Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2010
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from __________________ to ________________________
Commission file number: 1-16739
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VECTREN UTILITY HOLDINGS, INC.
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(Exact name of registrant as specified in its charter)
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INDIANA
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35-2104850
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(State or other jurisdiction of incorporation or organization)
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(IRS Employer Identification No.)
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One Vectren Square
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47708
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(Address of principal executive offices)
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(Zip Code)
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Registrant's telephone number, including area code: 812-491-4000
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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Vectren Utility 6.10% SR NTS 12/1/2035
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
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Title of each class
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Name of each exchange on which registered
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Common – Without Par
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None
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. *Yes ý No□
*Utility Holdings is a majority owned subsidiary of a well-known seasoned issuer, and well-known seasoned issuer status depends in part on the type of security being registered by the majority-owned subsidiary.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes □ No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No □
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
□ Yes □ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. □
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer □ Accelerated filer □
Non-accelerated filer ý Smaller reporting company □
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2010, was zero. All shares outstanding of the Registrant’s common stock were held by Vectren Corporation.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
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Common Stock - Without Par Value
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10
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February 28, 2011
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Class
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Number of Shares
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Date
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Omission of Information by Certain Wholly Owned Subsidiaries
The Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby.
Definitions
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AFUDC: allowance for funds used during construction
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MDth / MMDth: thousands / millions of dekatherms
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ASC: Accounting Standards Codification
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MISO: Midwest Independent System Operator
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BTU / MMBTU: British thermal units / millions of BTU
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MW: megawatts
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FASB: Financial Accounting Standards Board
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MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
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FERC: Federal Energy Regulatory Commission
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NERC: North American Electric Reliability Corporation
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IDEM: Indiana Department of Environmental Management
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OCC: Ohio Office of the Consumer Counselor
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IRC: Internal Revenue Code
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OUCC: Indiana Office of the Utility Consumer Counselor
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IURC: Indiana Utility Regulatory Commission
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PUCO: Public Utilities Commission of Ohio
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Kv: Kilovolt
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EPA: Environmental Protection Agency
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MCF / BCF: thousands / billions of cubic feet
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Throughput: combined gas sales and gas transportation volumes
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Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports, including those of Vectren Utility Holdings, Inc., free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:
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Mailing Address:
One Vectren Square
Evansville, Indiana 47708
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Phone Number:
(812) 491-4000
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Investor Relations Contact:
Robert L. Goocher
Treasurer and Vice President, Investor Relations
rgoocher@vectren.com
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Table of Contents
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Item
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Page
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Number
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Number
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Part I
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1
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1A
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1B
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2
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3
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Part II
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5
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6
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7
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7A
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8
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9
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9A
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9B
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Part III
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10
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11
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12
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13
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14
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Part IV
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15
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(A)
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– Omitted or amended as the Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby.
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PART I
Description of the Business
Vectren Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana corporation, was formed on March 31, 2000 to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana and was organized on June 10, 1999. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).
Indiana Gas provides energy delivery services to over 570,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 314,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.
Narrative Description of the Business
The Company has regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO’s natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment includes the operations of SIGECO’s electric transmission and distribution services, which provides electric distribution services primarily to southwestern Indiana, and the Company’s power generating and wholesale power operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers.
At December 31, 2010, the Company had $3.9 billion in total assets, with $2.1 billion (55 percent) attributed to Gas Utility Services, $1.7 billion (43 percent) attributed to Electric Utility Services, and $0.1 billion (2 percent) attributed to Other Operations. Net income for the year ended December 31, 2010, was $123.9 million, with $53.7 million attributed to Gas Utility Services, $60.9 million attributed to Electric Utility Services, and $9.3 million attributed to Other Operations. Net income for the year ended December 31, 2009, was $107.4 million. For further information regarding the activities and assets of operating segments, refer to Note 13 in the Company’s consolidated financial statements included under “Item 8 Financial Statements and Supplementary Data.”
Following is a more detailed description of the Gas Utility Services and Electric Utility Services operating segments. The Company’s Other Operations are not significant.
Gas Utility Services
At December 31, 2010, the Company supplied natural gas service to approximately 994,800 Indiana and Ohio customers, including 909,300 residential, 83,800 commercial, and 1,700 industrial and other contract customers. Average gas utility customers served were approximately 982,100 in 2010, 981,300 in 2009, and 986,700 in 2008.
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, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, ethanol, and coal mining. The largest Indiana communities served are Evansville, Bloomington, Terre Haute, suburban areas surrounding Indianapolis and Indiana counties near Louisville, Kentucky. The largest community served outside of Indiana is Dayton, Ohio.
Revenues
The Company receives gas revenues by selling gas directly to customers at approved rates or by transporting gas through its pipelines at approved rates to customers that have purchased gas directly from other producers, brokers, or marketers. Total throughput was 197.0 MMDth for the year ended December 31, 2010. Gas sold and transported to residential and commercial customers was 106.2 MMDth representing 54 percent of throughput. Gas transported or sold to industrial and other contract customers was 90.8 MMDth representing 46 percent of throughput. Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs.
For the year ended December 31, 2010, gas utility revenues were approximately $954.1 million, of which residential customers accounted for 68 percent and commercial 25 percent. Industrial and other contract customers account for only 7 percent of revenues due to the high number of transportation customers in that customer class.
Availability of Natural Gas
The volume of gas sold is seasonal and affected by variations in weather conditions. To mitigate seasonal demand, the Company’s Indiana gas utilities have storage capacity at seven active underground gas storage fields and six liquefied petroleum air-gas manufacturing plants. Periodically, purchased natural gas is injected into storage. The injected gas is then available to supplement contracted and manufactured volumes during periods of peak requirements. The volumes of gas per day that can be delivered during peak demand periods for each utility are located in “Item 2 Properties.”
Natural Gas Purchasing Activity in Indiana
The Indiana utilities also contract with a wholly-owned subsidiary of ProLiance Holdings, LLC (ProLiance), to ensure availability of gas. ProLiance is an unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens Energy Group (Citizens). (See the discussion of Energy Marketing below and Note 5 in the Company’s Consolidated Financial Statements included in “Item 8 Financial Statements and Supplementary Data” regarding transactions with ProLiance). The Company also prepays ProLiance for natural gas delivery services during the seven months prior to the peak heating season in lieu of maintaining gas storage. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to continue to provide natural gas supply services to the Company’s Indiana utilities through March 2011. On November 3, 2010, a settlement agreement was filed with the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Gas for the period of April 1, 2011 through March 31, 2016. The settlement has been agreed to by all of the representatives that were parties to the prior settlement. An order is anticipated during the first quarter of 2011.
Natural Gas Purchasing Activity in Ohio
On April 30, 2008, the PUCO issued an order adopting a stipulation involving the Company, the OCC, and other interveners. The order approved the first two phases of a three phase plan to exit the merchant function in the Company’s Ohio service territory. The Company used a third party provider for VEDO’s gas supply and portfolio services through September 30, 2008.
The initial phase of the plan was implemented on October 1, 2008 and continued through March 31, 2010. During the initial phase, wholesale suppliers that were winning bidders in a PUCO approved auction provided the gas commodity to VEDO for resale to its residential and general service customers at auction-determined standard pricing. This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder. On October 1, 2008, the Company transferred its natural gas inventory at book value to the winning bidders, receiving proceeds of approximately $107 million, and began purchasing natural gas from those suppliers (one of which was Vectren Source, a wholly owned natural gas retail marketing subsidiary of Vectren). This method of purchasing gas eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits.
The second phase of the exit process began on April 1, 2010. During this phase, the Company no longer sells natural gas directly to customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12-month period at auction-determined standard pricing. The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010. The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase. As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011. The results of that auction were approved by the PUCO on January 19, 2011. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO. Vectren Source, Vectren’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.
In the last phase, which was not approved in the April 2008 order, it is contemplated that all of the Company’s Ohio residential and general service customers will choose their commodity supplier from state-certified Competitive Retail Natural Gas Suppliers in a competitive market.
The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process. Exiting the merchant function should not have a material impact on earnings or financial condition. It, however, has and will continue to reduce Gas Utility revenues and have an equal and offsetting impact to Cost of gas sold as VEDO no longer purchases gas for resale to these customers.
Total Natural Gas Purchased Volumes
In 2010, Utility Holdings purchased 84,008 MDth volumes of gas at an average cost of $5.99 per Dth, of which approximately 86 percent was purchased from ProLiance, 2 percent was purchased from Vectren Source, and 12 percent was purchased from third party providers. The average cost of gas per Dth purchased for the previous four years was $5.97 in 2009, $9.61 in 2008, $8.14 in 2007, and $8.64 in 2006.
Electric Utility Services
At December 31, 2010, the Company supplied electric service to approximately 141,600 Indiana customers, including approximately 123,200 residential, 18,300 commercial, and 100 industrial and other customers. Average electric utility customers served were approximately 141,300 in 2010, 140,900 in 2009, and 141,100 in 2008.
The principal industries served include polycarbonate resin (Lexan®) and plastic products, aluminum smelting and recycling, aluminum sheet products, automotive assembly, steel finishing, pharmaceutical and nutritional products, automotive glass, gasoline and oil products, ethanol, and coal mining.
Revenues
For the year ended December 31, 2010, retail electricity sales totaled 5,616.9 GWh, resulting in revenues of approximately $564.3 million. Residential customers accounted for 37 percent of 2010 revenues; commercial 27 percent; industrial 35 percent, and other 1 percent. In addition, in 2010 the Company sold 587.6 GWh through wholesale activities principally to the MISO. Wholesale revenues, including transmission-related revenue, totaled $43.7 million in 2010.
System Load
Total load for each of the years 2006 through 2010 at the time of the system summer peak, and the related reserve margin, is presented below in MW.
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Date of summer peak load
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8/4/2010
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6/22/2009
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7/21/2008
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8/8/2007
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8/10/2006
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Total load at peak (1)
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1,275 | 1,143 | 1,167 | 1,341 | 1,325 | |||||||||||||||
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Generating capability
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1,298 | 1,295 | 1,295 | 1,295 | 1,351 | |||||||||||||||
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Firm purchase supply
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136 | 136 | 135 | 130 | 107 | |||||||||||||||
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Interruptible contracts & direct load control
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62 | 62 | 62 | 62 | 62 | |||||||||||||||
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Total power supply capacity
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1,496 | 1,493 | 1,492 | 1,487 | 1,520 | |||||||||||||||
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Reserve margin at peak
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17 | % | 31 | % | 28 | % | 11 | % | 15 | % | ||||||||||
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(1)
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The total load at peak is increased 25 MW in 2007 and 2006 from the total load actually experienced. The additional 25 MW represents load that would have been incurred if the Summer Cycler program had not been activated. The 25 MW is also included in the interruptible contract portion of the Company’s total power supply capacity in those years. On the date of peak in 2008-2010 the Summer Cycler program was not activated.
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The winter peak load for the 2009-2010 season of approximately 916 MW occurred on January 8, 2010. The prior year winter peak load was approximately 883 MW, occurring on January 15, 2009.
Generating Capability
Installed generating capacity as of December 31, 2010, was rated at 1,298 MW. Coal-fired generating units provide 1,000 MW of capacity, natural gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW, and in 2009 SIGECO purchased a landfill gas electric generation project which provides 3 MW. Electric generation for 2010 was fueled by coal (98 percent) and natural gas (2 percent). Oil was used only for testing of gas/oil-fired peaking units. The Company generated approximately 5,136 GWh in 2010. Further information about the Company’s owned generation is included in “Item 2 Properties.”
There are substantial coal reserves in the southern Indiana area, and coal for coal-fired generating stations has been supplied from operators of nearby coal mines, including coal mines in Indiana owned by Vectren Fuels, Inc. (Vectren Fuels), a wholly owned subsidiary of Vectren. Approximately 2.2 million tons were purchased for generating electricity during 2010, of which approximately 90 percent was supplied by Vectren Fuels from its mines and third party purchases. This compares to 2.8 million tons and 3.2 million tons purchased in 2009 and 2008, respectively. The utility’s coal inventory was approximately 1 million tons at December 31, 2010 and 2009.
The average cost of coal per ton consumed for the last five years was $67.01 in 2010, $61.67 in 2009, $42.50 in 2008, $40.23 in 2007, and $37.51 in 2006. Effective January 1, 2009, SIGECO began purchasing coal from Vectren Fuels under new coal purchase agreements. The term of these coal purchase agreements continues to December 31, 2014, with prices specified originally ranging from two to four years. The prices in these contracts were at or below market prices for Illinois Basin coal at the time of execution and were subject to a bidding process with third parties. The IURC has found that costs incurred under these contracts are reasonable (See Rate and Regulatory Matters in Item 7.)
Firm Purchase Supply
The Company has a 1.5 percent interest in the Ohio Valley Electric Corporation (OVEC). OVEC is comprised of several electric utility companies, including SIGECO, and supplies power requirements to the United States Department of Energy’s (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating companies can receive from OVEC, and are obligated to pay for, any available power in excess of the DOE contract demand. At the present time, the DOE contract demand is essentially zero. The Company’s 1.5 percent interest in OVEC makes available approximately 30 MW of capacity. The Company purchased approximately 193 GWh from OVEC in 2010.
The Company executed a capacity contract with Benton County Wind Farm, LLC in April 2008 to purchase as much as 30 MW from a wind farm located in Benton County, Indiana, with the approval of the IURC. The contract expires in 2029. In 2010, the Company purchased approximately 85 GWh under this contract.
In December 2009, the Company executed a 20 year power purchase agreement with Fowler Ridge II Wind Farm, LLC to purchase as much as 50 MW of energy from a wind farm located in Benton and Tippecanoe Counties in Indiana, with the approval of the IURC. The Company purchased 129 GWh under this contract in 2010.
The Company had a capacity contract with Duke Energy Marketing America, LLC to purchase as much as 100 MW at any time from a power plant located in Vermillion County, Indiana. The contract expired on December 31, 2009 and was not renewed.
Other Power Purchases
The Company also purchases power as needed principally from the MISO to supplement its generation and firm purchase supply in periods of peak demand. Volumes purchased principally from the MISO in 2010 totaled 880 GWh.
Midwest Independent System Operator (MISO) Capacity Purchase
In May 2008, the Company executed a MISO capacity purchase from Sempra Energy Trading, LLC to purchase 100 MW of name plate capacity from its generating facility in Dearborn, Michigan. The term of the contract began January 1, 2010 and continues through December 31, 2012.
Interconnections
The Company has interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, and the City of Jasper, Indiana, providing the ability to simultaneously interchange approximately 675 MW. This interchange capability has increased in recent years as a result of ongoing initiatives to improve the transmission grid throughout the Midwest. The Company, as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets, like many other Midwestern electric utilities, to MISO. See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s participation in MISO.
Competition
The utility industry has undergone structural change for several years, resulting in increasing competitive pressures faced by electric and gas utility companies. Currently, several states have passed legislation allowing electricity customers to choose their electricity supplier in a competitive electricity market and several other states have considered such legislation. At the present time, Indiana has not adopted such legislation. Ohio regulation allows gas customers to choose their commodity supplier. The Company implemented a choice program for its gas customers in Ohio in January 2003. At December 31, 2010, over 109,000 customers in Vectren’s Ohio service territory have opted to purchase natural gas from a supplier other than VEDO. In addition, VEDO’s service territory continues transition toward a choice model for all gas customers. Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs. Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting certain industrial and commercial large volume customers to choose their commodity supplier.
Regulatory and Environmental Matters
See “Item 7 Management’s Discussion and Analysis of Results of Operations and Financial Condition” regarding the Company’s regulatory environment and environmental matters.
Personnel
As of December 31, 2010, the Company and its consolidated subsidiaries had 1,600 employees, of which 800 are subject to collective bargaining arrangements.
In June 2010, the Company reached a three year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 30, 2013.
In April 2010, the Company reached a three year agreement with Local 175 of the Utility Workers Union of America. The labor agreement is retroactively effective to November 1, 2009 and ends October 31, 2012.
In September 2009, the Company reached a three year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 2012.
In December 2008, the Company reached a three-year labor agreement, ending December 1, 2011 with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441.
Investors should consider carefully the following factors that could cause the Company’s operating results and financial condition to be materially adversely affected. New risks may emerge at any time, and the Company cannot predict those risks or estimate the extent to which they may affect the Company’s businesses or financial performance.
Utility Holdings is a holding company and its assets consist primarily of investments in its subsidiaries.
The ability of Utility Holdings to receive dividends and repay indebtedness depends on the earnings, financial condition, capital requirements and cash flow of its subsidiaries, SIGECO, Indiana Gas, and VEDO and the distribution or other payment of earnings from those entities to Utility Holdings. Should the earnings, financial condition, capital requirements or cash flow of, or legal requirements applicable to them restrict their ability to pay dividends or make other payments to Utility Holdings, its ability to pay dividends to its parent could be limited. Utility Holdings’ results of operations, future growth, and earnings and dividend goals also will depend on the performance of its subsidiaries. Additionally, certain of the Company’s lending arrangements contain restrictive covenants, including the maintenance of a total debt to total capitalization ratio, which could limit its ability to pay dividends.
Deterioration in general economic conditions may have adverse impacts.
The industries in which the Company operates and serves continue to be impacted by economic uncertainty. Economic conditions may have some negative impact on both gas and electric large customers and wholesale power sales. This impact may continue to include volatility and unpredictability in the demand for natural gas and electricity, tempered growth strategies, significant conservation measures, and perhaps even further plant closures or bankruptcies. Economic conditions may also cause reductions in residential and commercial customer counts and lower Company revenues. It is also possible that an uncertain economy could continue to affect costs including pension costs, interest costs, and uncollectible accounts expense. The current economic conditions may continue to have some negative impact on utility industry spending for construction projects and demand for natural gas.
Financial market volatility could have adverse impacts.
The capital and credit markets may experience volatility and disruption. If market disruption and volatility occurs, there can be no assurance that the Company will not experience adverse effects, which may be material. These effects may include, but are not limited to, difficulties in accessing the short and long-term debt capital markets and the commercial paper market, increased borrowing costs associated with current short-term debt obligations, higher interest rates in future financings, and a smaller potential pool of investors and funding sources. Finally, there is no assurance the Company will have access to the equity capital markets to obtain financing when necessary or desirable.
A downgrade (or negative outlook) in or withdrawal of Utility Holdings’ credit ratings could negatively affect its ability to access capital and its cost.
The following table shows the current ratings assigned to certain outstanding debt by Moody’s and Standard & Poor’s:
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Current Rating
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Standard
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Moody’s
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& Poor’s
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Utility Holdings and Indiana Gas senior unsecured debt
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A3
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A-
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Utility Holdings commercial paper program
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P-2
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A-2
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SIGECO’s senior secured debt
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A1
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A
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The current outlook of both Standard and Poor’s and Moody’s is stable and both categorize the ratings of the above securities as investment grade. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.
If the rating agencies downgrade the Company’s credit ratings, particularly below investment grade, or initiate negative outlooks thereon, or withdraw Utility Holdings’ ratings or, in each case, the ratings of its subsidiaries, it may significantly limit Utility Holdings’ access to the debt capital markets and the commercial paper market, and the Company’s borrowing costs would increase. In addition, Utility Holdings would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Finally, there is no assurance that the Company will have access to the equity capital markets to obtain financing when necessary or desirable.
Utility Holdings’ gas and electric utility sales are concentrated in the Midwest.
The operations of the Company’s regulated utilities are concentrated in central and southern Indiana and west central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest. These industries include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, polycarbonate resin (Lexan®) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, ethanol and coal mining.
Utility Holdings operates in an increasingly competitive industry, which may affect its future earnings.
The utility industry has been undergoing structural change for several years, resulting in increasing competitive pressure faced by electric and gas utility companies. Increased competition may create greater risks to the stability of the Company’s earnings generally and may in the future reduce its earnings from retail electric and gas sales. Currently, several states, including Ohio, have passed legislation that allows customers to choose their electricity supplier in a competitive market. Indiana has not enacted such legislation. Ohio regulation also provides for choice of commodity providers for all gas customers. In 2003, the Company implemented this choice for its gas customers in Ohio and is currently in the second of the three phase process to exit the merchant function in its Ohio service territory. The state of Indiana has not adopted any regulation requiring gas choice in the Company’s Indiana service territories; however, the Company operates under approved tariffs permitting certain industrial and commercial large volume customers to choose their commodity supplier. 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 Utility Holdings’ electric utility sales are space heating and cooling. Accordingly, its operating results may fluctuate with variability of weather.
Utility Holdings’ electric utility sales are sensitive to variations in weather conditions. The Company forecasts utility sales on the basis of normal weather. Since the Company does not have a weather-normalization mechanism for its electric operations, significant variations from normal weather could have a material impact on its earnings. However, the impact of weather on the gas operations in the Company’s Indiana territories has been significantly mitigated through the implementation in 2005 of a normal temperature adjustment mechanism. Additionally, the implementation of a straight fixed variable rate design in a January 2009 PUCO order mitigates most weather risk related to Ohio residential gas sales.
Risks related to the regulation of Utility Holdings’ utility businesses, including environmental regulation, could affect the rates the Company charges its customers, its costs and its profitability.
Utility Holdings’ businesses are subject to regulation by federal, state, and local regulatory authorities and are exposed to public policy decisions that may negatively impact the Company’s earnings. In particular, Utility Holdings is subject to regulation by the FERC, the NERC, the EPA, the IURC, and the PUCO. These authorities regulate many aspects of its transmission and distribution operations, including construction and maintenance of facilities, operations, and safety, and its gas marketing operations involving title passage, reliability standards, and future adequacy. In addition, these regulatory agencies approve its utility-related debt and equity issuances, regulate the rates that the Company can charge customers, the rate of return that Utility Holdings’ utilities are authorized to earn, and its ability to timely recover gas and fuel costs. Further, there are consumer advocates and other parties which may intervene in regulatory proceedings and affect regulatory outcomes. The Company’s ability to obtain rate increases to maintain its current authorized rates of return depends upon regulatory discretion, and there can be no assurance that the Company will be able to obtain rate increases or rate supplements or earn its current authorized rates of return.
Utility Holdings’ operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. These environmental regulations impose, among other things, restrictions, liabilities, and obligations in connection with storage, transportation, treatment, and disposal of hazardous substances and waste in connection with spills, releases, and emissions of various substances in the environment. Such airborne emissions from electric generating facilities include particulate matter, sulfur dioxide (SO2), nitrogen oxide (NOx), and mercury, among others.
