized by the same residential customer. At December 31, 2005, there were approximately 2,000 commercial customers. SIGECOM’s operations are cash flow positive and have not required any further investment since May 2002.
Other Utilicom-related subsidiaries owned franchising agreements to provide broadband services to the greater Indianapolis, Indiana and Dayton, Ohio markets. In 2004, the build out of these markets was further evaluated, and the Company concluded that it was unlikely it would make additional investments in those markets. As a result, the Company recorded charges totaling $6.0 million, or $3.6 million after-tax, to write-off investments made in the Indianapolis and Dayton markets and to write down its investment in SIGECOM.
At December 31, 2005, convertible subordinated debt investments total $33.1 million, all of which is convertible into Utilicom ownership at the Company’s option or upon the event of a public offering of stock by Utilicom. The remaining equity investment in SIGECOM, LLC approximates $11.7 million. The Company accounts for its investment in Utilicom and SIGECOM Holdings, Inc. using the cost method.
Personnel
As of December 31, 2005, the Company and its consolidated subsidiaries had 1,975 employees, of which 858 are subject to collective bargaining arrangements.
In November 2005, the Company reached a four year agreement with Local 175 of the Utility Workers Union of America, ending October 2009. The agreement includes annual wage increases of 3.5% and market adjustments to healthcare and pensions. The agreement also provides increased flexibility in job assignments and work rules.
In September 2005, the Company reached a four year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 2009. The agreement provides for annual wage increases of 3.4%, modifications to the pension and insurance plans, and increased flexibility in operations.
In July 2004, the Company reached a three year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 2007. The agreement provides a 3% wage increase in the first two years and a 3.5% increase in the third year of the agreement. The agreement also provides for improvements in pension benefits and a multi-tiered health plan in which the employees pay 16% of the cost.
In January 2004, the Company reached a five year labor agreement, ending December 2008, with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441. The agreement provides for annual wage increases of 3%, a multi-tiered health care plan in which the employees pay 12% to 16% of the premium, and pension enhancements for early retirees.
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.
Vectren Corporation is a holding company, and its assets consist primarily of investments in its subsidiaries.
Dividends on the Company's common stock depend on the earnings, financial condition, and capital requirements of it's subsidiaries, principally Vectren Utility Holdings, Inc. and Vectren Enterprises, Inc. and the distribution or other payment of earnings from those subsidiaries to the Company. Should the earnings, financial condition, or capital requirements of, or legal requirements applicable to, the Company’s subsidiaries restrict the ability of these subsidiaries to pay dividends or make other payments to Vectren, Vectren’s ability to pay dividends on its common stock could be limited, and its stock price adversely affected.
The Company operates in an increasingly competitive industry, which may affect its future earnings.
The utility industry has been undergoing dramatic 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. Indiana has not adopted any regulation requiring gas choice except for large-volume customers. The Company 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 the Company’s gas and electric utility sales are space heating and cooling. Accordingly, its operating results may fluctuate with variability of weather.
The Company’s gas and electric utility sales are sensitive to variations in weather conditions. Vectren forecasts utility sales on the basis of normal weather, which represents a long-term historical average. Since the Company does not have a weather-normalization mechanism for its electric operations or its Ohio natural gas operations, significant variations from normal weather could have a material impact on its earnings. However, the impact of weather on the gas operations in its Indiana territories has been significantly mitigated through the implementation on October 15, 2005, of a normal temperature adjustment mechanism.
The Company’s 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, and coal mining.
Risks related to the regulation of the Company’s businesses, including environmental regulation, could affect the rates charged, its costs and its profitability.
Vectren’s businesses are subject to regulation by federal, state and local regulatory authorities. In particular, the Company is subject to regulation by the Federal Energy Regulatory Commission (FERC), the IURC and the PUCO. These authorities regulate many aspects of its transmission and distribution operations, including construction and maintenance of facilities, operations, safety, and the rates that it can charge customers and the rate of return that it is allowed to realize. The Company’s ability to obtain rate increases to maintain its current authorized rate of return depends upon regulatory discretion, and there can be no assurance that Vectren will be able to obtain rate increases or rate supplements or earn its current authorized rate of return.
In addition, its operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities and obligations in connection with storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances in the environment. Such emissions from electric generating facilities include particulate matter, sulfur dioxide (SO2), and nitrogen oxide (NOx), 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. Vectren’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 the Company subject to environmental regulation, its investment in environmentally compliant equipment has increased and is expected to increase in the future.
From time to time, the Company is subject to material litigation and regulatory proceedings.
The Company may be subject to material litigation and regulatory proceedings from time to time. There can be no assurance that the outcome of these matters will not have a material adverse effect on its business, results of operations or financial condition.
The Company’s 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 purchased power 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 Company may experience significantly increased gas costs.
Recently, commodity prices for natural gas purchases have increased and have become more volatile. Subject to regulatory approval, the Company’s subsidiaries are allowed recovery of gas costs from their retail customers through commission-approved gas cost adjustment mechanisms. As a result, profit margins on gas sales are not expected to be impacted. Nevertheless, it is possible regulators may disallow recovery of a portion of gas costs for various reasons, including but limited to, a finding by the regulator that natural gas was not prudently procured, as an example. In addition, it is possible that as a result of this near term change in natural gas commodity prices, Vectren’s subsidiaries may experience increased interest expense due to higher working capital requirements, increased uncollectible accounts expense and unaccounted for gas and some level of price sensitive reduction in volumes sold or delivered.
The impact of MISO participation is uncertain.
Since February, 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities.
On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
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 uncertainties around Day 2 energy market operations, it is difficult to predict near term operational impacts. However, it is believed that MISO’s regional operation of the transmission system will ultimately lead to reliability improvements.
The potential need to expend capital for improvements to the transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant.
Wholesale power marketing activities may add volatility to earnings.
The Company’s regulated electric utility engages in wholesale power marketing activities that primarily involve asset optimization strategies. These optimization strategies manage the utilization of available electric generating capacity and include the execution of energy contracts that are integrated with portfolio requirements around power supply and delivery. As part of these strategies, the Company will execute forward contracts and option contracts that may not result in the physical flow of electricity, but hedge, other commitments. While most physical forward positions to sell electricity are hedged with these contracts or with planned unutilized generation capability, the Company does not hedge its entire portfolio from market price volatility. To the extent the Company has unhedged positions or its hedging procedures do not work as planned, fluctuating prices for electricity are likely to cause its net income to be volatile and may lower its net income. Beginning in April 2005, substantially all physically delivered off-system sales occur into the MISO day-ahead market.
If the Company does not accurately forecast future commodities prices or if its hedging procedures do not operate as planned in certain nonregulated businesses, the Company could experience losses or lower net income.
The Company’s gas marketing, coal mining, and nonregulated retail gas supply business execute forward and option contracts that commit it to purchase and sell natural gas and coal in the future, including forward contracts to purchase commodities to fulfill forecasted sales transactions that may or may not occur. If the value of these contracts changes in a direction or manner that Vectren does not anticipate, or if the forecasted sales transactions do not occur, the Company may experience losses.
To lower the financial exposure related to commodity price fluctuations, these nonregulated businesses may execute contracts that hedge commodity price risk. As part of this strategy, fixed-price forward physical purchase and sales contracts, and/or financial forwards, futures, swaps and option contracts traded in the over-the-counter markets or on exchanges may be utilized. However, although almost all natural gas and coal positions are hedged, with either these contracts or with company-owned coal inventory and known reserves, the Company does not hedge its entire exposure or its positions to market price volatility. To the extent the Company has unhedged positions, its hedging procedures do not work as planned, or coal reserves cannot be accessed, fluctuating commodity prices are likely to cause its net income to be volatile and may lower its net income.
The performance of the Company’s nonregulated businesses are also subject to certain risks.
Execution of the Company’s synfuel, coal mining, gas marketing, performance contracting, utility infrastructure, and broadband strategies and the success of its efforts to invest in and develop new opportunities in the nonregulated 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; storage field and mining property development; increased coal mining industry regulation; 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; and changing market conditions;.
The Company’s nonregulated businesses support its regulated utilities pursuant to service contracts by providing natural gas supply services, coal, utility infrastructure services, and other services. In most instances, the Company’s ability to maintain these service contracts depends upon regulatory discretion and negotiation with interveners, and there can be no assurance that Vectren will be able to obtain future service contracts, or that existing arrangements will not be revisited.
The Company’s coal mining operations may be adversely affected if Section 29 credits are limited or disallowed.
The Company’s coal mining operations are comprised of Vectren Fuels, which includes the Company’s coal mines, and Vectren Synfuels, which holds an investment in Pace Carbon. Pace Carbon produces and sells coal-based synthetic fuel, and based on current US tax law, receives a tax credit for every ton of coal-based synthetic fuel sold. However, the Permanent Subcommittee on Investigations of the U.S. Senate’s Committee on Governmental Affairs has an ongoing investigation relating to Section 29 tax credits.
Further, Section 29 tax credits are only available when the price of oil is less than a base price specified by the tax code, as adjusted for inflation. Credits realized in 2005 or in prior years are not affected by the limitation. However, an average NYMEX price of approximately $60 per barrel in 2006, could begin to limit Section 29 tax credits, with a total phase out occurring at approximately $74 per barrel. Oil prices currently exceed the threshold where Section 29 tax credits would begin to be phased out. While Congress is considering legislation that would positively impact or entirely negate this potential limitation on tax credits related to oil prices in 2006, there can be no assurance Section 29 tax credits will be available in future periods.
Absent the effect of Section 29 tax credits, the Company’s investment in Pace Carbon has operated, and is expected to continue to operate, at a net loss. Due to the potential limitation of Section 29 tax credits, Pace Carbon investors must assess at what level to operate the synfuel plants. If the investors continue to operate the plants, and tax credits are phased out, the Company could potentially incur additional losses. In addition, the Company would be required to assess the potential impairment of its investment in Pace Carbon. If a phase out of tax credits were to occur in 2006 approximately, one third of that phase out risk is proportionately protected by an insurance arrangement that was executed in January 2005.
Vectren’s nonregulated group competes with larger, full-service energy providers, which may limit its ability to grow its business.
Competitors for the Company’s nonregulated businesses include regional, national and global companies. Many of Vectren’s competitors are well-established and have larger and more developed networks and systems, greater name recognition, longer operating histories and significantly greater financial, technical and marketing resources. This competition, and the addition of any new competitors, could negatively impact the Company’s nonregulated group and its ability to grow its businesses.
Catastrophic events could adversely affect the Company’s facilities and operations.
Catastrophic events such as fires, explosions, floods, terrorist acts or other similar occurrences could adversely affect the Company’s facilities and operations.
A downgrade in the Company’s credit rating could negatively affect its ability to access capital.
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, Indiana Gas and SIGECO senior unsecured debt | Baa1 | A- |
| Utility Holdings commercial paper program | P-2 | A-2 |
The current outlook of both Moody’s and Standard and Poor’s is stable and are categorized 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.
The Company 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 withdraw its ratings, it may significantly limit the Company’s access to the debt capital markets and the commercial paper market, and the Company’s borrowing costs would increase. In addition, Vectren 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 will have access to the equity capital markets to obtain financing when necessary or desirable.
None.
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana covering 58,130 acres of land with an estimated ready delivery from storage capability of 5.6 BCF of gas with maximum peak day delivery capabilities of 145,000 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 for 17.8 BCF of storage with a maximum peak day delivery capability of 299,717 MMBTU per day. Indiana Gas’ gas delivery system includes 12,118 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 underground gas storage fields located in Indiana covering 6,070 acres of land with an estimated ready delivery from storage capability of 6.3 BCF of gas with maximum peak day delivery capabilities of 108,000 MCF per day. In addition to its company owned storage delivery capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak day delivery capability of 19,166 MMBTU per day. SIGECO's gas delivery system includes 3,079 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 and a cavern for propane storage, all of which are located in Ohio. The plants and cavern can store 7.8 million gallons of propane, and the plants can manufacture for delivery 52,187 MCF of manufactured gas per day. In addition to its propane delivery capabilities, the Ohio operations have contracted for 12.0 BCF of storage with a maximum peak day delivery capability of 246,080 MMBTU per day. The Ohio operations’ gas delivery system includes 5,300 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, 2005, was rated at 1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with two units of 500 MW of combined capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the Culley Station with three units of 406 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. Pursuant to the settlement between the Company, the Department of Justice, and the USEPA, the Company will shut down Culley Unit 1, with generating capacity of 50 MW, effective December 31, 2006.
SIGECO's transmission system consists of 832 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 28 substations with an installed capacity of 4,622.3 megavolt amperes (Mva). The electric distribution system includes 3,226 pole miles of lower voltage overhead lines and 305 trench miles of conduit containing 1,710 miles of underground distribution cable. The distribution system also includes 95 distribution substations with an installed capacity of 1,964.9 Mva and 52,211 distribution transformers with an installed capacity of 2,418.5 Mva.
SIGECO owns utility property outside of Indiana approximating eight 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.
Nonregulated Properties
Subsidiaries other than the utility operations have no significant properties other than the ownership and operation of coal mining property in Indiana. The assets of the coal mining operations comprise approximately 3% of total assets.
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.
The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position results of operations, or cash flows. See the notes to the consolidated financial statements regarding investments in unconsolidated affiliates, commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated financial statements are included in “Item 8 Financial Statements and Supplementary Data.”
No matters were submitted during the fourth quarter to a vote of security holders.
PART II
Market Data, Dividends Paid, and Holders of Record
The Company’s common stock trades on the New York Stock Exchange under the symbol ‘‘VVC.’’ For each quarter in 2005 and 2004, the high and low sales prices for the Company’s common stock as reported on the New York Stock Exchange and dividends paid are presented below.
| | | | | | | | |
| | | | Cash | | Common Stock Price Range |
| | | | Dividend | | High Low |
2005 | | | | | | | |
| | First Quarter | | $ 0.295 | | $ 27.95 | | $ 25.82 |
| | Second Quarter | | 0.295 | | 28.98 | | 26.01 |
| | Third Quarter | | 0.295 | | 29.46 | | 26.50 |
| | Fourth Quarter | | 0.305 | | 28.75 | | 25.00 |
2004 | | | | | | | |
| | First Quarter | | $ 0.285 | | $ 25.87 | | $ 24.11 |
| | Second Quarter | | 0.285 | | 25.54 | | 22.86 |
| | Third Quarter | | 0.285 | | 25.75 | | 24.08 |
| | Fourth Quarter | | 0.295 | | 27.09 | | 24.79 |
On January 25, 2006, the board of directors declared a dividend of $0.305 per share, payable on March 1, 2006, to common shareholders of record on February 15, 2006.
As of January 31, 2006, there were 11,590 shareholders of record of the Company’s common stock.
Quarterly Share Purchases
Periodically, the Company purchases shares from the open market to satisfy share requirements associated with the Company’s share-based compensation plans. However, no such open market purchases were made by the Company during the three months ended December 31, 2005.
Dividend Policy
Common stock dividends are payable at the discretion of the board of directors, out of legally available funds. The Company’s policy is to distribute approximately 55% to 65% of earnings over time. On an annual basis, this percentage has varied and will continue to vary due to short-term earnings volatility. The Company and its predecessors have increased its dividend for 46 consecutive years. While the Company is under no contractual obligation to do so, it intends to continue to pay dividends and increase its annual dividend consistent with historical practice. Nevertheless, should the Company’s financial condition, operating results, capital requirements, or other relevant factors change, future payments of dividends, and the amounts of these dividends, will be reassessed.
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.
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, except per share data) | | 2005 | | 2004 | | 2003 | | 2002 | | 2001 (1) | |
Operating Data: | | | | | | | | | | | |
| Operating revenues | | $ | 2,028.0 | | $ | 1,689.8 | | $ | 1,587.7 | | $ | 1,523.8 | | $ | 2,009.1 | |
| Operating income | | $ | 213.1 | | $ | 199.5 | | $ | 196.0 | | $ | 211.3 | | $ | 127.9 | |
| Income before extraordinary loss & | | | | | | | | | | | | | | | | |
| cumulative effect of change in | | | | | | | | | | | | | | | | |
| accounting principle | | $ | 136.8 | | $ | 107.9 | | $ | 111.2 | | $ | 114.0 | | $ | 59.3 | |
| Net income | | $ | 136.8 | | $ | 107.9 | | $ | 111.2 | | $ | 114.0 | | $ | 52.7 | |
| Average common shares outstanding | | | 75.6 | | | 75.6 | | | 70.6 | | | 67.6 | | | 66.7 | |
| Fully diluted common shares outstanding | | | 76.1 | | | 75.9 | | | 70.8 | | | 67.9 | | | 66.9 | |
| Basic earnings per share before | | | | | | | | | | | | | | | | |
| extraordinary loss & cumulative | | | | | | | | | | | | | | | | |
| effect of change in accounting principle | | $ | 1.81 | | $ | 1.43 | | $ | 1.58 | | $ | 1.69 | | $ | 0.89 | |
| Basic earnings per share | | | | | | | | | | | | | | | | |
| on common stock | | $ | 1.81 | | $ | 1.43 | | $ | 1.58 | | $ | 1.69 | | $ | 0.79 | |
| Diluted earnings per share before | | | | | | | | | | | | | | | | |
| extraordinary loss & cumulative | | | | | | | | | | | | | | | | |
| effect of change in accounting principle | | $ | 1.80 | | $ | 1.42 | | $ | 1.57 | | $ | 1.68 | | $ | 0.89 | |
| Diluted earnings per share | | | | | | | | | | | | | | | | |
| on common stock | | $ | 1.80 | | $ | 1.42 | | $ | 1.57 | | $ | 1.68 | | $ | 0.79 | |
| Dividends per share on common stock | | $ | 1.19 | | $ | 1.15 | | $ | 1.11 | | $ | 1.07 | | $ | 1.03 | |
| | | | | | | | | | | | | | | | | |
Balance Sheet Data: | | | | | | | | | | | | | | | | |
| Total assets | | $ | 3,868.1 | | $ | 3,586.9 | | $ | 3,353.4 | | $ | 3,136.5 | | $ | 2,878.7 | |
| Long-term debt, net | | $ | 1,198.0 | | $ | 1,016.6 | | $ | 1,072.8 | | $ | 954.2 | | $ | 1,014.0 | |
| Redeemable preferred stock | | $ | - | | $ | 0.1 | | $ | 0.2 | | $ | 0.3 | | $ | 0.5 | |
| Common shareholders' equity | | $ | 1,143.3 | | $ | 1,094.8 | | $ | 1,071.7 | | $ | 869.9 | | $ | 839.3 | |
| | | | | | | | | | | | | | | | | |
| (1) | Merger and integration related costs associated with the merger of Indiana Energy and SIGCORP were $2.8 million for the year ended December 31, 2001. These costs relate primarily to transaction costs, severance and other merger and acquisition and integration activities. As a result of merger integration activities, management retired certain information systems in 2001. Accordingly, the useful lives of these assets were shortened to reflect this decision, resulting in additional depreciation expense of approximately $9.6 million for the year ended December 31, 2001. In total, merger and integration related costs incurred for the year ended December 31, 2001, were $12.4 million ($8.0 million after tax). |
In addition, the Company incurred restructuring charges of $19.0 million, ($11.8 million after tax) relating to employee severance, related benefits and other employee related costs, lease termination fees related to duplicate facilities, and consulting and other fees during the year ended December 31, 2001.
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
| | | Year Ended December 31, |
(In millions, except per share data) | | 2005 | | 2004 | | 2003 | |
| | | | | | | | |
| Net income | | $ | 136.8 | | $ | 107.9 | | $ | 111.2 | |
| Attributed to: | | | | | | | | | | |
| Utility Group | | $ | 95.1 | | $ | 83.1 | | $ | 85.6 | |
| Nonregulated Group | | | 48.2 | | | 26.4 | | | 27.6 | |
| Corporate & other | | | (6.5 | ) | | (1.6 | ) | | (2.0 | ) |
| | | | | | | | | | | |
| Basic earnings per share | | $ | 1.81 | | $ | 1.43 | | $ | 1.58 | |
| Attributed to: | | | | | | | | | | |
| Utility Group | | $ | 1.26 | | $ | 1.10 | | $ | 1.21 | |
| Nonregulated Group | | | 0.64 | | | 0.35 | | | 0.39 | |
| Corporate & other | | | (0.09 | ) | | (0.02 | ) | | (0.02 | ) |
Results
For the year ended December 31, 2005, reported earnings were $136.8 million, or $1.81 per share compared to $107.9 million, or $1.43 per share, in 2004 and $111.2 million, or $1.58 per share, in 2003. Of the $0.38 per share growth over 2004 results, the Utility Group contributed $0.16 per share, and the Nonregulated Group contributed $0.29 per share. The Corporate and Other Group results of $0.09 loss per share in 2005 reflects an additional contribution to the Vectren Foundation of $6.5 million, or $4.2 million after tax, to sustain its giving program over the next several years. The contribution is included in Other operating expenses in the Consolidated Statements of Income.
Utility Group results reflect the impact of a regulatory strategy that includes gas utility base rate increases, the recovery of pollution control investments, and a normal temperature adjustment mechanism implemented in its Indiana gas territories in October 2005, among other initiatives. Gas utility base rate increases added revenues of approximately $33.8 million, or $20.1 million after tax, in 2005 compared to 2004 and $4.7 million, or $2.8 million after tax, in 2004 compared to 2003. Increased revenues associated with recovery of pollution control investments, net of related operating and depreciation expenses, increased operating income $8.7 million, or $5.2 million after tax, in 2005 compared to 2004 and $6.0 million, or $3.6 million after tax, in 2004 compared to 2003. Results for the year ended December 31 2005, also reflect increased margins from generation asset optimization activities. In addition to higher operating costs, depreciation expense, and unfavorable weather, Utility Group results were impacted by a $4.2 million ($2.5 million after tax) charge recorded pursuant to the disallowance of Ohio gas costs in 2005. In 2003, $1.1 million ($0.7 million after tax) was recorded related to this matter.
Management estimates that the after tax impact of weather on the electric and gas utility businesses, including the effects of the recently implemented normal temperature adjustment mechanism, was unfavorable $3.2 million after tax in 2005, unfavorable $7.1 million after tax in 2004, and unfavorable $2.1 million after tax in 2003.
The Company experienced significant earnings growth from its primary nonregulated businesses during 2005 and 2004. Earnings from Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services were $47.0 million in 2005, $31.0 million in 2004, and $27.4 million in 2003. The primary business growth was primarily due to increased earnings ProLiance Energy, LLC and improved coal mining operations. Synfuel-related earnings included in primary business results were $11.7 million in 2005, $12.1 million in 2004 and $13.3 million in 2003.
Nonregulated Group results for 2005 also reflect earnings of $3.9 million from the Company’s investment in the Haddington Energy Partnerships, an increase of $1.9 million compared to 2004. Results for the year ended December 31, 2004, reflect $6.0 million in after tax charges related to the write-down of the Company’s broadband businesses. Earnings in 2003 reflect after tax gains from the divesture of businesses and investments totaling $2.6 million after tax.
While consolidated earnings decreased slightly in 2004 compared to 2003, earnings per share was further affected by an equity offering of 7.4 million shares in August of 2003. The equity offering generated net proceeds (after issuance expenses) of approximately $163 million.
The Utility Group generates revenue primarily from the delivery of natural gas and electric service to its customers. Its 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. The Utility Group’s results are impacted by weather patterns in its service territory and general economic conditions both in its Indiana and Ohio service territories as well as nationally.
The Nonregulated Group generates revenue or earnings from the provision of services to customers. The activities of the Nonregulated Group are closely linked to the utility industry, and the results of those operations are generally impacted by factors similar to those impacting the overall utility industry.
In this discussion and analysis of results of operations, the results of the Utility Group and Nonregulated Group are presented on a per share basis. Such per share amounts are based on the earnings contribution of each group included in Vectren’s consolidated results divided by Vectren’s average shares outstanding during the period. The earnings per share of the groups do not represent a direct legal interest in the assets and liabilities allocated to either group but rather represent a direct equity interest in Vectren Corporation's assets and liabilities as a whole.
The Company 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 the Company’s SEC filings.
Dividends
Dividends declared for the year ended December 31, 2005, were $1.19 per share compared to $1.15 per share in 2004 and $1.11 per share in 2003. In October 2005, the Company’s board of directors increased its quarterly dividend to $0.305 per share from $0.295 per share.
Detailed Discussion of Results of Operations
Following is a more detailed discussion of the results of operations of the Company’s Utility Group and Nonregulated Group. The detailed results of operations for the Utility Group and Nonregulated Group are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Consolidated Statements of Income. Other than the $6.5 million contribution made in 2005 to the Vectren Foundation discussed above, Corporate and Other operations are not significant.
Results of Operations of the Utility Group
The Utility Group is comprised of Vectren Utility Holdings, Inc.’s (Utility Holdings) operations. The operations of Utility Holdings consist of the Company’s 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 marketing operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers. The results of operations of the Utility Group before certain intersegment eliminations and reclassifications for the years ended December 31, 2005, 2004, and 2003, follow:
| | | | | | | | |
| | | Year Ended December 31, |
(In millions, except per share data) | | 2005 | | 2004 | | 2003 | |
| OPERATING REVENUES | | | | | | | |
| Gas utility | | $ | 1,359.7 | | $ | 1,126.2 | | $ | 1,112.3 | |
| Electric utility | | | 421.4 | | | 371.3 | | | 335.7 | |
| Other | | | 0.7 | | | 0.5 | | | 0.8 | |
Total operating revenues | | | 1,781.8 | | | 1,498.0 | | | 1,448.8 | |
| OPERATING EXPENSES | | | | | | | | | | |
| Cost of gas sold | | | 973.3 | | | 778.5 | | | 762.5 | |
| Fuel for electric generation | | | 126.3 | | | 96.1 | | | 86.5 | |
| Purchased electric energy | | | 17.8 | | | 20.7 | | | 16.2 | |
| Other operating | | | 241.3 | | | 220.4 | | | 211.9 | |
| Depreciation & amortization | | | 141.3 | | | 127.8 | | | 117.9 | |
| Taxes other than income taxes | | | 65.2 | | | 58.2 | | | 56.6 | |
| Total operating expenses | | | 1,565.2 | | | 1,301.7 | | | 1,251.6 | |
OPERATING INCOME | | | 216.6 | | | 196.3 | | | 197.2 | |
| OTHER INCOME (EXPENSE) | | | | | | | | | | |
| Equity in earnings (losses) of unconsolidated affiliates | | | - | | | 0.2 | | | (0.5 | ) |
| Other – net | | | 5.9 | | | 7.1 | | | 6.5 | |
| Total other income | | | 5.9 | | | 7.3 | | | 6.0 | |
| Interest expense | | | 69.9 | | | 67.4 | | | 66.1 | |
INCOME BEFORE INCOME TAXES | | | 152.6 | | | 136.2 | | | 137.1 | |
| Income taxes | | | 57.5 | | | 53.1 | | | 51.6 | |
NET INCOME | | $ | 95.1 | | $ | 83.1 | | $ | 85.5 | |
BASIC EARNINGS PER SHARE | | $ | 1.26 | | $ | 1.10 | | $ | 1.21 | |
The Utility Group’s 2005 earnings were $95.1 million, an increase of $12.0 million over the prior year. The improved performance is primarily due to gas base rate increases implemented in 2004 and early 2005, which added revenue of $33.8 million, or $20.1 million after tax, compared to 2004. The recovery of pollution control investments, net of related operating and depreciation expense, increased operating income $8.7 million, or $5.2 million after tax, compared to the prior year. In addition, margins from generation asset optimization activities increased due to increased availability of the generating units. The improved utility margins were partially offset by higher operating and depreciation expense. The 2005 results also reflect a $4.2 million, $2.5 million after tax, charge recorded pursuant to the disallowance of Ohio gas costs. Year over year, management estimates the effects of weather, as adjusted for a recently implemented normal temperature adjustment mechanism, increased earnings approximately $3.9 million after tax.