Environmental legislation also requires that facilities, sites, and other properties associated with the Company’s operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. The Company’s current costs to comply with these laws and regulations are significant to its results of operations and financial condition. In addition, claims against the Company under environmental laws and regulations could result in material costs and liabilities. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by the Company subject to environmental regulation, its investment in environmentally compliant equipment, and the costs associated with operating that equipment, have increased and are expected to increase in the future. As examples of the trend toward stricter regulation, the EPA is currently reviewing/revising regulations involving fly ash disposal, cooling tower intake facilities, greenhouse gases, and airborne emissions such as SO2 and NOx.
Climate change regulation could negatively impact operations.
There are proposals to address global climate change that would regulate carbon dioxide (CO2) and other greenhouse gases and other proposals that would mandate an investment in renewable energy sources. Any future legislative or regulatory actions taken by the EPA or other agencies to address global climate change or mandate renewable energy sources could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses. Further, such legislation or regulatory action would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation or regulatory mandates, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets.
Any additional expenses or capital incurred by the Company, as it relates to complying with greenhouse gas emissions regulation or other environmental regulations, are expected to be borne by the customers in its service territories through increased rates. Increased rates have an impact on the economic health of the communities served. New regulations could also negatively impact industries in the Company’s service territory, including industries in which the Company operates.
The Company is exposed to physical and financial risks related to the uncertainty of climate change.
A changing climate creates uncertainty and could result in broad changes to the Company’s service territories. These impacts could include, but are not limited to, population shifts; changes in the level of annual rainfall; changes in the weather; and changes to the frequency and severity of weather events such as thunderstorms, wind, tornadoes, and ice storms that can damage infrastructure. Such changes could impact the Company in a number of ways including the number and/or type of customers in the Company’s service territories; the demand for energy resulting in the need for additional investment in generation assets or the need to retire current infrastructure that is no longer required; an increase to the cost of providing service; and an increase in the likelihood of capital expenditures to replace damaged infrastructure.
To the extent climate change impacts a region’s economic health, it may also impact the Company’s revenues, costs, and capital structure and thus the need for changes to rates charged to regulated customers. Rate changes themselves can impact the economic health of the communities served and may in turn adversely affect the Company’s operating results.
The Company may face certain regulatory and financial risks related to pipeline safety legislation.
There are federal proposals currently pending that would increase pipeline operations oversight and would lead to an investment in the inspection, and where necessary, the replacement of pipeline infrastructure. At this time and in the absence of final legislation, compliance costs and other effects associated with increased pipeline safety regulations remain uncertain. However, any future legislative or regulatory actions taken to address pipeline safety could substantially affect both operating expenses and capital expenditures associated with the Company’s natural gas distribution businesses. The Company has been successful in the past recovering costs resulting from government mandates. However, if the Company is unable to recover from customers through the regulatory process all or some of these costs, including its authorized rate of return on replacement projects, results of operations, financial condition, and cash flows could be adversely impacted.
Utility Holdings’ regulated distribution operations are subject to various risks.
A variety of hazards and operations risks, such as leaks, accidental explosions, and mechanical problems are inherent in the Company’s gas and electric distribution activities. If such events occur, they could cause substantial financial losses and result in loss of human life, significant damage to property, environmental pollution, and impairment of operations. The location of pipelines, storage facilities, and the electric grid near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject the Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines, or penalties or be resolved on unfavorable terms. In accordance with customary industry practices, the Company maintains insurance against a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these events is not fully covered by insurance, it could adversely affect the Company’s financial condition and results of operations.
Utility Holdings’ electric operations are subject to various risks.
The Company’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs. Such operational risks can arise from circumstances such as facility shutdowns due to equipment failure or operator error; interruption of fuel supply or increased prices of fuel as contracts expire; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; and natural disasters.
The impact of MISO participation is uncertain.
Since February 2002 and with the IURC’s approval, the Company has been a member of the MISO. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over SIGECO’s electric transmission facilities as well as that of other Midwest utilities.
As a result of MISO’s operational control over much of the Midwestern electric transmission grid, including SIGECO’s transmission facilities, SIGECO’s continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted.
The need to expend capital for improvements to the regional transmission system, both to SIGECO’s facilities as well as to those facilities of adjacent utilities, over the next several years is expected to be significant. The Company timely recovers its investment in certain new electric transmission projects that benefit the MISO infrastructure at a FERC approved rate of return.
Wholesale power marketing activities may add volatility to earnings.
Utility Holdings’ regulated electric utility engages in wholesale power marketing activities that primarily involve the offering of utility-owned or contracted generation into the MISO hourly and real time markets. As part of these strategies, the Company may also execute energy contracts that are integrated with portfolio requirements around power supply and delivery. Presently, margin earned from these activities above or below $10.5 million is shared evenly with customers. These earnings from wholesale marketing activities may vary based on fluctuating prices for electricity and the amount of electric generating capacity or purchased power available beyond that needed to meet firm service requirements. In addition, this earnings sharing approach may be modified in future regulatory proceedings.
Increases in the wholesale price of natural gas, coal, and electricity could reduce earnings and working capital.
The Company’s operations have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal, and purchased power for the benefit of retail customers due to current state regulations, which subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. However, significant increases in the price of natural gas, coal, or purchased power may cause existing customers to conserve or motivate them to switch to alternate sources of energy as well as cause new home developers, builders, and new customers to select alternative sources of energy. Decreases in volumes sold could reduce earnings. The decrease would be more significant in the absence of constructive regulatory orders, such as those authorizing revenue decoupling, lost margin recovery, and other innovative rate designs. A decline in new customers could impede growth in future earnings. In addition, during periods when commodity prices are higher than historical levels, working capital costs could increase due to higher carrying costs of inventories and cost recovery mechanisms, and customers may have trouble paying higher bills leading to bad debt expenses.
Increased derivative regulation could impact results.
The Company uses natural gas derivative instruments in conjunction with procurement activities. The Company also uses interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances.
In July 2010, legislation regulating the use of derivative instruments was signed into law. These new regulations include, but are not limited to, a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral for certain transactions. Depending on the regulations adopted by the Commodities Futures Trading Commission (CFTC) and other agencies, the Company could be required to post additional collateral with dealer counterparties for commitments and interest rate derivative transactions. Requirements to post collateral could limit cash for investment and for other corporate purposes or could increase debt levels. In addition, a requirement for counterparties to post collateral could result in additional costs associated with executing transactions, thereby decreasing profitability. An increased collateral requirement could also reduce the Company’s ability to execute derivative transactions to reduce commodity price and interest rate uncertainty and to protect cash flows.
The law provides for a potential exception from these clearing and cash collateral requirements for commercial end-users. Significant rule-making by numerous governmental agencies, particularly the CFTC, must be adopted in the near term so that the restrictions, limitations, and requirements contemplated by the new law can be implemented. The Company will continue to evaluate the impact as these rules become available and whether any exemption will apply to the Company’s use of derivative instruments.
From time to time, Utility Holdings is subject to material litigation and regulatory proceedings.
From time to time, the Company may be subject to material litigation and regulatory proceedings including matters involving compliance with state and federal laws, regulations or other matters. There can be no assurance that the outcome of these matters will not have a material adverse effect on the Company’s business, prospects, results of operations, or financial condition.
The investment performance of Vectren’s pension plan holdings and other factors impacting pension plan costs could impact the Company’s liquidity and results of operations.
The costs associated with Vectren’s retirement plans are dependent on a number of factors, such as the rates of return on plan assets; discount rates; the level of interest rates used to measure funding levels; changes in actuarial assumptions; future government regulation; and Vectren contributions. In addition, Vectren could be required to provide for significant funding of these defined benefit pension plans. Vectren relies on Utility Holdings to fund a majority of the contributions to these plans. Such cash funding obligations could have a material impact on liquidity by reducing cash flows for other purposes and could negatively affect results of operations.
Catastrophic events could adversely affect Utility Holdings’ facilities and operations.
Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts or other similar occurrences could adversely affect the Company’s facilities, operations, financial condition and results of operations.
Workforce risks could affect Utility Holdings’ financial results.
The Company is subject to various workforce risks, including but not limited to, the risk that it will be unable to attract and retain qualified personnel; that it will be unable to effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; that it will be unable to react to a pandemic illness; and that it will be unable to reach collective bargaining arrangements with the unions that represent certain of its workers, which could result in work stoppages.
The performance of Vectren’s nonutility businesses may impact Utility Holdings.
Execution of Vectren’s nonutility business strategies and the success of efforts to invest in and develop new opportunities in the nonutility business area are subject to a number of risks.
Related to Vectren’s nonutility energy marketing activities, ProLiance is a 61 percent owned energy marketing affiliate of Vectren. ProLiance relies on long-term firm transportation and storage contracts with pipeline companies to deliver natural gas to its customer base which includes the Company’s Indiana utilities. Those contracts are optimized by balancing physical and financial markets and summer and winter time horizons. A significant decline in optimization opportunities may result in the inability to fully recover these fixed price obligations. Recent market conditions have compressed optimization opportunities, and ProLiance has operated at a loss. If current market conditions continue, resulting in continued depressed asset optimization opportunities, it is expected that ProLiance will experience a loss in 2011. Losses could continue in future years should ProLiance be unable to adjust to the current market conditions or be unsuccessful in renegotiating its transportation and storage contracts over time.
Related to Vectren’s nonutility coal mining activities, Vectren Fuels is wholly owned by Vectren and is supplier of coal to Utility Holdings’ Indiana electric utility. Risks specific to Vectren’s coal mining strategies include, but are not limited to, failure to fully access coal at owned mines; failure to operate mines in accordance with MSHA guidelines and regulations; increased coal mining industry regulation; failure to negotiate and execute new sales contracts; failure to manage coal mining production and production costs and other risks in response to changes in demand; changes in marked demand for coal; and unanticipated changes in coal commodity prices.
In addition, there are other risks impacting Vectren’s nonutility operations including the effects of weather; failure of installed performance contracting products to operate as planned; failure to properly estimate the cost to construct projects; failure to develop or obtain gas storage field and mining property; potential legislation that may limit CO2 and other greenhouse gas emissions; creditworthiness of customers and joint venture partners; changes in federal, state or local legal requirements, such as changes in tax laws or rates; and changing market conditions.
Credit ratings of individual entities within a consolidated organization can be influenced by changes in business prospects and developments of other entities within that organization. Thus, material adverse developments affecting those other entities related to Vectren could result in a downgrade in Utility Holdings’ credit ratings or outlook, limit its ability to access the debt markets, bank financing and commercial paper markets and, thus, its liquidity.
Vectren’s nonutility businesses support Utility Holdings’ utilities pursuant to service contracts by providing natural gas supply services, coal, and infrastructure services. In most instances, Vectren’s ability to maintain these service contracts depends upon regulatory discretion and negotiation with interveners, and there can be no assurance that it will be able to obtain future service contracts, or that existing arrangements will not be revisited.
None.
Gas Utility Services
Indiana Gas owns and operates four active gas storage fields located in Indiana covering 58,100 acres of land with an estimated ready delivery from storage capability of 6.0 BCF of gas with maximum peak day delivery capabilities of 151,000 MCF per day. Indiana Gas also owns and operates three liquefied petroleum (propane) air-gas manufacturing plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of manufactured gas per day. In addition to its company owned storage and propane capabilities, Indiana Gas has contracted with ProLiance for 16.7 BCF of interstate natural gas pipeline storage service with a maximum peak day delivery capability of 252,600 MMBTU per day. Indiana Gas’ gas delivery system includes 13,000 miles of distribution and transmission mains, all of which are in Indiana except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported by Indiana Gas to ultimate customers in Indiana.
SIGECO owns and operates three active underground gas storage fields located in Indiana covering 6,100 acres of land with an estimated ready delivery from storage capability of 6.3 BCF of gas with maximum peak day delivery capabilities of 108,500 MCF per day. In addition to its company owned storage delivery capabilities, SIGECO has contracted with ProLiance for 0.5 BCF of interstate pipeline storage service with a maximum peak day delivery capability of 19,200 MMBTU per day. SIGECO's gas delivery system includes 3,200 miles of distribution and transmission mains, all of which are located in Indiana.
The Ohio operations own and operate three liquefied petroleum (propane) air-gas manufacturing plants, all of which are located in Ohio. The plants can store 0.5 million gallons of propane, and the plants can manufacture for delivery 52,200 MCF of manufactured gas per day. In addition to its propane delivery capabilities, the Ohio operations have contracted for 11.8 BCF of natural gas delivery service with a maximum peak day delivery capability of 246,100 MMBTU per day. While the Company still has title to this delivery capability, it has released it to those retail gas marketers now supplying the Ohio operations with natural gas, and those suppliers are responsible for the demand charges. The Ohio operations’ gas delivery system includes 5,500 miles of distribution and transmission mains, all of which are located in Ohio.
Electric Utility Services
SIGECO's installed generating capacity as of December 31, 2010, was rated at 1,298 MW. SIGECO's coal-fired generating facilities are the Brown Station with two units of 490 MW of combined capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the Culley Station with two units of 360 MW of combined capacity, and Warrick Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking units are: two 80 MW gas turbines (Brown Unit 3 and Brown Unit 4) located at the Brown Station; two Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1, 50 MW and Broadway Avenue Unit 2, 65 MW); and two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW. The Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil. Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally used only for reserve, peaking, or emergency purposes due to the higher per unit cost of generation. In 2009, SIGECO, with IURC approval, purchased a landfill gas electric generation project in Pike County, Indiana with a total capability of 3 MW.
SIGECO's transmission system consists of 993 circuit miles of 345Kv, 138Kv and 69Kv lines. The transmission system also includes 34 substations with an installed capacity of 4,863 megavolt amperes (Mva). The electric distribution system includes 4,265 pole miles of lower voltage overhead lines and 366 trench miles of conduit containing 1,981 miles of underground distribution cable. The distribution system also includes 96 distribution substations with an installed capacity of 2,966 Mva and 54,000 distribution transformers with an installed capacity of 2,331 Mva.
SIGECO owns utility property outside of Indiana approximating nine miles of 138,000 volt electric transmission line which is located in Kentucky and which interconnects with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky.
Property Serving as Collateral
SIGECO's properties are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures.
The Company is party to various legal proceedings and audits and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows. See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated condensed financial statements are included in “Item 8 Financial Statements and Supplementary Data.”
PART II
Common Stock Market Price
All of the outstanding shares of Utility Holdings’ common stock are owned by Vectren. Utility Holdings’ common stock is not traded. There are no outstanding options or warrants to purchase Utility Holdings’ common equity or securities convertible into Utility Holdings’ common equity. Additionally, Utility Holdings has no plans to publicly offer its common equity securities.
Dividends Paid to Parent
During 2010, Utility Holdings paid dividends to its parent company in the first through fourth quarters totaling $19.1 million, $20.3 million, $20.3 million, and $28.1 million, respectively.
During 2009, Utility Holdings paid dividends to its parent company totaling $20.6 million in each quarter.
In the first quarter of 2011, Utility Holdings paid a $22.9 million dividend to its parent company.
Dividends on shares of common stock are payable at the discretion of the board of directors out of legally available funds. Future payments of dividends, and the amounts of these dividends, will depend on the Company’s financial condition, results of operations, capital requirements, and other factors. Certain lending arrangements contain restrictive covenants, including the maintenance of a total debt to total capitalization ratio, which could limit the Company’s ability to pay dividends. These restrictive covenants are not expected to affect the Company’s ability to pay dividends in the near term.
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.
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Year Ended December 31,
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||||||||||||||||||||
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(In millions)
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2010
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2009
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2008
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2007
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2006
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|||||||||||||||
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Operating Data:
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||||||||||||||||||||
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Operating revenues
|
$ | 1,563.7 | $ | 1,596.2 | $ | 1,958.7 | $ | 1,759.0 | $ | 1,656.5 | ||||||||||
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Operating income
|
277.0 | 238.0 | 254.6 | 244.4 | 209.0 | |||||||||||||||
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Net income
|
123.9 | 107.4 | 111.1 | 106.5 | 91.4 | |||||||||||||||
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Balance Sheet Data:
|
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Total assets
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$ | 3,924.5 | $ | 3,823.1 | $ | 3,838.1 | $ | 3,643.7 | $ | 3,440.8 | ||||||||||
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Long-term debt - net of current maturities
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||||||||||||||||||||
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& debt subject to tender
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1,024.8 | 1,254.8 | 1,065.1 | 1,062.6 | 1,025.3 | |||||||||||||||
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Common shareholder's equity
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1,315.4 | 1,274.7 | 1,242.9 | 1,090.4 | 1,056.7 | |||||||||||||||
Utility Holdings generates revenue primarily from the delivery of natural gas and electric service to its customers. Utility Holdings’ primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services.
Vectren has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of Utility Holdings’ SEC filings.
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The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto.
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Executive Summary of Consolidated Results of Operations
In 2010, Utility Holdings’ earnings were $123.9 million, compared to earnings of $107.4 million in 2009 and $111.1 million in 2008. The increase in 2010 compared to 2009 results from the return of large customer usage, summer cooling weather that was significantly warmer than normal and the prior year, and lower operating expenses. Utility Holdings’ results were down only modestly in 2009 compared to 2008, even after considering the impacts of the recession on large customer usage and wholesale power sales and mild cooling weather. The years presented have also been impacted by increased depreciation expense and interest expense associated with rate base growth, increased revenues associated with regulatory initiatives, volatile market values associated with investments related to benefit plans, and changes in the effective tax rate.
Margin in the Company’s electric and the Ohio natural gas service territory, which was not fully protected by straight fixed variable rate design in 2009 and 2008, is impacted by weather. During 2010, cooling weather was 34 percent warmer than normal and 49 percent warmer than the prior year. Due primarily to the extreme cooling weather, management estimates the margin impact of weather to be approximately $10.4 million favorable compared to normal temperatures. Compared to 2009 which was impacted by mild cooling weather, the margin impact is estimated to be $14.2 million. In 2008 weather impacts were $1.2 million unfavorable compared to normal temperatures. Management estimates the impact of weather based on an assumption of weather sensitive sales per degree day at current rates.
Trends in Operations
The Regulatory Environment
Gas and electric operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters specific to its Indiana customers (the operations of SIGECO and Indiana Gas), are regulated by the IURC. The retail gas operations of the Ohio operations (VEDO) are subject to regulation by the PUCO.
Over the last four years, the Company has obtained base rate orders at each of its four utilities with SIGECO’s gas and electric territories obtaining base rate increases in August of 2007, Indiana Gas in February 2008, and VEDO in January 2009. The orders authorize a return on equity ranging from 10.15% to 10.40%. The authorized returns reflect the impact of innovative rate design strategies having been authorized by these state commissions. Outside of a full base rate proceeding, these innovative approaches to some extent mitigate the impacts of investments in government-mandated projects, operating costs that are volatile or that increase with government mandates, and changing consumption patterns. In addition to timely gas and fuel cost recovery, just over $50 million of the Company’s approximate $300 million in other operating expenses incurred during 2010 are subject to a recovery mechanism outside of base rates.
Rate Design Strategies
Sales of natural gas and electricity to residential and commercial customers are seasonal and are impacted by weather. Trends in average use among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed, the Company’s utilities have implemented conservation programs, and the price of natural gas has been volatile. In the Company’s two Indiana natural gas service territories, normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. The Ohio natural gas service territory has a straight fixed variable rate design. This rate design, which was fully implemented in February 2010, mitigates most of the Ohio service territory’s weather risk and risk of decreasing consumption. Prior to the implementation of this rate design, the Ohio service territory had a lost margin recovery mechanism. In all natural gas service territories, commissions have authorized bare steel and cast iron replacement programs. SIGECO’s electric service territory currently recovers certain environmental investments and other transmission investments outside of base rates. The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs proposed in the current rate proceeding before the IURC and other related filings would limit weather risk and provide for a decoupling and/or a lost margin recovery mechanism that works in tandem with conservation initiatives.
Tracked Operating Expenses
Gas costs and fuel costs incurred to serve Indiana customers are two of the Company’s most significant operating expenses. Rates charged to natural gas customers in Indiana contain a gas cost adjustment (GCA) clause. The GCA clause allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on historical experience. Electric rates contain a fuel adjustment clause (FAC) that allows for timely adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an approved variable benchmark based on NYMEX natural gas prices, is also timely recovered through the FAC.
GCA and FAC procedures involve periodic filings and IURC hearings to establish the amount of price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred.
The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. These earnings tests have not had any material impact to the Company’s recent operating results and are not expected to have any material impact in the foreseeable future.
Prior to October 1, 2008, gas costs were recovered in Ohio through a gas cost recovery (GCR) mechanism. The GCR operated similar to the GCA clause in Indiana; however, the GCR was subject to a periodic audit rather than a quarterly hearing process. The PUCO has completed all audits of periods prior to October 2008, and no issues or findings are outstanding. After October 1, 2008, the Company is no longer the supplier of natural gas to customers, and therefore no longer recovers natural gas costs via the GCR.
In Indiana, gas pipeline integrity management costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of standard base rate recovery. Certain operating costs, including depreciation, associated with operating environmental compliance equipment at electric generation facilities and regional electric transmission investments are also recovered outside of base rates. In Ohio expenses such as uncollectible accounts expense, costs associated with exiting the merchant function, and costs associated with a distribution replacement program are subject to recovery outside of base rates. Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs.
See the Rate and Regulatory Matters section of this discussion and analysis for more specific information on significant proceedings involving the Company’s utilities over the last three years.
MARGIN
Gas Utility Margin (Gas utility revenues less Cost of gas sold)
Gas utility margin and throughput by customer type follows:
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Year Ended December 31,
|
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(In millions)
|
2010
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2009
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2008
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|||||||||
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Gas utility revenues
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$ | 954.1 | $ | 1,066.0 | $ | 1,432.7 | ||||||
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Cost of gas sold
|
504.7 | 618.1 | 983.1 | |||||||||
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Total gas utility margin
|
$ | 449.4 | $ | 447.9 | $ | 449.6 | ||||||
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Margin attributed to:
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||||||||||||
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Residential & commercial customers
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$ | 385.1 | $ | 388.8 | $ | 385.5 | ||||||
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Industrial customers
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52.4 | 46.8 | 51.2 | |||||||||
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Other
|
11.9 | 12.3 | 12.9 | |||||||||
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Sold & transported volumes in MMDth attributed to:
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||||||||||||
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Residential & commercial customers
|
106.2 | 106.5 | 114.8 | |||||||||
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Industrial customers
|
90.8 | 78.0 | 91.5 | |||||||||
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Total sold & transported volumes
|
197.0 | 184.5 | 206.3 | |||||||||
Over the three years ended December 31, 2010, there has been a decline in the volumes sold to residential and commercial customers driven by weather and changing consumption patterns. However, the impact on margin has been generally offset as planned by rate design strategies and the implementation of new base rates in two of the three gas service territories. Large customer volumes were impacted by the recession, falling approximately 15 percent in 2009 compared to 2008. With the economy stabilizing in 2010, volumes in 2010 returned to 2008 levels. The shifting volumes were the principal reason for the change in large customer margin in those years. The average cost per dekatherm of gas purchased during 2010 was $5.99, compared to $5.97 in 2009 and $9.61 in 2008.
For the year ended December 31, 2010, gas utility margins were $449.4 million and compared to 2009 increased $1.5 million. Management estimates an increase of $2.4 million due to Ohio rate design changes, as described below. Large customer margin, net of the impacts of regulatory initiatives and tracked costs, increased by $5.7 million due primarily to increased volumes sold. Margin decreased $1.9 million due to lower miscellaneous revenues and other revenues associated with lower gas costs. The remaining decrease is primarily due to a $5.0 million decrease for lower operating expenses and revenue taxes directly recovered in margin.
For the year ended December 31, 2009, gas utility margins decreased $1.7 million compared to 2008. Management estimates a $4.4 million year over year decrease in industrial customer margin associated with lower volumes sold, and slightly lower residential and commercial customer counts decreased margin approximately $1.7 million. These recessionary impacts were offset by margin associated with regulatory initiatives. Among all customer classes, margin increases associated with regulatory initiatives, including the full impact of the Vectren North base rate increase effective in February 2008 and the Vectren Ohio base rate increase effective February 2009, were $8.4 million year over year. The impact of operating costs, including revenue and usage taxes, recovered in margin was unfavorable $2.9 million year over year, reflecting lower revenue taxes offset by higher pass through operating expenses. The remaining decrease primarily relates to Ohio weather and lower miscellaneous revenues associated with reconnection fees. The lower fees as well as the lower revenue and usage taxes correlate with lower year over year gas costs.
The rate design approved by the PUCO on January 7, 2009, and initially implemented on February 22, 2009, allowed for the phased movement toward a straight fixed variable rate design, which places substantially all of the fixed cost recovery in the monthly customer service charge. This rate design mitigates most weather risk as well as the effects of declining usage, similar to the company’s lost margin recovery mechanism in place in the Indiana natural gas service territories and the mechanism in place in Ohio prior to this rate order. Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate gas margins were recovered through the customer service charge. As a result, some margin previously recovered during the peak delivery winter months was more ratably recognized throughout the year. In addition in 2010, the Company began recognizing a return on and of investments made to replace distribution risers and bare steel and cast iron infrastructure per a PUCO order.
Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)
Electric utility margin and volumes sold by customer type follows:
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Year Ended December 31,
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(In millions)
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2010
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2009
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2008
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Electric utility revenues
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$ | 608.0 | $ | 528.6 | $ | 524.2 | ||||||
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Cost of fuel & purchased power
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235.0 | 194.3 | 182.9 | |||||||||
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Total electric utility margin
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$ | 373.0 | $ | 334.3 | $ | 341.3 | ||||||
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Margin attributed to:
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Residential & commercial customers
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$ | 241.2 | $ | 224.7 | $ | 218.0 | ||||||
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Industrial customers
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97.1 | 81.7 | 83.4 | |||||||||
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Municipals & other customers
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8.5 | 7.2 | 7.4 | |||||||||
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Subtotal: Retail
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$ | 346.8 | $ | 313.6 | $ | 308.8 | ||||||
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Wholesale margin
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26.2 | 20.7 | 32.5 | |||||||||
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Total electric utility margin
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$ | 373.0 | $ | 334.3 | $ | 341.3 | ||||||
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Electric volumes sold in GWh attributed to:
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Residential & commercial customers
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2,964.0 | 2,760.8 | 2,850.5 | |||||||||
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Industrial customers
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2,630.3 | 2,258.9 | 2,409.1 | |||||||||
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Municipals & other
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22.6 | 20.0 | 63.8 | |||||||||
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Total retail & firm wholesale volumes sold
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5,616.9 | 5,039.7 | 5,323.4 | |||||||||
Retail
Electric retail utility margins were $346.8 million for the year ended December 31, 2010, and compared to 2009 increased $33.2 million. Management estimates the impact of warmer than normal weather to have increased residential and commercial margin $14.2 million year over year. Management also estimates industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, to have increased approximately $12.8 million year to date due primarily to increased volumes. Margin among the customer classes associated with returns on pollution control investments increased $3.4 million, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $4.1 million.
Electric retail utility margin was $313.6 million for the year ended December 31, 2009, and compared to 2008 increased $4.8 million. Increased margin among the customer classes associated with returns on pollution control equipment and other investments totaled $4.5 million year over year, and margin associated with tracked costs such as recovery of MISO and pollution control operating expenses increased $10.3 million. Management estimates weather, driven primarily by cooling weather 10 percent milder than the prior year, decreased residential and commercial margin $5.2 million compared to 2008. Industrial margins, net of the impacts of regulatory initiatives and recovery of tracked costs, decreased approximately $4.9 million due primarily to the weak economy. The industrial decreases were due primarily to lower usage.
Margin from Wholesale Electric Activities
Periodically, generation capacity is in excess of native load. The Company markets and sells this unutilized generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales occur into the MISO Day Ahead and Real Time markets. Further detail of Wholesale activity follows:
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Year Ended December 31,
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(In millions)
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2010
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2009
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2008
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Transmission system margin
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$ | 18.8 | $ | 14.6 | $ | 9.3 | ||||||
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Off-system margin
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7.4 | 6.1 | 23.2 | |||||||||
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Total wholesale margin
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$ | 26.2 | $ | 20.7 | $ | 32.5 | ||||||
Beginning in June 2008, the Company began earning a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of MISO’s regional transmission expansion plans. Margin associated with these projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $18.8 million during 2010, compared to $14.6 in 2009 and $9.3 million in 2008. The increase in these transmission system sales is principally due to the increased investment in qualifying projects.
For the year ended December 31, 2010, margin from off-system sales was $7.4 million, compared to $6.1 million in 2009 and $23.2 million in 2008. In 2009 compared to 2008, margin from off-system sales decreased $17.1 million. The Company experienced lower wholesale power marketing margins due primarily to lower demand and wholesale prices due to the recession, coupled with increased coal costs. Off-system sales totaled 587.6 GWh in 2010, compared to 603.6 GWh in 2009, and 1,512.9 GWh in 2008. The base rate increase effective August 17, 2007, requires that wholesale margin from off-system sales earned above or below $10.5 million be shared equally with customers as measured on a fiscal year ending in August. Results for the periods presented reflect the impact of that sharing.
Purchased Power
The Company’s mix of generated and purchased electricity has been more volatile in recent years due to changing commodity prices and the presence of wind farm purchased power agreements. For the years ended December 31, 2010, 2009, and 2008, respectively, the Company purchased approximately 1,287 GWh, 1,159 GWh, and 372 GWh, of power from the MISO and other sources. The total cost associated with these volumes of purchased power is approximately $56 million, $43 million, and $26 million in 2010, 2009, and 2008, respectively, and is included in the Cost of fuel & purchased power.
Operating Expenses
Other Operating
For the year ended December 31, 2010, other operating expenses were $ 299.2 million, which is a decrease in expenses compared to 2009. Excluding expenses tracked directly in margin, operating costs decreased $7.9 million. The primary drivers of the decrease are a $3.0 million reduction in Indiana uncollectible accounts expense and the $4.1 million in costs for environmental matters related to manufactured gas plant site clean-up incurred in 2009.
For the year ended December 31, 2009, other operating expenses were $304.6 million, increasing $4.3 million compared to 2008. Approximately $10.9 million of the change results from increased costs directly recovered through utility margin. Increases in other operating expenses in 2009, not directly recovered in margin, include an approximate $6.3 million increase for certain compensation costs and a $4.1 million increase associated with environmental matters related to manufactured gas plant site clean-up. All other operating expenses were approximately $17.0 million lower than the prior year driven primarily by reductions in electric maintenance costs and lower chemical costs. Despite significantly lower gas costs due to the recession, Indiana uncollectible accounts expense was only slightly favorable compared to 2008.
Depreciation & Amortization
For the year ended December 31, 2010, depreciation expense was $188.2 million, compared to $180.9 in 2009 and $165.5 in 2008. The increase over the periods presented is due largely to utility capital expenditures placed into service. Plant placed into service in 2009 included the approximate $100 million SO2 scrubber.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $0.7 million in 2010 compared to 2009 and decreased $12.0 million in 2009 compared to 2008. These taxes are primarily revenue-related taxes. The variations are primarily attributable to volatility in revenues, inclusive of changes in natural gas prices and gas volumes sold. These tax expenses are recovered through revenue.
Other Income-Net
Other income-net reflects income of $5.4 million in 2010, compared to income of $7.8 million in 2009 and $4.0 million in 2008. The higher earnings in 2009 reflect the partial recovery from the 2008 market declines associated with investments related to benefit plans.
Interest Expense
For the year ended December 31, 2010, interest expense was $81.4 million, compared to $79.2 million in 2009 and $79.9 million in 2008. The $2.2 million increase in 2010 compared to 2009 reflects the impact of long-term financing transactions completed in 2009, offset by lower interest from less debt outstanding overall. The slight decrease in interest expense in 2009 compared to 2008 reflects lower short-term interest rates and lower average short-term debt balances. The lower short-term balances were reflective of lower gas prices and the issuance of new long-term debt. The long-term financing transactions completed in 2009 include a second quarter issuance by Utility Holdings of $100 million in unsecured eleven year notes with an interest rate of 6.28 percent and a third quarter completion by SIGECO of a $22.3 million debt issuance of 31 year tax exempt first mortgage bonds with an interest rate of 5.4 percent.
Income Taxes
Federal and state income taxes were $77.1 million in 2010, compared to $59.2 million in 2009 and $67.6 million in 2008. The annual change is primarily impacted by greater pre-tax income in 2010 and no manufacturing tax deduction in 2010 as a result of significant bonus depreciation driving down qualifying income. In addition, the lower effective tax rate in 2009 reflects a greater share of taxable income in states with low, or no, state income taxes.
During the first quarter of 2010, the Company recorded a $2.3 million increase to its deferred tax liabilities associated with a change in the federal tax treatment of the Medicare Part D subsidy as a result of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 signed by the President as of the end of March 2010. Like tax law changes in the past, it is expected that the impact of this change will be reflected in customer rates in the future. As a result, the Company has recorded a $5.1 million regulatory asset related to this matter in its financial statements at December 31, 2010.
Environmental Matters
Clean Air Act
The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations. Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the EPA for promulgation of revisions in accordance with the Court’s July 11, 2008 order. Thus, the original version of CAIR promulgated in March of 2005 remains effective while EPA revises it per the Court’s guidance. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009, and the Phase I annual SO2 reduction requirements in effect on January 1, 2010. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised. Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.
Similarly, in March of 2005, EPA promulgated the Clean Air Mercury Rule (CAMR). CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008. In response to the court decision, EPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2011. It is uncertain what emission limit the EPA is considering, and whether they will address hazardous pollutants in addition to mercury.
To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2 reductions, SIGECO has IURC authority to invest in clean coal technology. Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO’s new electric base rates that went into effect on August 15, 2007, and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.
SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. SIGECO's investments in scrubber, SCR, and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by EPA. On July 6, 2010, the EPA issued its proposed revisions to CAIR, renamed the Clean Air Transport Rule, for public comment. The Transport Rule proposes a 71 percent reduction of SO2 over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels and would further impact the utilization of currently granted SO2 and NOx allowances. The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Clean Air Transport Rule and currently does not expect significant capital expenditures will be required to comply if the Transport Rule is adopted in its current form.
Climate Change
The Company is committed to responsible environmental stewardship and conservation efforts. While scientific uncertainties exist and the debate surrounding global climate change is ongoing, current information suggests a potential for adverse economic and social consequences should world-wide carbon dioxide (CO2) and other greenhouse gas emissions continue at present levels.
The Company emits greenhouse gases (GHG) primarily from its fossil fuel electric generation plants. The Company uses methodology described in the Acid Rain Program (under Title IV of the Clean Air Act) to calculate its level of direct CO2 emissions from its fossil fuel electric generating plants. The Company’s direct CO2 emissions from its plants over the past 5 years are represented below:
|
(in thousands)
|
2010
|
2009
|
2008
|
2007
|
2006
|
||||
|
Direct CO2 Emissions (tons)
|
6,120 | 5,500 | 1/ | 8,029 | 7,995 | 7,827 |
|
1/
|
The decline in emissions from 2008 to 2009 is primarily due to recessionary impacts that resulted in a 30 percent decrease in generation. It is not clear to what extent this recent reduction may continue.
|
Based on 2005 data made available through the Emissions and Generation Resource Integrated Database (eGRID) maintained by the EPA, the Company’s direct CO2 emissions from its fossil fuel electric generation that report under the Acid Rain Program were less than one half of one percent of all emissions in the United States from similar sources. The EPA has yet to release data subsequent to 2005.
Emissions from other Company operations, including those from its natural gas distribution operations, are monitored internally using the Department of Energy 1605(b) Standard, and the Company will report these other emissions generated in 2010 to the EPA per mandatory reporting requirements later in 2011.
The need to reduce CO2 and other greenhouse gas emissions, yet provide affordable energy, requires thoughtful balance. For these reasons, the Company supports a national climate change policy with the following elements:
|
·
|
An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions;
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·
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Provisions for enhanced use of renewable energy sources as a supplement to base load coal generation including effective energy conservation, demand side management, and generation efficiency measures;
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·
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A flexible market-based cap and trade approach with zero cost allowance allocations to coal-fired electric generators. The approach should have a properly designed economic safety valve in order to reduce or eliminate extreme price spikes and potential price volatility. A long lead time must be included to align nearer-term technology capabilities and expanded generation efficiency and other enhanced renewable strategies, ensuring that generation sources will rely less on natural gas to meet short term carbon reduction requirements. This new regime should allow for adequate resource and generation planning and remove existing impediments to efficiency enhancements posed by the current New Source Review provisions of the Clean Air Act;
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|
·
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Inclusion of incentives for investment in advanced clean coal technology and support for research and development;
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|
·
|
A strategy supporting alternative energy technologies and biofuels and increasing the domestic supply of natural gas to reduce dependence on foreign oil and imported natural gas; and
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|
·
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The allocation of zero cost allowances to natural gas distribution companies if those companies are required to hold allowances for the benefit of the end use customer.
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Current Initiatives to Increase Conservation & Reduce Emissions
The Company is committed to a policy that reduces greenhouse gas emissions and conserves energy usage. Evidence of this commitment includes:
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·
|
Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs;
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·
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Building a renewable energy portfolio to complement base load coal-fired generation in advance of mandated renewable energy portfolio standards;
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·
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Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories;
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·
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The recent settlement agreement between the Company and the OUCC regarding electric demand side management initiatives;
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·
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Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans;
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·
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Reducing the Company’s carbon footprint by measures such as utilizing hybrid vehicles and optimizing generation efficiencies; and
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·
|
Developing renewable energy and energy efficiency performance contracting projects through Vectren’s wholly owned subsidiary, Energy Systems Group.
|
Legislative Actions & Other Climate Change Initiatives
Numerous competing legislative proposals have been introduced in recent years that involve carbon, energy efficiency, and renewable energy. Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date. The progression of regional initiatives throughout the United States has also slowed. While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state’s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.
In advance of a federal or state renewable portfolio standard, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly interconnected to the Company’s distribution system. In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy. These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008.
In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December of 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases. The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities. In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010). The EPA has also recently finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.
Impact of Legislative Actions & Other Initiatives is Unknown
If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses. Further, any legislation or regulatory actions taken by the EPA or other agencies would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation or regulatory mandates, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.
Ash Ponds & Coal Ash Disposal Regulations
In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The EPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations. The alternatives include regulating coal combustion by-products as hazardous waste. At this time, the majority of the Company’s ash is being beneficially reused. The proposals offered by EPA allow for the beneficial reuse of ash in certain circumstances. The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected. Annual compliance costs could increase slightly or be impacted by as much as $5 million.
Clean Water Act
Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures. In April of 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing facilities. The regulation was remanded back to the EPA for further consideration. Depending upon the approaches taken by the EPA when it reissues the regulation, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.
Jacobsville Superfund Site
On July 22, 2004, the EPA 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 EPA 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 EPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. The Company’s property has not been named as a source of the lead contamination. The Company’s own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels. At this time, it is anticipated that the EPA may request only additional soil testing at some future date.
Environmental Remediation Efforts
In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.
Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.
Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.1 million. The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent. With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.
In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM in February 2004. SIGECO was also named in a lawsuit, involving another waste disposal site subject to potential environmental remediation efforts. With respect to that lawsuit, SIGECO settled with the plaintiff during 2010 mitigating any future claims at this site. SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the recently settled lawsuit. In November, the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.
SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $15.8 million. However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time. With respect to insurance coverage, SIGECO has recorded approximately $14.1 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation. While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $8.2 million in proceeds have been received.
The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2010 and 2009, respectively, approximately $5.5 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.
Rate & Regulatory Matters
Vectren South Electric Base Rate Filing
On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates. The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers. On July 30, 2010, Vectren South revised downward its increase requested through the filing of its rebuttal position to approximately $34 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service and updates to operating costs and revenues. The rate design proposed in the filing would break the link between small residential and commercial customers’ consumption and the utility’s margin, thereby aligning the utility’s and customers’ interests in using less energy. The revised request assumes an overall rate of return of 7.42 percent on rate base of approximately $1.3 billion and an allowed return on equity (ROE) of 10.7 percent. The OUCC and SIGECO Industrial Group separately filed testimony in this case, proposing an increase of approximately $11 million and $18 million, respectively. Furthermore, the intervening parties in the case took differing views on, among other matters, the proposed rate design and the level and price of coal inventory. Hearings on all matters in the case were held in early March and late August 2010. An order is anticipated in the first half of 2011.
Vectren South Electric Fuel Adjustment Filings
As stated above, electric retail rates contain a fuel adjustment clause (FAC) that allows for periodic adjustment in energy charges to reflect changes in the cost of fuel and purchased power. The FAC procedures involve periodic filings and IURC hearings to approve the recovery of Vectren South’s fuel and purchased power costs.
During 2010, as part of its FAC testimony, the OUCC requested the IURC require Vectren South to renegotiate its term coal contracts because they were priced higher than prevailing spot prices. This request was repeated by the OUCC in Vectren South’s base rate proceeding referred to above. Vectren South purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008. Vectren South states in its rate case testimony that the prices in the coal contracts were at or below the market at the time of contract execution and were subject to a bidding process that included third parties. Further, the Company has already engaged in contract renegotiations to defer certain deliveries, and to eliminate some volumes in 2011, with further price negotiation to occur in 2011 under the terms of the contracts. The IURC has already found in a number of FAC proceedings since 2008, including in its most recent FAC order dated November 4, 2010, that the costs incurred under these coal contracts are reasonable.
The OUCC also raised concerns regarding Vectren South’s generating unit “must run” policy. Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions. The OUCC is reviewing data related to Vectren South’s “must run” policy.
The parties agreed to the creation of an FAC sub docket proceeding to address the specific issues noted above. An order establishing the sub docket was issued by the IURC on July 28, 2010. On November 30, 2010, in response to a joint motion filed by the OUCC and Vectren South, the IURC issued an order dismissing this sub docket as these coal contract issues will be addressed in the pending Vectren South Electric base rate case.
Vectren South Electric Demand Side Management Program Filing
On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, including large industrial customers. Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.
In its August filing, Vectren South proposed a three-year DSM Plan that expands its current portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC. Vectren South requested recovery of these program costs under a current tracking mechanism. In addition, Vectren South proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC. This performance incentive would also be recovered in the same tracking mechanism. Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers, and cited its decoupling proposal applicable to residential and general service customers in the pending electric base rate case. On January 20, 2011, the OUCC and Vectren South filed a settlement with the IURC reflecting agreement on the Company’s programs and lost margin recovery from large customers. A hearing will be held on March 8, 2011 involving all parties to this proceeding.
VEDO Gas Base Rate Order Received
On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case. The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.
The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers. The order allows for the phased movement toward a straight fixed variable rate design for residential customers which places all of the fixed cost recovery in the customer service charge. A straight fixed variable design mitigates most weather risk as well as the effects of declining usage, similar to the Company’s decoupling mechanism, which expired when this new rate design went into effect on February 22, 2009. In 2008, annual results include approximately $4.3 million of revenue from the decoupling mechanism that did not continue once this base rate increase went into effect. Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge. The OCC appealed this rate order to the Ohio Supreme Court, which had affirmed PUCO orders authorizing straight fixed variable rate design in two other cases. On December 23, 2010, the Ohio Supreme Court affirmed the PUCO order authorizing straight fixed variable rate design in VEDO’s case.
With this rate order, the Company has in place for its Ohio gas territory rates that allow for a straight fixed variable rate design that mitigates both weather risk and lost margin for residential customers; tracking of uncollectible accounts and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.
VEDO Continues the Process to Exit the Merchant Function
On August 20, 2008, the PUCO approved the results of an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing. This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder. This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company’s Ohio service territory. The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. In October 2008, VEDO’s entire natural gas inventory was transferred to the auction’s winning wholesale suppliers, resulting in proceeds to VEDO of approximately $107 million.
The second phase of the exit process began on April 1, 2010. During this phase, the Company no longer sells natural gas directly to customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing. The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010. The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase. As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011. The results of that auction were approved by the PUCO on January 19, 2011. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO. Vectren Source, Vectren’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.
The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process. Exiting the merchant function should not have a material impact on earnings or financial condition. It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold as VEDO no longer purchases gas for resale to these customers.
Vectren North Gas Base Rate Order Received
On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case. The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million. The order also provided for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.
Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The accounting treatment allows for the continuation of the accrual for AFUDC and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years from the in-service date for each specific project.
With this order, the Company has in place for its North gas territory weather normalization, a conservation and decoupling mechanism, recovery of gas cost expense related to uncollectible accounts expense based on historical experience and tracking of unaccounted for gas costs through the existing GCA mechanism, and tracking of pipeline integrity management expense.
MISO
The Company is a member of the MISO, a FERC approved regional transmission organization. When the Company is a net seller of its generation, such net revenues, which totaled $24.9 million, $20.8 million, and $57.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Electric utility revenues. When the Company is a net purchaser such net purchases, which totaled $46.1 million, $34.4 million, and $16.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Cost of fuel & purchased power. Net positions are determined on an hourly basis.
The Company also receives transmission revenue from the MISO which is included in Electric utility revenues and totaled $18.8 million, $14.6 million, and $9.3 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively. These revenues result from other MISO members’ use of the Company’s transmission system as well as the recovery of the Company’s investment in certain new electric transmission projects meeting MISO’s transmission expansion plan criteria.