The $2.5 million decrease in earnings occurring in 2004 compared to 2003 was primarily due to unfavorable weather estimated at $5.0 million after tax. Margin growth, offsetting the weather impact, resulted from the recovery of NOx related environmental expenditures, gas base rate increases implemented in 2004, and customer growth. The primary expense changes were higher depreciation and lower bad debt expense in 2003. Bad debt expense in 2003 associated with the Ohio service territory was reversed and deferred for later recovery under an uncollectible accounts expense rider.
During 2004 and 2003, the Company initiated base rate cases in its three gas service territories. Orders in its two Indiana service territories were received in the second half of 2004, and the order in the Ohio territory was received early in the second quarter of 2005. On an annual basis, these orders allow for additional revenues approximating $45 million. The Company has sought and received regulatory recovery mechanisms (trackers) affecting electric margin that provide a return on utility plant constructed for environmental compliance and that allow for recovery of related operating expenses. After tax earnings associated with the environmental compliance trackers totaled $13.5 million in 2005, $8.3 million in 2004, and $4.7 million in 2003. The Company recently implemented a normal temperature adjustment mechanism in its Indiana gas service territories and also utilizes regulatory trackers affecting gas margin that recover, on a dollar-for-dollar basis, pipeline integrity management costs in its Indiana territories and uncollectible accounts expense and other costs in its Ohio service territory.
Significant Fluctuations
Utility Group Margin
Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric utility revenues less Fuel for electric generation and Purchased electric energy. These measures exclude Other operating expenses, Depreciation and amortization, and Taxes other than income taxes, which are included in the calculation of operating income. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.
Margin generated from the sale of natural gas and electricity to residential and commercial customers is seasonal and impacted by weather patterns in the Company’s service territories. The weather impact in the Company’s Indiana gas utility service territories is mitigated somewhat by a normal temperature adjustment mechanism, which was implemented in the fourth quarter of 2005. Margin generated from sales to large customers (generally industrial, other contract, and firm wholesale customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas costs, as well as other tracked expenses and is also impacted by some level of price sensitivity in volumes sold. Electric generating asset optimization activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations.
Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold)
Gas Utility margin and throughput by customer type follows:
| | | | | Year Ended December 31, |
(In millions) | | | | 2005 | | 2004 | | 2003 | |
| | | | | | | | | | |
| Gas utility revenues | | | | $ 1,359.7 | | $ 1,126.2 | | $ 1,112.3 | |
| Cost of gas sold | | | | 973.3 | | 778.5 | | 762.5 | |
| Total gas utility margin | | | | $ 386.4 | | $ 347.7 | | $ 349.8 | |
| Margin attributed to: | | | | | | | | | |
| Residential & commercial customers | | | | | $ | 333.2 | | $ | 297.7 | | $ | 302.1 | |
| Industrial customers | | | | | | 48.3 | | | 45.7 | | | 43.0 | |
Other customers | | | | | | 4.9 | | | 4.3 | | | 4.7 | |
| | | | | | | | | | | | | | |
| Sold & transported volumes in MMDth attributed to: | | | | | | | | | | | | | |
| Residential & commercial customers | | | | | | 112.9 | | | 114.5 | | | 122.6 | |
| Industrial customers | | | | | | 87.2 | | | 85.8 | | | 86.7 | |
Total sold & transported volumes | | | | | | 200.1 | | | 200.3 | | | 209.3 | |
Gas utility margins were $386.4 million for the year ended December 31, 2005, an increase of $38.7 million compared to 2004. The increase is primarily due to the favorable impact of gas base rate increases of $33.8 million and additional pass through expenses and revenue taxes recovered in margins of $5.8 million compared to last year. Results for the year ended December 31, 2005, reflect a $4.2 million charge for the impact of the disallowance of Ohio gas costs ordered by the PUCO. For the year ended December 31, 2005, weather was 5% warmer than normal but 4% colder than the prior year. Management estimates that weather, including of the effects of the normal temperature adjustment mechanism, increased margin an estimated $2.5 million compared to 2004. Though estimated to be modest to date and net of customer growth, management has seen evidence of gas customer usage declines in 2005, assumed to be driven primarily by price sensitivity. With the current outlook for continued high gas commodity prices, management expects that trend to continue and/or accelerate in 2006. The average cost per dekatherm of gas purchased was $9.05 in 2005, $6.92 in 2004; and $6.36 in 2003.
Gas utility margins were $347.7 and $349.8 million, respectively, for the years ended December 31, 2004 and 2003. This represents a decrease in gas utility margin of $2.1 million compared to 2003. Heating weather for the year ended December 31, 2004, was 8% warmer than normal and 8% warmer than 2003. The estimated unfavorable impact on gas utility margin caused by weather was approximately $9.8 million compared to 2003. Indiana base rate increases added $4.7 million compared to the prior year. Also offsetting the effects of weather were increased late and reconnect fees, expense recovery pursuant to Ohio regulatory trackers, and higher revenue taxes collected from rate payers. Gas sold and transported volumes were 4% less in 2004, compared to the prior year. The decreased throughput was primarily attributable to weather.
Electric Utility Margin (Electric Utility Revenues less Fuel for Electric Generation and Purchased Electric Energy)
Electric Utility margin and volume sold by customer type follows:
| | | Year Ended December 31, |
(In millions) | | 2005 | | 2004 | | 2003 | |
| | | | | | | | |
| Electric utility revenues | | $ | 421.4 | | $ | 371.3 | | $ | 335.7 | |
| Fuel for electric generation | | | 126.3 | | | 96.1 | | | 86.5 | |
| Purchased electric energy | | | 17.8 | | | 20.7 | | | 16.2 | |
Total electric utility margin | | $ | 277.3 | | $ | 254.5 | | $ | 233.0 | |
| Margin attributed to: | | | | | | | | | | |
| Residential & commercial customers | | $ | 170.8 | | $ | 157.3 | | $ | 141.1 | |
| Industrial customers | | | 66.9 | | | 63.7 | | | 53.5 | |
| Municipalities & other customers | | | 19.8 | | | 18.6 | | | 20.1 | |
Subtotal: Retail & firm wholesale | | $ | 257.5 | | $ | 239.6 | | $ | 214.7 | |
| Asset optimization | | $ | 19.8 | | $ | 14.9 | | $ | 18.3 | |
| | | | | | | | | | | |
| Electric volumes sold in GWh attributed to: | | | | | | | | | | |
| Residential & commercial customers | | | 2,933.2 | | | 2,830.9 | | | 2,715.8 | |
| Industrial customers | | | 2,575.9 | | | 2,511.2 | | | 2,369.6 | |
| Municipal & other customers | | | 689.9 | | | 645.9 | | | 624.7 | |
Total retail & firm wholesale volumes sold | | | 6,199.0 | | | 5,988.0 | | | 5,710.1 | |
Retail & Firm Wholesale Margin
Electric retail and firm wholesale utility margin was $257.5 million for the year ended December 31, 2005, an increase over the prior year of $17.9 million. The recovery of pollution control related investments and associated operating expenses and depreciation expense increased margins $14.3 million compared to 2004. Cooling weather was 9% warmer than normal and 21% warmer than last year. The estimated increase in electric margin related to weather was $4.0 million compared to the prior year ($3.8 million related to cooling weather and $0.2 million related to heating weather).
Electric retail and firm wholesale margin was $239.6 million for the year ended December 31, 2004. This represents a $24.9 million increase over 2003. Additional NOx recoveries increased margin $14.6 million in 2004. Cooling weather for the year was 12% warmer than 2003, increasing margin an estimated $2.0 million. The remaining increase in margin was attributable to increased small customer usage and increased sales to industrial customers.
Margin from Asset Optimization Activities
Periodically, generation capacity is in excess of that needed to serve retail load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of the margin from these activities is generated from contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk. Beginning in April 2005, substantially all off-system sales occur into the MISO day-ahead market.
Following is a reconciliation of asset optimization activity:
| | | | | | | | |
| | | Year Ended December 31, |
(In millions) | | 2005 | | 2004 | | 2003 | |
| Beginning of Year Net Balance Sheet Position | | $ | (0.6 | ) | $ | (0.4 | ) | $ | (0.7 | ) |
| Statement of Income Activity | | | | | | | | | | |
| Mark-to-market gains (losses) recognized | | | 0.5 | | | (1.4 | ) | | 0.7 | |
| Realized gains | | | 19.3 | | | 16.3 | | | 17.6 | |
Net activity in electric utility margin | | | 19.8 | | | 14.9 | | | 18.3 | |
| Net cash received & other adjustments | | | (17.9 | ) | | (15.1 | ) | | (18.0 | ) |
| End of Year Net Balance Sheet Position | | $ | 1.3 | | $ | (0.6 | ) | $ | (0.4 | ) |
| | | | | | | | | | | |
For the year ended December 31, 2005, net asset optimization margins were $19.8 million, which represents an increase of $4.9 million, as compared to 2004. The increase in margin results primarily from the timing of available capacity and mark to market gains. Net asset optimization margins decreased $3.2 million in 2004 as compared to 2003 due to reduced available capacity.
In 2005, the Company experienced increased availability of the generating units. The availability of excess capacity was reduced in 2004 by scheduled outages of owned generation related to the installation of environmental compliance equipment. Off system sales totaled 1,208.1 GWh in 2005, compared to 670.4 GWh in 2004 and 739.0 GWh in 2003.
Utility Group Operating Expenses
Other Operating
Other operating expenses increased $20.9 million for the year ended December 31, 2005, compared to 2004. Amortization of rate case expenses, expenses associated with the Ohio choice program and integrity management programs, and expenses recovered through margin increased $6.5 million. Bad debt expense in the Company’s Indiana service territories was $9.3 million in 2005, an increase of $1.8 million compared to 2004. Compensation and benefit costs increases, including performance and share-based compensation was $6.8 million higher than the prior year, reflective of the return to higher earnings in 2005 as compared to 2004. Higher maintenance, chemical costs, and all other costs account for $5.8 million of the increase.
Other operating expenses increased $8.4 million for the year ended December 31, 2004, compared to 2003. Expense in 2003 reflects the deferral of $4.0 million relating to the Ohio order allowing the Company to defer for future recovery its actual bad debt expense in excess of the amount provided in base rates (See Rate and Regulatory Matters below). Other factors contributing to the increase were an increase in environmental compliance-related expenses of $2.8 million recovered in rates and planned turbine maintenance of $1.9 million.
Depreciation & Amortization
Depreciation expense increased $13.5 million in 2005 compared to 2004 and increased $9.9 million in 2004 compared to 2003. In addition to depreciation on additions to plant in service, the increases were primarily due to incremental depreciation expense associated with environmental compliance equiptment additions. Depreciation expense associated with environmental compliance equiptment, which is recovered in Electric Utility margins, totaled $12.1 million in 2005, $6.2 million in 2004, and $0.7 million in 2003. Results for 2004 include $1.8 million of lower depreciation due to adjustments of Ohio depreciation rates and amortization of Indiana regulatory assets.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $7.0 million in 2005 compared to 2004, and $1.6 million in 2004 compared to 2003. These increases are primarily attributable to increased collections of utility receipts and excise taxes due to higher revenues.
Utility Group Other Income (Expense)
Total other income (expense)-net decreased $1.4 million in 2005 compared to 2004, and increased $1.3 million during 2004 compared to 2003. Lower amounts of AFUDC were recorded in 2005 compared to 2004 and in 2004 compared to 2003 as environmental compliance expenditures were placed in service. Fiscal year 2003 includes operating losses and the write-off of investments in an entity that processed fly ash, totaling $4.2 million.
Utility Group Interest Expense
Interest expense increased $2.5 million in 2005 compared to 2004. The increase was driven by rising interest rates and higher levels of short term borrowings due in part to higher working capital requirements resulting from the increased gas commodity prices.
In November 2005, the Company completed permanent financing transactions in which approximately $150 million in debt and interest rate swap settlement proceeds were received and used to retire higher coupon long-term debt and other short term borrowings.
In the second half of 2003, the Company completed permanent financing transactions in which approximately $366 million in equity, debt, and hedging net proceeds were received and used to retire higher coupon long-term debt and other short term borrowings. The changes in interest expense in 2004 and 2003 reflect the full impact of that transaction.
Utility Group Income Taxes
Federal and state income taxes increased $4.4 million in 2005 compared to 2004 due primarily to increased pre-tax income as compared to the prior year and adjustments to accruals resulting from the conclusion of state tax audits and other adjustments. Income taxes in 2004 were relatively consistent with 2003 with decreased earnings offset by a slightly higher effective rate.
Environmental Matters
The Company is subject to federal, state, and local regulations with respect to environmental matters, principally air, solid waste, and water quality. Pursuant to environmental regulations, the Company is required to obtain operating permits for the electric generating plants that it owns or operates and construction permits for any new plants it might propose to build. Regulations concerning air quality establish standards with respect to both ambient air quality and emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO2), and nitrogen oxide (NOx). Regulations concerning water quality establish standards relating to intake and discharge of water from electric generating facilities, including water used for cooling purposes in electric generating facilities. Because of the scope and complexity of these regulations, the Company is unable to predict the ultimate effect of such regulations on its future operations, nor is it possible to predict what other regulations may be adopted in the future. The Company intends to comply with all applicable governmental regulations, but will contest any regulation it deems to be unreasonable or impossible with which to comply.
Clean Air Act
NOx SIP Call Matter
The Company has taken steps to comply with Indiana’s State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A. B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
| · | the Company’s project to achieve environmental compliance by investing in clean coal technology; |
| · | a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred; |
| · | a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and |
| · | ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service. |
Through December 31, 2005, capital investments approximating the level approved by the IURC have been made. The last SCR was placed into service in May, 2005. Related annual operating expenses, including depreciation expense, were $15.4 million in 2005, $9.7 million in 2004 and $1.2 million in 2003. Such operating expenses could approximate $24 to $27 million once all installed equipment is operational for an entire year.
The Company has achieved timely compliance through the reduction of the Company’s overall NOx emissions to levels compliant with Indiana’s NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance.
Clean Air Interstate Rule & Clean Air Mercury Rule
In March of 2005 USEPA finalized two new air emission reduction regulations. The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2) emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. Both sets of regulations require emission reductions in two phases. The first phase deadline for both rules is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance with the emission reductions required under CAIR is 2015, while the second phase deadline for compliance with the emission reduction requirements of CAMR is 2018. The Company is evaluating compliance options and fully expects to be in compliance by the required deadlines.
In May 2005, Vectren’s utility subsidiary, SIGECO, filed a new multi-emission compliance plan with the IURC. If approved, SIGECO’s coal-fired plants will be 100% scrubbed for SO2, 90% scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury reduction standards. On October 20, 2005, the Company and the OUCC filed with the IURC a settlement agreement concerning the regulatory treatment and recovery of the investment required by this plan. On December 6, 2005, SIGECO, the OUCC and Citizens Action Coalition filed a supplement to the settlement in which SIGECO agreed to study renewable energy alternatives and to include a carbon forecast in future filings with regard to new generation and further environmental compliance plans, among other initiatives. If the settlement agreement is approved, the Company will recover an approximate 8% return on its capital investments, which are expected to approximate $110 million, and related operating expenses through a rider mechanism. This rider mechanism will operate similar to the rider used to recover NOx-related capital investments and operating expenses. The Company expects a final order from the IURC related to this settlement agreement in early 2006.
Culley Generating Station Litigation
During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to a generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications.
Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government’s complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation.
Under the agreement, SIGECO committed to:
| · | either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006; |
| · | operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions; |
| · | enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions; |
| · | install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007; |
| · | conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and |
| · | pay a $600,000 civil penalty. |
The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to its results from operations or financial condition. The $600,000 civil penalty was expensed and paid during 2003 and is reflected in Other-net.
Manufactured Gas Plants
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, Indiana Gas, SIGECO, and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites.
Indiana Gas has 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 has 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. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several 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.
In conjunction with data compiled by environmental consultants, Indiana Gas has 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 costs that it reasonably expects to incur totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects 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.
In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990’s. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have been initiated by the Company to confirm that the sites continue to pose no such risk.
On October 6, 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 on February 24, 2004. On July 13, 2004, SIGECO 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. Costs of remediation at the four SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot be determined at this time. The total costs accrued to date, including investigative costs, have been immaterial.
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, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA.
Rate and Regulatory Matters
Gas and electric operations with regard to retail rates and charges, terms of service, accounting matters, issuance of securities, and certain other operational matters specific to its Indiana customers are regulated by the IURC. The retail gas operations of the Ohio operations are subject to regulation by the PUCO.
All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and GCR clauses allow the Company to charge for changes in the cost of purchased gas. Metered 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 an agreed upon benchmark, is also recovered through regulatory proceedings.
GCA, GCR, and FAC procedures involve periodic filings and IURC and PUCO 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. For the recent past, the earnings test has not affected the Company’s ability to recover costs.
Weather Normalization
On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The OUCC had previously entered into a settlement agreement with Vectren Energy Delivery of Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These Indiana customer classes represent approximately 60-65% of the Company’s total natural gas heating load.
The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA has been applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven month heating season will be adjusted using the NTA.
The order provides that the Company will make, on a monthly basis, a commitment of $125,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.
Rate structures in the Company’s Indiana electric territory and Ohio gas territory do not include weather normalization-type clauses.
Gas Utility Base Rate Settlements
On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The new rate designs in all three territories include a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in SIGECO’s service territory was implemented on July 1, 2004; the base rate change in Indiana Gas’ service territory was implemented on December 1, 2004; and the base rate change in VEDO’s service territory was implemented on April 14, 2005.
The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO’s new base rates provide for the recovery of on-going costs to comply with the Pipeline Safety Improvement Act of 2002 as well as the funding of conservation programs.
Indiana and Ohio Decoupling/Conservation Filings
On October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC for approval of a conservation program and a conservation adjustment rider in its two Indiana gas service territories. If approved, the plan outlined in the petition will better align the interests of the Company with its customers through the promotion of natural gas conservation. The petition requests the use of a tracker mechanism to recover the costs of funding the design and implementation of conservation efforts, such as consumer education programs and rebates for high efficiency equipment. The conservation tracker works in tandem with a decoupling mechanism. The decoupling mechanism would allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer usage established in each utility’s last general rate case. The Company will file its evidence in March 2006 and a hearing is set for June 2006.
Similarly, on November 28, 2005, Vectren Energy Delivery of Ohio filed with the PUCO for approval of a conservation program and a conservation adjustment rider that would accomplish the same objectives. Discussions with interested parties are ongoing in both states.
MISO
Since February, 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) have been deferred for future recovery in the next general rate case.
On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
On June 1, 2005, Vectren, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in Vectren’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding.
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 uncertainties around Day 2 energy market operations, it is difficult to predict near term operational impacts. However, as stated above, it is believed that MISO’s regional operation of the transmission system will ultimately lead to reliability improvements.
The potential need to expend capital for improvements to the transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant.
Gas Cost Recovery (GCR) Audit Proceedings
On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions. During 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.2 million was recorded in Cost of Gas Sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.
VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. That appeal is pending with briefing scheduled to be completed in February, 2006. In addition, the Company solicited and received bids for VEDO’s gas supply and portfolio administration services and has selected a third party provider, who began providing services to VEDO on November 1, 2005, under a one year contract. On December 21, 2005, the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million disallowance related to portfolio administration to $1.98 million. The Company is considering whether to appeal that decision.
Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other regulated Ohio gas utilities to establish a mechanism to recover uncollectible account expense outside of base rates. The tariff mechanism establishes an automatic adjustment procedure to track and recover these costs instead of providing the recovery of the historic amount in base rates. Through this order, VEDO received authority to defer its 2003 uncollectible accounts expense to the extent it differs from the level included in base rates. The Company estimated the difference to approximate $4 million in excess of that included in base rates, and reversed and deferred that amount for future recovery in 2003. In 2005 and 2004, the Company recorded revenues of $5.1 million and $3.3 million, respectively, which is equal to the level of uncollectible accounts expense recognized for Ohio residential customers.
United States Securities and Exchange Commission Inquiry into PUHCA Exemption
In July 2004, the Company received a letter from the SEC regarding its exempt status under the Public Utility Holding Company Act of 1935 (PUHCA). The Company has responded fully to the SEC's letter and believes that it and its utility holding company subsidiary, Utility Holdings, remain entitled to exemption under Section 3(a)(1) of PUHCA. The question of the PUHCA exemptions was mooted by the Energy Policy Act of 2005 (Energy Act), which repealed the Public Utility Holding Company Act of 1935 effective February 8, 2006.
The Energy Act enacts a new Public Utility Holding Company Act of 2005 (PUHCA 2005). The Company and Utility Holdings, are holding companies under PUHCA 2005. Under PUHCA 2005, the FERC is granted authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities to the extent relevant to the rates of FERC-jurisdictional public utilities and natural gas companies that are part of the holding company system. FERC has issued rules implementing PUHCA 2005 that allow companies to seek an exemption or waiver from all or some of FERC’s books and records requirements. Under PUHCA 2005, the Company will be required to notify FERC of its status as a holding company, and, unless an exemption or waiver is obtained, file an annual report, maintain certain books and records and make them available to the FERC. Compliance with these requirements is not expected to materially affect the Company’s financial position or operations.
Results of Operations of the Nonregulated Group
The Nonregulated Group is comprised of Vectren Enterprises’ operations. The Nonregulated Group operates in three primary business areas: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services. Energy Marketing and Services markets and supplies natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal and generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. In addition, there are other businesses that invest in broadband communication services, energy-related opportunities and services, real estate, and leveraged leases, among other investments. The Nonregulated Group supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, utility infrastructure services, and other services. The results of operations of the Nonregulated Group for the years ended December 31, 2005, 2004, and 2003, follow:
| | | Year Ended December 31, |
(In millions, except per share amounts) | | 2005 | | 2004 | | 2003 | |
NET INCOME | | $ | 48.2 | | $ | 26.4 | | $ | 27.6 | |
| | | | | | | | | | | |
BASIC EARNINGS PER SHARE | | $ | 0.64 | | $ | 0.35 | | $ | 0.39 | |
| | | | | | | | | | | |
| NET INCOME ATTRIBUTED TO: | | | | | | | | | | |
| Energy Marketing & Services | | $ | 29.3 | | $ | 16.6 | | $ | 15.3 | |
| Coal Mining | | | 17.0 | | | 12.5 | | | 13.0 | |
| Utility Infrastructure | | | 0.7 | | | 1.8 | | | (0.9 | ) |
| Other Businesses | | | 1.2 | | | (4.5 | ) | | 0.2 | |
Nonregulated earnings for the year ended December 31, 2005, were $48.2 million compared to $26.4 million in 2004 and $27.6 million in 2003. The Company’s three primary nonregulated businesses, Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services, contributed $47.0 million in 2005, $30.9 million in 2004, and $27.4 million in 2003. Primary business growth was primarily due to increased earnings from ProLiance Energy, LLC, and improved coal mining operations. Synfuel-related earnings included in primary business results were $11.7 million in 2005, $12.1 million in 2004 and $13.3 million in 2003.
Other Businesses’ results for 2005 reflect $1.9 million of increased earnings over 2004 from the Company’s investment in Haddington Energy Partnerships. Results for 2004 reflect $6.0 million in after tax charges related to the write-down of the Company’s broadband businesses. Earnings in 2003 reflect after tax gains from the divesture of businesses and investments totaling $2.6 million after tax.
Energy Marketing & Services
Energy Marketing and Services is comprised of the Company’s gas marketing operations, performance contracting operations, and retail gas supply operations.
ProLiance Energy LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), 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 utilities and nonregulated gas supply operations and Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. The Company accounts for its investment in ProLiance using the equity method of accounting.
As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreements with Indiana Gas and SIGECO were approved and extended through March 31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer representatives, including the OUCC, filed a settlement agreement with the IURC providing for ProLiance to be the continued supplier of gas supply services to the Company’s Indiana utilities through March 2011. The settlement is subject to approval by the IURC. The Company does not expect the settlement to impact trends in ProLiance’s earnings contribution.
As required by a June 14, 2005, PUCO order (See Utility Holdings, Rate and Regulatory Matters discussion), VEDO solicited bids for its gas supply/portfolio administration services and has selected a third party provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. The Company believes this change will not materially affect ProLiance’s or Vectren’s future earnings, financial position, or cash flows.
Energy Systems Group, LLC (ESG), a wholly owned subsidiary, provides energy performance contracting and facility upgrades through its design and installation, as well as operation, of energy-efficient equipment throughout the Midwest, Southeast and Mid-Atlantic United States. Prior to April 2003, ESG was a consolidated venture between the Company and Citizens Gas with the Company owning two-thirds. In April 2003, the Company purchased the remaining interest in ESG.
Vectren Retail, LLC (d/b/a Vectren Source), a wholly owned subsidiary, provides natural gas and other related products and services in the Midwest and Southeast United States to nearly 130,000 customers opting for choice among energy providers. Vectren Source began serving choice customers in 2002.