One such project currently under construction meeting these expansion plan criteria is an interstate 345 Kv transmission line that will connect Vectren’s A.B. Brown Generating Station to a station in Indiana owned by Duke Energy to the north and to a station in Kentucky owned by Big Rivers Electric Corporation to the south. During the construction of these transmission assets and while these assets are in service, SIGECO will recover an approximate 10 percent return, inclusive of the FERC approved equity rate of return of 12.38 percent, on capital investments through a rider mechanism which is projected annually and reconciled the following year based on actual results. Of the total investment, which is expected to approximate $90 million, the Company has invested approximately $59.2 million as of December 31, 2010. The north leg of this expansion was placed in service in November 2010, and the south leg of this project is expected to be operational in 2012. Further, the FERC approval allows for recovery of expenditures made in the event of unforeseen difficulties that delay or permanently halt the project.
Impact of Recently Issued Accounting Guidance
Variable Interest Entities
In June 2009, the FASB issued new accounting guidance regarding variable interest entities (VIE’s). This new guidance is effective for annual reporting periods beginning after November 15, 2009. This guidance requires a qualitative analysis of which holder of a variable interest controls the VIE and if that interest holder must consolidate a VIE. Additionally, it requires additional disclosures and an ongoing reassessment of who must consolidate a VIE. The Company adopted this guidance on January 1, 2010. The adoption did not have any impact on the consolidated financial statements.
Fair Value Measurements & Disclosures
In January 2010, the FASB issued new accounting guidance on improving disclosures about fair market value. This guidance amends prior disclosure requirements involving fair value measurements to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The guidance also clarifies existing fair value disclosures in regard to the level of disaggregation and about inputs and valuation techniques used to measure fair value. The guidance also amends prior disclosure requirements regarding postretirement benefit plan assets to require that disclosures be provided by classes of assets instead of major categories of assets. This guidance is effective for the first reporting period beginning after December 15, 2009. The Company adopted this guidance for its 2010 reporting. Due to the low level of items carried at fair value in the Company’s financial statements, the adoption has not had any material impact.
Critical Accounting Policies
Management is required to make judgments, assumptions, and estimates that affect the amounts reported in the consolidated financial statements and the related disclosures that conform to accounting principles generally accepted in the United States. The consolidated financial statement footnotes describe the significant accounting policies and methods used in the preparation of the consolidated financial statements. Certain estimates used in the financial statements are subjective and use variables that require judgment. These include the estimates to perform goodwill and other asset impairments tests and to determine pension and postretirement benefit obligations. The Company makes other estimates in the course of accounting for unbilled revenue and the effects of regulation that are critical to the Company’s financial results but that are less likely to be impacted by near term changes. Other estimates that significantly affect the Company’s results, but are not necessarily critical to operations, include depreciating utility and nonutility plant, valuing reclamation liabilities, valuing derivative contracts, and estimating uncollectible accounts and coal reserves, among others. Actual results could differ from these estimates.
Goodwill
The Company performs an annual impairment analysis of its goodwill, all of which resides in the Gas Utility Services operating segment, at the beginning of each year, and more frequently if events or circumstances indicate that an impairment loss may have been incurred. Impairment tests are performed at the reporting unit level. The Company has determined its Gas Utility Services operating segment as identified in Note 13 to the consolidated financial statements to be the level at which impairment is tested as its reporting units are similar. An impairment test requires that a reporting unit’s fair value be estimated. The Company used a discounted cash flow model and other market based information to estimate the fair value of its Gas Utility Services operating segment, and that estimated fair value was compared to its carrying amount, including goodwill. The estimated fair value has been in excess of the carrying amount in each of the last three years and therefore resulted in no impairment.
Estimating fair value using a discounted cash flow model is subjective and requires significant judgment in applying a discount rate, growth assumptions, company expense allocations, and longevity of cash flows. A 100 basis point increase in the discount rate utilized to calculate the Gas Utility Services segment’s fair value also would have resulted in no impairment charge.
Intercompany Allocations
Support Services
Vectren provides corporate, general, and administrative services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers, and/or the level of payroll, revenue contribution, and capital expenditures. Allocations are at cost. Management believes that the allocation methodology is reasonable and approximates the costs that would have been incurred had the Company secured those services on a stand-alone basis. The allocation methodology is not subject to near term changes.
Pension and Other Postretirement Obligations
Vectren satisfies the future funding requirements of its pension and other postretirement plans and the payment of benefits from general corporate assets. An allocation of expense, comprised of only service cost and interest on that service cost by subsidiary, is determined based on direct labor at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Management believes these direct charges when combined with benefit-related corporate charges discussed in “support services” above approximate costs that would have been incurred if the Company accounted for benefit plans on a stand-alone basis.
Vectren estimates the expected return on plan assets, discount rate, rate of compensation increase, and future health care costs, among other inputs, and obtains actuarial estimates to assess the future potential liability and funding requirements of pension and postretirement plans. Vectren used the following weighted average assumptions to develop 2010 periodic benefit cost: a discount rate of 6.0 percent, an expected return on plan assets of 8.0 percent, a rate of compensation increase of 3.5 percent, and an inflation assumption of 3.0 percent. Due to the impacts of the recession, these assumptions were each lowered 25 basis points from assumptions used in 2009. To estimate 2011 costs, the discount rate, expected return on plan assets, rate of compensation increase, and inflation assumption were 5.5 percent, 8.0 percent, 3.5 percent, and 3.0 percent respectively, reflecting the lower interest rate environment. Vectren’s management currently estimates a pension and postretirement cost of approximately $13 million in 2011, compared to approximately $14 million in 2010, $15 million in 2009, and $11 million in 2008. Future changes in health care costs, work force demographics, interest rates, asset values or plan changes could significantly affect the estimated cost of these future benefits.
Vectren’s management estimates that a 50 basis point decrease in the discount rate used to estimate retirement costs generally increases periodic benefit cost by approximately $1.5 million to $2.0 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.
Regulation
At each reporting date, the Company reviews current regulatory trends in the markets in which it operates. This review involves judgment and is critical in assessing the recoverability of regulatory assets as well as the ability to continue to account for its activities based on the criteria set forth in FASB guidance related to accounting for the effects of certain types of regulation. Based on the Company’s current review, it believes its regulatory assets are probable of recovery. If all or part of the Company's operations cease to meet the criteria, a write off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets and liabilities. In the unlikely event of a change in the current regulatory environment, such write-offs and impairment charges could be significant.
Financial Condition
Utility Holdings funds the short-term and long-term financing needs of utility operations. Vectren does not guarantee Utility Holdings’ debt. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. Information about the subsidiary guarantors as a group is included in Note 15 to the consolidated financial statements. Utility Holdings’ long-term and short-term obligations outstanding at December 31, 2010, approximated $919 million and $47 million, respectively. Additionally, prior to Utility Holdings’ formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations. SIGECO will also occasionally issue tax exempt debt to fund qualifying pollution control capital expenditures. Utility Holdings’ operations have historically been the primary source for Vectren’s common stock dividends.
The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at December 31, 2010, are A-/A3 as rated by Standard and Poor's Ratings Services (Standard and Poor’s) and Moody’s Investors Service (Moody’s), respectively. The credit ratings on SIGECO's secured debt are A/A1. Utility Holdings’ commercial paper has a credit rating of A-2/P-2. In September of 2010, Moody’s increased its rating on Utility Holdings’ and Indiana Gas’ senior unsecured debt from Baa1 to A3 and on SIGECO’s secured debt from A2 to A1. The current outlook of both Moody’s and Standard and Poor’s is stable. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor’s and Moody’s lowest level investment grade rating is BBB- and Baa3, respectively.
The Company’s consolidated equity capitalization objective is 45-60 percent of long-term capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations. The Company’s equity component was 50 percent and 49 percent of long-term capitalization at December 31, 2010 and 2009, respectively. Long-term capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders’ equity.
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As an example, the Utility Holdings’ short-term debt agreement expiring in 2013 contains a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2010, the Company was in compliance with all financial covenants.
Available Liquidity in Current Credit Conditions
The Company’s A-/A3 investment grade credit ratings have allowed it to access the capital markets as needed. Over the last three years, the Company has significantly enhanced its short-term borrowing capacity with the completion of several long-term financing transactions including issuances of long-term debt and the receipt of a $125 million capital contribution from Vectren in 2008. The Company anticipates funding future capital expenditures and dividends through internally generated funds. In addition, available liquidity is expected to be enhanced by cash resulting from the extension of bonus depreciation legislation. Therefore, management expects that only a portion of the Utility Holdings’ $250 million debt redemption due in December 2011 needs to be refinanced with new long-term debt. The Company currently foresees no issues with accessing the capital markets to execute the refinancing.
No long-term debt transactions were completed in 2010. Long-term debt transactions completed in 2009 include a $100 million issuance by Vectren Utility Holdings. SIGECO also remarketed $41.3 million of long-term debt and completed a $22.3 million tax-exempt first mortgage bond issuance. These transactions, along with financing transactions completed in 2008, are more fully described below. (See Financing Cash Flow.)
Consolidated Short-Term Borrowing Arrangements
At December 31, 2010, the Company has $350 million of short-term borrowing capacity. As reduced by borrowings currently outstanding, approximately $303 million was available. This facility is used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis.
Utility Holdings’ short-term credit facility was renewed on September 30, 2010 and is available through September 2013. During the renewal process, the Company lowered the level of capacity from $515 million to $350 million due to the reduced requirements for short-term borrowings. The level of short-term borrowings is significantly lower compared to historical trends due to the recently completed long-term financing transactions, the impacts of additional bonus depreciation and other tax strategies, lower inventory values due to lower natural gas prices, and lower natural gas inventory volumes due to exiting the merchant function in Ohio. The Company has historically funded the short-term borrowing needs through the commercial paper market and expects to use the short-term borrowing facility in instances where the commercial paper market is not efficient. Following is certain information regarding these short-term borrowing arrangements.
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(In millions)
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2010
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2009
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2008
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Year End
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|||||||||||||
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Balance Outstanding
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$ | 47.0 | $ | 16.4 | $ | 191.9 | |||||||
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Weighted Average Interest Rate
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0.41 | % | 0.25 | % | 2.68 | % | |||||||
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Annual Average
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|||||||||||||
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Balance Outstanding
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$ | 14.0 | $ | 29.2 | $ | 178.3 | |||||||
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Weighted Average Interest Rate
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0.40 | % | 1.28 | % | 3.71 | % | |||||||
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Maximum Month End Balance Outstanding
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$ | 47.0 | $ | 151.1 | $ | 338.0 | |||||||
In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the turmoil and volatility in the financial markets. As a result, the Company met short-term financing needs through a combination of A-2/P-2 commercial paper issuances and draws on the back-up credit facility. At December 31, 2008, borrowings outstanding were comprised of $100.4 million of bank loans at a weighted average interest rate of 1.56% and $91.5 million of commercial paper at a weighted average interest rate of 3.87%. The average annual balance outstanding in 2008 was comprised of $28.1 million of bank loans at a weighted average interest rate of 3.42% and $150.2 million of commercial paper at a weighted average interest rate of 3.76%. Throughout 2010 and most of 2009, the Company has placed commercial paper without any significant issues and only had to borrow from its backup credit facility in early 2009 on a limited basis.
Due to the seasonal nature of the Company’s business peak borrowing typically occurs during the fourth quarter and therefore the year end balance is typically higher than the average throughout the year. Short-term borrowing metrics applicable to the fourth quarter of 2010 and 2009 follows.
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(In millions)
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2010
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2009
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Quarterly Average- December 31
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||||||||
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Balance Outstanding
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$ | 41.4 | $ | 7.4 | ||||
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Weighted Average Interest Rate
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0.40 | % | 0.26 | % | ||||
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Maximum Month End Balance Outstanding
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$ | 47.0 | $ | 16.4 | ||||
Proceeds from Stock Plans
Vectren may periodically issue new common shares to satisfy dividend reinvestment plan, stock option plan, and other employee benefit plan requirements and contribute those proceeds to Utility Holdings. New issuances contributed to Utility Holdings added additional liquidity of $4.7 million in 2010 and $6.9 million in 2009.
Potential Uses of Liquidity
Planned Capital Expenditures
During 2010 capital expenditures and other investments approximated $230 million. This compares to 2009 and 2008 where in each year consolidated investments exceeded $300 million. Planned capital expenditures, including contractual purchase commitments, for the five-year period 2011 – 2015 are expected to be more consistent with expenditures made in 2010 and total (in millions): $244, $231, $243, $245, and $243, respectively.
Pension and Postretirement Funding Obligations
As of December 31, 2010, Vectren’s pension plan asset values were approximately 83 percent of the projected benefit obligation. Vectren’s management currently estimates contributing $35 million to qualified pension plans in 2011, of which the majority is expected to be funded by Utility Holdings. Of that amount, approximately $25 million is made available by bonus depreciation opportunities. Contributions in 2012 and beyond are dependent on a variety of factors, including Vectren’s progress toward attaining its long-term goal of being fully funded related to the plans’ accrued benefit obligations and the available sources of cash to fund such additional contributions.
Contractual Obligations
The following is a summary of contractual obligations at December 31, 2010:
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Total
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2011
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2012
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2013
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2014
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2015
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Thereafter
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Long-term debt (1) (2)
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$ | 1,304.8 | $ | 250.0 | $ | - | $ | 105.0 | $ | - | $ | 104.8 | $ | 845.0 | ||||||||||||||
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Short-term debt
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47.0 | 47.0 | - | - | - | - | - | |||||||||||||||||||||
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Long-term debt interest commitments
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992.7 | 76.1 | 60.9 | 58.5 | 55.3 | 54.7 | 687.2 | |||||||||||||||||||||
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Plant & commodity purchase commitments
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16.5 | - | 5.3 | 5.5 | 5.7 | - | - | |||||||||||||||||||||
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Operating leases
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2.9 | 0.7 | 0.7 | 0.6 | 0.7 | 0.2 | - | |||||||||||||||||||||
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Total (3)
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$ | 2,363.9 | $ | 373.8 | $ | 66.9 | $ | 169.6 | $ | 61.7 | $ | 159.7 | $ | 1,532.2 | ||||||||||||||
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(1)
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Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. These provisions allow holders the one-time option to put debt back to the Company at face value or the Company to call debt at face value or at a premium. Long-term debt subject to tender during the years following 2010 (in millions) is $30.0 in 2011 and zero in 2012 and thereafter.
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(2)
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The Company currently anticipates that only a portion of the Utility Holdings $250 million maturity due in December 2011 will require refinancing.
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(3)
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The Company has other long-term liabilities that total approximately $79 million. This amount is comprised of the following: deferred compensation and share-based compensation $25 million, asset retirement obligations $32 million, investment tax credits $5 million, environmental remediation $6 million, and other obligations including unrecognized tax benefits totaling $11 million. Based on the nature of these items their expected settlement dates cannot be estimated.
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The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.
Off Balance Sheet Arrangements
As of December 31, 2010, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million. In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from the renewed credit line that expires in September of 2013. Due to the long-term nature of the credit agreement, such debt is classified as long-term at December 31, 2010. As of December 31, 2010, other than the letters of credit discussed, the Company does not have any material off balance sheet arrangements.
Comparison of Historical Sources & Uses of Liquidity
Operating Cash Flow
The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled $277.8 million in 2010, compared to $356.8 million in 2009 and $435.0 million in 2008.
The $79.0 million decrease in operating cash flow in 2010 compared to 2009 is primarily due to changes in working capital, which reduced operating cash flow approximately $107.1 million. The change in working capital is primarily due to the timing of intercompany tax transactions and the timing of gas cost recovery mechanisms. The decrease in operating cash flow resulting from working capital requirements was partially offset by higher net income and non-cash charges, as well as a lower level of payments by Utility Holdings related to retirement benefits during 2010.
The $78.2 million decrease occurring in 2009 compared to 2008 was primarily due to changes in working capital, which reduced operating cash flow approximately $60.1 million. This decrease is primarily due to the timing of natural gas inventory sales and purchases due to exiting the merchant function in the Ohio service territory in October of 2008. In addition, the Company made increased contributions to Vectren’s pension and other retirement plans during 2009. These impacts have been partially offset by a $31.8 million increase in net income before the impacts of depreciation, deferred taxes, and other non-cash charges.
Tax payments in the periods presented were favorably impacted by federal legislation extending bonus depreciation and a change in the tax method for recognizing repair and maintenance activities. Federal legislation extending bonus depreciation is expected to continue at 100 percent of qualifying capital expenditures in 2011 and 50 percent in 2012, based on current legislation. The Company estimates a significant portion of planned capital expenditures in 2011 and 2012 will qualify for this bonus treatment.
Financing Cash Flow
During 2010, 2009 and 2008, net cash flow associated with financing activities is reflective of management’s ongoing effort to rely less on short-term borrowing arrangements. Over the last three years, the Company’s operating cash flow funded over 80 percent of capital expenditures and dividends in those years, and absent changes in working capital funded 100 percent in 2010. Long-term financing transactions completed in 2008 and 2009 have allowed for the repayment of nearly $340 million in short term borrowings over the past three years. In addition, these long-term financing transactions have financed other capital expenditures on a long-term basis. During the first quarter of 2008, the Company mitigated its exposure to auction rate debt markets. These transactions are more fully described below.
Utility Holdings 2009 Debt Issuance
On April 7, 2009, Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million. The 2020 Notes have no sinking fund requirements, and interest payments are due semi-annually. The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.
SIGECO 2009 Debt Issuance
On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity. The bonds mature in 2040. The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 million.
Capital Contribution from Vectren
On June 27, 2008, Vectren settled an equity forward agreement associated with a 2007 public offering of its common stock. Vectren transferred net proceeds of approximately $124.8 million to Utility Holdings, and Utility Holdings used the proceeds to repay short-term debt obligations incurred primarily to fund its capital expenditure program. The proceeds received were recorded as an increase to Common Stock in Common Shareholder’s Equity and are presented in the Statement of Cash Flows as a financing activity.
Additional Capital Contributions
In addition to the $124.8 million capital contribution above, during the years ended December 31, 2010, 2009, and 2008, the Company has cumulatively received additional capital of $11.6 million from Vectren, funded by new share issues from Vectren’s dividend reinvestment plan.
Utility Holdings 2008 Debt Issuance
In March 2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes) at par. The 2039 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The 2039 Notes have no sinking fund requirements, and interest payments are due monthly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest. During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue. The proceeds from the sale of the 2039 Notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million.
Auction Rate Securities
In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode. In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest. During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million. The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041.
On March 26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations, receiving proceeds, net of issuance costs of approximately $40.6 million. The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit. The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.
-36-
Long-Term Debt Put and Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. Other than certain instruments that can be put to the company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. During 2010, 2009, and 2008, the Company repaid approximately $1.8 million, $3.0 million, and $1.6 million, respectively, related to death puts. Debt which may be put to the Company for reasons other than a death during the years following 2010 (in millions) is $30.0 in 2011 and zero in 2012 and thereafter. Investors had the one-time option to put $10 million in May 2010; however, no notice was received during the notification period and such debt is classified as long-term at December 31, 2010. Debt that can be put to the Company within one year or that is supported by a credit facility that expires within one year is classified in current liabilities in Long-term debt subject to tender.
Investing Cash Flow
Cash flow required for investing activities was $227.2 million in 2010, $310.3 million in 2009, and $308.3 million in 2008. Capital expenditures are the primary component of investing activities and totaled $229.1 million in 2010, compared to $306.9 million in 2009 and $306.3 million in 2008. The decrease in capital expenditures in 2010 compared to 2009 reflects the roughly $20 million spent in 2009 associated with the January 2009 ice storm restoration projects and less expenditures for fly ash management and generation projects.
Forward-Looking Information
A “safe harbor” for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management’s Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements. Such statements are based on management’s beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words “believe”, “anticipate”, “endeavor”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal”, “likely”, and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:
|
·
|
Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas transportation and storage costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints.
|
|
·
|
Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts or other similar occurrences could adversely affect Vectren’s facilities, operations, financial condition and results of operations.
|
|
·
|
Increased competition in the energy industry, including the effects of industry restructuring and unbundling.
|
|
·
|
Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases.
|
|
·
|
Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.
|
|
·
|
Economic conditions surrounding the current economic uncertainty, including significantly lower levels of economic activity; uncertainty regarding energy prices and the capital and commodity markets; volatile changes in the demand for natural gas and electricity; impacts on both gas and electric large customers; lower residential and commercial customer counts; and higher operating expenses.
|
|
·
|
Volatile natural gas and coal commodity prices and the potential impact on customer consumption, uncollectible accounts expense, unaccounted for gas and interest expense.
|
|
·
|
Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks.
|
|
·
|
Direct or indirect effects on the Company’s business, financial condition, liquidity and results of operations resulting from changes in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries.
|
|
·
|
Employee or contractor workforce factors including changes in key executives, collective bargaining agreements with union employees, aging workforce issues, work stoppages, or pandemic illness.
|
|
·
|
Legal and regulatory delays and other obstacles associated with mergers, acquisitions and investments in joint ventures.
|
|
·
|
Costs, fines, penalties and other effects of legal and administrative proceedings, settlements, investigations, claims, including, but not limited to, such matters involving compliance with state and federal laws and interpretations of these laws.
|
|
·
|
Changes in or additions to federal, state or local legislative requirements, such as changes in or additions to tax laws or rates, environmental laws, including laws governing greenhouse gases, mandates of sources of renewable energy, and other regulations.
|
|
·
|
The performance of projects undertaken by Vectren’s nonutility businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, Vectren’s coal mining, gas marketing, and energy infrastructure strategies.
|
The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.
The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company’s risk management program includes, among other things, the use of derivatives. The Company may also execute derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and optimizing its generation assets.
|
The Company has in place a risk management committee that consists of senior management as well as financial and operational management. The committee is actively involved in identifying risks as well as reviewing and authorizing risk mitigation strategies.
|
Commodity Price Risk
Regulated Operations
The Company’s regulated operations have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal and purchased power for the benefit of retail customers due to current state regulations, which subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. Constructive regulatory orders, such as those authorizing lost margin recovery, other innovative rate designs, and recovery of unaccounted for gas and other gas related expenses, also mitigate the effect volatile gas costs may have on the Company’s financial condition. Although the Company’s regulated operations are exposed to limited commodity price risk, volatile natural gas prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered.
Wholesale Power Marketing
The Company’s wholesale power marketing activities undertake strategies to optimize electric generating capacity beyond that needed for native load. In recent years, the primary strategy involves the sale of excess generation into the MISO Day Ahead and Real-time markets. As part of these strategies, the Company may also from time to time execute energy contracts that commit the Company to purchase and sell electricity in future periods. Commodity price risk results from forward positions that commit the Company to deliver electricity. The Company mitigates price risk exposure with planned unutilized generation capability. The Company accounts for any energy contracts that are derivatives at fair value with the offset marked to market through earnings. No market sensitive derivative positions were outstanding on December 31, 2010 and 2009.
For retail sales of electricity, the Company receives the majority of its NOx and SO2 allowances at zero cost through an allocation process. Based on arrangements with regulators, wholesale operations can purchase allowances from retail operations at current market values, the value of which is distributed back to retail customers through a MISO cost recovery tracking mechanism. Wholesale operations are therefore at risk for the cost of allowances, which for the recent past have been volatile. The Company manages this risk by purchasing allowances from retail operations as needed and occasionally from other third parties in advance of usage. In the past, the Company also used derivative financial instruments to hedge this risk, but no such derivative instruments were outstanding at December 31, 2010 or 2009.
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 limits this risk by allowing only an annual average of 15 percent to 25 percent of its total debt to be exposed to variable rate volatility. However, this targeted range may not always be attained during the seasonal increases in short-term borrowings. To manage this exposure, the Company may use derivative financial instruments.
Market risk is estimated as the potential impact resulting from fluctuations in interest rates on adjustable rate borrowing arrangements exposed to short-term interest rate volatility. During 2010 and 2009, the weighted average combined borrowings under these arrangements approximated $55 million and $60 million, respectively. At December 31, 2010 and 2009, combined borrowings under these arrangements were $88 million and $58 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2010 and 2009, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $0.6 million in both periods.
Other Risks
By using financial instruments to manage risk, the Company creates exposure to counter-party credit risk and market risk. The Company manages exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract. Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk. Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk. Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices or interest rates. The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by establishing parameters and monitoring those parameters that limit the types and degree of market risk that may be undertaken.
The Company’s customer receivables from gas and electric sales and gas transportation services are primarily derived from residential, commercial, and industrial customers located in Indiana and west central Ohio. The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits or refunds cash deposits based on that review. Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral. In addition, credit risk is mitigated by regulatory orders that allow recovery of all uncollectible accounts expense in Ohio and the gas cost portion of uncollectible accounts expense in Indiana based on historical experience.
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Vectren Utility Holdings, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Those control procedures underlie the preparation of the consolidated balance sheets, statements of income, cash flows, and common shareholder’s equity, and related footnotes contained herein.
These consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of these consolidated financial statements, including required estimates and judgments, is the responsibility of management.
These consolidated financial statements are also subject to an evaluation of internal control over financial reporting conducted under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, conducted under the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, the Company concluded that its internal control over financial reporting was effective as of December 31, 2010. Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2010 Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholder and Board of Directors of Vectren Utility Holdings, Inc.:
We have audited the accompanying consolidated balance sheets of Vectren Utility Holdings, Inc. and subsidiaries (the “Company”) (a wholly owned subsidiary of Vectren Corporation) as of December 31, 2010 and 2009, and the related consolidated statements of income, common shareholder’s equity and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule included in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Vectren Utility Holdings, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Indianapolis, Indiana
March 4, 2011
VECTREN UTILITY HOLDINGS. INC. AND SUBSIDIARY COMPANIES
|
|
CONSOLIDATED BALANCE SHEETS
|
(In millions)
|
At December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
ASSETS
|
||||||||
|
Current Assets
|
||||||||
|
Cash & cash equivalents
|
$ | 2.4 | $ | 6.2 | ||||
|
Accounts receivable - less reserves of $4.5 &
|
||||||||
|
$4.0, respectively
|
106.7 | 108.1 | ||||||
|
Receivables due from other Vectren companies
|
0.1 | 0.7 | ||||||
|
Accrued unbilled revenues
|
127.8 | 115.4 | ||||||
|
Inventories
|
135.2 | 127.9 | ||||||
|
Recoverable fuel & natural gas costs
|
7.9 | - | ||||||
|
Prepayments & other current assets
|
83.4 | 69.2 | ||||||
|
Total current assets
|
463.5 | 427.5 | ||||||
|
Utility Plant
|
||||||||
|
Original cost
|
4,791.7 | 4,601.4 | ||||||
|
Less: accumulated depreciation & amortization
|
1,836.3 | 1,722.6 | ||||||
|
Net utility plant
|
2,955.4 | 2,878.8 | ||||||
|
Investments in unconsolidated affiliates
|
0.2 | 0.2 | ||||||
|
Other investments
|
31.3 | 31.4 | ||||||
|
Nonutility plant - net
|
167.2 | 171.8 | ||||||
|
Goodwill - net
|
205.0 | 205.0 | ||||||
|
Regulatory assets
|
96.9 | 104.1 | ||||||
|
Other assets
|
5.0 | 4.3 | ||||||
|
TOTAL ASSETS
|
$ | 3,924.5 | $ | 3,823.1 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
|
At December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
LIABILITIES & SHAREHOLDER'S EQUITY
|
||||||||
|
Current Liabilities
|
||||||||
|
Accounts payable
|
$ | 126.0 | $ | 133.1 | ||||
|
Accounts payable to affiliated companies
|
59.3 | 54.1 | ||||||
|
Payables to other Vectren companies
|
48.7 | 53.6 | ||||||
|
Refundable fuel & natural gas costs
|
- | 22.3 | ||||||
|
Accrued liabilities
|
135.9 | 131.4 | ||||||
|
Short-term borrowings
|
47.0 | 16.4 | ||||||
|
Current maturities of long-term debt
|
250.0 | - | ||||||
|
Long-term debt subject to tender
|
30.0 | 51.3 | ||||||
|
Total current liabilities
|
696.9 | 462.2 | ||||||
|
Long-Term Debt - Net of Current Maturities &
|
||||||||
|
Debt Subject to Tender
|
1,024.8 | 1,254.8 | ||||||
|
Deferred Income Taxes & Other Liabilities
|
||||||||
|
Deferred income taxes
|
474.7 | 418.0 | ||||||
|
Regulatory liabilities
|
333.5 | 322.2 | ||||||
|
Deferred credits & other liabilities
|
79.2 | 91.2 | ||||||
|
Total deferred credits & other liabilities
|
887.4 | 831.4 | ||||||
|
Commitments & Contingencies (Notes 9 - 11)
|
||||||||
|
Common Shareholder's Equity
|
||||||||
|
Common stock (no par value)
|
774.6 | 769.9 | ||||||
|
Retained earnings
|
540.7 | 504.7 | ||||||
|
Accumulated other comprehensive income
|
0.1 | 0.1 | ||||||
|
Total common shareholder's equity
|
1,315.4 | 1,274.7 | ||||||
|
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,924.5 | $ | 3,823.1 | ||||
|
|
The accompanying notes are an integral part of these consolidated financial statements.
|
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
2010
|
2009
|
2008
|
||||||||||
|
OPERATING REVENUES
|
||||||||||||
|
Gas utility
|
$ | 954.1 | $ | 1,066.0 | $ | 1,432.7 | ||||||
|
Electric utility
|
608.0 | 528.6 | 524.2 | |||||||||
|
Other
|
1.6 | 1.6 | 1.8 | |||||||||
|
Total operating revenues
|
1,563.7 | 1,596.2 | 1,958.7 | |||||||||
|
OPERATING EXPENSES
|
||||||||||||
|
Cost of gas sold
|
504.7 | 618.1 | 983.1 | |||||||||
|
Cost of fuel & purchased power
|
235.0 | 194.3 | 182.9 | |||||||||
|
Other operating
|
299.2 | 304.6 | 300.3 | |||||||||
|
Depreciation & amortization
|
188.2 | 180.9 | 165.5 | |||||||||
|
Taxes other than income taxes
|
59.6 | 60.3 | 72.3 | |||||||||
|
Total operating expenses
|
1,286.7 | 1,358.2 | 1,704.1 | |||||||||
|
OPERATING INCOME
|
277.0 | 238.0 | 254.6 | |||||||||
|
Other income - net
|
5.4 | 7.8 | 4.0 | |||||||||
|
Interest expense
|
81.4 | 79.2 | 79.9 | |||||||||
|
INCOME BEFORE INCOME TAXES
|
201.0 | 166.6 | 178.7 | |||||||||
|
Income taxes
|
77.1 | 59.2 | 67.6 | |||||||||
|
NET INCOME
|
$ | 123.9 | $ | 107.4 | $ | 111.1 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
2010
|
2009
|
2008
|
||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net income
|
$ | 123.9 | $ | 107.4 | $ | 111.1 | ||||||
|
Adjustments to reconcile net income to cash from operating activities:
|
||||||||||||
|
Depreciation & amortization
|
188.2 | 180.9 | 165.5 | |||||||||
|
Deferred income taxes & investment tax credits
|
71.2 | 76.2 | 54.7 | |||||||||
|
Expense portion of pension & postretirement periodic benefit cost
|
4.1 | 4.1 | 2.6 | |||||||||
|
Provision for uncollectible accounts
|
16.2 | 14.6 | 15.8 | |||||||||
|
Other non-cash expense - net
|
12.4 | 14.0 | 15.7 | |||||||||
|
Changes in working capital accounts:
|
||||||||||||
|
Accounts receivable, including to Vectren companies
|
||||||||||||
|
& accrued unbilled revenue
|
(26.6 | ) | 93.1 | (56.1 | ) | |||||||
|
Inventories
|
(7.3 | ) | (43.2 | ) | 46.8 | |||||||
|
Recoverable/refundable fuel & natural gas costs
|
(30.2 | ) | 21.3 | (26.2 | ) | |||||||
|
Prepayments & other current assets
|
(31.3 | ) | 48.1 | (13.4 | ) | |||||||
|
Accounts payable, including to Vectren companies
|
||||||||||||
|
& affiliated companies
|
(6.7 | ) | (95.9 | ) | 96.2 | |||||||
|
Accrued liabilities
|
6.4 | (12.0 | ) | 24.2 | ||||||||
|
Changes in noncurrent assets
|
(7.8 | ) | 1.7 | 20.6 | ||||||||
|
Changes in noncurrent liabilities
|
(34.7 | ) | (53.5 | ) | (22.5 | ) | ||||||
|
Net cash flows from operating activities
|
277.8 | 356.8 | 435.0 | |||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds from:
|
||||||||||||
|
Long-term debt - net of issuance costs & hedging proceeds
|
- | 161.3 | 171.1 | |||||||||
|
Additional capital contribution
|
4.7 | 6.9 | 124.8 | |||||||||
|
Requirements for:
|
||||||||||||
|
Dividends to parent
|
(87.9 | ) | (82.5 | ) | (83.2 | ) | ||||||
|
Retirement of long-term debt
|
(1.8 | ) | (3.0 | ) | (104.6 | ) | ||||||
|
Net change in short-term borrowings, including from other
|
||||||||||||
|
Vectren companies
|
30.6 | (175.5 | ) | (194.0 | ) | |||||||
|
Net cash flows from financing activities
|
(54.4 | ) | (92.8 | ) | (85.9 | ) | ||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Proceeds from other investing activities
|
3.0 | 0.2 | 2.5 | |||||||||
|
Requirements for:
|
||||||||||||
|
Capital expenditures, excluding AFUDC equity
|
(229.1 | ) | (306.9 | ) | (306.3 | ) | ||||||
|
Other investments
|
(1.1 | ) | (3.6 | ) | (4.5 | ) | ||||||
|
Net cash flows from investing activities
|
(227.2 | ) | (310.3 | ) | (308.3 | ) | ||||||
|
Net change in cash & cash equivalents
|
(3.8 | ) | (46.3 | ) | 40.8 | |||||||
|
Cash & cash equivalents at beginning of period
|
6.2 | 52.5 | 11.7 | |||||||||
|
Cash & cash equivalents at end of period
|
$ | 2.4 | $ | 6.2 | $ | 52.5 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(In millions)
|
Accumulated
|
||||||||||||||||
|
Other
|
||||||||||||||||
|
Common
|
Retained
|
Comprehensive
|
||||||||||||||
|
Stock
|
Earnings
|
Income
|
Total
|
|||||||||||||
|
Balance at January 1, 2008
|
$ | 638.2 | $ | 451.9 | $ | 0.3 | $ | 1,090.4 | ||||||||
|
Comprehensive income:
|
||||||||||||||||
|
Net income
|
111.1 | 111.1 | ||||||||||||||
|
Cash flow hedge
|
||||||||||||||||
|
Reclassification to net income - net of $0.2 million in tax
|
(0.2 | ) | (0.2 | ) | ||||||||||||
|
Total comprehensive income
|
110.9 | |||||||||||||||
|
Common stock:
|
||||||||||||||||
|
Additional capital contribution
|
124.8 | 124.8 | ||||||||||||||
|
Dividends
|
(83.2 | ) | (83.2 | ) | ||||||||||||
|
Balance at December 31, 2008
|
763.0 | 479.8 | 0.1 | 1,242.9 | ||||||||||||
|
Comprehensive income:
|
||||||||||||||||
|
Net income & total comprehensive income
|
107.4 | 107.4 | ||||||||||||||
|
Common stock:
|
||||||||||||||||
|
Additional capital contribution
|
6.9 | 6.9 | ||||||||||||||
|
Dividends
|
(82.5 | ) | (82.5 | ) | ||||||||||||
|
Balance at December 31, 2009
|
769.9 | 504.7 | 0.1 | 1,274.7 | ||||||||||||
|
Comprehensive income:
|
||||||||||||||||
|
Net income & total comprehensive income
|
123.9 | 123.9 | ||||||||||||||
|
Common stock:
|
||||||||||||||||
|
Additional capital contribution
|
4.7 | 4.7 | ||||||||||||||
|
Dividends
|
(87.9 | ) | (87.9 | ) | ||||||||||||
|
Balance at December 31, 2010
|
$ | 774.6 | $ | 540.7 | $ | 0.1 | $ | 1,315.4 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
|
1.
|
Organization & Nature of Operations
|
Vectren Utility Holdings, Inc. (the Company or Utility Holdings), an Indiana corporation, was formed on March 31, 2000, to serve as the intermediate holding company for Vectren Corporation’s (Vectren) three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas or Vectren North), Southern Indiana Gas and Electric Company (SIGECO or Vectren South), and the Ohio operations (VEDO or Vectren Ohio). Utility Holdings also has other assets that provide information technology and other services to the three utilities. Vectren, an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana, and was organized on June 10, 1999. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act).
Indiana Gas provides energy delivery services to over 570,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 111,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 314,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary of Utility Holdings (53 percent ownership), and Indiana Gas (47 percent ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio.
|
2.
|
Summary of Significant Accounting Policies
|
In applying its accounting policies, the Company makes judgments, assumptions, and estimates that affect the amounts reported in these consolidated financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing pension and postretirement benefit obligations, deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, reclamation liabilities, and derivatives and other financial instruments. Estimates also impact the depreciation of utility and nonutility plant and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from current estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after elimination of significant intercompany transactions.
Subsequent Events Review
Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued.
Cash & Cash Equivalents
All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value.
Allowance for Uncollectible Accounts
The Company maintains allowances for uncollectible accounts for estimated losses resulting from the inability of its customers to make required payments. The Company estimates the allowance for uncollectible accounts based on a variety of factors including the length of time receivables are past due, the financial health of its customers, unusual macroeconomic conditions, and historical experience. If the financial condition of its customers deteriorates or other circumstances occur that result in an impairment of customers’ ability to make payments, the Company records additional allowances as needed.
Inventories
In most circumstances, the Company’s inventory components are recorded using an average cost method; however, natural gas in storage at the Company’s Indiana utilities is recorded using the Last In – First Out (LIFO) method. Inventory related to the Company’s regulated operations is valued at historical cost consistent with ratemaking treatment. Materials and supplies are recorded as inventory when purchased and subsequently charged to expense or capitalized to plant when installed.
Property, Plant & Equipment
Both the Company’s Utility Plant and Nonutility Plant is stated at historical cost, inclusive of financing costs and direct and indirect construction costs, less accumulated depreciation and when necessary, impairment charges. The cost of renewals and betterments that extend the useful life are capitalized. Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred.
Utility Plant & Related Depreciation
Both the IURC and PUCO allow the Company’s utilities to capitalize financing costs associated with Utility Plant based on a computed interest cost and a designated cost of equity funds. These financing costs are commonly referred to as AFUDC and are capitalized for ratemaking purposes and for financial reporting purposes instead of amounts that would otherwise be capitalized when acquiring nonutility plant. The Company reports both the debt and equity components of AFUDC in Other income – net in the Consolidated Statements of Income.
When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.
The Company’s portion of jointly-owned Utility Plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.
Nonutility Plant & Related Depreciation
The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation or units-of-production method of amortization for certain coal mining assets. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.
Impairment Reviews
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.
Goodwill
Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions in the Gas Utility Services operating segment and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. No goodwill impairments have been recorded during the periods presented.
Regulation
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies.
Refundable or Recoverable Gas Costs & Cost of Fuel & Purchased Power
All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed.
Regulatory Assets & Liabilities
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company continually assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to recognize new regulatory assets and liabilities associated with its regulated utility operations. Given the current regulatory environment in its jurisdictions, the Company believes such accounting is appropriate.
The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation.
Asset Retirement Obligations
A portion of removal costs related to interim retirements of gas utility pipeline and utility poles and certain asbestos-related issues meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.
Energy Contracts & Derivatives
The Company will periodically execute 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. A derivative is recognized on the balance sheet as an asset or liability measured at its fair market value and the change in the derivative's fair market value is 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 (NPNS), it is exempted from mark-to-market accounting. Most energy contracts executed by the Company are subject to the NPNS exclusion or are not considered derivatives. Such energy contracts include Real Time and Day Ahead purchase and sale contracts with the MISO, natural gas purchases from ProLiance and others, and wind farm and other electric generating capacity contracts.
When the Company engages in energy contracts and financial contracts that are derivatives and are not subject to the NPNS or other exclusions, such contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to regulatory accounting treatment. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in Accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked to market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by regulatory accounting treatment are marked to market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. The Company rarely enters into contracts that have a significant impact to the financial statements where internal models are used to calculate fair value. As of and for the periods presented, related derivative activity is not material to these financial statements.
Revenues
Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period.
MISO Transactions
With the IURC’s approval, the Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midwest and maintains operational control over the Company’s electric transmission facilities as well as that of other Midwest utilities. Since April 1, 2005, the Company has been an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market.
MISO-related purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. On occasion, prior period transactions are resettled outside the routine process due to a change in MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.
The Company also receives transmission revenue that results from other members’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues. Generally, these transmission revenues along with costs charged by the MISO are considered components of base rates and any variance from that included in base rates is recovered from / refunded to retail customers through tracking mechanisms.
Excise & Utility Receipts Taxes
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $33.6 million in 2010, $36.2 million in 2009, and $44.9 million in 2008. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.
Fair Value Measurements
Certain assets and liabilities are valued and/or disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill, intangible assets and long-lived assets impairment tests, FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows:
|
Level 1
|
Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets.
|
|
Level 2
|
Inputs to the valuation methodology include
· quoted prices for similar assets or liabilities in active markets;
· quoted prices for identical or similar assets or liabilities in inactive markets;
· inputs other than quoted prices that are observable for the asset or liability;
· inputs that are derived principally from or corroborated by observable market data by correlation or other means
If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
|
|
Level 3
|
Inputs to the valuation methodology are unobservable and significant to the fair value measurement.
|
The asset's or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.
Earnings Per Share
Earnings per share are not presented as Utility Holdings’ common stock is wholly owned by Vectren.
Other Significant Policies
Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 5).
|
3.
|
Utility & Nonutility Plant
|
The original cost of Utility Plant, together with depreciation rates expressed as a percentage of original cost, follows:
|
At and For the Year Ended December 31,
|
||||||||||||||||
|
(In millions)
|
2010
|
2009
|
||||||||||||||
|
Original Cost
|
Depreciation
Rates as a
Percent of
Original Cost
|
Original Cost
|
Depreciation
Rates as a
Percent of
Original Cost
|
|||||||||||||
|
Gas utility plant
|
$ | 2,410.2 | 3.6 | % | $ | 2,299.1 | 3.5 | % | ||||||||
|
Electric utility plant
|
2,258.6 | 3.4 | % | 2,113.3 | 3.4 | % | ||||||||||
|
Common utility plant
|
49.7 | 3.1 | % | 48.7 | 2.9 | % | ||||||||||
|
Construction work in progress
|
73.2 | - | 140.3 | - | ||||||||||||
|
Total original cost
|
$ | 4,791.7 | $ | 4,601.4 | ||||||||||||
SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own the 300 MW Unit 4 at the Warrick Power Plant as tenants in common. SIGECO's share of the cost of this unit at December 31, 2010, is $176.2 million with accumulated depreciation totaling $59.2 million. The construction work-in-progress balance associated with SIGECO’s ownership interest totaled $3.1 million at December 31, 2010. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.
Nonutility plant, net of accumulated depreciation and amortization follows:
|
At December 31,
|
||||||||
|
(In millions)
|
2010
|
2009
|
||||||
|
Computer hardware & software
|
$ | 112.9 | $ | 117.9 | ||||
|
Land & buildings
|
39.0 | 39.3 | ||||||
|
All other
|
15.3 | 14.6 | ||||||
|
Nonutility plant - net
|
$ | 167.2 | $ | 171.8 | ||||
Nonutility plant is presented net of accumulated depreciation and amortization totaling $184.0 million and $160.2 million as of December 31, 2010 and 2009, respectively. For the years ended December 31, 2010, 2009, and 2008, the Company capitalized interest totaling $0.2 million, $0.2 million, and $2.0 million, respectively, on nonutility plant construction projects.
|
4.
|
Regulatory Assets & Liabilities
|
Regulatory Assets
Regulatory assets consist of the following:
|
At December 31,
|
||||||||
|
(In millions)
|
2010
|
2009
|
||||||
|
Future amounts recoverable from ratepayers related to:
|
||||||||
|
Deferred income taxes
|
$ | 19.2 | $ | 14.7 | ||||
|
Asset retirement obligations & other
|
2.1 | 4.3 | ||||||
| 21.3 | 19.0 | |||||||
|
Amounts deferred for future recovery related to:
|
||||||||
|
Cost recovery riders & other
|
2.8 | 1.0 | ||||||
| 2.8 | 1.0 | |||||||
|
Amounts currently recovered in customer rates related to:
|
||||||||
|
Unamortized debt issue costs & hedging proceeds
|
35.7 | 38.1 | ||||||
|
Demand side management programs
|
9.5 | 15.3 | ||||||
|
Indiana authorized trackers
|
17.3 | 15.6 | ||||||
|
Ohio authorized trackers
|
2.0 | 8.2 | ||||||
|
Premiums paid to reacquire debt
|
3.8 | 4.3 | ||||||
|
Other base rate recoveries
|
4.5 | 2.6 | ||||||
| 72.8 | 84.1 | |||||||
|
Total regulatory assets
|
$ | 96.9 | $ | 104.1 | ||||
Of the $72.8 million currently being recovered in customer rates, $9.5 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 16 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable.