Net income generated by Energy Marketing and Services for the year ended December 31, 2005, was $29.3 million compared to $16.6 million in 2004 and $15.3 million in 2003. Throughout the periods presented, gas marketing operations, performed through ProLiance, provided the primary earnings contribution, totaling $31.1 million in 2005, compared to $15.2 million in 2004 and $15.3 million in 2003. The significant increase in earnings in 2005 compared to 2004 was made possible by storage and transportation opportunities resulting from increased firm storage capacity and price volatility and market disruptions during the fourth quarter of 2005. While ProLiance’s earnings remained relatively consistent in 2004 compared to 2003, ProLiance experienced increased earnings primarily related to asset optimization from storage activities as a result of significant price volatility. However, those increases were offset by the reserve established for the contingency described below.
Vectren Source operations have also provided earnings growth. Vectren Source’s earnings totaled $0.9 million in 2005 compared to a loss of $0.4 million in 2004 and a loss of $1.9 million in 2003. During 2005 Vectren Source added approximately 30,000 customers compared to 2004. Customer growth was the primary source of increased earnings in 2004 compared to 2003.
Earnings from performance contracting operations, performed through ESG, were a net loss of $0.4 million in 2005, compared to earnings of $2.8 million in 2004 and $3.0 million in 2003. For the year ended December 31, 2005, the decrease is primarily attributable to the delay in the closing of new contracts and increased overhead from an acquisition completed in 2004.
ProLiance Contingency
In 2002, a civil lawsuit was filed in the United States District Court for the Northern District of Alabama by the City of Huntsville, Alabama d/b/a Huntsville Utilities, Inc. (Huntsville Utilities) against ProLiance. Huntsville Utilities asserted claims based on alleged breach of contract with respect to the provision of portfolio services and/or pricing advice, fraud, fraudulent inducement, and other theories, including conversion and violations under the Racketeering, Influenced and Corrupt Organizations Act (RICO). These claims related generally to: (1) alleged breach of contract in providing advice and/or administering portfolio arrangements; (2) alleged promises to provide gas at a below-market rate; (3) the creation and repayment of a “winter levelizing program” instituted by ProLiance in conjunction with the Manager of Huntsville’s Gas Utility to allow Huntsville Utilities to pay its natural gas bills from the winter of 2000-2001 over an extended period of time coupled with the alleged ignorance about the program on the part of Huntsville Utilities’ Gas Board and other management, and; (4) conversion of Huntsville Utilities’ gas storage supplies to repay the balance owed on the winter levelizing program and the alleged lack of authority of Huntsville Utilities’ gas manager to approve those sales.
In early 2005, a jury trial commenced and on February 10, 2005, the jury returned a verdict largely in favor of Huntsville Utilities and awarded Huntsville Utilities compensatory damages of $8.2 million and punitive damages of $25.0 million. The jury rejected Huntsville Utilities’ claim of conversion. The jury also rejected a counter claim by ProLiance for payment of amounts due from Huntsville Utilities. Following that verdict, there were a number of issues presented to the judge for resolution. Huntsville made a claim under federal law that it was entitled to have the compensatory damage award trebled. The judge rejected that request. ProLiance made a claim against Huntsville for unjust enrichment, which was also rejected by the judge. The judge also determined that attorneys’ fees and prejudgment interest are owed by ProLiance to Huntsville Utilities. The verdict, as affected by the judge’s subsequent rulings, totals $38.9 million, and ProLiance has posted an appeal bond for that estimated amount. ProLiance’s management believes there are reasonable grounds for appeal which offer a basis for reversal of the entire verdict, and initiated the appeal process on July 26, 2005. The appeal will not be fully briefed until early 2006. The earliest an appellate decision might be issued would be in late 2006.
While it is reasonably possible that a liability has been incurred by ProLiance, it is not possible to predict the ultimate outcome of an appeal of the verdict. ProLiance recorded a reserve of $3.9 million as of December 31, 2004, reflective of their assessment of the lower end of the range of potential exposure on certain issues identified in the case and inclusive of estimated ongoing litigation costs. Amounts due from Huntsville Utilities were fully reserved by ProLiance in 2003.
As an equity investor in ProLiance, the Company reflected its share of the charge, or $1.4 million after tax, in its 2004 fourth quarter results. That charge does not reflect the possibility that some actual losses might be recovered from insurance carriers, as to which there can be no assurance. It is not expected that an unfavorable outcome on appeal will have a material adverse effect on the Company’s consolidated financial position or its liquidity, but an unfavorable outcome could be material to the Company’s earnings.
Commodity Prices
In response to the effects of higher gas costs, ProLiance obtained an approximate $112.5 million short-term credit facility for the October 2005 to March 2006 heating season from its existing lenders. This additional line increased ProLiance’s total borrowing capacity to $362.5 million. Neither ProLiance’s $250 million annual credit facility nor the $112.5 million additional line of credit is guaranteed by Vectren Corporation.
Coal Mining
The Coal Mining group mines and sells coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Fuels). The Coal Mining Group also generates IRS Code Section 29 tax credits relating to the production of coal-based synthetic fuels through its 8.3% ownership interest in Pace Carbon Synfuels, LP (Pace Carbon). Pace Carbon developed, owns, and operates four projects to produce and sell coal-based synthetic fuel (synfuel) utilizing Covol technology. Vectren accounts for its investment in Pace Carbon using the equity method. In addition, Fuels receives synfuel-related fees from a synfuel producer unrelated to Pace Carbon for a portion of its coal production.
Coal Mining net income for the year ended December 31, 2005, was $17.0 million, as compared to $12.5 million in 2004, and $13.0 million in 2003. Earnings from Mining operations were $5.3 million in 2005, compared to $0.4 million in 2004 and a loss of $0.3 million in 2003. The increased performance is primarily due to greater production, improved yield and higher prices, despite the effects of rising costs for steel, explosives, and diesel fuel in 2005 and 2004. The Company produced 4.4 million tons of coal in 2005, compared to 3.6 million tons in 2004 and 3.3 million tons in 2003. Synfuel-related results, which include earnings from Pace Carbon and synfuel processing fees earned by Fuels, were $11.7 million in 2005, $12.1 million in 2004, and $13.3 million in 2003. The 2005 decrease reflects lower synfuel processing fees earned by Fuels and costs associated with protecting Section 29 tax credits from oil price risk. The 2004 decrease reflects lower production of synthetic fuel produced by Pace Carbon due to feedstock problems at one of their four plants. The underperforming plant was relocated and began production in January 2005. An additional plant was relocated, due to feedstock problems, on the fourth quarter of 2005 and began production in December 2005. The production of synthetic fuel generates Section 29 tax credits that are utilized by the Company, reducing income tax expense in those years.
Section 29 Tax Credit Developments
Under Section 29 of the Internal Revenue Code, manufacturers such as Pace Carbon receive a tax credit for every ton of synthetic fuel sold. To qualify for the credits, the synthetic fuel must meet three primary conditions: 1) there must be a significant chemical change in the coal feedstock, 2) the product must be sold to an unrelated person, and 3) the production facility must have been placed in service before July 1, 1998.
In past rulings, the Internal Revenue Service (IRS) has concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for Section 29 tax credits. The IRS issued a private letter ruling with respect to the four projects on November 11, 1997, and subsequently issued an updated private letter ruling on September 23, 2002. As a partner in Pace Carbon, Vectren has reflected total tax credits under Section 29 in its consolidated results from inception through December 31, 2005, of approximately $79 million. To date, Vectren has been in a position to fully utilize or carryforward the credits generated. Primarily from the use of these credits, the Company generated an Alternative Minimum Tax (AMT) credit carryforward in 2005 and 2004. As a result, the Company has an accumulated AMT credit carryforward of approximately $47.4 million and $31.9 million at December 31, 2005 and 2004, respectively.
During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year and later expanded the audit to include tax years 1999, 2000, and 2001. In May 2004, the IRS completed its audit of the 1998 to 2001 tax returns of Pace Carbon requesting only minor modifications to previously filed returns. There were no changes to any of the filed Section 29 tax credit calculations. The Permanent Subcommittee on Investigations of the U.S. Senate’s Committee on Governmental Affairs, however, has an ongoing investigation related to Section 29 tax credits. Vectren believes it is justified in its reliance on the private letter rulings and most recent IRS audit results for the Pace Carbon facilities.
Further, Section 29 tax credits are only available when the price of oil is less than a base price specified by the tax code, as adjusted for inflation. Credits realized in 2005 or in prior years are not affected by the limitation. However, an average NYMEX price of approximately $60 per barrel in 2006, could begin to limit Section 29 tax credits, with a total phase out occurring at approximately $74 per barrel. Oil prices currently exceed the threshold where Section 29 tax credits would begin to be phased out. While Congress is considering legislation that would positively impact or entirely negate this potential limitation on tax credits related to oil prices in 2006, there can be no assurance Section 29 tax credits will be available in future periods.
Absent the effect of Section 29 tax credits, the Company’s investment in Pace Carbon has operated, and is expected to continue to operate, at a net loss. Due to the potential limitation of Section 29 tax credits, Pace Carbon investors must assess at what level to operate the synfuel plants. If the investors continue to operate the plants, and tax credits are phased out, the Company could potentially incur additional losses. In addition, the Company would be required to assess the potential impairment of its investment in Pace Carbon.
If a phase out of tax credits were to occur in 2006, approximately one third of that phase out risk is proportionately protected by an insurance arrangement that was executed in January 2005.
Utility Infrastructure Services
Utility Infrastructure Services provides underground construction and repair to gas, water, and telecommunications companies primarily through its investment in Reliant Services, LLC (Reliant) and Reliant’s 100% ownership in Miller Pipeline. Reliant is a 50% owned strategic alliance with an affiliate of Cinergy Corporation and is accounted for using the equity method of accounting. Utility Infrastructure’s net income decreased $1.1 million compared to 2004 and increased $2.7 million in 2004, compared to 2003. The 2005 decrease is primarily attributable to fewer large pipeline projects and customer requested delays in the start of awarded waste water projects. The $2.7 million improvement in 2004 was primarily driven by better pricing, increased large pipeline projects, and increases in utility and municipal waste water construction and repair spending, along with productivity improvements.
Other Businesses
Other Businesses includes a variety of operations and investments, including investments in Broadband and the Haddington Energy Partnerships (Haddington). Broadband invests in communication services, such as cable television, high-speed internet, and advanced local and long distance phone services.
Other Businesses reported net income of $1.2 million in 2005 compared to a loss of $4.5 million in 2004 and income of $0.2 million in 2003. Results for 2005 reflect $1.9 million of increased earnings from the Company’s investment in the Haddington Energy Partnerships compared to 2004. During 2004, the Company recorded charges related to its broadband investments totaling $6.0 million after tax. Results in 2005 were further affected by planned decreases in leveraged lease income as well as additional charges associated with Vectren Communication Services, Inc. The year ended December 31, 2003, includes a $2.6 million after tax net gain associated with divestures of a debt collection subsidiary and various other investments.
The Haddington Energy Partnerships are equity method investments that invest in energy-related ventures. Earnings from Haddington for the year ended December 31, 2005, were $3.9 million compared to $2.0 million in 2004, and a loss of $0.6 million in 2003. In 2005, Haddington sold its investment in Lodi Gas Storage, LLC for cash. The Company recognized its portion of the gain resulting from that sale which totaled $3.8 million after tax. During 2004, these partnerships sold their investments in SAGO Energy, LP, for cash and wrote-down their investment in Nations Energy Holdings, resulting in a net after tax gain of $1.8 million.
Broadband investments include an approximate 2% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom) that if converted bring the Company’s ownership interest up to 16% and an approximate 19% equity interest in SIGECOM Holdings, Inc., which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services, such as cable television, high-speed internet, and advanced local and long distance phone services, to approximately 29,000 customers in the greater Evansville, Indiana area. SIGECOM’s operations are cash flow positive and have not required any further investment since May 2002.
Other Utilicom-related subsidiaries also owned franchising agreements to provide broadband services to the greater Indianapolis, Indiana and Dayton, Ohio markets. In 2004, the build out of these markets was further evaluated, and the Company concluded that it was unlikely it would make additional investments in those markets. As a result, the Company recorded charges totaling $6.0 million, or $3.6 million after-tax, to write off investments made in the Indianapolis and Dayton markets and to write down its investment in SIGECOM.
In 2004, as part of its decision to no longer expand its broadband-related operations, the Company ceased operations of Vectren Communications Services, Inc. (VCS), a municipal broadband consulting business, during the second quarter. This decision resulted in losses of $2.4 million after tax due primarily to inventory write downs, cessation charges, and other costs. In 2005, the Company incurred approximately $1.3 million in after tax charges associated with the settlement of a lawsuit and other charges. VCS’ total loss for 2005 was $1.5 million compared to losses of $2.6 million in 2004 and $1.8 million in 2003.
Impact of Recently Issued Accounting Guidance
SFAS No. 154
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a Replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS 154). This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement in the instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of the direct effects caused by a change in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Further, changes in depreciation, amortization or depletion methods for long-lived, nonfinancial assets are to be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted. The adoption of this standard, beginning in fiscal year 2006, is not expected to have any material effect on the Company’s operating results or financial condition.
FIN 47
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47). FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an asset retirement obligation (ARO) that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
The Company adopted this interpretation on December 31, 2005. The primary issue resulting from FIN 47’s adoption was the reassessment of whether a portion of removal costs accrued through depreciation rates established in regulatory proceedings should be recharacterized as an ARO. The adoption of this interpretation established an approximate $16 million ARO for interim retirements of gas utility pipeline and utility poles and certain asbestos-related issues, the majority of which was already accrued as a cost of removal regulatory liability. The ARO is included in Other liabilities and deferred credits. Adoption also resulted in an increase to Utility plant of approximately $12 million. Because of the effects of regulation, the difference was recorded to Regulatory assets and liabilities.
EITF 04-06
At its March 2005 meeting, the EITF Task Force reached a consensus on EITF 04-06, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” (EITF 04-06) that stripping costs incurred during the production phase of a strip mine are variable production costs that should be included in the costs of the inventory produced (that is, extracted) during the period that the stripping costs are incurred. EITF 04-06 is effective for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. If material, any unamortized costs that cannot be reclassified to inventory must be charged to earnings as a cumulative effect of change in accounting principle. The Company expects that the adoption of EITF 04-06 will have no current impact on its operating results or financial condition.
SFAS 123 (revised 2004) and related interpretations
In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) that will require compensation costs related to all share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to January 1, 2006 for calendar year companies like Vectren. The Company intends to adopt SFAS 123R using the modified prospective method. The adoption of this standard, and subsequent interpretations of this standard, is not expected to have a material effect on the Company’s operating results or financial condition.
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. Note 2 to the consolidated financial statements describes 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 non-utility plant, valuing derivative contracts, and estimating uncollectible accounts, among others. Actual results could differ from these estimates.
Impairment Review of Investments
The Company has investments in notes receivable, entities accounted for using the cost method of accounting, and entities accounted for using the equity method of accounting. When events occur that may cause one of these investments to be impaired, the Company performs an impairment analysis. An impairment analysis of notes receivable usually involves the comparison of the investment’s estimated free cash flows to the stated terms of the note, or for notes that are collateral dependent, a comparison of the collateral’s fair value to the carrying amount of the note. An impairment analysis of cost method and equity method investments involves comparison of the investment’s estimated fair value to its carrying amount. Fair value is estimated using market comparisons, appraisals, and/or discounted cash flow analyses. Calculating free cash flows and fair value using the above methods is subjective and requires judgment concerning growth assumptions, longevity of cash flows, and discount rates (for fair value calculations).
During 2004, the Company performed an impairment analysis on its Utilicom-related investments. The Company used free cash flow analyses to estimate fair value for the cost method portion of the Utilicom investment and recoverability of the related notes receivable. An impairment charge totaling $6.0 million was recorded as a result of the analysis. A 10% increase in the discount rate assumption utilized to calculate Utilicom’s fair value would have resulted in an estimated additional $2 million impairment charge to the cost method investment and no additional impairment charge to the notes receivable.
Impairment tests on other investments were also conducted using appraisals and discounted cash flow models to estimate fair value. A $3.9 million write-off of investments in an entity that processed fly ash resulted in 2003.
Goodwill
Pursuant to SFAS No. 142, the Company performs an annual impairment analysis of its goodwill, almost 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 15 to the consolidated financial statements to be the reporting unit. An impairment test performed in accordance with SFAS 142 requires that a reporting unit’s fair value be estimated. The Company used a discounted cash flow model to estimate the fair value of its Gas Utility Services operating segment, and that estimated fair value was compared to its carrying amount, including goodwill. The estimated fair value was in excess of the carrying amount in 2005, 2004, and 2003 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.
Pension and Other Postretirement Obligations
The Company estimates the expected return on plan assets, discount rate, rate of compensation increase, and future health care costs, among other things, and relies on actuarial estimates to assess the future potential liability and funding requirements of the Company's pension and postretirement plans. The Company annually measures its obligations on September 30. The Company used the following weighted average assumptions to develop 2005 periodic benefit cost: a discount rate of 5.75%, an expected return on plan assets of 8.25%, a rate of compensation increase of 3.5%, and an inflation assumption of 3.5%. During 2005, the Company reduced the discount rate by 25 basis points to value 2005 ending pension and postretirement obligations due to a decline in benchmark interest rates. In January 2005, the Company announced the amendment of certain postretirement benefit plans, effective January 1, 2006. The amendment resulted in an estimated $4 million annual decrease in periodic cost, of which $3.1 million was recognized in 2005. Two of the unions that represent bargaining employees at the Company’s regulated subsidiaries have advised the Company that it is their position that these changes are not permitted under the existing collective bargaining agreements which govern the relationship between the employees and the affected subsidiaries. With assistance from legal counsel, management has analyzed the unions’ position and continues to believe that the Company has reserved the right to amend the affected plans and that changing these benefits for retirees is not a mandatory subject of bargaining. Future changes in health care costs, work force demographics, interest rates, or plan changes could significantly affect the estimated cost of these future benefits.
Management estimates that a 50 basis point decrease in the discount rate would have increased 2005 periodic benefit cost by approximately $1.0 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. While certain estimates are used in the calculation of unbilled revenue, the method from which these estimates are derived is not subject to near-term changes.
Regulation
At each reporting date, the Company reviews current regulatory trends in the markets in which it operates. This review involves judgment and is critical in assessing the recoverability of regulatory assets as well as the ability to continue to account for its activities based on the criteria set forth in SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Based on the Company’s current review, it believes its regulatory assets are probable of recovery. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets. In the unlikely event of a change in the current regulatory environment, such write-offs and impairment charges could be significant.
Financial Condition
Within Vectren’s consolidated group, Utility Holdings funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the Nonregulated Group and corporate operations. Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holding debt. Vectren Capital’s long-term and short-term obligations outstanding at December 31, 2005, totaled $200.0 million and $73.0 million, respectively. Utility Holdings' outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings' long-term and short-term obligations outstanding at December 31, 2005, totaled $700.0 million and $226.9 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.
The Company’s common stock dividends are primarily funded by utility operations. Nonregulated operations have demonstrated sustained profitability, and the ability to generate cash flows. These cash flows are primarily reinvested in other nonregulated ventures, but are also used to fund a portion of the Company’s dividends, and from time to time may be reinvested in utility operations or used for corporate expenses.
The credit ratings on outstanding senior unsecured debt of Utility Holdings, SIGECO and Indiana Gas, at December 31, 2005, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. SIGECO's credit ratings on outstanding secured debt are A/A3. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. The current outlook of both Moody’s and Standard and Poor’s is stable. Standard and Poor’s revised its current outlook to stable from negative in January 2005 and in March 2005 revised SIGECO’s secured debt rating to A from A- and its unsecured debt to A- from BBB+. Credit ratings on Vectren Capital’s senior unsecured debt were withdrawn in December 2005 at the Company’s request. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.
The Company’s consolidated equity capitalization objective is 45-55% 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 48% and 51% of long-term capitalization at December 31, 2005, and 2004, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity and any outstanding preferred stock.
In the fourth quarter of 2005, the Company issued $275 million of long-term debt, taking advantage of favorable long-term debt capital markets. Proceeds from the issuance, net of those used to retire maturing and called debt, converted approximately $187 million of short-term debt to long-term. This short-term debt had been incurred primarily to support Vectren’s capital expenditure and investment programs. In addition to permanently financing these long-lived assets, the issuance of new long-term debt improved Vectren’s liquidity position allowing additional capacity on its credit lines to meet expected working capital requirements for 2006 and beyond. Resulting primarily from this issuance, the equity component of long-term capitalization decreased 3% at December 31, 2005, compared to 2004.
The Company expects the majority of its capital expenditures, investments, and debt security redemptions to be provided by internally generated funds. However, due to significant capital expenditures and expected growth in nonregulated operations, the Company may require additional permanent financing.
Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary historical source of liquidity to fund working capital requirements has been cash generated from operations. Cash flow from operating activities increased $30.4 million in 2005 compared to 2004 and increased $54.3 million in 2004 compared to 2003. Cash utilized for working capital increases was $6.6 million in 2005, $31.2 million in 2004, and $90.1 million in 2003, and is the primary reason for the increased operating cash flow. Earnings before non-cash charges were impacted by $15.5 million and $31.9 million in alternative minimum taxes in 2005 and 2004, respectively.
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.
Cash flow required for financing activities reflects the impact of long-term financing arrangements executed in 2005 and 2003 and increases in common stock dividends over the periods presented. In 2005, Utility Holdings issued $150 million of senior unsecured securities and used those proceeds to retire higher coupon long-term debt and refinance certain capital projects originally financed with short-term borrowings. In addition, Vectren Capital issued $125 million in senior unsecured securities and used those proceeds to fund $38 million of maturing debt and refinance certain capital projects originally financed with short-term borrowings. Cash flow provided by financing activities for the year ended December 31, 2003, includes the effects of the long-term financing in which approximately $366 million in equity, debt, and hedging net proceeds were received and used to retire higher coupon long-term debt and other short-term borrowings. These transactions are more fully described below.
Utility Holdings 2005 Debt Issuance
In November 2005, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $150 million in two $75 million tranches. The first tranche was 10-year notes due December 2015, with an interest rate of 5.45% priced at 99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year notes due December 2035 with an interest rate of 6.10% priced at 99.779% to yield 6.11% to maturity (2035 Notes).
The notes are guaranteed by the Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. In addition, they have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by Utility Holdings, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2015 Notes and 25 basis points for the 2035 Notes.
In January and June 2005, Utility Holdings entered into forward starting interest rate swaps with a notional value of $75 million. Upon issuance of the debt, the interest rate swaps were settled resulting in the receipt of approximately $1.9 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issue maturing on December 2035.
The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $150 million and were used to repay short-term borrowings and to retire approximately $50 million of long-term debt with higher interest rates.
Vectren Capital Corp. 2005 Debt Issuance
On October 11, 2005, Vectren and Vectren Capital Corp., its wholly-owned subsidiary (Vectren Capital), entered into a private placement Note Purchase Agreement (2005 Note Purchase Agreement) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $25 million 4.99% Guaranteed Senior Notes, Series A due 2010, (ii) $25 million 5.13% Guaranteed Senior Notes, Series B due 2012 and (iii) $75 million 5.31% Guaranteed Senior Notes, Series C due 2015. These Guaranteed Senior Notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital. The proceeds from this financing were received on December 15, 2005. This Note Purchase Agreement contains customary representations, warranties and covenants, including a covenant to the effect that the ratio of consolidated total debt to consolidated total capitalization will not exceed 75%.
On October 11, 2005, Vectren and Vectren Capital entered into First Amendments with respect to a Note Purchase Agreement dated as of December 31, 2000 pursuant to which Vectren Capital issued to institutional investors the following tranches of notes: (i) $38 million 7.67% Senior Notes due 2005, (ii) $17.5 million 7.83% Senior Notes due 2007, (iii) $22.5 million 7.98% Senior Notes due 2010 and (iv) a Note Purchase Agreement, dated April 25, 1997, pursuant to which Vectren Capital issued to an institutional investor a $35 million 7.43% Senior Note due 2012. The First Amendments (i) conform the covenants to those contained in the 2005 Note Purchase Agreement, (ii) eliminate a credit ratings trigger which would have afforded noteholders the option to require prepayment if the ratings of Indiana Gas or SIGECO fell below a certain level, (iii) substitute the unconditional guarantee by Vectren of the notes for the more limited support agreement previously in place and (iv) provide for a 100 basis point increase in interest rates if the ratio of consolidated total debt to total capitalization exceeds 65%.
Utility Holdings 2003 Debt Issuance
In July 2003, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $200 million in two $100 million tranches. The first tranche was 10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746% to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity (2018 Notes).
The notes are guaranteed by the Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. In addition, they have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by Utility Holdings, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2013 Notes and 25 basis points for the 2018 Notes.
Shortly before these issues, Utility Holdings entered into several treasury locks with a total notional amount of $150 million. Upon issuance of the debt, the treasury locks were settled resulting in the receipt of $5.7 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issues.
The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $203 million and were used refinance certain capital projects originally financed with short-term borrowings and to retire long-term debt with higher interest rates.
Equity Issuance
In March 2003, the Company filed a registration statement with the Securities and Exchange Commission with respect to a public offering of authorized but previously unissued shares of common stock as well as the senior unsecured notes of Utility Holdings described above. In August 2003, the registration became effective, and an agreement was reached to sell approximately 7.4 million shares to a group of underwriters. The net proceeds totaled $163.2 million and were utilized entirely by Utility Holdings and Utility Holdings’ subsidiaries to refinance short-term borrowings and to retire callable long-term debt.
Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements, such as when notes are remarketed. During 2005, no debt was put to the Company. In 2004, and 2003, debt totaling $2.5 million, and $0.1 million, respectively, was put to the Company. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.
SIGECO and Indiana Gas Debt Calls
In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2015. The notes called in 2005 and 2004 had stated interest rates of 7.45% and 7.15%, respectively.
During 2003, the Company called two first mortgage bonds outstanding at SIGECO and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond had a principal amount of $45.0 million, an interest rate of 7.60%, was originally due in 2023, and was redeemed at 103.745% of its stated principal amount. The second SIGECO bond had a principal amount of $20.0 million, an interest rate of 7.625%, was originally due in 2025, and was redeemed at 103.763% of the stated principal amount.