Regulatory Liabilities
At December 31, 2010 and 2009, the Company has approximately $333.5 million and $322.2 million, respectively, in Regulatory liabilities. Of these amounts, $307.5 million and $294.4 million relate to cost of removal obligations. The remaining amounts primarily relate to timing differences associated with asset retirement obligations and deferred financing costs.
|
5.
|
Transactions with Other Vectren Companies and Affiliates
|
Vectren Fuels, Inc.
Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases coal used for electric generation. The price of coal that is charged by Vectren Fuels to SIGECO is priced consistent with contracts reviewed by the OUCC and on file with IURC. Amounts paid for such purchases for the years ended December 31, 2010, 2009 and 2008, totaled $152.4 million, $152.9 million, and $119.8 million, respectively. Amounts owed to Vectren Fuels at December 31, 2010 and 2009 are included in Payables to other Vectren companies.
Miller Pipeline Corporation
Miller Pipeline Corporation (Miller), a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. Miller’s customers include Utility Holdings’ utilities. Fees paid by Utility Holdings and its subsidiaries totaled $26.1 million in 2010, $40.4 million in 2009, and $39.9 million in 2008. Amounts owed to Miller at December 31, 2010 and 2009 are included in Payables to other Vectren companies.
Vectren Source
Vectren Source, a nonutility wholly owned subsidiary of Vectren, provides natural gas and other related products and services in the Midwest and Northeast United States to over 227,000 equivalent residential and commercial customers. The 2010 customer count reflects nearly 100,000 customers in VEDO’s service territory that have either voluntarily opted to choose their natural gas supplier or are supplied natural gas by Vectren Source but remain customers of the regulated utility as part of VEDO’s exit the merchant function process. As a result of a supplier choice auction held on January 18, 2011 in VEDO’s service territory, Vectren Source will increase its customer base by 28,000 to over 255,000.
The cost of natural gas inventory purchased by Vectren Source on October 1, 2008 totaled approximately $31.6 million. The Company purchased natural gas from Vectren Source totaling approximately $14.9 million in 2010, $27.0 million in 2009, and $14.5 million in 2008, which represented approximately 2 percent, 4 percent, and 2 percent of the Company’s total gas purchased during 2010, 2009, and 2008, respectively. Amounts charged by Vectren Source for gas supply services is comprised of the monthly NYMEX settlement price plus a fixed adder, as authorized by the PUCO. Amounts owed to Vectren Source at December 31, 2010 are included in Payables to other Vectren companies.
ProLiance Holdings, LLC (ProLiance)
ProLiance, a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include the Company’s Indiana utilities and nonutility gas supply operations as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Vectren received regulatory approval on April 25, 2006, from the IURC for ProLiance to provide natural gas supply services to the Company’s Indiana utilities through March 2011. On November 3, 2010, a settlement agreement was filed with the IURC providing for ProLiance’s continued provision of gas supply services to the Company’s Indiana utilities and Citizens Gas for the period of April 1, 2011 through March 31, 2016. The settlement has been agreed to by all of the representatives that were parties to the prior settlement. An order is anticipated during the first quarter of 2011.
Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2010, 2009 and 2008 totaled $426.9 million, $436.2 million, and $739.3 million, respectively. Amounts owed to ProLiance at December 31, 2010 and 2009, for those purchases were $59.3 million and $54.1 million, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. The Company purchased approximately 86 percent of its gas through ProLiance in 2010, 76 percent in 2009, and 71 percent in 2008. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility.
Support Services & Purchases
Vectren provides corporate and general and administrative services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. Utility Holdings received corporate allocations totaling $47.8 million, $48.4 million, and $45.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Retirement Plans & Other Postretirement Benefits
At December 31, 2010, Vectren 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 the Company’s 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 employees of Utility Holdings and its subsidiaries comprise the vast majority of the participants and retirees covered by these plans.
Vectren satisfies the future funding requirements and the payment of benefits from general corporate assets and, as necessary, relies on Utility Holdings to support the funding of these obligations. However, Utility Holdings has no contractual funding commitment. Vectren allocates the cost of these plans following labor; therefore, Utility Holdings incurs the majority of the cost associated with these plans. Cost, comprised of service cost and interest on that service cost, is directly charged to Utility Holdings based on labor at each measurement date. For the years ended December 31, 2010, 2009 and 2008, costs totaling $5.9 million, $5.9 million and $3.5 million, respectively, were directly charged to Utility Holdings and are expected to be funded by Utility Holdings at some future date. Other components of costs (such as interest cost and asset returns) are charged to subsidiaries through an allocation process discussed above and are funded currently. Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. The allocation methodology is consistent with FASB guidance related to “multiemployer” benefit accounting. As of December 31, 2010 and 2009, $0.7 million and $10.9 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.
Share-Based Incentive Plans & Deferred Compensation Plans
Utility Holdings does not have share-based compensation plans separate from Vectren. The Company recognizes its allocated portion of expenses related to share-based incentive plans and deferred compensation plans in accordance with FASB guidance and to the extent these awards are expected to be settled in cash that liability is pushed down to Utility Holdings. As of December 31, 2010 and 2009, $24.6 million and $28.5 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.
Income Taxes
Vectren files a consolidated federal income tax return. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Utility Holdings’ current and deferred tax expense is computed on a separate company basis. Current taxes payable/receivable are settled with Vectren in cash.
Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company’s rate-regulated utilities recognize regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized.
Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Consolidated Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Deferred credits & other liabilities.
Investment tax credits (ITCs) are deferred and amortized to income over the approximate lives of the related property in accordance with the regulatory treatment. Production tax credits (PTCs) are recognized as energy is generated and sold based on a per kilowatt hour rate prescribed in applicable federal and state statutes.
The components of income tax expense and utilization of investment tax credits follow:
|
Year Ended December 31,
|
||||||||||||
|
(In millions)
|
2010
|
2009
|
2008
|
|||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | (0.7 | ) | $ | (18.2 | ) | $ | 3.7 | ||||
|
State
|
6.6 | 1.2 | 9.2 | |||||||||
|
Total current taxes
|
5.9 | (17.0 | ) | 12.9 | ||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
67.6 | 70.3 | 52.7 | |||||||||
|
State
|
4.4 | 7.0 | 3.3 | |||||||||
|
Total deferred taxes
|
72.0 | 77.3 | 56.0 | |||||||||
|
Amortization of investment tax credits
|
(0.8 | ) | (1.1 | ) | (1.3 | ) | ||||||
|
Total income tax expense
|
$ | 77.1 | $ | 59.2 | $ | 67.6 | ||||||
A reconciliation of the federal statutory rate to the effective income tax rate follows:
|
Year Ended December 31,
|
||||||||||||
|
2010
|
2009
|
2008
|
||||||||||
|
Statutory rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
State and local taxes-net of federal benefit
|
3.8 | 2.9 | 3.4 | |||||||||
|
Amortization of investment tax credit
|
(0.4 | ) | (0.6 | ) | (0.7 | ) | ||||||
|
Tax law changes and other adjustments to income tax accruals
|
- | (1.7 | ) | (1.3 | ) | |||||||
|
All other - net
|
- | - | 1.4 | |||||||||
|
Effective tax rate
|
38.4 | % | 35.6 | % | 37.8 | % | ||||||
Significant components of the net deferred tax liability follow:
|
At December 31,
|
||||||||||
|
(In millions)
|
2010 | 2009 | ||||||||
|
Noncurrent deferred tax liabilities (assets):
|
||||||||||
|
Depreciation & cost recovery timing differences
|
$ | 508.8 | $ | 431.8 | ||||||
|
Regulatory assets recoverable through future rates
|
24.9 | 25.6 | ||||||||
|
Alternative minimum tax carryforward
|
(48.6 | ) | (21.5 | ) | ||||||
|
Employee benefit obligations
|
- | (7.8 | ) | |||||||
|
Regulatory liabilities to be settled through future rates
|
(9.5 | ) | (11.7 | ) | ||||||
|
Other – net
|
(0.9 | ) | 1.6 | |||||||
|
Net noncurrent deferred tax liability
|
474.7 | 418.0 | ||||||||
|
Current deferred tax liabilities (assets):
|
||||||||||
|
Deferred fuel costs - net
|
4.9 | 1.2 | ||||||||
|
Alternative minimum tax carryforward
|
(0.8 | ) | (15.8 | ) | ||||||
|
Demand side management programs
|
2.5 | 5.2 | ||||||||
|
Other – net
|
(6.2 | ) | (7.7 | ) | ||||||
|
Net current deferred tax liability (asset)
|
0.4 | (17.1 | ) | |||||||
|
Net deferred tax liability
|
$ | 475.1 | $ | 400.9 | ||||||
At December 31, 2010 and 2009, investment tax credits totaling $5.0 million and $5.8 million, respectively, are included in Deferred credits & other liabilities. At December 31, 2010, the Company has alternative minimum tax carryforwards of $49.4 million, which do not expire.
Uncertain Tax Positions
Utility Holdings does not file federal or state income tax returns separate from those filed by its parent, Vectren Corporation. Vectren files a consolidated U.S. federal income tax return, and Vectren and/or certain of its subsidiaries file income tax returns in various states. The Internal Revenue Service (IRS) has conducted examinations of Vectren’s U.S. federal income tax returns for tax years through December 31, 2005. Tax years 2006 and 2008 are currently under IRS exam. The State of Indiana, Vectren’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2007. The statutes of limitations for assessment of federal income tax have expired with respect to tax years through 2005 and through 2006 for Indiana income tax.
Following is a roll forward of the total amount of unrecognized tax benefits for the three years ended December 31, 2010 and 2009:
|
(In millions)
|
2010
|
2009
|
2008
|
|||||||||
|
Unrecognized tax benefits at January 1
|
$ | 9.5 | $ | 0.5 | $ | 3.8 | ||||||
|
Gross increases - tax positions in prior periods
|
1.5 | 1.0 | 0.3 | |||||||||
|
Gross decreases - tax positions in prior periods
|
(0.2 | ) | (1.9 | ) | (3.6 | ) | ||||||
|
Gross increases - current period tax positions
|
1.0 | 9.0 | - | |||||||||
|
Settlements
|
- | 0.3 | - | |||||||||
|
Lapse of statute of limitations
|
- | 0.6 | - | |||||||||
|
Unrecognized tax benefits at December 31
|
$ | 11.8 | $ | 9.5 | $ | 0.5 | ||||||
Of the change in unrecognized tax benefits during 2010, 2009, and 2008, almost none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was $0.2 million December 31, 2009, and almost none at December 31, 2010 and 2008. As of December 31, 2010, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority. Thus, it is not expected that any changes to these tax positions would have a significant impact on earnings.
The Company recognized expense related to interest and penalties totaling approximately $0.3 million in 2010, $0.1 million in 2009, and less than $0.1 million in 2008. The Company had approximately $0.5 million and $0.2 million for the payment of interest and penalties accrued as of December 31, 2010 and 2009, respectively.
The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $11.3 million and $8.9 million, respectively, at December 31, 2010 and 2009.
|
6.
|
Borrowing Arrangements
|
Long-Term Debt
Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:
|
At December 31,
|
|||||
|
(In millions)
|
2010
|
2009
|
|||
|
Utility Holdings
|
|||||
|
Fixed Rate Senior Unsecured Notes
|
|||||
|
2011, 6.625%
|
$ 250.0
|
$ 250.0
|
|||
|
2013, 5.25%
|
100.0
|
100.0
|
|||
|
2015, 5.45%
|
75.0
|
75.0
|
|||
|
2018, 5.75%
|
100.0
|
100.0
|
|||
|
2020, 6.28%
|
100.0
|
100.0
|
|||
|
2035, 6.10%
|
75.0
|
75.0
|
|||
|
2036, 5.95%
|
96.7
|
97.8
|
|||
|
2039, 6.25%
|
121.9
|
122.5
|
|||
|
Total Utility Holdings
|
918.6
|
920.3
|
|||
|
SIGECO
|
|||||
|
First Mortgage Bonds
|
|||||
|
2015, 1985 Pollution Control Series A, current adjustable rate 0.33%,
|
|||||
|
tax exempt, 2010 weighted average: 0.27%
|
9.8
|
9.8
|
|||
|
2016, 1986 Series, 8.875%
|
13.0
|
13.0
|
|||
|
2020, 1998 Pollution Control Series B, 4.50%, tax exempt
|
4.6
|
4.6
|
|||
|
2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt
|
22.6
|
22.6
|
|||
|
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt
|
22.5
|
22.5
|
|||
|
2025, 1998 Pollution Control Series A, current adjustable rate 0.33%,
|
|||||
|
tax exempt, 2010 weighted average: 0.27%
|
31.5
|
31.5
|
|||
|
2029, 1999 Senior Notes, 6.72%
|
80.0
|
80.0
|
|||
|
2030, 1998 Pollution Control Series B, 5.00%, tax exempt
|
22.0
|
22.0
|
|||
|
2030, 1998 Pollution Control Series C, 5.35%, tax exempt
|
22.2
|
22.2
|
|||
|
2040, 2009 Environmental Improvement Series, 5.40%, tax exempt
|
22.3
|
22.3
|
|||
|
2041, 2007 Pollution Control Series, 5.45%, tax exempt
|
17.0
|
17.0
|
|||
|
Total SIGECO
|
267.5
|
267.5
|
|||
|
Indiana Gas
|
|||||
|
Senior Unsecured Notes
|
|||||
|
2013, Series E, 6.69%
|
5.0
|
5.0
|
|||
|
2015, Series E, 7.15%
|
5.0
|
5.0
|
|||
|
2015, Series E, 6.69%
|
5.0
|
5.0
|
|||
|
2015, Series E, 6.69%
|
10.0
|
10.0
|
|||
|
2025, Series E, 6.53%
|
10.0
|
10.0
|
|||
|
2027, Series E, 6.42%
|
5.0
|
5.0
|
|||
|
2027, Series E, 6.68%
|
1.0
|
1.0
|
|||
|
|
2027, Series F, 6.34%
|
20.0
|
20.0
|
||
|
2028, Series F, 6.36%
|
10.0
|
10.0
|
|||
|
2028, Series F, 6.55%
|
20.0
|
20.0
|
|||
|
2029, Series G, 7.08%
|
30.0
|
30.0
|
|||
|
Total Indiana Gas
|
121.0
|
121.0
|
|||
|
Total long-term debt outstanding
|
1,307.1
|
1,308.8
|
|||
|
Current maturities of long-term debt
|
(250.0)
|
-
|
|||
|
Debt subject to tender
|
(30.0)
|
(51.3)
|
|||
|
Unamortized debt premium & discount - net
|
(2.3)
|
(2.7)
|
|||
|
Total long-term debt-net
|
$ 1,024.8
|
$ 1,254.8
|
|||
Utility Holdings 2009 Debt Issuance
On April 7, 2009, Utility Holdings entered into a private placement Note Purchase Agreement pursuant to which institutional investors purchased from Utility Holdings $100 million in 6.28 percent senior unsecured notes due April 7, 2020 (2020 Notes). The 2020 Notes are guaranteed by Utility Holdings’ three utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The proceeds from the sale of the 2020 Notes, net of issuance costs, totaled approximately $99.5 million. The 2020 Notes have no sinking fund requirements, and interest payments are due semi-annually. The 2020 Notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.
SIGECO 2009 Debt Issuance
On August 19, 2009 SIGECO also completed a $22.3 million tax-exempt first mortgage bond issuance at an interest rate of 5.4 percent that is fixed through maturity. The bonds mature in 2040. The proceeds from the sale of the bonds, net of issuance costs, totaled approximately $21.3 million.
Utility Holdings 2008 Debt Issuance
In March 2008, Utility Holdings issued $125 million in 6.25 percent senior unsecured notes due April 1, 2039 (2039 Notes) at par. The 2039 Notes are guaranteed by Utility Holdings’ three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. The 2039 Notes have no sinking fund requirements, and interest payments are due monthly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest. During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue. The proceeds from the sale of the 2039 Notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million.
Auction Rate Securities
In February 2008, SIGECO provided notice to the current holders of approximately $103 million of tax-exempt auction rate mode long-term debt of its plans to convert that debt from its current auction rate mode into a daily interest rate mode. In March 2008, the debt was tendered at 100 percent of the principal amount plus accrued interest. During March 2008, SIGECO remarketed approximately $61.8 million of these instruments at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60.0 million. The terms are $22.6 million at 5.15 percent due in 2023, $22.2 million at 5.35 percent due in 2030 and $17.0 million at 5.45 percent due in 2041.
On March 26, 2009, SIGECO remarketed the remaining $41.3 million of these obligations, receiving proceeds, net of issuance costs of approximately $40.6 million. The remarketed notes have a variable rate interest rate which is reset weekly and are supported by a standby letter of credit. The notes are collateralized by SIGECO’s utility plant, and $9.8 million are due in 2015 and $31.5 million are due in 2025.
Long-Term Debt Put and Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. Other than certain instruments that can be put to the Company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. During 2010, 2009, and 2008, the Company repaid approximately $1.8 million, $3.0 million, and $1.6 million, respectively, related to death puts. Debt which may be put to the Company for reasons other than a death during the years following 2010 (in millions) is $30.0 in 2011 and zero in 2012 and thereafter. Debt that may be put to the Company within one year or debt that is supported by lines of credit that expire within one year are classified as Long-term debt subject to tender in current liabilities. Investors had the one-time option to put $10 million in May 2010; however, no notice was received during the notification period and such debt is classified as long-term at December 31, 2010. Debt that can be put to the Company within one year or that is supported by a credit facility that expires within one year is classified in current liabilities in Long-term debt subject to tender.
Future Long-Term Debt Sinking Fund Requirements and Maturities
The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2010 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2010 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2010, $1.2 billion of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO’s gross utility plant balance subject to the Mortgage Indenture approximated $2.6 billion at December 31, 2010.
Consolidated maturities of long-term debt during the five years following 2010 (in millions) are $250.0 in 2011, zero in 2012, $105.0 in 2013, zero in 2014, and $104.8 in 2015.
Short-Term Borrowings
At December 31, 2010, the Company has $350 million of short-term borrowing capacity. As reduced by borrowings currently outstanding, approximately $303 million was available. Utility Holdings’ short-term credit facility was renewed on September 30, 2010 and is available through September 2013. During the renewal process, the Company lowered the level of capacity. The short-term borrowing facility was lowered from $515 million to $350 million. The Company has historically funded the short-term borrowing needs of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient.
Following is certain information regarding these short-term borrowing arrangements:
|
(In millions)
|
2010
|
2009
|
2008
|
||||||||||
|
Year End
|
|||||||||||||
|
Balance Outstanding
|
$ | 47.0 | $ | 16.4 | $ | 191.9 | |||||||
|
Weighted Average Interest Rate
|
0.41 | % | 0.25 | % | 2.68 | % | |||||||
|
Annual Average
|
|||||||||||||
|
Balance Outstanding
|
$ | 14.0 | $ | 29.2 | $ | 178.3 | |||||||
|
Weighted Average Interest Rate
|
0.40 | % | 1.28 | % | 3.71 | % | |||||||
|
Maximum Month End Balance Outstanding
|
$ | 47.0 | $ | 151.1 | $ | 338.0 | |||||||
In 2008, the Company’s access to longer term commercial paper was significantly reduced as a result of the turmoil and volatility in the financial markets. As a result, the Company met short-term financing needs through a combination of A-2/P-2 commercial paper issuances and draws on Utility Holdings’ back-up credit facility. At December 31, 2008, borrowings outstanding were comprised of $100.4 million of bank loans at a weighted average interest rate of 1.56% and $91.5 million of commercial paper at a weighted average interest rate of 3.87%. The average annual balance outstanding in 2008 was comprised of $28.1 million of bank loans at a weighted average interest rate of 3.42% and $150.2 million of commercial paper at a weighted average interest rate of 3.76%. Throughout 2010 and most of 2009, the Company has placed commercial paper without any significant issues and only had to borrow from its backup credit facility in 2009 in early 2009 on a limited basis.
Covenants
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As an example, the Utility Holdings’ short-term debt agreement expiring in 2013 contains a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2010, the Company was in compliance with all financial covenants.
|
7.
|
Common Shareholder’s Equity
|
On June 27, 2008, Vectren settled an equity forward agreement associated with a 2007 public offering of its common stock. Vectren transferred net proceeds of approximately $124.8 million to Utility Holdings. The proceeds received were recorded as an increase to Common Stock in Common Shareholder’s Equity and are presented in the Statement of Cash Flows as a financing activity.
In addition to the $124.8 million capital contribution above, during the years ended December 31, 2010, 2009, and 2008, the Company has cumulatively received additional capital of $11.6 million from Vectren which was funded by new share issues from Vectren’s dividend reinvestment plan and other stock plans.
|
8.
|
Accumulated Other Comprehensive Income
|
Comprehensive income is a measure of all changes in equity that result from the non-shareholder transactions. This information is reported in the Consolidated Statements of Common Shareholder’s Equity. A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
|
2008
|
2009
|
2010
|
||||||||||||||||||||||||||
|
Beginning
|
Changes
|
End
|
Changes
|
End
|
Changes
|
End
|
||||||||||||||||||||||
|
of Year
|
During
|
of Year
|
During
|
of Year
|
During
|
of Year
|
||||||||||||||||||||||
|
(In millions)
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
Year
|
Balance
|
|||||||||||||||||||||
|
Cash flow hedges
|
$ | 0.5 | $ | (0.4 | ) | $ | 0.1 | $ | - | $ | 0.1 | $ | - | $ | 0.1 | |||||||||||||
|
Deferred income taxes
|
(0.2 | ) | 0.2 | - | - | - | - | - | ||||||||||||||||||||
|
Accumulated other comprehensive income
|
$ | 0.3 | $ | (0.2 | ) | $ | 0.1 | $ | - | $ | 0.1 | $ | - | $ | 0.1 | |||||||||||||
|
9.
|
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 2010 and thereafter (in millions) are $0.7 in 2011, $0.7 in 2012, $0.6 in 2013, $0.7 in 2014, $0.2 million in 2015, and zero thereafter. Total lease expense (in millions) was $0.7 in 2010, $0.9 in 2009, and $1.6 in 2008. Firm purchase commitments for commodities and utility plant total zero in 2011, $5.3 million in 2012, $5.5 million in 2013, $5.7 million in 2014, and zero thereafter.