The first Indiana Gas note had a remaining principal amount of $21.3 million, an interest rate of 9.375%, was originally due in 2021, and was redeemed at 105.525% of the stated principal amount. The second Indiana Gas note had a principal amount of $13.5 million, an interest rate of 6.75%, was originally due in 2028, and was redeemed at the principal amount.
Pursuant to regulatory authority, the premiums paid to retire these notes totaling $3.6 million were deferred as a Regulatory asset.
Other Financing Transactions
During 2004, the Company remarketed two first mortgage bonds outstanding at SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset weekly. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These remarketing efforts resulted in the extinguishment and reissuance of debt at generally the same par value.
Other Company debt totaling $38.0 million in 2005, $15.0 million in 2004, and $18.5 million in 2003 was retired as scheduled.
Investing Cash Flow
Cash flow required for investing activities was $239.6 million in 2005, $262.0 million in 2004, and $239.3 million in 2003. Capital expenditures are the primary component of investing activities. Capital expenditures were $231.6 million in 2005 compared to $252.5 million in 2004 and $233.5 million in 2003. The year ended December 31, 2004, included higher levels of expenditures for environmental compliance equipment.
Available Sources of Liquidity
At December 31, 2005, the Company has $780.0 million of short-term borrowing capacity, including $520.0 million for the Utility Group and $260.0 million for the wholly owned Nonregulated Group and corporate operations, of which approximately $293.0 million is available for the Utility Group operations and approximately $187.0 million is available for the wholly owned Nonregulated Group and corporate operations.
In response to higher natural gas prices, Utility Holdings increased its available consolidated short-term borrowing capacity to $520 million, a $165 million increase over previous levels. In addition, Utility Holdings extended the maturity of its largest credit facility, which totals $515 million, through November, 2010. Vectren Capital also extended the maturity of its largest facility, which totals $255 million, through November, 2010. The amendments were completed on November 10, 2005.
The Company periodically issues new common shares to satisfy dividend reinvestment plan and stock option plan requirements. New issuances added additional liquidity of $4.5 million in 2004 and $7.1 million in 2003.
Potential & Future Uses of Liquidity
Pension and Postretirement Funding Obligations
The Company believes making contributions to its qualified pension plans in the coming years will be necessary. Management currently estimates that the qualified pension plans will require minimum Company contributions of approximately $5 million in 2006 and approximately $15 million in 2007. During 2005, $3.7 million in contributions were made.
Planned Capital Expenditures & Investments
Planned capital expenditures and investments in nonregulated unconsolidated affiliates, including contractual purchase and investment commitments discussed below, for the five-year period 2006 - 2010 are estimated as follows:
| | | | | | | | | | | | |
(In millions) | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | |
| Utility Group | | $ | 245.8 | | $ | 292.1 | | $ | 358.4 | | $ | 319.1 | | $ | 244.5 | |
| Nonregulated Group | | | 127.6 | | | 62.1 | | | 77.0 | | | 52.8 | | | 25.3 | |
| Total capital expenditures & investments | | $ | 373.4 | | $ | 354.2 | | $ | 435.4 | | $ | 371.9 | | $ | 269.8 | |
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2005:
| | | | | | | | | | | | | | |
(In millions) | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | |
| | | | | | | | | | | | | | |
Long-term debt (1) | | $ | 53.7 | | $ | 24.0 | | $ | - | | $ | - | | $ | 47.5 | | $ | 1,131.7 | |
| Short-term debt | | | 299.9 | | | - | | | - | | | - | | | - | | | - | |
| Long-term debt interest commitments | | | 77.4 | | | 77.4 | | | 75.5 | | | 75.4 | | | 75.4 | | | 689.9 | |
| Nonregulated firm commodity purchase commitments | | | 100.6 | | | 16.9 | | | 10.6 | | | 6.3 | | | - | | | - | |
Utility & nonutility plant purchase commitments (2) | | | 13.0 | | | - | | | - | | | - | | | - | | | - | |
| Operating leases | | | 4.9 | | | 4.0 | | | 1.9 | | | 0.9 | | | 0.5 | | | 2.4 | |
Unconsolidated affiliate investments (2) (3) | | | 2.5 | | | - | | | - | | | | | | - | | | - | |
| Total | | $ | 552.0 | | $ | 122.3 | | $ | 88.0 | | $ | 82.6 | | $ | 123.4 | | $ | 1,824.0 | |
| (1) | Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. These provisions allow holders 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 2005 (in millions) is $53.7 in 2006, $20.0 in 2007, zero in 2008, $80.0 in 2009, $10.0 in 2010 and $30.0 thereafter. |
| (2) | The settlement period of these obligations is estimated. |
| (3) | Future investments in Pace Carbon will be made to the extent Pace Carbon generates federal tax credits, with any such additional investments to be funded by these credits. |
The Company’s regulated utilities have both firm and non-firm commitments to purchase commodities as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass through costs, generally collected dollar-for-dollar from retail customers through regulator approved cost recovery mechanisms. Because of the pass through nature of these costs and their insignificant implications to earnings, they have not been included in the listing of contractual obligations.
Off Balance Sheet Arrangements
Ratings Triggers
In conjunction with the transaction described above, the ratings triggers that related to $113.0 million of Vectren Capital’s senior unsecured notes, outstanding at December 31, 2004, were removed. None of Vectren’s other outstanding debt contains ratings triggers
Guarantees and Letters of Credit
In the normal course of business, Vectren issues guarantees to third parties on behalf of its consolidated subsidiaries and unconsolidated affiliates. Such guarantees allow those subsidiaries and affiliates to execute transactions on more favorable terms than the subsidiary or affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of December 31, 2005, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $7 million. In addition, the Company has also issued a guarantee approximating $4 million related to the residual value of an operating lease that expires in 2006. Through December 31, 2005, the Company has not been called upon to satisfy any obligations pursuant to its guarantees.
Forward-Looking Information
A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements. Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:
| · | Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas supply costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints. |
| · | Increased competition in the energy environment including 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 or regulatory 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. |
| · | Increased natural gas 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. |
| · | The performance of projects undertaken by the Company’s nonregulated businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the realization of Section 29 income tax credits and the Company’s coal mining, gas marketing, and broadband strategies. |
| · | Direct or indirect effects on the Company’s business, financial condition or liquidity resulting from a change 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, or work stoppages. |
| · | Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures. |
| · | Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in Management’s Discussion and Analysis of Results of Operations and Financial Condition. |
| · | Changes in Federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations. |
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.
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 also executes 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 purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations, which subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. Nevertheless, it is possible regulators may disallow recovery of a portion of gas costs for various reasons, including but not limited to, a finding by the regulator that natural gas was not prudently procured, as an example. Although Vectren’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold or delivered. The Company mitigates these risks by executing derivative contracts that manage the price of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings.
Recently, commodity prices for natural gas purchases have increased and have become more volatile. Despite hedging strategies, this near term change in natural gas commodity prices may have significant effects on operating results as described above.
Wholesale and Other Operations
Electric sales and purchases in the wholesale power market and other commodity-related operations are exposed to commodity price risk associated with fluctuating commodity prices including electricity, natural gas, and coal. Other commodity-related operations include regulated sales of electricity to certain municipalities and large industrial customers and nonregulated retail gas marketing and coal mining operations. Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described below with frequent management reporting.
The Company’s wholesale power marketing activities include asset optimization strategies that manage the utilization of available electric generating capacity. Execution of asset optimization strategies require entering into energy contracts that commit the Company to purchase and sell electricity in the future. Commodity price risk results from forward positions that commit the Company to deliver electricity. The Company mitigates price risk exposure with planned unutilized generation capability and offsetting forward purchase contracts. The Company accounts for asset optimization contracts that are derivatives at fair value with the offset marked to market through earnings.
The Company’s other commodity-related operations involve the purchase and sale of commodities, including electricity, natural gas, and coal to meet customer demands and operational needs. These operations also enter into forward and option contracts that commit the Company to purchase and sell commodities in the future. Price risk from forward positions obligating the Company to deliver commodities is mitigated using stored inventory, generating capability, and offsetting forward purchase contracts. Price risk also results from forward contracts obligating the Company to purchase commodities to fulfill forecasted nonregulated sales of natural gas and coal that may, or may not, occur. With the exception of a small portion of contracts that are derivatives that qualify as hedges of forecasted transactions under SFAS 133, these contracts are expected to be settled by physical receipt or delivery of the commodity.
Nonregulated gas retail operations will from time-to-time purchase weather derivatives to mitigate extreme weather affecting unregulated retail gas sales, and the Company may purchase other tailored products that mitigate unique risks involving emission allowances and the effect oil prices may have on the availability of Section 29 tax credits.
Market risk resulting from commodity contracts is measured by management using the potential impact on pre-tax earnings caused by the effect a 10% adverse change in forward commodity prices might have on market sensitive derivative positions outstanding on specific dates. For the years ended December 31, 2005, and 2004, a 10% adverse change in forward commodity prices would have decreased earnings by $0.3 million and $0.7 million, respectively, based upon open positions existing on the last day of those years.
Unconsolidated Affiliate
ProLiance, a nonregulated energy marketing affiliate, engages in energy hedging activities to manage pricing decisions, minimize the risk of price volatility, and minimize price risk exposure in the energy markets. ProLiance's market exposure arises from storage inventory, imbalances, and fixed-price forward purchase and sale contracts, which are entered into to support its operating activities. Currently, ProLiance buys and sells physical commodities and utilizes financial instruments to hedge its market exposure. However, net open positions in terms of price, volume and specified delivery point do occur. ProLiance manages open positions with policies which limit its exposure to market risk and require reporting potential financial exposure to its management and its members.
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 20% and 30% of its total debt to be exposed to variable rate volatility. However, there are times when this targeted range of interest rate exposure may not be attained. To manage this exposure, the Company may use derivative financial instruments. At December 31, 2005, debt subject to short-term interest rate volatility and seasonal increases in short-term debt outstanding, represented 22% of the Company's total debt portfolio.
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 2005 and 2004, the weighted average combined borrowings under these arrangements were $390.8 million and $276.4 million, respectively. At December 31, 2005, and 2004, combined borrowings under these arrangements were $349.8 million and $500.2 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2005 and 2004, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $3.9 million and $2.8 million, respectively.
Other Risks
By using forward purchase contracts and derivative financial instruments to manage risk, the Company as well as ProLiance exposes itself to counter-party credit risk and market risk. The Company manages exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract. Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk. Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk. Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices or interest rates. The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by establishing parameters and monitoring those parameters that limit the types and degree of market risk that may be undertaken.
The Company’s customer receivables from gas and electric sales and gas transportation services are primarily derived from a diversified base of 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.
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Vectren Corporation’s management is responsible for establishing and maintaining adequate internal controls over financial reporting. Those control procedures underlie the preparation of the consolidated balance sheets, statements of income, cash flows, and common shareholders’ 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, 2005. Management certified this fact in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2005 Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Vectren Corporation:
We have audited the accompanying consolidated balance sheets of Vectren Corporation and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, common shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, included at Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 16, 2006
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
| | | | | | |
| | | At December 31, |
| | | 2005 | | 2004 | |
ASSETS | | | | | |
| | | | | | |
| Current Assets | | | | | |
| Cash & cash equivalents | | $ | 20.4 | | $ | 9.6 | |
| Accounts receivable - less reserves of $2.8 & | | | | | | | |
$2.0, respectively | | | 197.8 | | | 173.5 | |
| Accrued unbilled revenues | | | 240.6 | | | 176.6 | |
| Inventories | | | 144.6 | | | 72.8 | |
| Recoverable fuel & natural gas costs | | | 15.4 | | | 17.6 | |
| Prepayments & other current assets | | | 106.4 | | | 136.2 | |
Total current assets | | | 725.2 | | | 586.3 | |
| | | | | | | | |
| Utility Plant | | | | | | | |
Original cost | | | 3,632.0 | | | 3,465.2 | |
Less: accumulated depreciation & amortization | | | 1,380.1 | | | 1,309.0 | |
Net utility plant | | | 2,251.9 | | | 2,156.2 | |
| | | | | | | | |
| Investments in unconsolidated affiliates | | | 214.7 | | | 180.0 | |
| Other investments | | | 111.6 | | | 115.1 | |
| Non-utility property - net | | | 240.3 | | | 229.2 | |
| Goodwill - net | | | 207.1 | | | 207.1 | |
| Regulatory assets | | | 89.9 | | | 82.5 | |
| Other assets | | | 27.4 | | | 30.5 | |
TOTAL ASSETS | | $ | 3,868.1 | | $ | 3,586.9 | |
| | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
| | | | | | |
| | | At December 31, |
| | | 2005 | | 2004 | |
LIABILITIES & SHAREHOLDERS' EQUITY | | | | | |
| | | | | | |
| Current Liabilities | | | | | |
| Accounts payable | | $ | 159.0 | | $ | 123.8 | |
| Accounts payable to affiliated companies | | | 162.3 | | | 109.3 | |
| Refundable fuel & natural gas costs | | | 7.6 | | | 6.3 | |
| Accrued liabilities | | | 156.6 | | | 125.8 | |
| Short-term borrowings | | | 299.9 | | | 412.4 | |
| Current maturities of long-term debt | | | 0.4 | | | 38.5 | |
| Long-term debt subject to tender | | | 53.7 | | | 10.0 | |
Total current liabilities | | | 839.5 | | | 826.1 | |
| | | | | | | | |
| Long-term Debt - Net of Current Maturities & | | | | | | | |
| Debt Subject to Tender | | | 1,198.0 | | | 1,016.6 | |
| | | | | | | | |
| Deferred Income Taxes & Other Liabilities | | | | | | | |
| Deferred income taxes | | | 227.3 | | | 234.0 | |
| Regulatory liabilities | | | 272.9 | | | 251.7 | |
| Deferred credits & other liabilities | | | 186.7 | | | 163.2 | |
Total deferred credits & other liabilities | | | 686.9 | | | 648.9 | |
| | | | | | | | |
| Minority Interest in Subsidiary | | | 0.4 | | | 0.4 | |
| | | | | | | | |
| Commitments & Contingencies (Notes 3, 11-13) | | | | | | | |
| | | | | | | | |
| Cumulative, Redeemable Preferred Stock of a Subsidiary | | | - | | | 0.1 | |
| | | | | | | | |
| Common Shareholders' Equity | | | | | | | |
| Common stock (no par value) – issued & outstanding | | | | | | | |
| 76.0 and 75.9, respectively | | | 528.1 | | | 526.8 | |
| Retained earnings | | | 628.8 | | | 583.0 | |
| Accumulated other comprehensive loss | | | (13.6 | ) | | (15.0 | ) |
Total common shareholders' equity | | | 1,143.3 | | | 1,094.8 | |
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY | | $ | 3,868.1 | | $ | 3,586.9 | |
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
| | | Year Ended December 31, |
| | | 2005 | | 2004 | | 2003 | |
| OPERATING REVENUES | | | | | | | |
| Gas utility | | $ | 1,359.7 | | $ | 1,126.2 | | $ | 1,112.3 | |
| Electric utility | | | 421.4 | | | 371.3 | | | 335.7 | |
| Energy services & other | | | 246.9 | | | 192.3 | | | 139.7 | |
Total operating revenues | | | 2,028.0 | | | 1,689.8 | | | 1,587.7 | |
| OPERATING EXPENSES | | | | | | | | | | |
| Cost of gas sold | | | 973.3 | | | 778.5 | | | 762.5 | |
| Fuel for electric generation | | | 126.3 | | | 96.1 | | | 86.5 | |
| Purchased electric energy | | | 17.8 | | | 20.7 | | | 16.2 | |
| Cost of energy services & other | | | 191.0 | | | 143.5 | | | 103.7 | |
| Other operating | | | 282.2 | | | 252.0 | | | 237.1 | |
| Depreciation & amortization | | | 158.2 | | | 140.1 | | | 128.7 | |
| Taxes other than income taxes | | | 66.1 | | | 59.4 | | | 57.0 | |
| Total operating expenses | | | 1,814.9 | | | 1,490.3 | | | 1,391.7 | |
OPERATING INCOME | | | 213.1 | | | 199.5 | | | 196.0 | |
| OTHER INCOME | | | | | | | | | | |
| Equity in earnings of unconsolidated affiliates | | | 45.6 | | | 20.6 | | | 12.2 | |
| Other – net | | | 6.2 | | | 4.6 | | | 16.4 | |
| Total other income | | | 51.8 | | | 25.2 | | | 28.6 | |
| Interest expense | | | 83.9 | | | 77.7 | | | 75.6 | |
INCOME BEFORE INCOME TAXES | | | 181.0 | | | 147.0 | | | 149.0 | |
| Income taxes | | | 44.1 | | | 39.0 | | | 37.7 | |
| Minority interest | | | 0.1 | | | 0.1 | | | 0.1 | |
NET INCOME | | $ | 136.8 | | $ | 107.9 | | $ | 111.2 | |
| | | | | | | | | | | |
| AVERAGE COMMON SHARES OUTSTANDING | | | 75.6 | | | 75.6 | | | 70.6 | |
| DILUTED COMMON SHARES OUTSTANDING | | | 76.1 | | | 75.9 | | | 70.8 | |
| | | | | | | | | | | |
| EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | |
BASIC | | $ | 1.81 | | $ | 1.43 | | $ | 1.58 | |
DILUTED | | $ | 1.80 | | $ | 1.42 | | $ | 1.57 | |
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| | | Year Ended December 31, | |
| | | 2005 | | 2004 | | 2003 | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
| Net income | | $ | 136.8 | | $ | 107.9 | | $ | 111.2 | |
| Adjustments to reconcile net income to cash from operating activities: | | | | | | | | | | |
| Depreciation & amortization | | | 158.2 | | | 140.1 | | | 128.7 | |
| Deferred income taxes & investment tax credits | | | (8.6 | ) | | 5.9 | | | 35.1 | |
| Equity in earnings of unconsolidated affiliates | | | (45.6 | ) | | (20.6 | ) | | (12.2 | ) |
| Provision for uncollectible accounts | | | 15.1 | | | 11.9 | | | 12.8 | |
| Expense portion of pension & postretirement benefit cost | | | 10.7 | | | 11.8 | | | 10.0 | |
| Other non-cash charges - net | | | 1.9 | | | 8.3 | | | (11.8 | ) |
| Changes in working capital accounts: | | | | | | | | | | |
| Accounts receivable & accrued unbilled revenue | | | (102.9 | ) | | (84.0 | ) | | (16.1 | ) |
| Inventories | | | (71.9 | ) | | 0.4 | | | (7.6 | ) |
| Recoverable fuel & natural gas costs | | | 3.5 | | | 8.9 | | | (1.0 | ) |
| Prepayments & other current assets | | | 36.1 | | | (10.2 | ) | | (42.5 | ) |
| Accounts payable, including to affiliated companies | | | 101.2 | | | 42.5 | | | (11.9 | ) |
| Accrued liabilities | | | 27.4 | | | 11.2 | | | (11.0 | ) |
| Unconsolidated affiliate dividends | | | 18.8 | | | 22.3 | | | 9.3 | |
| Changes in noncurrent assets | | | (6.9 | ) | | (3.5 | ) | | (3.9 | ) |
| Changes in noncurrent liabilities | | | (5.4 | ) | | (14.9 | ) | | (5.4 | ) |
Net cash flows from operating activities | | | 268.4 | | | 238.0 | | | 183.7 | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | |
| Proceeds from: | | | | | | | | | | |
| Long-term debt - net of issuance costs | | | 274.2 | | | 32.4 | | | 202.9 | |
| Stock option exercises & other stock plans | | | - | | | 4.5 | | | 7.1 | |
| Common stock - net of issuance costs | | | - | | | - | | | 163.2 | |
| Requirements for: | | | | | | | | | | |
| Dividends on common stock | | | (90.5 | ) | | (87.3 | ) | | (79.2 | ) |
| Retirement of long-term debt | | | (88.5 | ) | | (70.7 | ) | | (121.9 | ) |
| Redemption of preferred stock of subsidiary | | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) |
| Net change in short-term borrowings | | | (112.5 | ) | | 139.5 | | | (124.6 | ) |
| Other activity | | | (0.6 | ) | | - | | | (1.6 | ) |
Net cash flows from financing activities | | | (18.0 | ) | | 18.3 | | | 45.8 | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | |
| Proceeds from: | | | | | | | | | | |
| Unconsolidated affiliate distributions | | | 6.9 | | | 3.2 | | | 4.8 | |
| Notes receivable & other collections | | | 4.3 | | | 9.3 | | | 14.4 | |
| Requirements for: | | | | | | | | | | |
| Capital expenditures, excluding AFUDC equity | | | (231.6 | ) | | (252.5 | ) | | (233.5 | ) |
| Unconsolidated affiliate investments | | | (19.2 | ) | | (18.2 | ) | | (16.6 | ) |
| Notes receivable & other investments | | | - | | | (3.8 | ) | | (8.4 | ) |
Net cash flows from investing activities | | | (239.6 | ) | | (262.0 | ) | | (239.3 | ) |
| Net increase (decrease) in cash & cash equivalents | | | 10.8 | | | (5.7 | ) | | (9.8 | ) |
| Cash & cash equivalents at beginning of period | | | 9.6 | | | 15.3 | | | 25.1 | |
| Cash & cash equivalents at end of period | | $ | 20.4 | | $ | 9.6 | | $ | 15.3 | |
| | | | | | | | |
| Cash paid during the year for: | | | | | | | |
| Interest | | $ | 79.6 | | $ | 75.3 | | $ | 70.9 | |
| Income taxes | | | 48.1 | | | 26.6 | | | 33.9 | |
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In millions, except per share amounts)
| | Common Stock | | | | | | |
| | | | | | | | Accumulated |
| | | | | | | Restricted | Other |
| | | | | | | Stock | | Retained | | Comprehensive | | | |
| | | Shares | | Amount | | Grants | | Earnings | | Income (Loss) | | Total | |
| | | | | | | | | | | | | | |
| Balance at January 1, 2003 | | | 67.9 | | $ | 352.3 | | $ | (2.3 | ) | $ | 530.4 | | $ | (10.5 | ) | $ | 869.9 | |
| | | | | | | | | | | | | | | | | | | | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | | | | | | 111.2 | | | | | | 111.2 | |
| Minimum pension liability adjustments & | | | | | | | | | | | | | | | | | | | |
| other - net of tax | | | | | | | | | | | | | | | (6.3 | ) | | (6.3 | ) |
| Comprehensive loss of unconsolidated | | | | | | | | | | | | | | | | | | | |
| affiliates - net of tax | | | | | | | | | | | | | | | 5.7 | | | 5.7 | |
| Total comprehensive income | | | | | | | | | | | | | | | | | | 110.6 | |
| Common stock: | | | | | | | | | | | | | | | | | | | |
| Public issuance - net of $6.2 million of | | | | | | | | | | | | | | | | | | | |
| issuance costs | | | 7.4 | | | 163.2 | | | | | | | | | | | | 163.2 | |
| Stock option exercises & other stock plans | | | 0.3 | | | 7.1 | | | | | | | | | | | | 7.1 | |
| Dividends ($1.11 per share) | | | | | | | | | | | | (79.2 | ) | | | | | (79.2 | ) |
| Other | | | | | | 0.3 | | | (0.2 | ) | | | | | | | | 0.1 | |
Balance at December 31, 2003 | | | 75.6 | | | 522.9 | | | (2.5 | ) | | 562.4 | | | (11.1 | ) | | 1,071.7 | |
| | | | | | | | | | | | | | | | | | | | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | | | | | | 107.9 | | | | | | 107.9 | |
| Minimum pension liability adjustments & | | | | | | | | | | | | | | | | | | | |
| other - net of tax | | | | | | | | | | | | | | | (0.1 | ) | | (0.1 | ) |
| Comprehensive income of unconsolidated | | | | | | | | | | | | | | | | | | | |
| affiliates - net of tax | | | | | | | | | | | | | | | (3.8 | ) | | (3.8 | ) |
| Total comprehensive income | | | | | | | | | | | | | | | | | | 104.0 | |
| Common stock: | | | | | | | | | | | | | | | | | | | |
| Stock option exercises & other stock plans | | | 0.2 | | | 4.5 | | | | | | | | | | | | 4.5 | |
| Dividends ($1.15 per share) | | | | | | | | | | | | (87.3 | ) | | | | | (87.3 | ) |
| Other | | | 0.1 | | | 3.8 | | | (1.9 | ) | | | | | | | | 1.9 | |
Balance at December 31, 2004 | | | 75.9 | | | 531.2 | | | (4.4 | ) | | 583.0 | | | (15.0 | ) | | 1,094.8 | |
| | | | | | | | | | | | | | | | | | | | |
| Comprehensive income: | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | | | | | | 136.8 | | | | | | 136.8 | |
| Minimum pension liability adjustments & | | | | | | | | | | | | | | | | | | | |
| other - net of tax | | | | | | | | | | | | | | | 0.2 | | | 0.2 | |
| Cash flow hedges- net of tax | | | | | | | | | | | | | | | 4.0 | | | 4.0 | |
| Comprehensive income of unconsolidated | | | | | | | | | | | | | | | | | | | |
| affiliates - net of tax | | | | | | | | | | | | | | | (2.8 | ) | | (2.8 | ) |
| Total comprehensive income | | | | | | | | | | | | | | | | | | 138.2 | |
| Common stock: | | | | | | | | | | | | | | | | | | | |
| Dividends ($1.19 per share) | | | | | | | | | | | | (90.5 | ) | | | | | (90.5 | ) |
| Other | | | 0.1 | | | 2.3 | | | (1.0 | ) | | (0.5 | ) | | | | | 0.8 | |
Balance at December 31, 2005 | | | 76.0 | | $ | 533.5 | | $ | (5.4 | ) | $ | 628.8 | | $ | (13.6 | ) | $ | 1,143.3 | |
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
| 1. | Organization and Nature of Operations |
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and the Ohio operations. Utility Holdings also has other assets that provide information technology and other services to the three utilities. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006, by the Energy Policy Act of 2005 (Energy Act). Both Vectren and Utility Holdings are holding companies as defined by the Energy Act.
Indiana Gas provides energy delivery services to approximately 562,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 140,000 electric customers and approximately 112,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 318,000 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, (53% ownership) and Indiana Gas (47% ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.
The Company, through Vectren Enterprises, Inc. (Enterprises), is also involved in nonregulated activities in three primary business areas: Energy Marketing and Services, Coal Mining, and Utility Infrastructure Services. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal and generates IRS Code Section 29 tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. In addition, there are other businesses that invest in broadband communication services, energy-related opportunities and services, real estate, and leveraged leases, among other investments. These operations are collectively referred to as the Nonregulated Group. Enterprises supports the Company’s regulated utilities pursuant to service contracts by providing natural gas supply services, coal, utility infrastructure services, and other services.
| 2. | Summary of Significant Accounting Policies |
| A. | Principles of Consolidation |
The consolidated financial statements include the accounts of the Company and its wholly owned and majority owned subsidiaries, after elimination of significant intercompany transactions.
The Company has investments in partnership-like structures that are variable interest entities as defined by FASB Interpretation 46(R), “Consolidation of Variable Interest Entities” as a limited partner or as a subordinated lender. The activities of these entities are to purchase or construct as well as operate multifamily housing and office properties. The Company’s exposure to loss is limited to its investment which as of December 31, 2005, and 2004, totaled $15.1 million and $16.2 million, respectively, of Investments in unconsolidated affiliates, and $13.4 million and $16.7 million, respectively, of Other investments. The Company is also the equity owner in three leveraged leases where its exposure to loss is limited to its net investment, which as of December 31, 2005, and 2004, totaled $7.8 million and $7.0 million, respectively. The Company does not consolidate any of these entities.
| B. | Cash & Cash Equivalents |
All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.
Inventories consist of the following:
| | At December 31, |
(In millions) | | 2005 | | 2004 | |
| Gas in storage – at average cost | | $ | 73.3 | | $ | 7.9 | |
| Materials & supplies | | | 30.2 | | | 27.6 | |
| Fuel (coal & oil) for electric generation | | | 19.4 | | | 13.9 | |
| Gas in storage – at LIFO cost | | | 18.8 | | | 18.9 | |
| Other | | | 2.9 | | | 4.5 | |
Total inventories | | $ | 144.6 | | $ | 72.8 | |
Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2005, and 2004, by approximately $117.0 million and $56.4 million, respectively. Gas in storage of the Indiana regulated operations is stated at LIFO. All other inventories are carried at average cost.
| D. | Utility Plant & Depreciation |
Utility plant is stated at historical cost, including AFUDC. Depreciation rates, which include a cost of removal component, are established through regulatory proceedings and are applied to all in-service utility plant. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:
| | At December 31, |
(In millions) | 2005 2004 |
| | | Original Cost | | Depreciation Rates as a Percent of Original Cost | | Original Cost | | Depreciation Rates as a Percent of Original Cost | |
| Gas utility plant | | $ | 1,879.1 | | | 3.5 | % | $ | 1,793.6 | | | 3.5 | % |
| Electric utility plant | | | 1,611.4 | | | 3.7 | % | | 1,458.1 | | | 3.6 | % |
| Common utility plant | | | 44.2 | | | 2.6 | % | | 44.2 | | | 2.7 | % |
| Construction work in progress | | | 97.3 | | | - | | | 169.3 | | | - | |
Total original cost | | $ | 3,632.0 | | | | | $ | 3,465.2 | | | | |
AFUDC represents the cost of borrowed and equity funds used for construction purposes, and is charged to construction work in progress during the construction period. AFUDC is included in Other - net in the Consolidated Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:
| | Year Ended December 31, |
(In millions) | | 2005 | | 2004 | | 2003 | |
| AFUDC – borrowed funds | | $ | 1.6 | | $ | 1.6 | | $ | 2.1 | |
| AFUDC – equity funds | | | 0.3 | | | 1.6 | | | 2.9 | |
Total AFUDC | | $ | 1.9 | | $ | 3.2 | | $ | 5.0 | |
Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.
Jointly Owned Plant
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 270 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2005 is $63.2 million with accumulated depreciation totaling $40.2 million. 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.
Non-utility property, net of accumulated depreciation and amortization follows:
| | At December 31, |
(In millions) | | 2005 | | 2004 | |
| Computer hardware and software | | $ | 105.6 | | $ | 104.6 | |
| Land & buildings | | | 69.5 | | | 62.8 | |
| Coal mine development costs & equipment | | | 48.0 | | | 49.0 | |
| All other | | | 17.2 | | | 12.8 | |
Non-utility property - net | | $ | 240.3 | | $ | 229.2 | |
| | | | | | | | |
The depreciation of non-utility property is charged against income over its estimated useful life (ranging from 5 to 40 years), using the straight-line method of depreciation or units-of-production method of amortization. Repairs and maintenance, which are not considered improvements and do not extend the useful life of the non-utility property, are charged to expense as incurred. When non-utility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income. Non-utility property is presented net of accumulated depreciation and amortization totaling $144.6 million and $111.1 million as of December 31, 2005, and 2004, respectively. For the years ended December 31, 2005, 2004, and 2003, the Company capitalized interest totaling $0.4 million, $1.4 million, and $0.9 million, respectively, on non-utility plant construction projects.
EITF 04-06
At its March 2005 meeting, the EITF Task Force reached a consensus on EITF 04-06, “Accounting for Stripping Costs Incurred during Production in the Mining Industry”(EITF 04-06) that stripping costs incurred during the production phase of a strip mine are variable production costs that should be included in the costs of the inventory produced (that is, extracted) during the period that the stripping costs are incurred. EITF 04-06 is effective for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. If material, any unamortized costs that cannot be reclassified to inventory must be charged to earnings as a cumulative effect of change in accounting principle. The Company will adopt EITF 04-06 on January 1, 2006, and that the adoption will have no current impact on its operating results or financial condition.
Goodwill arising from business combinations is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 requires a portion of goodwill be charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Through December 31, 2005, no goodwill impairments have been recorded. Approximately $205.0 million of the Company’s goodwill is included in the Gas Utility Services operating segment. The remaining $2.1 million is attributable to the Nonregulated Group.
| G. | Asset Retirement Obligations |
SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) requires entities to record the fair value of a liability for a legal asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company’s results of operations.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143” (FIN 47). FIN 47 clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within SFAS 143’s scope. It also clarifies the meaning of the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be estimated reasonably. The interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
The Company adopted this interpretation on December 31, 2005. The primary issue resulting from FIN 47’s adoption was the reassessment of whether a portion of removal costs accrued through depreciation rates established in regulatory proceedings should be recharacterized as an ARO. The adoption of this interpretation established an approximate $16 million ARO for interim retirements of gas utility pipeline and utility poles and certain asbestos-related issues. The ARO is included in Other liabilities and deferred credits. Adoption also resulted in an increase to Utility plant of approximately $12 million. Because of the effects of regulation, the difference was recorded to Regulatory assets and liabilities.
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).
Regulatory Assets and Liabilities
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 rate-making process. Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets.
Regulatory liabilities consist of the following:
| | At December 31, |
(In millions) | | 2005 | | 2004 | |
| Cost of removal | | $ | 251.4 | | $ | 246.2 | |
| Asset retirement obligation timing difference | | | 11.6 | | | - | |
| Interest rate hedging proceeds (See Note 14) | | | 6.8 | | | 5.5 | |
| MISO-related costs | | | 3.1 | | | - | |
Total regulatory liabilities | | $ | 272.9 | | $ | 251.7 | |
| | | | | | | | |
Cost of Removal
The Company collects an estimated cost of removal of its utility plant through depreciation rates established by 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 ARO as defined by SFAS No. 143.
Regulatory assets consist of the following:
| | At December 31, |
(In millions) | | 2005 | | 2004 | |
| Future amounts recoverable from ratepayers related to: | | | | | |
| Income taxes | | $ | 11.1 | | $ | 11.5 | |
| Asset retirement obligations & other | | | 1.7 | | | 1.0 | |
| | | | 12.8 | | | 12.5 | |
| Amounts deferred for future recovery related to: | | | | | | | |
| Demand side management programs | | | 26.7 | | | 25.9 | |
| MISO-related costs | | | 9.4 | | | 3.1 | |
| Other | | | 3.0 | | | 4.2 | |
| | | | 39.1 | | | 33.2 | |
| Amounts currently recovered through base rates related to: | | | | | | | |
| Unamortized debt issue costs | | | 20.2 | | | 20.4 | |
| Premiums paid to reacquire debt | | | 6.5 | | | 7.0 | |
| Demand side management programs & other | | | 3.7 | | | 3.5 | |
| | | | 30.4 | | | 30.9 | |
| Amounts currently recovered through tracking mechanisms related to: | | | | | | | |
| Ohio authorized trackers | | | 5.6 | | | 6.3 | |
| Indiana authorized trackers | | | 2.0 | | | (0.4 | ) |
| | | | 7.6 | | | 5.9 | |
Total regulatory assets | | $ | 89.9 | | $ | 82.5 | |
| | | | | | | | |
Of the $30.4 million currently being recovered through base rates charged to customers, $28.6 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 13.6 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.
Refundable or Recoverable Gas Costs, Fuel for Electric Production & 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 an agreed upon benchmark, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel for electric generation is charged to operating expense when consumed.
| I. | Impairment Review of Long-Lived Assets |
Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires that the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows that the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.
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 Shareholders' Equity. A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
| | | | | | | | | | | | | | | | |
| | | 2003 | | 2004 | | 2005 |
| | | 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 | |
| | | | | | | | | | | | | | | | |
| Unconsolidated affiliates | | $ | 0.9 | | $ | 9.6 | | $ | 10.5 | | $ | (6.4 | ) | $ | 4.1 | | $ | (4.6 | ) | | (0.5 | ) |
| Minimum pension liability | | | (19.4 | ) | | (9.8 | ) | | (29.2 | ) | | (0.1 | ) | | (29.3 | ) | | 0.3 | | | (29.0 | ) |
| Cash flow hedges & other | | | 0.8 | | | (0.8 | ) | | - | | | - | | | - | | | 6.7 | | | 6.7 | |
| Deferred income taxes | | | 7.2 | | | 0.4 | | | 7.6 | | | 2.6 | | | 10.2 | | | (1.0 | ) | | 9.2 | |
Accumulated other comprehensive income (loss) | | $ | (10.5 | ) | $ | (0.6 | ) | $ | (11.1 | ) | $ | (3.9 | ) | $ | (15.0 | ) | $ | 1.4 | | $ | (13.6 | ) |
Accumulated other comprehensive income arising from unconsolidated affiliates is the Company’s portion of ProLiance Energy, LLC’s and Reliant Services, LLC’s accumulated comprehensive income related to use of cash flow hedges, including commodity contracts and interest rate swaps, and the Company’s portion of Haddington Energy Partners, LP’s accumulated comprehensive income related to unrealized gains and losses on marketable securities. (See Note 3 for more information on unconsolidated affiliates.)
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.
| L. | Excise and Utility Receipts Taxes |
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $42.6 million in 2005, $38.3 million in 2004, and $37.1 million in 2003. Excise and utility receipts taxes expensed are recorded as a component of Taxes other than income taxes.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Certain amounts included in prior years’ consolidated balance sheet and the consolidated statements of income and cash flows have been reclassified to conform the to the current year presentation. These reclassifications had no effect on reported total assets, liabilities, shareholders’ equity, or net income. Reclassifications made to the consolidated statements of income decreased operating income and increased total other income by $3.2 million in 2004 and $3.4 million in 2003. Reclassifications made to the consolidated statement of cash flows decreased net cash flows provided by operating activities and decreased net cash flows required for investing activities by $3.1 million in 2004 and increased net cash flows provided by operating activities and net cash flows required for investing activities by $6.6 million in 2003.
| O. | Other Significant Policies |
Included elsewhere in these Notes are significant accounting policies related to investments in unconsolidated affiliates (Note 3), income taxes (Note 5), earnings per share (Note 10), and derivatives (Note 14).
As more fully described in Note 8, the Company applies the intrinsic method prescribed in APB Opinion 25, “Accounting for Stock Issued to Employees” (APB 25) and related interpretations when measuring compensation expense for its share-based compensation plans. The exercise price of stock options awarded under the Company’s stock option plans is equal to the fair market value of the underlying common stock on the date of grant. Accordingly, no compensation expense has been recognized related to stock option plans. The Company also maintains restricted stock and phantom stock plans for executives, employees, and non-employee directors that result in share-based compensation expense recognized in reported net income consistent with expense that would have been recognized if the Company used the fair value based method prescribed in SFAS No. 123 “Accounting for Stock-Based Compensation” (SFAS 123). Following is the effect on net income and earnings per share as if the fair value based method prescribed in SFAS 123 had been applied to all of the Company’s share-based compensation plans:
| | | | | Year Ended December 31, |
(In millions, except per share amounts) | | | | 2005 | | 2004 | | 2003 | |
| Net Income: | | | | | | | | | |
| As reported | | | | | $ | 136.8 | | $ | 107.9 | | $ | 111.2 | |
Add: Equity-based employee compensation included | | | | | | | | | | | | | |
in reported net income- net of tax | | | | | | 2.1 | | | 1.7 | | | 2.1 | |
Deduct: Total equity-based employee compensation | | | | | | | | | | | | | |
expense determined under fair value based | | | | | | | | | | | | | |
method for all awards- net of tax | | | | | | 2.8 | | | 2.6 | | | 3.4 | |
Pro forma | | | | | $ | 136.1 | | $ | 107.0 | | $ | 109.9 | |
| Basic Earnings Per Share: | | | | | | | | | | | | | |
As reported | | | | | $ | 1.81 | | $ | 1.43 | | $ | 1.58 | |
Pro forma | | | | | | 1.80 | | | 1.42 | | | 1.56 | |
| Diluted Earnings Per Share: | | | | | | | | | | | | | |
As reported | | | | | $ | 1.80 | | $ | 1.42 | | $ | 1.57 | |
Pro forma | | | | | | 1.79 | | | 1.41 | | | 1.55 | |
| | | | | | | | | | | | | | |
SFAS 123 (revised 2004) and related interpretations
In December 2004, the FASB issued Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R) that will require compensation costs related to all share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123R replaces SFAS 123 and supersedes APB 25. In April 2005, the SEC extended the effective date of SFAS 123R to January 1, 2006 for calendar year companies like Vectren. The Company intends to adopt SFAS 123R using the modified prospective method. The adoption of this standard, and subsequent interpretations of the standard, is not expected to have a material effect on the Company’s operating results or financial condition.
| 3. | Investments in Unconsolidated Affiliates |
Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in earnings of unconsolidated affiliates. Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting less write-downs for declines in value judged to be other than temporary. Dividends are recorded as Other - net when received.
Investments in unconsolidated affiliates consist of the following:
| | At December 31, |
(In millions) | | 2005 | | 2004 | |
| ProLiance Energy, LLC | | $ | 136.5 | | $ | 93.2 | |
| Reliant Services, LLC | | | 29.3 | | | 26.5 | |
| Utilicom Networks, LLC & related entities | | | 11.7 | | | 11.7 | |
| Haddington Energy Partnerships | | | 10.8 | | | 20.3 | |
| Pace Carbon Synfuels, LP | | | 9.6 | | | 9.4 | |
| Other partnerships & corporations | | | 16.8 | | | 18.9 | |
Total investments in unconsolidated affiliates | | $ | 214.7 | | $ | 180.0 | |
| | | | | | | | |
ProLiance Energy, LLC
ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), 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 primary customers include Vectren’s utilities and nonregulated gas supply operations as well as Citizens Gas. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. The Company, including its retail gas supply operations, contracted for 95% of its natural gas purchases through ProLiance in 2005. Pre-tax income of $52.4 million, $25.9 million, and $25.9 million was recognized as ProLiance’s contribution to earnings for the years ended December 31, 2005, 2004, and 2003, respectively.
Transactions with ProLiance
Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2005, 2004, and 2003, totaled $1,049.3 million, $875.9 million, and $797.7 million, respectively. Amounts owed to ProLiance at December 31, 2005, and 2004, for those purchases were $159.1 million and $108.2 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.
As required by a June 2005, PUCO order, VEDO solicited bids for its gas supply/portfolio administration services and selected a third party provider under a one year contract. ProLiance’s obligation to supply these services to VEDO ended October 31, 2005. As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreements with Indiana Gas and SIGECO, were approved and extended through March 31, 2007. On February 1, 2006, the Company, Citizens Gas, and three consumer representatives, including the OUCC, filed a settlement agreement with the IURC providing for ProLiance to be the continued supplier of gas supply services to the Company’s Indiana utilities through March 2011. The settlement is subject to approval by the IURC.
Summarized Financial Information
For the year ended December 31, 2005, ProLiance’s revenues, margin, operating income, and net income were (in millions) $3,237.0, $116.0, $87.1, and $86.0, respectively. For the year ended December 31, 2004, ProLiance’s revenues, margin, operating income, and net income were (in millions) $2,573.8, $74.0, $43.2, and $42.6, respectively. For the year ended December 31, 2003, revenues, margin, operating income, and net income were (in millions) $2,269.7, $71.5, $43.3, and $42.5, respectively. As of December 31, 2005, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $870.2, $31.0, $698.2, and $3.3, respectively. As of December 31, 2004, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $595.6, $0.4, $462.2, and $6.6, respectively. As a result of ProLiance’s increased performance for the quarter ending December 31, 2005, its pre-tax earnings exceeded 20% of Vectren’s consolidated pre-tax earnings for the year ended December 31, 2005 and it is therefore considered a significant subsidiary for the purposes of Regulation S-X, paragraph 3.09, as promulgated by the SEC.
ProLiance Contingency
In 2002, a civil lawsuit was filed in the United States District Court for the Northern District of Alabama by the City of Huntsville, Alabama d/b/a Huntsville Utilities, Inc. (Huntsville Utilities) against ProLiance. Huntsville Utilities asserted claims based on alleged breach of contract with respect to the provision of portfolio services and/or pricing advice, fraud, fraudulent inducement, and other theories, including conversion and violations under the Racketeering, Influenced and Corrupt Organizations Act (RICO). These claims related generally to: (1) alleged breach of contract in providing advice and/or administering portfolio arrangements; (2) alleged promises to provide gas at a below-market rate; (3) the creation and repayment of a “winter levelizing program” instituted by ProLiance in conjunction with the Manager of Huntsville’s Gas Utility to allow Huntsville Utilities to pay its natural gas bills from the winter of 2000-2001 over an extended period of time coupled with the alleged ignorance about the program on the part of Huntsville Utilities’ Gas Board and other management, and; (4) conversion of Huntsville Utilities’ gas storage supplies to repay the balance owed on the winter levelizing program and the alleged lack of authority of Huntsville Utilities’ gas manager to approve those sales.
In early 2005, a jury trial commenced and on February 10, 2005, the jury returned a verdict largely in favor of Huntsville Utilities and awarded Huntsville Utilities compensatory damages of $8.2 million and punitive damages of $25.0 million. The jury rejected Huntsville Utilities’ claim of conversion. The jury also rejected a counter claim by ProLiance for payment of amounts due from Huntsville Utilities. Following that verdict, there were a number of issues presented to the judge for resolution. Huntsville made a claim under federal law that it was entitled to have the compensatory damage award trebled. The judge rejected that request. ProLiance made a claim against Huntsville for unjust enrichment, which was also rejected by the judge. The judge also determined that attorneys’ fees and prejudgment interest are owed by ProLiance to Huntsville Utilities. The verdict, as affected by the judge’s subsequent rulings, totals $38.9 million, and ProLiance has posted an appeal bond for that estimated amount. ProLiance’s management believes there are reasonable grounds for appeal which offer a basis for reversal of the entire verdict, and initiated the appeal process on July 26, 2005. The appeal will not be fully briefed until early 2006. The earliest an appellate decision might be issued would be in late in 2006.
While it is reasonably possible that a liability has been incurred by ProLiance, it is not possible to predict the ultimate outcome of an appeal of the verdict. ProLiance recorded a reserve of $3.9 million as of December 31, 2004, reflective of their assessment of the lower end of the range of potential exposure on certain issues identified in the case and inclusive of estimated ongoing litigation costs. Amounts due from Huntsville Utilities were fully reserved by ProLiance in 2003.
As an equity investor in ProLiance, the Company reflected its share of the charge, or $1.4 million after tax, in its 2004 fourth quarter results. That charge does not reflect the possibility that some actual losses might be recovered from insurance carriers, as to which there can be no assurance. It is not expected that an unfavorable outcome on appeal will have a material adverse effect on the Company’s consolidated financial position or its liquidity, but an unfavorable outcome could be material to the Company’s earnings.
Commodity Prices
In response to the anticipated effects of higher gas costs, ProLiance obtained an approximate $112.5 million short-term credit facility for the October 2005 to March 2006 heating season from its existing lenders. This additional line increased ProLiance’s total borrowing capacity to $362.5 million. Neither ProLiance’s $250 million annual credit facility nor the $112.5 million additional line of credit is guaranteed by Vectren Corporation.
Haddington Energy Partnerships
The Company has an approximate 40% ownership interest in both Haddington Energy Partners, LP (Haddington I) and Haddington Energy Partners II, LP (Haddington II). On a combined basis, these partnerships raised a total of $67 million to invest in energy related ventures such as energy storage; cogeneration; natural gas gathering and processing; coal bed methane gathering; hydrogen production and fuel cells; and energy management software. As of December 31, 2005, the Company has no further commitments to invest in Haddington I and is committed to invest $2.5 million in Haddington II. Both Haddington ventures are investment companies accounted for using the equity method of accounting. Pre-tax earnings of $7.7 million and $4.5 million were recognized as the partnerships' contribution to earnings for the years ended December 31, 2005 and 2004, respectively. In 2003, the earnings contribution was not significant.
The following is summarized financial information as to the assets, liabilities, and results of operations of the Haddington Partnerships. For the year ended December 31, 2005, revenues, operating income, and net income were (in millions) $13.2, $12.4, and $22.2, respectively. For the year ended December 31, 2004, revenues, operating income, and net income were (in millions) $3.3, $2.5, and $9.6, respectively. For the year ended December 31, 2003, revenues, operating income, and net income were (in millions) $0.6, ($0.3), and ($0.3), respectively. As of December 31, 2005, investments, other assets, and liabilities were (in millions) $25.0, $1.2, and zero, respectively. As of December 31, 2004, investments, other assets, and liabilities were (in millions) $50.7, $0.2, and zero, respectively.
Pace Carbon Synfuels, LP
Pace Carbon Synfuels, LP (Pace Carbon) is a Delaware limited partnership formed to develop, own, and operate four projects to produce and sell coal-based synthetic fuel (synfuel) utilizing Covol technology. The Company has an 8.3% interest in Pace Carbon which is accounted for using the equity method of accounting. Additional investments in Pace Carbon will be made to the extent Pace Carbon generates federal tax credits, with any such additional investments to be funded by these credits. The investment in Pace Carbon resulted in losses reflected in Equity in earnings of unconsolidated affiliates totaling $15.7 million in 2005, $12.0 million in 2004, and $11.4 million in 2003. The production of synthetic fuel generates IRS Code Section 29 tax credits that are reflected in Income taxes. Net income, including the losses, tax benefits, and tax credits, generated from the investment in Pace Carbon totaled $11.0 million in 2005, $9.0 million in 2004, and $10.3 million in 2003.
The following is summarized financial information as to the assets, liabilities, and results of operations of Pace Carbon. For the year ended December 31, 2005, revenues, margin, operating loss, and net loss were (in millions) $333.4, ($135.3), ($170.3), and ($175.7), respectively. For the year ended December 31, 2004, revenues, margin, operating loss, and net loss were (in millions) $243.0, ($99.8), ($128.6), and ($141.1), respectively. For the year ended December 31, 2003, revenues, margin, operating loss, and net loss were (in millions) $254.2, ($90.7), ($121.3), and ($134.4), respectively. As of December 31, 2005, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $72.8, $53.0, $43.4, and $24.5, respectively. As of December 31, 2004, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $44.1, $57.0, $25.3, and $19.8, respectively.
Section 29 Tax Credit Developments
Under Section 29 of the Internal Revenue Code, manufacturers such as Pace Carbon receive a tax credit for every ton of synthetic fuel sold. To qualify for the credits, the synthetic fuel must meet three primary conditions: 1) there must be a significant chemical change in the coal feedstock, 2) the product must be sold to an unrelated person, and 3) the production facility must have been placed in service before July 1, 1998.
In past rulings, the Internal Revenue Service (IRS) has concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for Section 29 tax credits. The IRS issued a private letter ruling with respect to the four projects on November 11, 1997, and subsequently issued an updated private letter ruling on September 23, 2002. As a partner in Pace Carbon, Vectren has reflected total tax credits under Section 29 in its consolidated results from inception through December 31, 2005, of approximately $79 million. To date, Vectren has been in a position to fully utilize or carryforward the credits generated. Primarily from the use of these credits, the Company generated an Alternative Minimum Tax (AMT) credit carryforward in 2005 and 2004. As a result, the Company has an accumulated AMT credit carryforward of approximately $47.4 million and $31.9 million at December 31, 2005 and 2004, respectively.
During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year and later expanded the audit to include tax years 1999, 2000, and 2001. In May 2004, the IRS completed its audit of the 1998 to 2001 tax returns of Pace Carbon requesting only minor modifications to previously filed returns. There were no changes to any of the filed Section 29 tax credit calculations. The Permanent Subcommittee on Investigations of the U.S. Senate’s Committee on Governmental Affairs, however, has an ongoing investigation related to Section 29 tax credits. Vectren believes it is justified in its reliance on the private letter rulings and most recent IRS audit results for the Pace Carbon facilities.
Further, Section 29 tax credits are only available when the price of oil is less than a base price specified by the tax code, as adjusted for inflation. Credits realized in 2005 or in prior years are not affected by the limitation. However, an average NYMEX price of approximately $60 per barrel in 2006, could begin to limit Section 29 tax credits, with a total phase out occurring at approximately $74 per barrel. Oil prices currently exceed the threshold where Section 29 tax credits would begin to be phased out. While Congress is considering legislation that would positively impact or entirely negate this potential limitation on tax credits related to oil prices in 2006, there can be no assurance Section 29 tax credits will be available in future periods.
Absent the effect of Section 29 tax credits, the Company’s investment in Pace Carbon has operated, and is expected to continue to operate, at a net loss. Due to the potential limitation of Section 29 tax credits, Pace Carbon investors must assess at what level to operate the synfuel plants. If the investors continue to operate the plants, and tax credits are phased out, the Company could potentially incur additional losses. In addition, the Company would be required to assess the potential impairment of its investment in Pace Carbon.
If a phase out of tax credits were to occur in 2006, approximately one third of that phase out risk is proportionately protected by an insurance arrangement that was executed in January 2005.
Utilicom Networks, LLC & Related Entities
The Company has an approximate 2% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom) that if converted bring the Company’s ownership interest up to 16%. The Company also has an approximate 19% equity interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services, such as cable television, high-speed internet, and advanced local and long distance phone services, to the greater Evansville, Indiana area. The Company accounts for its investments in Utilicom and Holdings using the cost method of accounting.
Other Utilicom-related subsidiaries owned franchising agreements to provide broadband services to the greater Indianapolis, Indiana and Dayton, Ohio markets. In 2004, the build out of these markets was further evaluated, and the Company concluded that it was unlikely it would make additional investments in those markets. As a result, the Company recorded charges totaling $6.0 million, or $3.6 million after-tax, to write-off investments made in the Indianapolis and Dayton markets and to write down its investment in SIGECOM.
At December 31, 2005, convertible subordinated debt investments total $33.1 million, all of which is convertible into Utilicom ownership at the Company’s option or upon the event of a public offering of stock by Utilicom. Investments in the convertible notes are included in Other investments. At December 31, 2005, and 2004, the Company’s combined investment in equity and debt securities of Utilicom-related entities totaled $44.8 million and $43.3 million, respectively.
Other Affiliate Transactions
The Company has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2005, 2004, and 2003, fees for these services and construction-related expenditures paid by the Company to its affiliates totaled $21.3 million, $31.2 million, and $37.2 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates other than ProLiance totaled $3.2 million and $1.1 million at December 31, 2005, and 2004, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. Amounts due from unconsolidated affiliates included in Accounts receivable totaled $0.4 million and $0.6 million, respectively, at December 31, 2005, and 2004.
Undistributed Earnings of Unconsolidated Affiliates
As of December 31, 2005, the portion of the Company’s retained earnings that represents undistributed earnings of unconsolidated affiliates approximated $130 million and is primarily comprised of the undistributed earnings of Proliance.
Other investments consist of the following:
| | At December 31, |
(In millions) | | 2005 | | 2004 | |
| Convertible notes receivable from Utilicom-related entities (See Note 3) | | $ | 33.1 | | $ | 31.6 | |
| Leveraged leases | | | 32.6 | | | 33.2 | |
| Other investments | | | 45.9 | | | 50.3 | |
Total other investments | | $ | 111.6 | | $ | 115.1 | |
Leveraged Leases
The Company is a lessor in three leveraged lease agreements under which real estate or equipment is leased to third parties. The total equipment and facilities cost was approximately $76.2 million at both December 31, 2005, and 2004, respectively. The cost of the equipment and facilities was partially financed by non-recourse debt provided by lenders who have been granted an assignment of rentals due under the leases and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee. Such debt amounted to approximately $44.5 million and $48.3 million at December 31, 2005, and 2004, respectively. At December 31, 2005 and 2004, the Company’s leveraged lease investment, net of related deferred tax liabilities, was $7.8 million and $7.0 million, respectively.
Other Investments
Other investments include other notes receivable, the cash surrender value of life insurance policies, restricted cash, and a municipal bond, among other items.
The components of income tax expense and utilization of investment tax credits follow:
| | Year Ended December 31, |
(In millions) | | 2005 | | 2004 | | 2003 | |
| Current: | | | | | | | |
| Federal | | $ | 37.9 | | $ | 24.1 | | $ | (11.9 | ) |
| State | | | 14.8 | | | 9.0 | | | 14.5 | |
Total current taxes | | | 52.7 | | | 33.1 | | | 2.6 | |
| Deferred: | | | | | | | | | | |
| Federal | | | (6.0 | ) | | 3.8 | | | 39.1 | |
| State | | | (0.2 | ) | | 4.3 | | | (1.8 | ) |
Total deferred taxes | | | (6.2 | ) | | 8.1 | | | 37.3 | |
| Amortization of investment tax credits | | | (2.4 | ) | | (2.2 | ) | | (2.2 | ) |
Total income tax expense | | $ | 44.1 | | $ | 39.0 | | $ | 37.7 | |
| | | | | | | | | | | |
A reconciliation of the federal statutory rate to the effective income tax rate follows:
| | Year Ended December 31, |
| | | 2005 | | 2004 | | 2003 | |
| Statutory rate | | | 35.0 | % | | 35.0 | % | | 35.0 | % |
| State and local taxes-net of federal benefit | | | 5.5 | | | 5.9 | | | 5.5 | |
| Section 29 tax credits | | | (12.3 | ) | | (11.6 | ) | | (11.7 | ) |
| Adjustment of income tax accruals | | | (1.9 | ) | | (0.1 | ) | | (0.1 | ) |
| Amortization of investment tax credit | | | (1.3 | ) | | (1.5 | ) | | (1.5 | ) |
| Other tax credits | | | (0.4 | ) | | (0.6 | ) | | (0.9 | ) |
| All other-net | | | (0.2 | ) | | (0.6 | ) | | (1.0 | ) |
Effective tax rate | | | 24.4 | % | | 26.5 | % | | 25.3 | % |
The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:
| | At December 31, |
(In millions) | | 2005 | | 2004 | |
| Noncurrent deferred tax liabilities (assets): | | | | | |
| Depreciation & cost recovery timing differences | | $ | 288.3 | | $ | 253.0 | |
| Leveraged leases | | | 24.8 | | | 26.2 | |
| Regulatory assets recoverable through future rates | | | 19.3 | | | 19.2 | |
| Demand side management programs | | | 7.7 | | | 12.5 | |
| Alternative minimum tax carryforward | | | (47.4 | ) | | (31.9 | ) |
| Employee benefit obligations | | | (36.0 | ) | | (29.2 | ) |
| Other comprehensive income | | | (9.2 | ) | | (10.2 | ) |
| Regulatory liabilities to be settled through future rates | | | (8.1 | ) | | (7.7 | ) |
| Other – net | | | (12.1 | ) | | 2.1 | |
| Net noncurrent deferred tax liability | | | 227.3 | | | 234.0 | |
| Current deferred tax liabilities: | | | | | | | |
| Deferred fuel costs-net | | | 7.6 | | | 4.5 | |
| Net current deferred tax liability | | | 7.6 | | | 4.5 | |
Net deferred tax liability | | $ | 234.9 | | $ | 238.5 | |
| | | | | | | | |
At December 31, 2005, and 2004, investment tax credits totaling $11.8 million and $14.2 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. At December 31, 2005, the Company has alternative minimum tax carryforwards of $47.4 million, which do not expire and $1.6 million of other tax credit carryforwards that expire in approximately 20 years.
| 6. | Retirement Plans & Other Postretirement Benefits |
At December 31, 2005, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and three other postretirement benefit plans. The defined benefit pension and other postretirement benefit plans, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The Company has Voluntary Employee Beneficiary Association (VEBA) Trust Agreements for the partial funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries. Annual VEBA funding is discretionary. To the extent these postretirement benefits are funded, the benefits are not liabilities in these consolidated financial statements. The detailed disclosures of benefit components that follow are based on an actuarial valuation using a measurement date as of September 30. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” Other postretirement benefit plans are aggregated under the heading “Other Benefits.”
Medicare Prescription Drug Improvement and Modernization Act of 2003
On December 8, 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (Medicare Act) was enacted. The Medicare Act introduces a Medicare prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least “actuarially equivalent” to the Medicare benefit. In accordance with FASB Staff Position (FSP) 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003, the Company elected to early adopt the accounting for the federal subsidy under the Medicare Act on April 1, 2004, and remeasured its obligation as of January 1, 2004, to incorporate the impact of the Medicare Act which resulted in a reduction to the accumulated benefit obligation of $10.4 million. For the years ended December 31, 2005 and 2004, the remeasurement resulted in a reduction in net periodic postretirement benefit cost of $0.7 million and $0.8 million, respectively. The reduction is a component of amortization of actuarial loss (gain) in the information that follows. The Company has applied to the federal government for the subsidy and will begin receiving the subsidy in 2006.
Benefit Obligations
A reconciliation of the Company’s benefit obligations at December 31, 2005, and 2004, follows:
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits |
(In millions) | | 2005 | | 2004 | | 2005 | | 2004 | |
| Benefit obligation, beginning of period | | $ | 241.1 | | $ | 222.7 | | $ | 92.8 | | $ | 97.3 | |
| Service cost – benefits earned during the period | | | 5.6 | | | 6.6 | | | 0.7 | | | 0.9 | |
| Interest cost on projected benefit obligation | | | 13.8 | | | 13.4 | | | 4.5 | | | 5.3 | |
| Plan participants' contributions | | | - | | | - | | | 1.4 | | | 1.3 | |
| Plan amendments | | | - | | | 4.5 | | | (21.7 | ) | | - | |
| Actuarial loss (gain) | | | 6.3 | | | 5.3 | | | 1.4 | | | (5.3 | ) |
| Benefits paid | | | (11.4 | ) | | (11.4 | ) | | (7.1 | ) | | (6.7 | ) |
Benefit obligation, end of period | | $ | 255.4 | | $ | 241.1 | | $ | 72.0 | | $ | 92.8 | |
The accumulated benefit obligation for all defined benefit pension plans was $235.8 million and $219.5 million at December 31, 2005, and 2004, respectively.
The benefit obligation as of December 31, 2005, and 2004, was calculated using the following weighted average assumptions:
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits |
| | | 2005 | | 2004 | | 2005 | | 2004 | |
| Discount rate | | | 5.50 | % | | 5.75 | % | | 5.50 | % | | 5.75 | % |
| Rate of compensation increase | | | 3.25 | % | | 3.50 | % | | 3.25 | % | | 3.50 | % |
| Expected increase in Consumer Price Index | | | N/A | | | N/A | | | 3.50 | % | | 3.50 | % |
To calculate the 2005 ending postretirement benefit obligation, medical claims costs in 2006 were assumed to be 10% higher than those incurred in 2005. That trend was assumed to gradually decline to 5% in 2010 and remain level thereafter. A one percentage point increase in assumed health care cost trend rates would have increased the benefit obligation by approximately $1.2 million, conversely, a one percentage point decrease would have decreased the obligation by approximately $1.2 million. To calculate the 2004 ending postretirement benefit obligation, medical claims costs in 2005 were assumed to be 10% higher than those incurred in 2004. That trend was assumed to gradually decline to 5% in 2009 and remain level thereafter.
Plan Assets
A reconciliation of the Company’s plan assets at December 31, 2005, and 2004, follows:
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits |
(In millions) | | 2005 | | 2004 | | 2005 | | 2004 | |
| Plan assets at fair value, beginning of period | | $ | 161.2 | | $ | 147.8 | | $ | 8.3 | | $ | 9.2 | |
| Actual return on plan assets | | | 20.1 | | | 16.3 | | | 1.3 | | | 0.7 | |
| Employer contributions | | | 3.7 | | | 8.5 | | | 4.1 | | | 3.8 | |
| Plan participants' contributions | | | - | | | - | | | 1.4 | | | 1.3 | |
| Benefits paid | | | (11.4 | ) | | (11.4 | ) | | (7.7 | ) | | (6.7 | ) |
Fair value of plan assets, end of period | | $ | 173.6 | | $ | 161.2 | | $ | 7.4 | | $ | 8.3 | |
| | | | | | | | | | | | | | |
| | | | Pension Benefits | | Other Benefits |
| | | | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | | 2003 |
| Equity securities | | 64% | | 60% | | 59% | | 53% | | 60% | | 54% |
| Debt securities | | 33% | | 33% | | 35% | | 37% | | 36% | | 32% |
| Real estate | | 3% | | 6% | | 6% | | - | | - | | - |
| Short term investments & other | | - | | 1% | | - | | 10% | | 4% | | 14% |
| | Total | | 100% | | 100% | | 100% | | 100% | | 100% | | 100% |
The Company invests in a master trust that benefits its qualified defined benefit pension plans. The general investment objectives are to invest in a diversified portfolio, comprised of both equity and fixed income investments, which are further diversified among various asset classes. The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk. The investment objectives specify a targeted investment allocation for the pension plans of 60% equities, 35% debt, and 5% real estate for 2006, and for postretirement plans of 55% equities, 35% debt, and 10% short-term investments and other for 2006. Objectives do not target a specific return by asset class. The portfolio’s return is monitored in total and investment objectives are long-term in nature.
Funded Status
The funded status of the plans, reconciled to amounts reflected in the balance sheets as of December 31, 2005, and 2004, follows:
| | | | | | | | | | |
| | | Pension Benefits | | Other Benefits |
(In millions) | | 2005 | | 2004 | | 2005 | | 2004 | |
| Fair value of plan assets, end of period | | $ | 173.6 | | $ | 161.2 | | $ | 7.4 | | $ | 8.3 | |
| Benefit obligation, end of period | | | (255.4 | ) | | (241.1 | ) | | (72.0 | ) | | (92.8 | ) |
Funded status, end of period | | | (81.8 | ) | | (79.9 | ) | | (64.6 | ) | | (84.5 | ) |
| Unrecognized net loss (gain) | | | 48.6 | | | 50.9 | | | (2.0 | ) | | (3.5 | ) |
| Unrecognized prior service cost | | | 12.6 | | | 14.2 | | | (6.3 | ) | | - | |
| Unrecognized transitional (asset) obligation | | | - | | | - | | | 9.9 | | | 26.2 | |
| Post measurement date adjustments | | | 1.0 | | | 0.2 | | | 1.2 | | | 1.3 | |
Net amount recognized, end of year | | $ | (19.6 | ) | $ | (14.6 | ) | $ | (61.8 | ) | $ | (60.5 | ) |
As of December 31, 2005, and 2004, the funded status of the SERP, which is included in Pension Benefits in the chart above, was an unfunded amount of $14.4 million and $13.8 million, respectively, and the net amount recognized in the balance sheet related to the SERP as of December 31, 2005, and 2004 was a liability of $9.1 million and $8.4 million, respectively.
At December 31, 2005, and 2004, all pension and postretirement plans had accumulated benefit obligations in excess of plan assets. As required by SFAS 87, the Company has recorded additional minimum pension liability adjustments to reflect the total unfunded accumulated liability arising from its pension plans. This additional minimum pension liability adjustment is included in Deferred credits & other liabilities. The offset to this additional liability is recorded to an intangible asset included in Other assets to the extent pension plans have unrecognized prior service cost. Any unfunded or unaccrued amount in excess of prior service cost is recorded in net of tax amounts to Accumulated other comprehensive income in shareholders’ equity.
The effects of additional minimum pension liability adjustments at December 31, 2005, and 2004, follow:
| | | | | | |
(In millions) | | 2005 | | 2004 | |
| Minimum pension liability adjustment, beginning of year | | $ | 43.5 | | $ | 39.7 | |
| Change in minimum pension liability adjustment included in: | | | | | | | |
| Other comprehensive income before effect of taxes | | | 0.3 | | | 0.1 | |
| Other assets | | | (2.2 | ) | | 3.7 | |
Minimum pension liability adjustment, end of year | | $ | 41.6 | | $ | 43.5 | |
| Offset included in: | | | | | | | |
Accumulated other comprehensive income | | $ | 17.2 | | $ | 17.5 | |
Other assets | | | 12.6 | | | 14.2 | |
Deferred income taxes | | | 11.8 | | | 11.8 | |
| | | | | | | | |
In 2006, the Company expects to make contributions of approximately $5.2 million to its pension plan trusts. In addition, the Company expects to make payments totaling approximately $0.8 million directly to SERP participants and approximately $4.4 million directly to those participating in other postretirement plans.
Expected retiree pension benefit payments, including the SERP, projected to be required during the years following 2005 (in millions) are $12.4 in 2006, $12.2 in 2007, $12.6 in 2008 $12.7 in 2009, $13.3 in 2010 and $70.8 in years 2011-2015. Expected benefit payments projected to be required for postretirement benefits during the years following 2005 (in millions) are $4.8 in 2006, $4.4 in 2007, $4.6 in 2008, $4.8 in 2009, $5.0 in 2010 and $25.5 in years 2011-2015.
Net Periodic Benefit Costs
A summary of the components of net periodic benefit cost for the three years ended December 31, 2005, follows:
| | | | | | | | | | | | | | |
| | | Pension Benefits | | Other Benefits |
(In millions) | | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | | 2003 | |
| Service cost | | $ | 5.6 | | $ | 6.6 | | $ | 5.8 | | $ | 0.7 | | $ | 0.9 | | $ | 0.9 | |
| Interest cost | | | 13.8 | | | 13.4 | | | 13.6 | | | 4.5 | | | 5.3 | | | 5.4 | |
| Expected return on plan assets | | | (13.2 | ) | | (13.5 | ) | | (14.8 | ) | | (0.6 | ) | | (0.7 | ) | | (0.7 | ) |
| Amortization of prior service cost | | | 1.6 | | | 0.9 | | | 0.8 | | | (0.6 | ) | | - | | | - | |
| Amortization of actuarial loss (gain) | | | 1.8 | | | 1.0 | | | 0.5 | | | (0.2 | ) | | (0.2 | ) | | (0.5 | ) |
| Amortization of transitional (asset) obligation | | | - | | | (0.2 | ) | | (0.2 | ) | | 1.5 | | | 2.9 | | | 2.9 | |
Net periodic benefit cost | | $ | 9.6 | | $ | 8.2 | | $ | 5.7 | | $ | 5.3 | | $ | 8.2 | | $ | 8.0 | |
| | | | | | | | | | | | | | | | | | | | |
A portion of benefit costs are capitalized as utility plant. Costs capitalized in 2005, 2004, and 2003 approximated $4.2, million, $4.6 million, and $3.8 million, respectively.
To calculate the expected return on plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. The fair market value of the assets at the measurement date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period.
Based on a targeted 60% equity, 35% debt, and 5% real estate allocation for the pension plans, the Company has used a long-term expected rate of return of 8.25% to calculate 2005 periodic benefit cost. For fiscal 2006, the expected long-term rate of return will also be 8.25%.
In January 2005, the Company announced the amendment of certain postretirement benefit plans, effective January 1, 2006. The amendment resulted in an estimated $4 million annual decrease in periodic cost, of which approximately $3.1 million was recognized in 2005. Two of the unions that represent bargaining employees at the Company’s regulated subsidiaries have advised the Company that it is their position that these changes are not permitted under the existing collective bargaining agreements which govern the relationship between the employees and the affected subsidiaries. With assistance from legal counsel, management has analyzed the unions’ position and continues to believe that the Company has reserved the right to amend the affected plans and that changing these benefits for retirees is not a mandatory subject of bargaining.
The weighted averages of significant assumptions used to determine net periodic benefit costs follow:
| | | | | | | | | | | | | | |
| | | Pension Benefits | | Other Benefits |
(In millions) | | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | | 2003 | |
| Discount rate | | | 5.75 | % | | 6.00 | % | | 6.75 | % | | 5.75 | % | | 6.00 | % | | 6.75 | % |
| Rate of compensation increase | | | 3.50 | % | | 3.50 | % | | 4.25 | % | | 3.50 | % | | 3.50 | % | | 4.25 | % |
| Expected return on plan assets | | | 8.25 | % | | 8.50 | % | | 9.00 | % | | 8.25 | % | | 8.50 | % | | 9.00 | % |
| Expected increase in Consumer Price Index | | | N/A | | | N/A | | | N/A | | | 3.50 | % | | 3.50 | % | | 3.50 | % |
Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs. The Company’s benefit plans limit the Company’s exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI). Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants.
Defined Contribution Plan
The Company also has defined contribution retirement savings plans that are qualified under sections 401(a) and 401(k) of the Internal Revenue Code. During 2005, 2004 and 2003, the Company made contributions to these plans of $3.5 million, $3.5 million, and $3.6 million, respectively.
Deferred Compensation Plans
The Company has nonqualified deferred compensation plans, which permit eligible executives and non-employee directors to defer portions of their compensation and vested restricted stock. A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts. The measurement funds are similar to the funds in the Company's defined contribution plan and include an investment in phantom stock units of the Company. The account balance fluctuates with the investment returns on those funds. At December 31, 2005 and 2004, the liability associated with these plans totaled $20.6 million and $16.8 million, respectively, and is included in Deferred credits and other liabilities. Deferred compensation expense was $2.6 million, $1.6 million and $1.3 million in 2005, 2004, and 2003, respectively.
The Company has established certain investments to fund its deferred compensation liabilities that are currently funded primarily through corporate-owned life insurance policies. These investments, which are consolidated, are available to pay plan benefits and are subject to the claims of the Company's creditors. The cash surrender value of these policies included in Other investments on the Consolidated Balance Sheets were $16.1 million and $14.3 million at December 31, 2005 and 2004, respectively. Earnings from those investments totaled $1.8 million in 2005, $0.6 million in 2004, and $1.5 million in 2003.
| 7. | Borrowing Arrangements |
Long-Term Debt
Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
| | | | | At December 31, |
(In millions) | | | | 2005 | | 2004 | |
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 | | | - | |
| 2018, 5.75% | | | | | | 100.0 | | | 100.0 | |
| 2031, 7.25% | | | | | | 100.0 | | | 100.0 | |
| 2035, 6.10% | | | | | | 75.0 | | | - | |
Total Utility Holdings | | | | | | 700.0 | | | 550.0 | |
SIGECO | | | | | | | | | | |
| First Mortgage Bonds | | | | | | | | | | |
| 2016, 1986 Series, 8.875% | | | | | | 13.0 | | | 13.0 | |
| 2023, 1993 Environmental Improvement Series B, current adjustable rate 3.70%, | | | | | | | | | | |
| tax exempt, auction rate mode, 2005 weighted average: 2.66% | | | | | | 22.6 | | | 22.6 | |
| 2029, 1999 Senior Notes, 6.72% | | | | | | 80.0 | | | 80.0 | |
| 2015, 1985 Pollution Control Series A, current adjustable rate 3.35%, tax exempt, | | | | | | | | | | |
| auction rate mode, 2005 weighted average: 2.46% | | | | | | 9.8 | | | 9.8 | |
| 2020, 1998 Pollution Control Series B, 4.50%, tax exempt | | | | | | 4.6 | | | 4.6 | |
| 2030, 1998 Pollution Control Series B, 5.00%, tax exempt | | | | | | 22.0 | | | 22.0 | |
| 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt | | | | | | 22.5 | | | 22.5 | |
| Total first mortgage bonds | | | | | | 174.5 | | | 174.5 | |
| Senior Secured Bonds to Third Parties: | | | | | | | | | | |
| 2025, 1998 Pollution Control Series A, current adjustable rate 4.75%, tax exempt, | | | | | | | | | | |
| next rate adjustment: 2006 | | | | | | 31.5 | | | 31.5 | |
| Senior Unsecured Bonds to Third Parties: | | | | | | | | | | |
| 2030, 1998 Pollution Control Series C, current adjustable rate 5.00%, tax exempt, | | | | | | | | | | |
| next rate adjustment: 2006 | | | | | | 22.2 | | | 22.2 | |
Total SIGECO | | | | | | 228.2 | | | 228.2 | |
Indiana Gas | | | | | | | | | | |
| Senior Unsecured Notes | | | | | | | | | | |
| 2007, Series E, 6.54% | | | | | | 6.5 | | | 6.5 | |
| 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 | |
| 2030, Insured Quarterly, 7.45% | | | | | | - | | | 49.9 | |
Total Indiana Gas | | | | | | 127.5 | | | 177.4 | |
| | | At December 31, |
| (In millions) | | 2005 | | 2004 | |
Vectren Capital Corp. | | | | | |
| Fixed Rate Senior Unsecured Notes | | | | | | | |
| 2005, 7.67% | | | - | | | 38.0 | |
| 2007, 7.83% | | | 17.5 | | | 17.5 | |
| 2010, 4.99% | | | 25.0 | | | - | |
| 2010, 7.98% | | | 22.5 | | | 22.5 | |
| 2012, 5.13% | | | 25.0 | | | - | |
| 2012, 7.43% | | | 35.0 | | | 35.0 | |
| 2015, 5.31% | | | 75.0 | | | - | |
Total Vectren Capital Corp. | | | 200.0 | | | 113.0 | |
| Other Long-Term Notes Payable | | | 1.2 | | | 1.6 | |
Total long-term debt outstanding | | | 1,256.9 | | | 1,070.2 | |
| Current maturities of long-term debt | | | (0.4 | ) | | (38.5 | ) |
| Debt subject to tender | | | (53.7 | ) | | (10.0 | ) |
| Unamortized debt premium & discount - net | | | (4.4 | ) | | (4.6 | ) |
| Fair value of hedging arrangements | | | (0.4 | ) | | (0.5 | ) |
Total long-term debt-net | | | 1,198.0 | | | 1,016.6 | |
Utility Holdings 2005 Issuance
In December 2005, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $150 million in two $75 million tranches. The first tranche was 10-year notes due December 2015, with an interest rate of 5.45% priced at 99.799% to yield 5.47% to maturity (2015 Notes). The second tranche was 30-year notes due December 2035 with an interest rate of 6.10% priced at 99.799% to yield 6.11% to maturity (2035 Notes).
The notes have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by Utility Holdings, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2015 Notes and 25 basis points for the 2035 Notes.
In January and June 2005, Utility Holdings entered into forward starting interest rate swaps with a total notional amount of $75 million. Upon issuance of the debt, the instruments were settled resulting in the receipt of approximately $1.9 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issue maturing December 2035.
The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $150 million.
Vectren Capital Corp. Debt Issuance
On October 11, 2005, Vectren and Vectren Capital Corp., its wholly-owned subsidiary (Vectren Capital), entered into a private placement Note Purchase Agreement (2005 Note Purchase Agreement) pursuant to which various institutional investors purchased the following tranches of notes from Vectren Capital: (i) $25 million 4.99% Guaranteed Senior Notes, Series A due 2010, (ii) $25 million 5.13% Guaranteed Senior Notes, Series B due 2012 and (iii) $75 million 5.31% Guaranteed Senior Notes, Series C due 2015. These Guaranteed Senior Notes are unconditionally guaranteed by Vectren, the parent of Vectren Capital. The proceeds from this financing were received on December 15, 2005. This Note Purchase Agreement contains customary representations, warranties and covenants, including a covenant to the effect that the ratio of consolidated total debt to consolidated total capitalization will not exceed 75%.
On October 11, 2005, Vectren and Vectren Capital entered into First Amendments with respect to a Note Purchase Agreement dated as of December 31, 2000 pursuant to which Vectren Capital issued to institutional investors the following tranches of notes: (i) $38 million 7.67% Senior Notes due 2005, (ii) $17.5 million 7.83% Senior Notes due 2007, (iii) $22.5 million 7.98% Senior Notes due 2010 and (iv) a Note Purchase Agreement, dated April 25, 1997, pursuant to which Vectren Capital issued to an institutional investor a $35 million 7.43% Senior Note due 2012. The First Amendments (i) conform the covenants to those contained in the 2005 Note Purchase Agreement, (ii) eliminate a credit ratings trigger which would have afforded noteholders the option to require prepayment if the ratings of Indiana Gas or SIGECO fell below a certain level, (iii) substitute the unconditional guarantee by Vectren of the notes for the more limited support agreement previously in place and (iv) provide for a 100 basis point increase in interest rates if the ratio of consolidated total debt to total capitalization exceeds 65%.
Utility Holdings 2003 Issuance
In July 2003, Utility Holdings issued senior unsecured notes with an aggregate principal amount of $200 million in two $100 million tranches. The first tranche was 10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746% to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity (2018 Notes).
The notes have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by Utility Holdings, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2013 Notes and 25 basis points for the 2018 Notes.
Shortly before these issues, Utility Holdings entered into several treasury locks with a total notional amount of $150.0 million. Upon issuance of the debt, the treasury locks were settled resulting in the receipt of $5.7 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issues.
The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $203 million.
Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements, such as when notes are remarketed. During 2005, no debt was put to the Company. During 2004 and 2003, debt totaling $2.5 million, and $0.1 million, respectively, was put to the Company. Debt which may be put to the Company during the years following 2005 (in millions) is $53.7 in 2006, $20.0 in 2007, zero in 2008, $80.0 in 2009, $10.0 in 2010, and $30.0 thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.
SIGECO and Indiana Gas Debt Calls
In 2005, the Company called at par $49.9 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2030, and in 2004, called at par $20.0 million of Indiana Gas insured quarterly senior unsecured notes originally due in 2015. The notes called in 2005 and 2004 had stated interest rates of 7.45% and 7.15%, respectively.
During 2003, the Company called two first mortgage bonds outstanding at SIGECO and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond had a principal amount of $45.0 million, an interest rate of 7.60%, was originally due in 2023, and was redeemed at 103.745% of its stated principal amount. The second SIGECO bond had a principal amount of $20.0 million, an interest rate of 7.625%, was originally due in 2025, and was redeemed at 103.763% of the stated principal amount.
The first Indiana Gas note had a remaining principal amount of $21.3 million, an interest rate of 9.375%, was originally due in 2021, and was redeemed at 105.525% of the stated principal amount. The second Indiana Gas note had a principal amount of $13.5 million, an interest rate of 6.75%, was originally due in 2028, and was redeemed at the principal amount.
Pursuant to regulatory authority, the premiums paid to retire the net carrying value of these notes totaling $3.6 million were deferred in Regulatory assets.
Other Financing Transactions
During 2004, the Company remarketed two first mortgage bonds outstanding at SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset weekly. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These remarketing efforts resulted in the extinguishment of debt and the reissuance of new debt at generally the same par value. These bonds are classified in Long-term debt.
Other Company debt totaling $38.0 million in 2005, $15.0 million in 2004, and $18.5 million in 2003 was retired as scheduled.
Future Long-Term Debt Sinking Fund Requirements & Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1% 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 2006 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2006 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2005, $549.4 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $1.9 billion at December 31, 2005.
Consolidated maturities and sinking fund requirements on long-term debt during the five years following 2005 (in millions) are $0.4 in 2006, $24.0 in 2007, zero in 2008 and in 2009, and $47.5 in 2010.
Short-Term Borrowings
At December 31, 2005, the Company has $780.0 million of short-term borrowing capacity, including $520.0 million for the Utility Group operations and $260.0 million for the wholly owned Nonregulated Group and corporate operations, of which approximately $293.0 million is available for the Utility Group operations and approximately $187.0 million is available for wholly owned Nonregulated Group and corporate operations. These short-term borrowing arrangements expire in 2010. Utility Group credit facilities are primarily used to support the Company’s access to the commercial paper market. Interest rates and outstanding balances associated with short term borrowing arrangements follows.
| | | Year Ended December 31, |
(In millions) | | 2005 | | 2004 | | 2003 | |
| Weighted average commercial paper and bank loans | | | | | | | |
| outstanding during the year | | $ | 304.5 | | $ | 211.4 | | $ | 296.9 | |
| Weighted average interest rates during the year | | | | | | | | | | |
| Commercial paper | | | 3.42 | % | | 1.78 | % | | 1.36 | % |
| Bank loans | | | 3.82 | % | | 2.12 | % | | 1.94 | % |
| | �� | At December 31, | | | | |
(In millions) | | | 2005 | | | 2004 | | | | |
| Commercial paper | | $ | 226.9 | | $ | 104.3 | | | | |
| Bank loans | | | 73.0 | | | 308.0 | | | | |
| Other | | | - | | | 0.1 | | | | |
Total short-term borrowings | | $ | 299.9 | | $ | 412.4 | | | | |
| | | | | | | | | | | |
During 2005, the Company increased the capacity of its utility-related credit facilities by approximately $165 million in response to increased natural gas costs.
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 of December 31, 2005, the Company was in compliance with all financial covenants.
Ratings Triggers
In conjunction with the transaction described above, the ratings triggers that related to $113.0 million of Vectren Capital’s senior unsecured notes, outstanding at December 31, 2004, were removed. None of Vectren’s other outstanding debt contains ratings triggers.
Debt Guarantees
Vectren Corporation guarantees Vectren Capital’s long-term and short-term debt, which totaled $200.0 million and $73.0 million, respectively, at December 31, 2005. Utility Holdings' currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings' long-term and short-term debt outstanding at December 31, 2005, totaled $700.0 million and $226.9 million, respectively.
| 8 | Share-Based Incentive Plans |
The Company has various share-based incentive plans to encourage executives, strategic employees, and non-employee directors to remain with the Company and to more closely align their interest with those of the Company’s shareholders.
Stock Option Plans
Stock options granted to employees in 2005, 2004 and 2003 become fully vested and exercisable at the end of three years. Stock options granted to employees in 2001 and 2002 become fully vested and exercisable at the end of five years. Stock options granted to non-employee directors since 2001 become fully vested and exercisable at the end of one year. All options granted prior to 2001 are fully vested and exercisable. Options granted both before and after 2001 generally expire ten years from the date of grant. Options generally vest on a straight-line graded basis over their terms.
A summary of activity within the Company’s stock option plans for the past three years follows:
| | | | | | |
| | | Options | | Wtd. Avg. Exercise Price | |
| Outstanding at January 1, 2003 | | | 1,349,262 | | $ | 21.48 | |
| Granted | | | 521,200 | | | 23.07 | |
| Cancelled | | | (5,800 | ) | | 22.56 | |
| Exercised | | | (61,766 | ) | | 17.30 | |
| Outstanding at December 31, 2003 | | | 1,802,896 | | | 22.08 | |
| Granted | | | 219,000 | | | 24.74 | |
| Cancelled | | | (6,043 | ) | | 19.66 | |
| Exercised | | | (90,400 | ) | | 18.27 | |
| Outstanding at December 31, 2004 | | | 1,925,453 | | | 22.57 | |
| Granted | | | 289,294 | | | 26.64 | |
| Cancelled | | | (7,879 | ) | | 15.32 | |
| Exercised | | | (83,289 | ) | | 21.22 | |
Outstanding at December 31, 2005 | | | 2,123,579 | | $ | 23.18 | |
| | | | | | | | |
The following table summarizes information about stock options outstanding and exercisable at December 31, 2005:
| | | | | | | | | | | |
| | | Outstanding | | Exercisable |
Range of Exercise Prices | | # of Options | | Wtd. Avg.Remaining Contractual Life | | Wtd. Avg. Exercise Price | | # of Options | | Wtd. Avg. Exercise Price |
| $13.82 - $17.45 | | 25,318 | | 0.5 | $ | 17.44 | | 25,318 | $ | 17.44 |
| $19.83 - $20.26 | | 249,978 | | 2.4 | | 20.08 | | 249,978 | | 20.08 |
| $22.37 - $22.57 | | 819,117 | | 5.6 | | 22.54 | | 679,318 | | 22.54 |
| $23.19 - $25.59 | | 739,872 | | 6.8 | | 23.78 | | 464,830 | | 23.64 |
| $25.60 - $30.00 | | 289,294 | | 9.0 | | 26.64 | | 3,500 | | 26.63 |
Total | | 2,123,579 | | 6.0 | $ | 23.18 | | 1,422,944 | $ | 22.39 |
Stock options that were exercisable and those options’ weighted average exercise prices were 1,154,510 and $22.57, respectively, at December 31, 2004 and 924,849 and $21.34, respectively, at December 31, 2003.
The fair value of each option granted used to determine pro forma net income as disclosed in Note 2, is estimated as of the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in the years ended December 31, 2005, 2004, and 2003: risk-free rate of return of 4.22%, 4.37%, and 4.00%, respectively; expected option term of 8 years for all 3 years presented; expected volatility of 21.43%, 24.01%, and 26.98%, respectively; and dividend yield of 4.4%, 4.65%, and 4.81% respectively. The weighted average fair value of options granted in 2005, 2004, and 2003 were $4.36, $4.39, and $4.31, respectively.
Restricted Stock & Phantom Stock Plans
The Company maintains a performance-based restricted stock plan for its executives and employees and a non-performance based restricted stock plan through which non-employee directors receive a portion of their director fees. A summary of restricted stock activity during the three years ended December 31, 2005, follows:
| | Restricted Stock |
| Outstanding at January 1, 2003 | | 240,687 |
| Grants | | 120,228 |
| Forfeitures | | (14,136) |
| Vested | | (137,777) |
| Outstanding at December 31, 2003 | | 209,002 |
| Grants | | 168,680 |
| Forfeitures | | (150) |
| Vested | | (76,980) |
| Outstanding at December 31, 2004 | | 300,552 |
| Grants | | 164,669 |
| Forfeitures | | (35,017) |
| Vested | | (76,619) |
Outstanding at December 31, 2005 | | 353,585 |
| | | |
For the years ended December 31, 2005, 2004, and 2003, the weighted average fair value per share of restricted stock granted was $26.72, $24.87, and $23.33, respectively. In January 2006, 170,100 restricted shares were issued. The share price on the date of grant was $27.62. The restrictions lift over a four year period subject to adjustments for performance.
Executives and non-employee directors may defer certain portions of their salary, annual bonus, incentive compensation, and earned restricted stock into phantom stock units. Such units are vested when granted.
Compensation expense, net of amounts capitalized into utility plant projects, associated with the restricted stock and phantom stock plans for the years ended December 31, 2005, 2004, and 2003, was $3.5 million, $2.9 million, and $3.6 million, respectively.
| 9. | Common Shareholders’ Equity |
Equity Issuance
In March 2003, the Company filed a registration statement with the Securities and Exchange Commission with respect to a public offering of authorized but previously unissued shares of common stock as well as the senior unsecured notes of Utility Holdings described above in Note 7. In August 2003, the registration became effective, and an agreement was reached to sell approximately 7.4 million shares to a group of underwriters. The net proceeds totaled $163.2 million.
Authorized, Reserved Common and Preferred Shares
At December 31, 2005, and 2004, the Company was authorized to issue 480.0 million shares of common stock and 20.0 million shares of preferred stock. Of the authorized common shares, approximately 9.3 million shares at December 31, 2005, and 9.4 million shares at December 31, 2004, were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan. At both December 31, 2005, and 2004, there were 394.6 million of authorized shares of common stock, and all authorized shares of preferred stock available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions.
Shareholder Rights Agreement
The Company’s board of directors adopted a Shareholder Rights Agreement (Rights Agreement). As part of the Rights Agreement, the board of directors declared a dividend distribution of one right for each outstanding Vectren common share. Each right entitles the holder to purchase from Vectren one share of common stock at a price of $65.00 per share (subject to adjustment to prevent dilution). The rights become exercisable 10 days following a public announcement that a person or group of affiliated or associated persons (Vectren Acquiring Person) has acquired beneficial ownership of 15% or more of the outstanding Vectren common shares (or a 10% acquirer who is determined by the board of directors to be an adverse person), or 10 days following the announcement of an intention to make a tender offer or exchange offer, the consummation of which would result in any person or group becoming a Vectren Acquiring Person. The Vectren Shareholder Rights Agreement expires October 21, 2009.
Basic earnings per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share assumes the conversion of stock options into common shares and the lifting of restrictions on issued restricted shares using the treasury stock method to the extent the effect would be dilutive. The following table illustrates the basic and dilutive earnings per share calculations for the three years ended December 31, 2005:
| | | Year Ended December 31, |
(In millions, except per share data) | | 2005 | | 2004 | | 2003 | |
Numerator: | | | | | | | |
| Numerator for basic and diluted EPS - Net income | | $ | 136.8 | | $ | 107.9 | | $ | 111.2 | |
Denominator: | | | | | | | | | | |
| Denominator for basic EPS - Weighted average | | | | | | | | | | |
| common shares outstanding | | | 75.6 | | | 75.6 | | | 70.6 | |
| Conversion of stock options and lifting of | | | | | | | | | | |
| restrictions on issued restricted stock | | | 0.5 | | | 0.3 | | | 0.2 | |
| Denominator for diluted EPS - Adjusted weighted | | | | | | | | | | |
| average shares outstanding and assumed | | | | | | | | | | |
| conversions outstanding | | | 76.1 | | | 75.9 | | | 70.8 | |
Basic earnings per share | | $ | 1.81 | | $ | 1.43 | | $ | 1.58 | |
Diluted earnings per share | | $ | 1.80 | | $ | 1.42 | | $ | 1.57 | |
Options to purchase 4,200 shares of common stock for the year ended December 31, 2004 and 530,663 shares of common stock for the year ended December 31, 2003, were excluded in the computation of dilutive earnings per share because the options’ exercise price was greater than the average market price of a share of common stock during the period. Exercise prices for options excluded from the computation were $25.59 in 2004 ranged from and $23.19 to $25.59 in 2003. For the year ended December 31, 2005, all options were dilutive.
| 11. | 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 2005 and thereafter (in millions) are $4.9 in 2006, $4.0 in 2007, $1.9 in 2008, $0.9 in 2009, $0.5 in 2010 and $2.4 thereafter. Total lease expense (in millions) was $6.1 in 2005, $6.7 in 2004, and $7.2 in 2003.
Firm purchase commitments for commodities by consolidated nonregulated companies total $100.6 million in 2006, $16.9 million in 2007, $10.6 million in 2008, and $6.3 million in 2009. Firm purchase commitment for utility and non-utility plant total $13.0 million.
Vectren issues guarantees to third parties on behalf of its unconsolidated affiliates. Such guarantees allow those affiliates to execute transactions on more favorable terms than the affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of December 31, 2005, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $7 million. The Company has also issued a guarantee approximating $4 million related to the residual value of an operating lease that expires in 2006.
Vectren has accrued no liabilities for these guarantees as they relate to guarantees issued among related parties, are not material, or such guarantees were executed prior to the adoption of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Liabilities accrued for, and activity related to, product warranties are not significant.
Securities & Exchange Commission Inquiry into PUHCA Exemption
In July 2004, the Company received a letter from the SEC regarding its exempt status under the Public Utility Holding Company Act of 1935 (PUHCA). The Company has responded fully to the SEC's letter and believes that it and its utility holding company subsidiary, Utility Holdings, remain entitled to exemption under Section 3(a)(1) of PUHCA. The question of the PUHCA exemptions was mooted by the Energy Policy Act of 2005 (Energy Act), which repealed the Public Utility Holding Company Act of 1935 effective February 8, 2006.
The Energy Act enacts a new Public Utility Holding Company Act of 2005 (PUHCA 2005). The Company and Utility Holdings, are holding companies under PUHCA 2005. Under PUHCA 2005, the FERC is granted authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities to the extent relevant to the rates of FERC-jurisdictional public utilities and natural gas companies that are part of the holding company system. FERC has issued rules implementing PUHCA 2005 that allow companies to seek an exemption or waiver from all or some of FERC’s books and records requirements. Under PUHCA 2005, the Company will be required to notify FERC of its status as a holding company, and, unless an exemption or waiver is obtained, file an annual report, maintain certain books and records and make them available to the FERC. Compliance with these requirements is not expected to materially affect the Company’s financial position or operations.
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows. See the ProLiance discussion in Note 3.
| 12. | Environmental Matters |
Clean Air Act
NOx SIP Call Matter
The Company has taken steps to comply with Indiana’s State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A. B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required.
The IURC has issued orders that approve:
| · | the Company’s project to achieve environmental compliance by investing in clean coal technology; |
| · | a total capital cost investment for this project up to $250 million (excluding AFUDC and administrative overheads), subject to periodic review of the actual costs incurred; |
| · | a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and |
| · | ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service. |
Through December 31, 2005, capital investments approximating the level approved by the IURC have been made. The last SCR was placed into service in May, 2005. Related annual operating expenses, including depreciation expense, were $15.4 million in 2005, $9.7 million in 2004 and $1.2 million in 2003. Such operating expenses could approximate $24 to $27 million once all installed equipment is operational for an entire year.
The Company has achieved timely compliance through the reduction of the Company’s overall NOx emissions to levels compliant with Indiana’s NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance.
Clean Air Interstate Rule & Clean Air Mercury Rule
In March of 2005 USEPA finalized two new air emission reduction regulations. The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program requiring further reductions in Nitrogen Oxides (NOx) and Sulfur Dioxide (SO2) emissions from coal-burning power plants. The Clean Air Mercury Rule (CAMR) is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. Both sets of regulations require emission reductions in two phases. The first phase deadline for both rules is 2010 (2009 for NOx under CAIR), and the second phase deadline for compliance with the emission reductions required under CAIR is 2015, while the second phase deadline for compliance with the emission reduction requirements of CAMR is 2018. The Company is evaluating compliance options and fully expects to be in compliance by the required deadlines.
In May 2005, Vectren’s utility subsidiary, SIGECO, filed a new multi-emission compliance plan with the IURC. If approved, SIGECO’s coal-fired plants will be 100% scrubbed for SO2, 90% scrubbed for NOx, and mercury emissions will be reduced to meet the new mercury reduction standards. On October 20, 2005, the Company and the OUCC filed with the IURC a settlement agreement concerning the regulatory treatment and recovery of the investment required by this plan. On December 6, SIGECO, the OUCC and Citizens Action Coalition filed a supplement to the settlement in which SIGECO agreed to study renewable energy alternatives and include a carbon forecast in future filings with regard to new generation and further environmental compliance plans, among other initiatives. If the settlement agreement is approved, the Company will recover an approximate 8% return on its capital investments, which are expected to approximate $110 million, and related operating expenses through a rider mechanism. This rider mechanism will operate similar to the rider used to recover NOx-related capital investments and operating expenses. The Company expects a final order from the IURC related to this settlement agreement in early 2006.
Culley Generating Station Litigation
During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications.
Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government’s complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation.
Under the agreement, SIGECO committed to:
| · | either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006; |
| · | operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions; |
| · | enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions; |
| · | install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007; |
| · | conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and |
| · | pay a $600,000 civil penalty. |
The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to its results from operations or financial condition. The $600,000 civil penalty was accrued during 2003 and is reflected in Other-net.
Manufactured Gas Plants
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, Indiana Gas, SIGECO, and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites.
Indiana Gas has 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 has 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. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several 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.
In conjunction with data compiled by environmental consultants, Indiana Gas has 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 costs that it reasonably expects to incur totaling approximately $20.4 million.
The estimated accrued costs are limited to Indiana Gas’ proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20% and 50%.
With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million.
Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects 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.
In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM’s VRP. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990’s. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have been initiated by the Company to confirm that the sites continue to pose no such risk.
On October 6, 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 on February 24, 2004. On July 13, 2004, SIGECO 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. Costs of remediation at the four SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot be determined at this time. The total costs accrued to date, including investigative costs, have been immaterial.
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, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA.
| 13. | Rate & Regulatory Matters |
Gas Utility Base Rate Settlements
On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO’s gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas’ gas distribution business. On April 13, 2005, the PUCO approved a $15.7 million base rate increase for VEDO’s gas distribution business. The new rate designs in all three territories include a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in SIGECO’s service territory was implemented on July 1, 2004; the base rate change in Indiana Gas’ service territory was implemented on December 1, 2004; and the base rate change in VEDO’s service territory was implemented on April 14, 2005.
The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO’s new base rates provide for the recovery of on-going costs to comply with the Pipeline Safety Improvement Act of 2002 as well as the funding of conservation programs.
Indiana and Ohio Decoupling/Conservation Filing
On October 25, 2005, Vectren Energy Delivery of Indiana filed with the IURC for approval of a conservation program and a conservation adjustment rider in its two Indiana service territories. If approved, the plan outlined in the petition will better align the interests of the Company with its customers through the promotion of natural gas conservation. The petition requests the use of a tracker mechanism to recover the costs of funding the design and implementation of conservation efforts, such as consumer education programs and rebates for high efficiency equipment. The conservation tracker works in tandem with a decoupling mechanism. The decoupling mechanism would allow the Company to recover the distribution portion of its rates from residential and commercial customers based on the level of customer usage established in each utility’s last general rate case. The Company will file its evidence in March 2006 and a hearing is set for June 2006.
Similarly, on November 28, 2005, Vectren Energy Delivery of Ohio filed with the PUCO for approval of a conservation program and a conservation adjustment rider that would accomplish the same objectives. Discussions with interested parties are ongoing in both states.
Normal Temperature Adjustment Order
On October 5, 2005, the IURC approved the establishment of a normal temperature adjustment (NTA) mechanism for Vectren Energy Delivery of Indiana. The Indiana Office of Utility Consumer Counselor (OUCC) had previously entered into a settlement agreement with Vectren Energy Delivery of Indiana providing for the NTA. The NTA affects the Company’s Indiana regulated residential and commercial natural gas customers and should mitigate weather risk in those customer classes during the October to April heating season. These Indiana customer classes represent approximately 60-65% of the Company’s total natural gas heating load.
The NTA mechanism will mitigate volatility in distribution charges created by fluctuations in weather by lowering customer bills when weather is colder than normal and increasing customer bills when weather is warmer than normal. The NTA has been applied to meters read and bills rendered after October 15, 2005. Each subsequent monthly bill for the seven month heating season will be adjusted using the NTA.
The order provides that the Company will make, on a monthly basis, a commitment of $125,000 to a universal service fund program or other low income assistance program for the duration of the NTA or until a general rate case.
Gas Cost Recovery (GCR) Audit Proceedings
On June 14, 2005, the PUCO issued an order disallowing the recovery of approximately $9.6 million of gas costs relating to the two year audit period ended November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The disallowance includes approximately $1.3 million relating to pipeline refunds and penalties and approximately $4.5 million of costs for winter delivery services purchased by VEDO to ensure reliability over the two year period. The PUCO also held that ProLiance should have credited to VEDO an additional $3.8 million more than credits actually received for the right to use VEDO’s gas transportation capacity periodically during the periods when it was not required for serving VEDO’s customers. The PUCO also directed VEDO to either submit its receipt of portfolio administration services to a request for proposal process or to in-source those functions. During the fourth quarter of 2003, the Company recorded a reserve of $1.1 million for this matter. An additional pretax charge of $4.2 million was recorded in Cost of Gas Sold in 2005. The reserve reflects management’s assessment of the impact of the PUCO decisions, an estimate of any current impact that decision may have on subsequent audit periods, and an estimate of a sharing in any final disallowance by Vectren’s partner in ProLiance.
VEDO filed its request for rehearing on July 14, 2005, and on August 10, 2005, the PUCO granted rehearing to further consider the $3.8 million portfolio administration issue and all interest on the findings, but denied rehearing on all other aspects of the case. On October 7, 2005, the Company filed an appeal with the Ohio Supreme Court requesting that the $4.5 million disallowance related to the winter delivery service issue be reversed. That appeal is pending with briefing scheduled to be completed in February, 2006. In addition, the Company solicited and received bids for VEDO’s gas supply and portfolio administration services and has selected a third party provider, who began providing services to VEDO on November 1, 2005, under a one year contract. On December 21, 2005, the PUCO granted in part VEDO’s rehearing request, and reduced the $3.8 million disallowance related to portfolio administration to $1.98 million. The Company is considering whether to appeal that decision.
Commodity Prices
Recently, commodity prices for natural gas purchases have increased and have become more volatile. Subject to compliance with applicable state laws, the Company's utility subsidiaries are allowed recovery of such changes in purchased gas costs from their retail customers through commission-approved gas cost adjustment mechanisms, and margin on gas sales are not expected to be impacted. Nevertheless, it is possible regulators may disallow recovery of a portion of gas costs for a variety of reasons, including, but not limited to, a finding by the regulator that natural gas was not prudently procured. In addition, it is reasonably possible that as a result of this near term change in the natural gas commodity price, the Company’s utility subsidiaries may experience increased interest expense due to higher working capital requirements; increased uncollectible accounts expense and unaccounted for gas; and some level of price sensitive reduction in volumes sold or delivered. In response to higher gas prices, the Company increased its utility-related credit facilities (See Note 7) and ProLiance increased its credit facility (See Note 3).
MISO
Since February, 2002 and with the IURC’s approval, the Company has been a member of the Midwest Independent System Operator, Inc. (MISO), a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Pursuant to an order from the IURC received in December 2001, certain MISO startup costs (referred to as Day 1 costs) have been deferred for future recovery in the next general rate case.
On April 1, 2005, the MISO energy market commenced operation (the Day 2 energy market). As a result of being a market participant, the Company now bids its owned generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
On June 1, 2005, Vectren, together with three other Indiana electric utilities, received regulatory authority from the IURC that allows recovery of fuel related costs and deferral of other costs associated with the Day 2 energy market. The order allows fuel related costs to be passed through to customers in Vectren’s existing fuel cost recovery proceedings. The other non-fuel and MISO administrative related costs are to be deferred for recovery as part of the next electric general rate case proceeding.
Ohio Uncollectible Accounts Expense Tracker
On December 17, 2003, the PUCO approved a request by VEDO and several other regulated Ohio gas utilities to establish a mechanism to recover uncollectible account expense outside of base rates. The tariff mechanism establishes an automatic adjustment procedure to track and recover these costs instead of providing the recovery of the historic amount in base rates. Through this order, VEDO received authority to defer its 2003 uncollectible accounts expense to the extent it differs from the level included in base rates. The Company estimated the difference to approximate $4 million in excess of that included in base rates, and reversed and deferred that amount for future recovery in 2003. In 2005 and 2004, the Company recorded revenues of $5.1 and $3.3 million, respectively, which is equal to the level of uncollectible accounts expense recognized for Ohio residential customers.
| 14. | Derivatives & Other Financial Instruments |
Accounting Policy for Derivatives
The Company executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, “Accounting for Derivatives” and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met.
When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or as an adjustment to the underlying’s basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting in four primary areas: asset optimization, SO2 emission allowance risk management, natural gas procurement, and interest rate management.
Asset Optimization
Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of the income from these activities is generated from contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk. Contracts with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. Asset optimization contracts are recorded at market value. Beginning in 2005, substantially all off-system sales occur into the MISO day-ahead market.
At December 31, 2005, asset optimization contracts recorded at market value to Prepayments & other current assets were $1.3 million and were zero in Accrued liabilities. At December 31, 2004, asset optimization contracts recorded at market value approximated $2.5 million of Prepayments & other current assets and $3.1 million of Accrued liabilities.
The proceeds received and paid upon settlement of both purchase and sale contracts along with changes in market value of open contracts are recorded in Electric utility revenues. The change in market value is a function of the normal decline in market value as earnings are realized and the fluctuation in market value resulting from price volatility. Net revenues from asset optimization activities totaled $38.0 million in 2005, $23.8 million in 2004, and $26.5 million in 2003.
SO2 Emission Allowance Risk Management
The Company’s wholesale power marketing operations are exposed to price risk associated with SO2 emission allowances. During 2004 and 2005, emission allowances became more volatile and prices increased. To hedge this risk, the Company executed call options to hedge wholesale emission allowance utilization in future periods. The Company designated and documented these derivatives as cash flow hedges. At December 31, 2005, a deferred gain of approximately $3.2 million remains in accumulated comprehensive income which will be recognized in earnings as emission allowances are utilized. At December 31, 2005, outstanding call options hedging a forecasted 2006 transaction, have a fair value of $3.9 million and are recorded in Prepayments and other current assets. Hedge ineffectiveness totaling $0.8 million of expense is included in 2005’s earnings, and the effective portion of outstanding hedges totaling $3.6 million resides in Accumulated comprehensive income.
Natural Gas Procurement Activity
The Company’s regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Although Vectren’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold. The Company mitigates these risks by executing derivative contracts that manage the price volatility of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings.
The Company’s wholly owned gas retail operations also mitigate price risk associated with forecasted natural gas purchases by using derivatives. These nonregulated gas retail operations may also from time-to-time execute weather derivatives to mitigate extreme weather affecting unregulated gas retail sales.
At December 31, 2005 and 2004, the market values of these contracts and the book value of weather contracts were not significant.
Interest Rate Management
The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company has used interest rate swaps and treasury locks to hedge forecasted debt issuances and other interest rate swaps to manage interest rate exposure. Hedging instruments are recorded at market value. Changes in market value, when effective, are recorded in Accumulated other comprehensive income for cash flow hedges, as an adjustment to the outstanding debt balance for fair value hedges, or as regulatory asset/liability when regulation is involved. Amounts are recorded to interest expense as settled.
Interest rate swaps hedging the fair value of fixed-rate debt with a total notional amount of $17.5 million are outstanding. The fair value liability associated with those swaps was $0.4 million and $0.5 million, respectively, at December 31, 2005 and 2004. At December 31, 2005, approximately $6.8 million remains in Regulatory liabilities related to future interest payments. Of the existing regulatory liability, $0.7 million will be reclassified to earnings in 2006, $0.6 million was reclassified to earnings in 2005, and $0.6 million was reclassified to earnings during 2004.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial instruments follow:
| | | | At December 31, |
| | | | 2005 | | 2004 |
(In millions) | | Carrying Amount | | Est. Fair Value | | Carrying Amount | | Est. Fair Value |
| | Long-term debt | | $ 1,256.9 | | $ 1,312.9 | | $ 1,070.2 | | $ 1,146.2 |
| | Short-term borrowings & notes payable | | 299.9 | | 299.9 | | 412.4 | | 412.4 |
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.
Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.
Periodically, the Company tests its cost method investments and notes receivable for impairment which may require their fair value to be estimated. Because of the customized nature of these investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and costs. At December 31, 2005, and 2004, fair value for these financial instruments was not estimated.
The Company segregates its operations into three groups: 1) Utility Group, 2) Nonregulated Group, and 3) Corporate and Other.
The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s 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 marketing operations. The Company cross 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 marketing operations. In total, regulated operations supply natural gas and /or electricity to over one million customers. For these regulated operations, the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. For the Utility Group’s other operations, net income is used as the measure of profitability.
In total, the Utility Group has three operating segments of as defined by SFAS 131 “Disclosure About Segments of an Enterprise and Related Information” (SFAS 131).
The Nonregulated Group is comprised of one operating segment as defined by SFAS 131 that includes various subsidiaries and affiliates investing in energy marketing and services, coal mining, utility infrastructure services, and broadband communications, among other energy-related opportunities.
Corporate and Other includes unallocated corporate expenses such as branding and charitable contributions, among other activities, that benefit the Company’s other operating segments. Net income is the measure of profitability used by management for both the Nonregulated Group and Corporate and Other. Information related to the Company’s business segments is summarized below:
| | | | | Year Ended December 31, | |
(In millions) | | | | 2005 | | 2004 | | 2003 | |
Revenues | | | | | | | | | |
| Utility Group | | | | | | | | | |
| Gas Utility Services | | | | | $ | 1,359.7 | | $ | 1,126.2 | | $ | 1,112.3 | |
| Electric Utility Services | | | | | | 421.4 | | | 371.3 | | | 335.7 | |
| Other Operations | | | | | | 36.1 | | | 32.9 | | | 26.5 | |
| Eliminations | | | | | | (35.4 | ) | | (32.4 | ) | | (25.7 | ) |
| Total Utility Group | | | | | | 1,781.8 | | | 1,498.0 | | | 1,448.8 | |
| Nonregulated Group | | | | | | 344.3 | | | 272.1 | | | 219.2 | |
| Corporate & Other | | | | | | - | | | - | | | 1.0 | |
| Eliminations | | | | | | (98.1 | ) | | (80.3 | ) | | (81.3 | ) |
| Consolidated Revenues | | | | | $ | 2,028.0 | | $ | 1,689.8 | | $ | 1,587.7 | |
Profitability Measure | | | | | | | | | | | | | |
| Utility Group: Regulated Operating Income | | | | | | | | | | | | | |
| (Operating Income Less Applicable Income Taxes) | | | | | | | | | | | | | |
| Gas Utility Services | | | | | $ | 74.8 | | $ | 70.9 | | $ | 74.9 | |
| Electric Utility Services | | | | | | 72.4 | | | 65.6 | | | 63.8 | |
| Total Regulated Operating Income | | | | | | 147.2 | | | 136.5 | | | 138.7 | |
| Regulated other income - net | | | | | | 2.0 | | | 2.1 | | | 5.1 | |
| Regulated interest expense & preferred dividends | | | | | | (63.9 | ) | | (62.7 | ) | | (62.0 | ) |
| Regulated Net Income | | | | | | 85.3 | | | 75.9 | | | 81.8 | |
| Other Operations Net Income | | | | | | 9.8 | | | 7.2 | | | 3.7 | |
| Utility Group Net Income | | | | | | 95.1 | | | 83.1 | | | 85.5 | |
| Nonregulated Group Net Income | | | | | | 48.2 | | | 26.4 | | | 27.6 | |
| Corporate & Other Net Loss | | | | | | (6.5 | ) | | (1.6 | ) | | (2.0 | ) |
| Consolidated Net Income | | | | | $ | 136.8 | | $ | 107.9 | | $ | 111.1 | |
| | | | | | | | | | | | | | |
| | | | | | | Year Ended December 31, |
(In millions) | | | | | | 2005 | | 2004 | | 2003 | |
Amounts Included in Profitability Measures | | | | | | | | | | | |
| Depreciation & Amortization | | | | | | | | | | | |
Utility Group | | | | | | | | | | | |
| Gas Utility Services | | | | | | | | $ | 64.9 | | $ | 57.0 | | $ | 61.1 | |
| Electric Utility Services | | | | | | | | | 56.9 | | | 53.3 | | | 42.6 | |
| Other Operations | | | | | | | | | 19.5 | | | 17.5 | | | 14.2 | |
| Total Utility Group | | | | | | | | | 141.3 | | | 127.8 | | | 117.9 | |
| Nonregulated Group | | | | | | | | | 16.0 | | | 12.0 | | | 10.5 | |
| Corporate & Other | | | | | | | | | 0.9 | | | 0.3 | | | 0.3 | |
| Consolidated Depreciation & Amortization | | | | | | | | $ | 158.2 | | $ | 140.1 | | $ | 128.7 | |
Interest Expense | | | | | | | | | | | | | | | | |
| Utility Group | | | | | | | | | | | | | | | | |
| Regulated Operations | | | | | | | | $ | 63.9 | | $ | 62.7 | | $ | 62.0 | |
| Other Operations | | | | | | | | | 6.0 | | | 4.7 | | | 4.1 | |
| Total Utility Group | | | | | | | | | 69.9 | | | 67.4 | | | 66.1 | |
| Nonregulated Group | | | | | | | | | 14.6 | | | 11.3 | | | 9.7 | |
| Corporate & Other | | | | | | | | | (0.6 | ) | | (1.0 | ) | | (0.2 | ) |
| Consolidated Interest Expense | | | | | | | | $ | 83.9 | | $ | 77.7 | | | 75.6 | |
Equity in Earnings of Unconsolidated Affiliates | | | | | | | | | | | | | | | | |
| Utility Group: Other Operations | | | | | | | | $ | - | | $ | 0.2 | | $ | (0.5 | ) |
| Nonregulated Group | | | | | | | | | 45.6 | | | 20.4 | | | 12.7 | |
| Consolidated Equity in Earnings of Unconsolidated Affiliates | | | | | | | | $ | 45.6 | | $ | 20.6 | | $ | 12.2 | |
Income Taxes | | | | | | | | | | | | | | | | |
| Utility Group | | | | | | | | | | | | | | | | |
| Gas Utility Services | | | | | | | | $ | 22.3 | | $ | 17.5 | | $ | 19.5 | |
| Electric Utility Services | | | | | | | | | 33.5 | | | 30.8 | | | 29.8 | |
| Other Operations | | | | | | | | | 1.7 | | | 4.8 | | | 2.3 | |
| Total Utility Group | | | | | | | | | 57.5 | | | 53.1 | | | 51.6 | |
| Nonregulated Group | | | | | | | | | (9.9 | ) | | (13.6 | ) | | (13.2 | ) |
| Corporate & Other | | | | | | | | | (3.5 | ) | | (0.5 | ) | | (0.7 | ) |
| Consolidated Income Taxes | | | | | | | | $ | 44.1 | | $ | 39.0 | | $ | 37.7 | |
Capital Expenditures | | | | | | | | | | | | | | | | |
| Utility Group | | | | | | | | | | | | | | | | |
| Gas Utility Services | | | | | | | | $ | 81.0 | | $ | 89.1 | | $ | 95.0 | |
| Electric Utility Services | | | | | | | | | 100.0 | | | 150.6 | | | 124.1 | |
| Other Operations | | | | | | | | | 29.9 | | | 27.9 | | | 15.9 | |
| Non-cash costs & changes in accruals | | | | | | | | | 3.6 | | | (25.4 | ) | | (2.7 | ) |
| Total Utility Group | | | | | | | | | 214.5 | | | 242.2 | | | 232.3 | |
| Nonregulated Group | | | | | | | | | 17.1 | | | 10.3 | | | 13.2 | |
| Corporate & Other | | | | | | | | | - | | | 0.1 | | | 2.3 | |
| Transfers of Assets | | | | | | | | | - | | | (0.1 | ) | | (14.3 | ) |
| Consolidated Capital Expenditures | | | | | | | | $ | 231.6 | | $ | 252.5 | | $ | 233.5 | |
Investments in Equity Method Investees | | | | | | | | | | | | | | | | |
| Nonregulated Group | | | | | | | | | 19.2 | | | 18.2 | | | 16.6 | |
| | | | | | | | | | | | | | | | | |
| | | | | At December 31, |
(In millions) | | | | 2005 | | 2004 | |
Assets | | | | | | | |
| Utility Group | | | | | | | |
| Gas Utility Services | | | | | $ | 2,030.8 | | $ | 1,892.8 | |
| Electric Utility Services | | | | | | 1,176.0 | | | 1,090.1 | |
| Other Operations | | | | | | 188.9 | | | 175.0 | |
| Eliminations | | | | | | (5.6 | ) | | (10.2 | ) |
| Total Utility Group | | | | | | 3,390.1 | | | 3,147.7 | |
| Nonregulated Group | | | | | | 542.4 | | | 447.9 | |
| Corporate & Other | | | | | | 369.1 | | | 292.8 | |
| Eliminations | | | | | | (433.5 | ) | | (301.5 | ) |
| Consolidated Assets | | | | | $ | 3,868.1 | | $ | 3,586.9 | |
Prepayments and other current assets in the Consolidated Balance Sheets consist of the following:
| | | At December 31, | |
(In millions) | | 2005 | | 2004 | |
| Prepaid gas delivery service | | $ | 69.3 | | $ | 116.9 | |
| Prepaid taxes | | | 5.3 | | | 9.8 | |
| Other prepayments & current assets | | | 31.8 | | | 9.5 | |
Total prepayments & other current assets | | $ | 106.4 | | $ | 136.2 | |
| | | At December 31, |
(In millions) | | 2005 | | 2004 | |
| Refunds to customers & customer deposits | | $ | 36.7 | | $ | 31.0 | |
| Accrued taxes | | | 34.2 | | | 32.1 | |
| Accrued interest | | | 17.2 | | | 15.9 | |
| Deferred income taxes | | | 7.6 | | | 4.5 | |
| Accrued salaries & other | | | 60.9 | | | 42.3 | |
Total accrued liabilities | | $ | 156.6 | | $ | 125.8 | |
Other - net in the Consolidated Statements of Income consists of the following:
| | | Year Ended December 31, |
(In millions) | | 2005 | | 2004 | | 2003 | |
| Interest income | | $ | 3.8 | | $ | 3.0 | | $ | 3.2 | |
| AFUDC & capitalized interest | | | 2.6 | | | 4.6 | | | 5.9 | |
| Gains on sale of investments & assets | | | - | | | 0.6 | | | 7.5 | |
| Leveraged lease investment income | | | 0.2 | | | 1.5 | | | 1.9 | |
| Other income | | | 1.8 | | | 1.0 | | | - | |
| Other expense | | | (2.2 | ) | | (6.1 | ) | | (2.1 | ) |
Total other – net | | $ | 6.2 | | $ | 4.6 | | $ | 16.4 | |
| | | | | | | | | | | |
| 17. | 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 2005 and 2004 follows:
| | | | | | | | | | |
(In millions, except per share amounts) | | Q1 | | Q2 | | Q3 | | Q4 | |
2005 | | | | | | | | | |
| Operating revenues | | $ | 677.2 | | $ | 326.2 | | $ | 310.8 | | $ | 713.8 | |
| Operating income | | | 95.2 | | | 29.2 | | | 29.9 | | | 58.8 | |
| Net income | | | 56.1 | | | 13.4 | | | 16.5 | | | 50.8 | |
| Earnings per share: | | | | | | | | | | | | | |
| Basic | | $ | 0.74 | | $ | 0.18 | | $ | 0.22 | | $ | 0.67 | |
| Diluted | | | 0.74 | | | 0.18 | | | 0.22 | | | 0.66 | |
2004 | | | | | | | | | | | | | |
| Operating revenues | | $ | 645.3 | | $ | 276.7 | | $ | 254.4 | | $ | 513.4 | |
| Operating income | | | 86.0 | | | 20.4 | | | 23.4 | | | 69.7 | |
| Net income | | | 54.8 | | | 3.3 | | | 9.7 | | | 40.1 | |
| Earnings per share: | | | | | | | | | | | | | |
| Basic | | $ | 0.73 | | $ | 0.04 | | $ | 0.13 | | $ | 0.53 | |
| Diluted | | | 0.72 | | | 0.04 | | | 0.13 | | | 0.53 | |
| | | | | | | | | | | | | | |
None.
Changes in Internal Controls over Financial Reporting
During the quarter ended December 31, 2005, 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, 2005, 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, 2005, to ensure that the information required to be disclosed and filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Management’s Report on Internal Control over Financial Reporting
Vectren Corporation’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, 2005.
Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this annual report.
None.
PART III
The information required by Part III, Item 10 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year. The Company’s executive officers are the same as those named executive officers detailed in the Proxy Statement.
The Company’s Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Nominating and Corporate Governance Committees, and its Code of Ethics covering the Company’s directors, officers and employees are available on the Company’s website, www.vectren.com, and a copy will be mailed upon request to Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708. The Company intends to disclose any amendments to the Code of Ethics or waivers of the Code of Ethics on behalf of the Company’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer or controller and persons performing similar functions on 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 Investor Relations, Attention: Steve Schein, One Vectren Square, Evansville, Indiana 47708.
Information required by Part III, Item 11 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
Except with respect to equity compensation plan information of the Registrant, which is included herein, the information required by Part III, Item 12 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
Shares Issuable under Share-Based Compensation Plans
As of December 31, 2005, the following shares were authorized to be issued under share-based compensation plans:
| | | | | | | | | | |
| | | A | | B | | C | |
| Plan category | | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | Weighted average exercise price of outstanding options, warrants and rights | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a) | |
| | | | | | | | | | |
| Equity compensation plans approved by | | | | | | | | | |
security holders (1) | | | 2,123,579 | | $ | 23.18 | | | 2,499,822 | | (2 | ) |
| Equity compensation plans not approved | | | | | | | | | | | | | |
| by security holders | | | - | | | - | | | - | | | | |
| Total | | | 2,123,579 | | $ | 23.18 | | | 2,499,822 | | | |
| | | | | | | | | | | | | | |
| (1) | Includes the following Vectren Corporation Plans: Vectren Corporation At-Risk Compensation Plan, 1994 SIGCORP Stock Option Plan, Vectren Corporation Executive Restricted Stock Plan, and Vectren Corporation Directors Restricted Stock Plan. |
| (2) | Includes shares available for issuance under the Vectren Corporation At-Risk Compensation Plan (1,769,221), of which up to 800,000 shares may be issued in restricted stock, 1994 SIGCORP Stock Option Plan (387,503), Vectren Corporation Executive Restricted Stock Plan (310,288), and Vectren Corporation Directors Restricted Stock Plan (48,229). Shares available for issuance under the At Risk Plan have been reduced by the issuance of 170,100 restricted shares approved by the board of directors’ Compensation Committee, effective January 1, 2006. |
The SIGCORP stock option plan was approved by SIGCORP common shareholders prior to the merger forming Vectren, and both the directors and executive restricted stock plans were approved by Indiana Energy common shareholders prior to the merger forming Vectren. The At-Risk Compensation plan was approved by Vectren Corporation common shareholders after the merger forming Vectren.
Information required by Part III, Item 13 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
Information required by Part III, Item 14 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
PART IV
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. The financial statements of ProLiance Energy LLC are attached as exhibit 99.1 to this Form 10-K.
Supplemental Schedules
For the years ended December 31, 2005, 2004, and 2003, 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 Corporation 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 2005 – Accumulated provision for | | | | | | | | | | | |
| uncollectible accounts | | $ | 2.0 | | $ | 15.1 | | $ | - | | $ | 14.3 | | $ | 2.8 | |
| Year 2004 – Accumulated provision for | | | | | | | | | | | | | | | | |
| uncollectible accounts | | $ | 3.2 | | $ | 11.9 | | $ | - | | $ | 13.1 | | $ | 2.0 | |
| Year 2003 – Accumulated provision for | | | | | | | | | | | | | | | | |
| uncollectible accounts | | $ | 5.5 | | $ | 12.8 | | $ | - | | $ | 15.1 | | $ | 3.2 | |
OTHER RESERVES: | | | | | | | | | | | | | | | | |
| Year 2005 – Restructuring costs | | $ | 2.7 | | $ | - | | $ | - | | $ | 0.3 | | $ | 2.4 | |
| Year 2004 – Restructuring costs | | $ | 3.2 | | $ | - | | $ | - | | $ | 0.5 | | $ | 2.7 | |
| Year 2003 – Restructuring costs | | $ | 4.2 | | $ | - | | $ | - | | $ | 1.0 | | $ | 3.2 | |
| | | | | | | | | | | | | | | | | |
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. Exhibits for the Company are listed in the Index to Exhibits beginning on page 94.
Vectren Corporation
Form 10-K
Attached Exhibits
The following Exhibits were filed electronically with the SEC with this filing.
INDEX TO EXHIBITS
2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
| 2.1 | Asset Purchase Agreement dated December 14, 1999 between Indiana Energy, Inc. and The Dayton Power and Light Company and Number-3CHK with a commitment letter for a 364-Day Credit Facility dated December 16,1999. (Filed and designated in Current Report on Form 8-K dated December 28, 1999, File No. 1-9091, as Exhibit 2 and 99.1) |
3. Articles of Incorporation and By-Laws
| 3.1 | Amended and Restated Articles of Incorporation of Vectren Corporation effective May 1, 2005. (Filed and designated in Quarterly Report on Form 10-Q filed August 2, 2005, File No. 1-15467, as Exhibit 3.4.) |
| 3.2 | Amended and Restated Code of By-Laws of Vectren Corporation as of October 29, 2003. (Filed and designated in Quarterly Report on Form 10-Q filed November 13, 2003, File No. 1-15467, as Exhibit 3.1.) |
| 3.3 | Shareholders Rights Agreement dated as of October 21, 1999 between Vectren Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No. 1-15467, as Exhibit 4.) |
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 designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.) |
| 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). |
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 | Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a Select Group of Management Employees as amended and restated effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-G.) |
| 10.4 | Indiana Energy, Inc. Nonqualified Deferred Compensation Plan effective January 1, 1999. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-H.) |
| 10.5 | Indiana Energy, Inc. Executive Restricted Stock Plan as amended and restated effective October 1, 1998. (Filed and designated in Form 10-K for the fiscal year ended September 30, 1998, File No. 1-9091, as Exhibit 10-O.) First Amendment, effective December 1, 1998 (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-I.). |
| 10.6 | Indiana Energy, Inc. Director's Restricted Stock Plan as amended and restated effective May 1, 1997. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 1997, File No. 1-9091, as Exhibit 10-B.) First Amendment, effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-J.) Second Amendment, Plan renamed the Vectren Corporation Directors Restricted Stock Plan effective October 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10-34.) Third Amendment, effective March 28, 2001. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10-35.) |
| 10.7 | Vectren Corporation At Risk Compensation Plan effective May 1, 2001. (Filed and designated in Vectren Corporation’s Proxy Statement dated March 16, 2001, File No. 1-15467, as Appendix B.) |
| 10.8 | 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.) |
| 10.9 | Vectren Corporation Employment Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.1.) |
| 10.10 | Vectren Corporation Employment Agreement between Vectren Corporation and Jerome A. Benkert, Jr. dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.3.) |
| 10.11 | Vectren Corporation Employment Agreement between Vectren Corporation and Carl L. Chapman dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.4.) |
| 10.12 | Vectren Corporation Employment Agreement between Vectren Corporation and Ronald E. Christian dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.5.) |
| 10.13 | Vectren Corporation Employment Agreement between Vectren Corporation and Richard G. Lynch dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.8.) |
| 10.14 | Vectren Corporation Employment Agreement between Vectren Corporation and William S. Doty dated as of April 30, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.43.) |
| 10.15 | Vectren Corporation At Risk Compensation Plan specimen Restricted Stock 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 99-1.) |
| 10.16 | 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.) |
| 10.17 | 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.) |
| 10.18 | 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.) |
| 10.19 | 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.) |
| 10.20 | Gas Sales and Portfolio Administration Agreement between Vectren Energy Delivery of Ohio and ProLiance Energy, LLC, effective October 31, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10-24.) |
| 10.21 | Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated December 17, 1997 and effective January 1, 1998. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.18.) Portions of the document have been omitted pursuant to a request to a request for confidential treatment. Amendment 1, effective January 1, 2003, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated December 17, 1997. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.19.) |
| 10.22 | Coal Supply Agreement for Generating Stations at Yankeetown, Warrick County, Indiana, and West Franklin, Posey County, Indiana between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.20.) Amendment 1, effective January 1, 2004, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.21.) |
| 10.23 | Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke Utility, 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.) |
21. Subsidiaries of the Company
The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1.
23. Consents of Experts and Counsel
The consents of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 and 23.2.
31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32.1
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 CORPORATION
Dated February 16, 2006
/s/ Niel C. Ellerbrook
Niel C. Ellerbrook,
Chairman, President, 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, President, Chief Executive Officer, & | | February 16, 2006 |
Niel C. Ellerbrook | | Director (Principal Executive Officer) | | |
| /s/ Jerome A. Benkert, Jr. | | Executive Vice President & | | February 16, 2006 |
Jerome A. Benkert, Jr. | | Chief Financial Officer (Principal Financial Officer) | | |
| /s/ M. Susan Hardwick | | Vice President & Controller | | February 16, 2006 |
M. Susan Hardwick | | (Principal Accounting Officer) | | |
| /s/ John M. Dunn | | Director | | February 16, 2006 |
John M. Dunn | | | | |
| /s/ John D. Engelbrecht | | Director | | February 16, 2006 |
John D. Engelbrecht | | | | |
| /s/ Anton H. George | | Director | | February 16, 2006 |
| Anton H. George | | | | |
| | | | | |
| /s/ Robert L. Koch II | | Director | | February 16, 2006 |
Robert L. Koch II | | | | |
| | | Director | | February 16, 2006 |
William G. Mays
| | | | |
| /s/ J. Timothy McGinley | | Director | | February 16, 2006 |
J. Timothy McGinley | | | | |
| /s/ Richard P. Rechter | | Director | | February 16, 2006 |
Richard P. Rechter | | | | |
| /s/ R. Daniel Sadlier | | Director | | February 16, 2006 |
R. Daniel Sadlier | | | | |
| /s/ Richard W. Shymanski | | Director | | February 16, 2006 |
Richard W. Shymanski | | | | |
| | | Director | | February 16, 2006 |
| Jean L.Wojtowicz | | | | |