The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.
Legal Proceedings
The Company is party to various legal proceedings, audits, and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations or cash flows.
|
10.
|
Environmental Matters
|
Clean Air Act
The Clean Air Interstate Rule (CAIR) is an allowance cap and trade program that required reductions from coal-burning power plants for NOx emissions beginning January 1, 2009 and SO2 emissions beginning January 1, 2010, with a second phase of reductions in 2015. On July 11, 2008, the US Court of Appeals for the District of Columbia vacated the federal CAIR regulations. Various parties filed motions for reconsideration, and on December 23, 2008, the Court reinstated the CAIR regulations and remanded the regulations back to the EPA for promulgation of revisions in accordance with the Court’s July 11, 2008 order. Thus, the original version of CAIR promulgated in March of 2005 remains effective while EPA revises it per the Court’s guidance. SIGECO is in compliance with the current CAIR Phase I annual NOx reduction requirements in effect on January 1, 2009, and the Phase I annual SO2 reduction requirements in effect on January 1, 2010. Utilization of the Company’s inventory of NOx and SO2 allowances may also be impacted if CAIR is further revised. Most of these allowances were granted to the Company at zero cost; therefore, any reduction in carrying value that could result from future changes in regulations would be immaterial.
Similarly, in March of 2005, EPA promulgated the Clean Air Mercury Rule (CAMR). CAMR is an allowance cap and trade program requiring further reductions in mercury emissions from coal-burning power plants. The CAMR regulations were vacated by the US Court of Appeals for the DC Circuit in July 2008. In response to the court decision, EPA has announced that it intends to publish proposed Maximum Achievable Control Technology standards for mercury in 2011. It is uncertain what emission limit the EPA is considering, and whether they will address hazardous pollutants in addition to mercury.
To comply with Indiana’s implementation plan of the Clean Air Act of 1990, the CAIR regulations, and to comply with potential future regulations of mercury and further NOx and SO2 reductions, SIGECO has IURC authority to invest in clean coal technology. Using this authorization, SIGECO has invested approximately $411 million in pollution control equipment, including Selective Catalytic Reduction (SCR) systems, fabric filters, and an SO2 scrubber at its generating facility that is jointly owned with ALCOA (the Company’s portion is 150 MW). SCR technology is the most effective method of reducing NOx emissions where high removal efficiencies are required and fabric filters control particulate matter emissions. Of the $411 million, $312 million was included in rate base for purposes of determining SIGECO’s new electric base rates that went into effect on August 15, 2007, and $99 million is currently recovered through a rider mechanism which is periodically updated for actual costs incurred including depreciation expense. As part of its recent rate proceeding, the Company has requested to also include these more recent expenditures in rate base as well.
SIGECO’s coal fired generating fleet is 100 percent scrubbed for SO2 and 90 percent controlled for NOx. SIGECO's investments in scrubber, SCR, and fabric filter technology allows for compliance with existing regulations and should position it to comply with future reasonable mercury pollution control legislation, if and when, reductions are promulgated by EPA. On July 6, 2010, the EPA issued its proposed revisions to CAIR, renamed the Clean Air Transport Rule, for public comment. The Transport Rule proposes a 71 percent reduction of SO2 over 2005 national levels and a 52 percent reduction of NOx over 2005 national levels and would further impact the utilization of currently granted SO2 and NOx allowances. The Company is currently reviewing the sufficiency of its existing pollution control equipment in relation to the requirements proposed in the Clean Air Transport Rule and currently does not expect significant capital expenditures will be required to comply if the Transport Rule is adopted in its current form.
Climate Change
Numerous competing legislative proposals have also been introduced in recent years that involve carbon, energy efficiency, and renewable energy. Comprehensive energy legislation at the federal level continues to be debated, but there has been little progress to date. The progression of regional initiatives throughout the United States has slowed. While no climate change legislation is pending in Indiana, the state is an observer to the Midwestern Regional Greenhouse Gas Reduction Accord and the state’s legislature debated, but did not pass, a renewable energy portfolio standard in 2009.
In advance of a federal or state renewable portfolio standard, SIGECO received regulatory approval to purchase a 3 MW landfill gas generation facility from a related entity. The facility was purchased in 2009 and is directly interconnected to the Company’s distribution system. In 2009, the Company also executed a long term purchase power commitment for 50 MW of wind energy. These transactions supplement a 30 MW wind energy purchase power agreement executed in 2008.
In April of 2007, the US Supreme Court determined that greenhouse gases meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether greenhouse gas emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April of 2009, the EPA published its proposed endangerment finding for public comment. The proposed endangerment finding concludes that carbon emissions from mobile sources pose an endangerment to public health and the environment. The endangerment finding was finalized in December of 2009, and is the first step toward EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. Therefore, any new regulations would likely also impact major stationary sources of greenhouse gases. The EPA has promulgated two greenhouse gas regulations that apply to SIGECO’s generating facilities. In 2009, the EPA finalized a mandatory greenhouse gas emissions registry which will require reporting of emissions beginning in 2011 (for the emission year 2010). The EPA has also recently finalized a revision to the Prevention of Significant Deterioration (PSD) and Title V permitting rules which would require facilities that emit 75,000 tons or more of greenhouse gases a year to obtain a PSD permit for new construction or a significant modification of an existing facility.
Impact of Legislative Actions & Other Initiatives is Unknown
If regulations are enacted by the EPA or other agencies or if legislation requiring reductions in CO2 and other greenhouse gases or legislation mandating a renewable energy portfolio standard is adopted, such regulation could substantially affect both the costs and operating characteristics of the Company’s fossil fuel generating plants and natural gas distribution businesses. Further, any legislation or regulatory actions taken by the EPA or other agencies would likely impact the Company’s generation resource planning decisions. At this time and in the absence of final legislation, compliance costs and other effects associated with reductions in greenhouse gas emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control greenhouse gas emissions. A preliminary investigation demonstrated costs to comply would be significant, first with regard to operating expenses and later for capital expenditures as technology becomes available to control greenhouse gas emissions. However, these compliance cost estimates are based on highly uncertain assumptions, including allowance prices if a cap and trade approach were employed, and energy efficiency targets. Costs to purchase allowances that cap greenhouse gas emissions or expenditures made to control emissions should be considered a cost of providing electricity, and as such, the Company believes recovery should be timely reflected in rates charged to customers. Customer rates may also be impacted should decisions be made to reduce the level of sales to municipal and other wholesale customers in order to meet emission targets.
Ash Ponds & Coal Ash Disposal Regulations
In June 2010, the EPA issued proposed regulations affecting the management and disposal of coal combustion products, such as ash generated by the Company’s coal-fired power plants. The proposed rules more stringently regulate these byproducts and would likely increase the cost of operating or expanding existing ash ponds and the development of new ash ponds. The EPA did not offer a preferred alternative, but is taking public comment on multiple alternative regulations. The alternatives include regulating coal combustion by-products as hazardous waste. At this time, the majority of the Company’s ash is being beneficially reused. The proposals offered by EPA allow for the beneficial reuse of ash in certain circumstances. The Company estimates capital expenditures to comply could be as much as $30 million, and such expenditures could exceed $100 million if the most stringent of the alternatives is selected. Annual compliance costs could increase slightly or be impacted by as much as $5 million.
Clean Water Act
Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures. In April of 2009, the U.S. Supreme Court affirmed that the EPA could, but was not required to, consider costs and benefits in making the evaluation as to the best technology available for existing facilities. The regulation was remanded back to the EPA for further consideration. Depending upon the approaches taken by the EPA when it reissues the regulation, capital investments could be in the $40 million range if new infrastructure, such as new cooling water towers, is required.
Jacobsville Superfund Site
On July 22, 2004, the EPA 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 EPA 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 EPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. The Company’s property has not been named as a source of the lead contamination. The Company's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils above industrial cleanup levels. At this time, it is anticipated that the EPA may request only additional soil testing at some future date.
Environmental Remediation Efforts
In the past, Indiana Gas, SIGECO, and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.
Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.
Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $23.1 million. The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which limit Indiana Gas’ costs at these 19 sites to between 20 percent and 50 percent. With respect to insurance coverage, Indiana Gas has received approximately $20.8 million from all known insurance carriers under insurance policies in effect when these plants were in operation.
In October 2002, SIGECO received a formal information request letter from the IDEM regarding five manufactured gas plants that it owned and/or operated and were not enrolled in the IDEM’s VRP. In October 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM in February 2004. SIGECO was also named in a lawsuit, involving another waste disposal site subject to potential environmental remediation efforts. With respect to that lawsuit, SIGECO settled with the plaintiff during 2010 mitigating any future claims at this site. SIGECO has filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program and/or related to the site subject to the recently settled lawsuit. In November the Court ruled on two motions for summary judgment, finding for SIGECO and against certain insurers on indemnification and defense obligations in the policies at issue.
SIGECO has recorded cumulative costs that it reasonably expects to incur related to these environmental matters, including the recent settlement discussed above, totaling approximately $15.8 million. However, the total costs that may be incurred in connection with addressing all of these sites cannot be determined at this time. With respect to insurance coverage, SIGECO has recorded approximately $14.1 million of expected insurance recoveries from certain of its insurance carriers under insurance policies in effect when these sites were in operation. While negotiations are ongoing with certain carriers, settlements have been reached with some carriers and $8.2 million in proceeds have been received.
The costs the Company expects to incur are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company’s utilities have recorded all costs which they presently expect to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2010 and 2009, respectively, approximately $5.5 million and $6.5 million of accrued, but not yet spent, costs are included in Other Liabilities related to both the Indiana Gas and SIGECO sites.
|
11.
|
Rate & Regulatory Matters
|
Vectren South Electric Base Rate Filing
On December 11, 2009, Vectren South filed a request with the IURC to adjust its base electric rates. The requested increase in base rates addresses capital investments, a modified electric rate design that facilitates a partnership between Vectren South and customers to pursue energy efficiency and conservation, and new energy efficiency programs to complement those currently offered for natural gas customers. On July 30, 2010, Vectren South revised downward its increase requested through the filing of its rebuttal position to approximately $34 million. The request addresses the roughly $325 million spent in infrastructure construction since its last base rate increase in August 2007 that was needed to continue to provide reliable service and updates to operating costs and revenues. The rate design proposed in the filing would break the link between small residential and commercial customers’ consumption and the utility’s margin, thereby aligning the utility’s and customers’ interests in using less energy. The revised request assumes an overall rate of return of 7.42 percent on rate base of approximately $1.3 billion and an allowed return on equity (ROE) of 10.7 percent. The OUCC and SIGECO Industrial Group separately filed testimony in this case, proposing an increase of approximately $11 million and $18 million, respectively. Furthermore, the intervening parties in the case took differing views on, among other matters, the proposed rate design and the level and price of coal inventory. Hearings on all matters in the case were held in early March and late August 2010. An order is anticipated in the first half of 2011.
Vectren South Electric Fuel Adjustment Filings
As stated above, electric retail rates contain a fuel adjustment clause (FAC) that allows for periodic adjustment in energy charges to reflect changes in the cost of fuel and purchased power. The FAC procedures involve periodic filings and IURC hearings to approve the recovery of Vectren South’s fuel and purchased power costs.
During 2010, as part of its FAC testimony, the OUCC requested the IURC require Vectren South to renegotiate its term coal contracts because they were priced higher than prevailing spot prices. This request was repeated by the OUCC in Vectren South’s base rate proceeding referred to above. Vectren South purchases the majority of its coal from Vectren Fuels, Inc. (a nonutility wholly owned subsidiary of the Company) under coal contracts entered into in 2008. Vectren South states in its rate case testimony that the prices in the coal contracts were at or below the market at the time of contract execution and were subject to a bidding process that included third parties. Further, the Company has already engaged in contract renegotiations to defer certain deliveries, and to eliminate some volumes in 2011, with further price negotiation to occur in 2011 under the terms of the contracts. The IURC has already found in a number of FAC proceedings since 2008, including in its most recent FAC order dated November 4, 2010, that the costs incurred under these coal contracts are reasonable.
The OUCC also raised concerns regarding Vectren South’s generating unit “must run” policy. Under that policy, for reliability reasons, Vectren South instructs the MISO that certain units must be dispatched regardless of current market conditions. The OUCC is reviewing data related to Vectren South’s “must run” policy.
The parties agreed to the creation of an FAC sub docket proceeding to address the specific issues noted above. An order establishing the sub docket was issued by the IURC on July 28, 2010. On November 30, 2010, in response to a joint motion filed by the OUCC and Vectren South, the IURC issued an order dismissing this sub docket as these coal contract issues will be addressed in the pending Vectren South Electric base rate case.
Vectren South Electric Demand Side Management Program Filing
On August 16, 2010, Vectren South filed a petition with the IURC, seeking approval of its proposed Demand Side Management (DSM) Programs, recovery of the costs associated with these programs, recovery of lost margins as a result of implementing these programs for large customers, and recovery of performance incentives linked with specific measurement criteria on all programs. The DSM Programs proposed are consistent with a December 9, 2009 order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indiana electric utilities under a consistent statewide approach. In order to meet these objectives, the IURC order divided the DSM programs into Core and Core Plus programs. Core programs are joint programs required to be offered by all Indiana electric utilities to all customers, including large industrial customers. Core Plus programs are those programs not required specifically by the IURC, but defined by each utility to meet the overall energy savings targets defined by the IURC.
In its August filing, Vectren South proposed a three-year DSM Plan that expands its current portfolio of Core and Core Plus DSM Programs in order to meet the energy savings goals established by the IURC. Vectren South requested recovery of these program costs under a current tracking mechanism. In addition, Vectren South proposed a performance incentive mechanism that is contingent upon the success of each of the DSM Programs in reducing energy usage to the levels defined by the IURC. This performance incentive would also be recovered in the same tracking mechanism. Finally, the Company proposed lost margin recovery associated with the implementation of DSM programs for large customers, and cited its decoupling proposal applicable to residential and general service customers in the pending electric base rate case. On January 20, 2011, the OUCC and Vectren South filed a settlement with the IURC reflecting agreement on the Company’s programs and lost margin recovery from large customers. A hearing will be held on March 8, 2011 involving all parties to this proceeding.
VEDO Gas Base Rate Order Received
On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case. The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.
The order also adjusted the rate design used to collect the agreed-upon revenue from VEDO's customers. The order allows for the phased movement toward a straight fixed variable rate design for residential customers which places all of the fixed cost recovery in the customer service charge. A straight fixed variable design mitigates most weather risk as well as the effects of declining usage, similar to the Company’s decoupling mechanism, which expired when this new rate design went into effect on February 22, 2009. In 2008, annual results include approximately $4.3 million of revenue from the decoupling mechanism that did not continue once this base rate increase went into effect. Since the straight fixed variable rate design was fully implemented in February 2010, nearly 90 percent of the combined residential and commercial base rate margins were recovered through the customer service charge. The OCC appealed this rate order to the Ohio Supreme Court, which had affirmed PUCO orders authorizing straight fixed variable rate design in two other cases. On December 23, 2010, the Ohio Supreme Court affirmed the PUCO order authorizing straight fixed variable rate design in VEDO’s case.
With this rate order, the Company has in place for its Ohio gas territory rates that allow for a straight fixed variable rate design that mitigates both weather risk and lost margin for residential customers; tracking of uncollectible accounts and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.
VEDO Continues the Process to Exit the Merchant Function
On August 20, 2008, the PUCO approved the results of an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing. This standard pricing was comprised of the monthly NYMEX settlement price plus a fixed adder. This standard pricing, which was effective from October 1, 2008 through March 31, 2010, was the initial step in exiting the merchant function in the Company’s Ohio service territory. The approach eliminated the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. In October 2008, VEDO’s entire natural gas inventory was transferred to the auction’s winning wholesale suppliers, resulting in proceeds to VEDO of approximately $107 million.
The second phase of the exit process began on April 1, 2010. During this phase, the Company no longer sells natural gas directly to customers. Rather, state-certified Competitive Retail Natural Gas Suppliers, that were successful bidders in a similar regulatory-approved auction, sell the gas commodity to specific customers for a 12 month period at auction-determined standard pricing. The first auction was conducted on January 12, 2010, and the auction results were approved by the PUCO on January 13, 2010. The plan approved by the PUCO required that the Company conduct at least two annual auctions during this phase. As such, the Company conducted another auction on January 18, 2011 in advance of the second 12-month term which commences on April 1, 2011. The results of that auction were approved by the PUCO on January 19, 2011. Consistent with current practice, customers will continue to receive a single bill for the commodity as well as the delivery component of natural gas service from VEDO. Vectren Source, Vectren’s wholly owned nonutility retail gas marketer, was a successful bidder in both auctions.
The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition process. Exiting the merchant function should not have a material impact on earnings or financial condition. It, however, has and will continue to reduce Gas utility revenues and have an equal and offsetting impact to Cost of gas sold as VEDO no longer purchases gas for resale to these customers.
Vectren North Gas Base Rate Order Received
On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case. The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million. The order also provided for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.
Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The accounting treatment allows for the continuation of the accrual for AFUDC and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years from the in-service date for each specific project.
With this order, the Company has in place for its North gas territory weather normalization, a conservation and decoupling mechanism, recovery of gas cost expense related to uncollectible accounts expense based on historical experience and tracking of unaccounted for gas costs through the existing GCA mechanism, and tracking of pipeline integrity management expense.
MISO Transactions
The Company is a member of the MISO, a FERC approved regional transmission organization. When the Company is a net seller of its generation, such net revenues, which totaled $24.9 million, $20.8 million, and $57.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Electric utility revenues. When the Company is a net purchaser such net purchases, which totaled $46.1 million, $34.4 million, and $16.6 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, are included in Cost of fuel & purchased power. Net positions are determined on an hourly basis.
The Company also receives transmission revenue from the MISO which is included in Electric utility revenues and totaled $18.8 million, $14.6 million, and $9.3 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively. These revenues result from other MISO members’ use of the Company’s transmission system as well as the recovery of the Company’s investment in certain new electric transmission projects meeting MISO’s transmission expansion plan criteria.
|
12.
|
Fair Value Measurements
|
The carrying values and estimated fair values of the Company's other financial instruments follow:
|
At December 31,
|
||||||||||||||||
|
2010
|
2009
|
|||||||||||||||
|
(In millions)
|
Carrying Amount
|
Est. Fair Value
|
Carrying Amount
|
Est. Fair Value
|
||||||||||||
|
Long-term debt
|
$ | 1,304.8 | $ | 1,392.9 | $ | 1,306.1 | $ | 1,366.4 | ||||||||
|
Short-term borrowings
|
47.0 | 47.0 | 16.4 | 16.4 | ||||||||||||
|
Cash & cash equivalents
|
2.4 | 2.4 | 6.2 | 6.2 | ||||||||||||
For the balance sheet dates presented in these financial statements, the Company had no material assets or liabilities recorded at fair value outstanding, and no material assets or liabilities valued using Level 3 inputs.
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.
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.
|
13.
|
Segment Reporting
|
The Company’s operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. Regulated operations supply natural gas and/or electricity to over one million customers. In total, the Company is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other Shared Service operations. Net income is the measure of profitability used by management for all operations.
Information related to the Company’s business segments is summarized below:
|
Year Ended December 31,
|
||||||||||||
|
(In millions)
|
2010
|
2009
|
2008
|
|||||||||
|
Revenues
|
||||||||||||
|
Gas Utility Services
|
$ | 954.1 | $ | 1,066.0 | $ | 1,432.7 | ||||||
|
Electric Utility Services
|
608.0 | 528.6 | 524.2 | |||||||||
|
Other Operations
|
44.5 | 42.8 | 36.8 | |||||||||
|
Eliminations
|
(42.9 | ) | (41.2 | ) | (35.0 | ) | ||||||
|
Total revenues
|
$ | 1,563.7 | $ | 1,596.2 | $ | 1,958.7 | ||||||
|
Profitability Measure - Net Income
|
||||||||||||
|
Gas Utility Services
|
$ | 53.7 | $ | 50.2 | $ | 53.3 | ||||||
|
Electric Utility Services
|
60.9 | 48.3 | 50.7 | |||||||||
|
Other Operations
|
9.3 | 8.9 | 7.1 | |||||||||
|
Total net income
|
$ | 123.9 | $ | 107.4 | $ | 111.1 | ||||||
|
Amounts Included in Profitability Measures
|
||||||||||||
|
Depreciation & Amortization
|
||||||||||||
|
Gas Utility Services
|
$ | 80.7 | $ | 76.9 | $ | 74.1 | ||||||
|
Electric Utility Services
|
80.8 | 77.5 | 68.5 | |||||||||
|
Other Operations
|
26.7 | 26.5 | 22.9 | |||||||||
|
Total depreciation & amortization
|
$ | 188.2 | $ | 180.9 | $ | 165.5 | ||||||
|
Interest Expense
|
||||||||||||
|
Gas Utility Services
|
$ | 38.8 | $ | 38.8 | $ | 42.0 | ||||||
|
Electric Utility Services
|
36.4 | 34.8 | 32.0 | |||||||||
|
Other Operations
|
6.2 | 5.6 | 5.9 | |||||||||
|
Total interest expense
|
$ | 81.4 | $ | 79.2 | $ | 79.9 | ||||||
|
Income Taxes
|
||||||||||||
|
Gas Utility Services
|
$ | 35.1 | $ | 31.3 | $ | 35.5 | ||||||
|
Electric Utility Services
|
40.8 | 27.4 | 32.0 | |||||||||
|
Other Operations
|
1.2 | 0.5 | 0.1 | |||||||||
|
Total income taxes
|
$ | 77.1 | $ | 59.2 | $ | 67.6 | ||||||
|
Capital Expenditures
|
||||||||||||
|
Gas Utility Services
|
$ | 88.7 | $ | 121.1 | $ | 110.4 | ||||||
|
Electric Utility Services
|
120.1 | 154.1 | 172.0 | |||||||||
|
Other Operations
|
22.5 | 16.7 | 29.6 | |||||||||
|
Non-cash costs & changes in accruals
|
(2.2 | ) | 15.0 | (5.7 | ) | |||||||
| Total capital expenditures | $ | 229.1 | $ | 306.9 | $ | 306.3 | ||||||
|
At December 31,
|
||||||
|
(In millions)
|
2010
|
2009
|
||||
|
Assets
|
||||||
|
Utility Group
|
||||||
|
Gas Utility Services
|
$ | 2,161.7 | $ | 2,102.4 | ||
|
Electric Utility Services
|
1,666.5 | 1,592.4 | ||||
|
Other Operations, net of eliminations
|
96.3 | 128.3 | ||||
|
Total assets
|
$ | 3,924.5 | $ | 3,823.1 | ||
|
14.
|
Additional Balance Sheet & Operational Information
|
Inventories consist of the following:
|
At December 31,
|
||||||||
|
(In millions)
|
2010
|
2009
|
||||||
|
Gas in storage – at LIFO cost
|
$ | 26.2 | $ | 24.4 | ||||
|
Materials & supplies
|
37.3 | 35.0 | ||||||
|
Fuel (coal & oil) for electric generation
|
70.1 | 66.8 | ||||||
|
Other
|
1.6 | 1.7 | ||||||
|
Total inventories
|
$ | 135.2 | $ | 127.9 | ||||
Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded that carrying value at December 31, 2010, and 2009, by approximately $14 million and $19 million, respectively.
Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:
|
At December 31,
|
||||||||
|
(In millions)
|
2010
|
2009
|
||||||
|
Prepaid gas delivery service
|
$ | 40.7 | $ | 38.7 | ||||
|
Prepaid taxes
|
34.3 | 11.4 | ||||||
|
Deferred income taxes
|
- | 17.1 | ||||||
|
Other prepayments & current assets
|
8.4 | 2.0 | ||||||
|
Total prepayments & other current assets
|
$ | 83.4 | $ | 69.2 | ||||
Other investments in the Consolidated Balance Sheets consist of the following:
|
At December 31,
|
||||||||
|
(In millions)
|
2010
|
2009
|
||||||
|
Cash surrender value of life insurance policies
|
$ | 26.1 | $ | 23.1 | ||||
|
Municipal bond
|
4.1 | 4.3 | ||||||
|
Restricted cash
|
- | 2.8 | ||||||
|
Other investments
|
1.1 | 1.2 | ||||||
|
Total other investments
|
$ | 31.3 | $ | 31.4 | ||||
Accrued liabilities in the Consolidated Balance Sheets consist of the following:
|
At December 31,
|
||||||||
|
(In millions)
|
2010
|
2009
|
||||||
|
Refunds to customers & customer deposits
|
$ | 54.8 | $ | 51.0 | ||||
|
Accrued taxes
|
39.7 | 36.9 | ||||||
|
Accrued interest
|
19.7 | 19.6 | ||||||
|
Deferred income taxes
|
0.4 | - | ||||||
|
Accrued salaries & other
|
21.3 | 23.9 | ||||||
|
Total accrued liabilities
|
$ | 135.9 | $ | 131.4 | ||||
Asset retirement obligations included in the Consolidated Balance Sheets roll forward as follows:
|
(In millions)
|
2010
|
2009
|
||||||
|
Asset retirement obligation, January 1
|
$ | 32.9 | $ | 31.9 | ||||
|
Accretion
|
1.9 | 1.4 | ||||||
|
Increases (decreases) in estimates, net of cash payments
|
(2.8 | ) | (0.4 | ) | ||||
|
Asset retirement obligation, December 31
|
32.0 | 32.9 | ||||||
|
Accrued liabilities
|
$ | 0.2 | $ | 3.0 | ||||
|
Deferred credits & other liabilities
|
$ | 31.8 | $ | 29.9 | ||||
Other – net in the Consolidated Statements of Income consists of the following:
|
Year Ended December 31,
|
||||||||||||
|
(In millions)
|
2010 | 2009 | 2008 | |||||||||
|
AFUDC - borrowed funds
|
$ | 1.4 | $ | 1.3 | $ | 2.2 | ||||||
|
AFUDC - equity funds
|
0.3 | 0.7 | 0.3 | |||||||||
|
Nonutility plant capitalized interest
|
0.2 | 0.2 | 2.0 | |||||||||
|
Interest income
|
0.6 | 0.7 | 1.0 | |||||||||
|
Cash surrender value of life insurance policies
|
1.8 | 3.9 | (2.6 | ) | ||||||||
|
Other income
|
1.1 | 1.0 | 1.1 | |||||||||
|
Total other – net
|
$ | 5.4 | $ | 7.8 | $ | 4.0 | ||||||
Supplemental Cash Flow Information:
|
Year Ended December 31,
|
||||||||||||
|
(In millions)
|
2010
|
2009
|
2008
|
|||||||||
|
Cash paid (received) for:
|
||||||||||||
|
Interest
|
$ | 81.4 | $ | 77.6 | $ | 74.9 | ||||||
|
Income taxes
|
25.4 | (26.1 | ) | 14.8 | ||||||||
As of December 31, 2010 and 2009, the Company has accruals related to utility and nonutility plant purchases totaling approximately $11.1 million and $8.8 million, respectively.
-69-
|
15.
|
Subsidiary Guarantor & Consolidating Information
|
The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of Utility Holdings’ $320 million in short-term credit facilities, of which $47 million is outstanding at December 31, 2010, and Utility Holdings’ $919 million unsecured senior notes outstanding at December 31, 2010. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. However, Utility Holdings does have operations other than those of the subsidiary guarantors. Pursuant to Item 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors, which are 100 percent owned, separate from the parent company’s operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Pursuant to a tax sharing agreement, consolidating tax effects, which are calculated on a separate return basis, are reflected at the parent level.
Consolidating Statement of Income for the year ended December 31, 2010 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING REVENUES
|
||||||||||||||||
|
Gas utility
|
$ | 954.1 | $ | - | $ | - | $ | 954.1 | ||||||||
|
Electric utility
|
608.0 | - | - | 608.0 | ||||||||||||
|
Other
|
- | 44.5 | (42.9 | ) | 1.6 | |||||||||||
|
Total operating revenues
|
1,562.1 | 44.5 | (42.9 | ) | 1,563.7 | |||||||||||
|
OPERATING EXPENSES
|
||||||||||||||||
|
Cost of gas sold
|
504.7 | - | - | 504.7 | ||||||||||||
|
Cost of fuel & purchased power
|
235.0 | - | - | 235.0 | ||||||||||||
|
Other operating
|
341.9 | - | (42.7 | ) | 299.2 | |||||||||||
|
Depreciation & amortization
|
161.1 | 26.7 | 0.4 | 188.2 | ||||||||||||
|
Taxes other than income taxes
|
58.0 | 1.5 | 0.1 | 59.6 | ||||||||||||
|
Total operating expenses
|
1,300.7 | 28.2 | (42.2 | ) | 1,286.7 | |||||||||||
|
OPERATING INCOME
|
261.4 | 16.3 | (0.7 | ) | 277.0 | |||||||||||
|
OTHER INCOME (EXPENSE)
|
||||||||||||||||
|
Equity in earnings of consolidated companies
|
- | 114.6 | (114.6 | ) | - | |||||||||||
|
Other – net
|
4.3 | 51.1 | (50.0 | ) | 5.4 | |||||||||||
|
Total other income (expense)
|
4.3 | 165.7 | (164.6 | ) | 5.4 | |||||||||||
|
Interest expense
|
75.2 | 56.9 | (50.7 | ) | 81.4 | |||||||||||
|
INCOME BEFORE INCOME TAXES
|
190.5 | 125.1 | (114.6 | ) | 201.0 | |||||||||||
|
Income taxes
|
75.9 | 1.2 | - | 77.1 | ||||||||||||
|
NET INCOME
|
$ | 114.6 | $ | 123.9 | $ | (114.6 | ) | $ | 123.9 | |||||||
Consolidating Statement of Income for the year ended December 31, 2009 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING REVENUES
|
||||||||||||||||
|
Gas utility
|
$ | 1,066.0 | $ | - | $ | - | $ | 1,066.0 | ||||||||
|
Electric utility
|
528.6 | - | - | 528.6 | ||||||||||||
|
Other
|
- | 42.8 | (41.2 | ) | 1.6 | |||||||||||
|
Total operating revenues
|
1,594.6 | 42.8 | (41.2 | ) | 1,596.2 | |||||||||||
|
OPERATING EXPENSES
|
||||||||||||||||
|
Cost of gas sold
|
618.1 | - | - | 618.1 | ||||||||||||
|
Cost of fuel & purchased power
|
194.3 | - | - | 194.3 | ||||||||||||
|
Other operating
|
345.3 | 0.1 | (40.8 | ) | 304.6 | |||||||||||
|
Depreciation & amortization
|
154.1 | 26.5 | 0.3 | 180.9 | ||||||||||||
|
Taxes other than income taxes
|
58.6 | 1.6 | 0.1 | 60.3 | ||||||||||||
|
Total operating expenses
|
1,370.4 | 28.2 | (40.4 | ) | 1,358.2 | |||||||||||
|
OPERATING INCOME
|
224.2 | 14.6 | (0.8 | ) | 238.0 | |||||||||||
|
OTHER INCOME (EXPENSE)
|
||||||||||||||||
|
Equity in earnings of consolidated companies
|
- | 98.5 | (98.5 | ) | - | |||||||||||
|
Other – net
|
6.6 | 50.9 | (49.7 | ) | 7.8 | |||||||||||
|
Total other income (expense)
|
6.6 | 149.4 | (148.2 | ) | 7.8 | |||||||||||
|
Interest expense
|
73.6 | 56.1 | (50.5 | ) | 79.2 | |||||||||||
|
INCOME BEFORE INCOME TAXES
|
157.2 | 107.9 | (98.5 | ) | 166.6 | |||||||||||
|
Income taxes
|
58.7 | 0.5 | - | 59.2 | ||||||||||||
|
NET INCOME
|
$ | 98.5 | $ | 107.4 | $ | (98.5 | ) | $ | 107.4 | |||||||
Consolidating Statement of Income for the year ended December 31, 2008 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
OPERATING REVENUES
|
||||||||||||||||
|
Gas utility
|
$ | 1,432.7 | $ | - | $ | - | $ | 1,432.7 | ||||||||
|
Electric utility
|
524.2 | - | - | 524.2 | ||||||||||||
|
Other
|
- | 36.8 | (35.0 | ) | 1.8 | |||||||||||
|
Total operating revenues
|
1,956.9 | 36.8 | (35.0 | ) | 1,958.7 | |||||||||||
|
OPERATING EXPENSES
|
||||||||||||||||
|
Cost of gas sold
|
983.1 | - | - | 983.1 | ||||||||||||
|
Cost of fuel & purchased power
|
182.9 | - | - | 182.9 | ||||||||||||
|
Other operating
|
334.2 | - | (33.9 | ) | 300.3 | |||||||||||
|
Depreciation & amortization
|
142.3 | 22.9 | 0.3 | 165.5 | ||||||||||||
|
Taxes other than income taxes
|
70.5 | 1.7 | 0.1 | 72.3 | ||||||||||||
|
Total operating expenses
|
1,713.0 | 24.6 | (33.5 | ) | 1,704.1 | |||||||||||
|
OPERATING INCOME
|
243.9 | 12.2 | (1.5 | ) | 254.6 | |||||||||||
|
OTHER INCOME (EXPENSE)
|
||||||||||||||||
|
Equity in earnings of consolidated companies
|
- | 104.0 | (104.0 | ) | - | |||||||||||
|
Other – net
|
1.6 | 52.4 | (50.0 | ) | 4.0 | |||||||||||
|
Total other income (expense)
|
1.6 | 156.4 | (154.0 | ) | 4.0 | |||||||||||
|
Interest expense
|
74.0 | 57.4 | (51.5 | ) | 79.9 | |||||||||||
|
INCOME BEFORE INCOME TAXES
|
171.5 | 111.2 | (104.0 | ) | 178.7 | |||||||||||
|
Income taxes
|
67.5 | 0.1 | - | 67.6 | ||||||||||||
|
NET INCOME
|
$ | 104.0 | $ | 111.1 | $ | (104.0 | ) | $ | 111.1 | |||||||
Consolidating Balance Sheet as of December 31, 2010 (in millions):
| ASSETS |
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current Assets
|
||||||||||||||||
|
Cash & cash equivalents
|
$ | 2.0 | $ | 0.4 | - | $ | 2.4 | |||||||||
|
Accounts receivable - less reserves
|
106.7 | - | - | 106.7 | ||||||||||||
|
Intercompany receivables
|
65.9 | 162.2 | (228.1 | ) | - | |||||||||||
|
Receivables due from other Vectren companies
|
0.1 | - | - | 0.1 | ||||||||||||
|
Accrued unbilled revenues
|
127.8 | - | - | 127.8 | ||||||||||||
|
Inventories
|
135.2 | - | - | 135.2 | ||||||||||||
|
Recoverable fuel & natural gas costs
|
7.9 | - | - | 7.9 | ||||||||||||
|
Prepayments & other current assets
|
97.2 | 2.4 | (16.2 | ) | 83.4 | |||||||||||
|
Total current assets
|
542.8 | 165.0 | (244.3 | ) | 463.5 | |||||||||||
|
Utility Plant
|
||||||||||||||||
|
Original cost
|
4,791.7 | - | - | 4,791.7 | ||||||||||||
|
Less: accumulated depreciation & amortization
|
1,836.3 | - | - | 1,836.3 | ||||||||||||
|
Net utility plant
|
2,955.4 | - | - | 2,955.4 | ||||||||||||
|
Investments in consolidated subsidiaries
|
- | 1,239.1 | (1,239.1 | ) | - | |||||||||||
|
Notes receivable from consolidated subsidiaries
|
- | 768.7 | (768.7 | ) | - | |||||||||||
|
Investments in unconsolidated affiliates
|
0.2 | - | - | 0.2 | ||||||||||||
|
Other investments
|
26.1 | 5.2 | - | 31.3 | ||||||||||||
|
Nonutility property - net
|
3.7 | 163.5 | - | 167.2 | ||||||||||||
|
Goodwill - net
|
205.0 | - | - | 205.0 | ||||||||||||
|
Regulatory assets
|
73.7 | 23.2 | - | 96.9 | ||||||||||||
|
Other assets
|
21.5 | 1.7 | (18.2 | ) | 5.0 | |||||||||||
|
TOTAL ASSETS
|
$ | 3,828.4 | $ | 2,366.4 | $ | (2,270.3 | ) | $ | 3,924.5 | |||||||
|
LIABILITIES & SHAREHOLDER'S EQUITY
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current Liabilities
|
||||||||||||||||
|
Accounts payable
|
$ | 116.0 | $ | 10.0 | $ | - | $ | 126.0 | ||||||||
|
Accounts payable to affiliated companies
|
59.3 | - | - | 59.3 | ||||||||||||
|
Intercompany payables
|
16.9 | - | (16.9 | ) | - | |||||||||||
|
Payables to other Vectren companies
|
48.7 | - | - | 48.7 | ||||||||||||
|
Refundable fuel & natural gas costs
|
- | - | - | - | ||||||||||||
|
Accrued liabilities
|
124.3 | 27.8 | (16.2 | ) | 135.9 | |||||||||||
|
Short-term borrowings
|
- | 47.0 | - | 47.0 | ||||||||||||
|
Intercompany short-term borrowings
|
145.1 | 65.9 | (211.0 | ) | - | |||||||||||
|
Current maturities of long-term debt
|
- | 250.0 | - | 250.0 | ||||||||||||
|
Long-term debt subject to tender
|
30.0 | - | - | 30.0 | ||||||||||||
|
Total current liabilities
|
540.3 | 400.7 | (244.1 | ) | 696.9 | |||||||||||
|
Long-Term Debt
|
||||||||||||||||
|
Long-term debt - net of current maturities &
|
||||||||||||||||
|
debt subject to tender
|
357.1 | 667.7 | - | 1,024.8 | ||||||||||||
|
Long-term debt due to VUHI
|
768.7 | - | (768.7 | ) | - | |||||||||||
|
Total long-term debt - net
|
1,125.8 | 667.7 | (768.7 | ) | 1,024.8 | |||||||||||
|
Deferred Income Taxes & Other Liabilities
|
||||||||||||||||
|
Deferred income taxes
|
496.9 | (22.1 | ) | (0.1 | ) | 474.7 | ||||||||||
|
Regulatory liabilities
|
330.2 | 3.3 | - | 333.5 | ||||||||||||
|
Deferred credits & other liabilities
|
96.1 | 1.4 | (18.3 | ) | 79.2 | |||||||||||
|
Total deferred credits & other liabilities
|
923.2 | (17.4 | ) | (18.4 | ) | 887.4 | ||||||||||
|
Common Shareholder's Equity
|
||||||||||||||||
|
Common stock (no par value)
|
787.8 | 774.6 | (787.8 | ) | 774.6 | |||||||||||
|
Retained earnings
|
451.2 | 540.7 | (451.2 | ) | 540.7 | |||||||||||
|
Accumulated other comprehensive income
|
0.1 | 0.1 | (0.1 | ) | 0.1 | |||||||||||
|
Total common shareholder's equity
|
1,239.1 | 1,315.4 | (1,239.1 | ) | 1,315.4 | |||||||||||
|
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,828.4 | $ | 2,366.4 | $ | (2,270.3 | ) | $ | 3,924.5 | |||||||
Consolidating Balance Sheet as of December 31, 2009
|
ASSETS
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current Assets
|
||||||||||||||||
|
Cash & cash equivalents
|
$ | 5.6 | $ | 0.6 | $ | - | $ | 6.2 | ||||||||
|
Accounts receivable - less reserves
|
108.1 | - | - | 108.1 | ||||||||||||
|
Intercompany receivables
|
68.2 | 132.7 | (200.9 | ) | - | |||||||||||
|
Receivables due from other Vectren companies
|
0.7 | - | - | 0.7 | ||||||||||||
|
Accrued unbilled revenues
|
115.4 | - | - | 115.4 | ||||||||||||
|
Inventories
|
124.6 | 3.3 | - | 127.9 | ||||||||||||
|
Recoverable fuel & natural gas costs
|
- | - | - | - | ||||||||||||
|
Prepayments & other current assets
|
63.4 | 16.4 | (10.6 | ) | 69.2 | |||||||||||
|
Total current assets
|
486.0 | 153.0 | (211.5 | ) | 427.5 | |||||||||||
|
Utility Plant
|
||||||||||||||||
|
Original cost
|
4,601.4 | - | - | 4,601.4 | ||||||||||||
|
Less: accumulated depreciation & amortization
|
1,722.6 | - | - | 1,722.6 | ||||||||||||
|
Net utility plant
|
2,878.8 | - | - | 2,878.8 | ||||||||||||
|
Investments in consolidated subsidiaries
|
- | 1,190.3 | (1,190.3 | ) | - | |||||||||||
|
Notes receivable from consolidated subsidiaries
|
- | 770.4 | (770.4 | ) | - | |||||||||||
|
Investments in unconsolidated affiliates
|
0.2 | - | - | 0.2 | ||||||||||||
|
Other investments
|
26.0 | 5.4 | - | 31.4 | ||||||||||||
|
Nonutility property - net
|
4.1 | 167.7 | - | 171.8 | ||||||||||||
|
Goodwill - net
|
205.0 | - | - | 205.0 | ||||||||||||
|
Regulatory assets
|
79.6 | 24.5 | - | 104.1 | ||||||||||||
|
Other assets
|
15.2 | - | (10.9 | ) | 4.3 | |||||||||||
|
TOTAL ASSETS
|
$ | 3,694.9 | $ | 2,311.3 | $ | (2,183.1 | ) | $ | 3,823.1 | |||||||
|
LIABILITIES & SHAREHOLDER'S EQUITY
|
Subsidiary
|
Parent
|
||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
Current Liabilities
|
||||||||||||||||
|
Accounts payable
|
$ | 127.5 | $ | 5.6 | $ | - | $ | 133.1 | ||||||||
|
Accounts payable to affiliated companies
|
54.1 | - | - | 54.1 | ||||||||||||
|
Intercompany payables
|
18.2 | - | (18.2 | ) | - | |||||||||||
|
Payables to other Vectren companies
|
53.6 | - | - | 53.6 | ||||||||||||
|
Refundable fuel & natural gas costs
|
22.3 | - | - | 22.3 | ||||||||||||
|
Accrued liabilities
|
120.8 | 21.2 | (10.6 | ) | 131.4 | |||||||||||
|
Short-term borrowings
|
- | 16.4 | - | 16.4 | ||||||||||||
|
Intercompany short-term borrowings
|
113.8 | 68.9 | (182.7 | ) | - | |||||||||||
|
Long-term debt subject to tender
|
51.3 | - | - | 51.3 | ||||||||||||
|
Total current liabilities
|
561.6 | 112.1 | (211.5 | ) | 462.2 | |||||||||||
|
Long-Term Debt
|
||||||||||||||||
|
Long-term debt - net of current maturities &
|
||||||||||||||||
|
debt subject to tender
|
335.6 | 919.2 | - | 1,254.8 | ||||||||||||
|
Long-term debt due to VUHI
|
770.4 | - | (770.4 | ) | - | |||||||||||
|
Total long-term debt - net
|
1,106.0 | 919.2 | (770.4 | ) | 1,254.8 | |||||||||||
|
Deferred Income Taxes & Other Liabilities
|
||||||||||||||||
|
Deferred income taxes
|
417.8 | 0.2 | - | 418.0 | ||||||||||||
|
Regulatory liabilities
|
318.2 | 4.0 | - | 322.2 | ||||||||||||
|
Deferred credits & other liabilities
|
101.0 | 1.1 | (10.9 | ) | 91.2 | |||||||||||
|
Total deferred credits & other liabilities
|
837.0 | 5.3 | (10.9 | ) | 831.4 | |||||||||||
|
Common Shareholder's Equity
|
||||||||||||||||
|
Common stock (no par value)
|
783.1 | 769.9 | (783.1 | ) | 769.9 | |||||||||||
|
Retained earnings
|
407.1 | 504.7 | (407.1 | ) | 504.7 | |||||||||||
|
Accumulated other comprehensive income
|
0.1 | 0.1 | (0.1 | ) | 0.1 | |||||||||||
|
Total common shareholder's equity
|
1,190.3 | 1,274.7 | (1,190.3 | ) | 1,274.7 | |||||||||||
|
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY
|
$ | 3,694.9 | $ | 2,311.3 | $ | (2,183.1 | ) | $ | 3,823.1 | |||||||
Consolidating Statement of Cash Flows for the year ended December 31, 2010 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 234.3 | $ | 43.5 | $ | - | $ | 277.8 | ||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from additional capital contribution from parent
|
4.7 | 4.7 | (4.7 | ) | 4.7 | |||||||||||
|
Requirements for:
|
||||||||||||||||
|
Dividends to parent
|
(70.4 | ) | (87.9 | ) | 70.4 | (87.9 | ) | |||||||||
|
Retirement of long-term debt, including premiums paid
|
(1.8 | ) | (1.8 | ) | 1.8 | (1.8 | ) | |||||||||
|
Net change in intercompany short-term borrowings
|
31.3 | (2.9 | ) | (28.4 | ) | - | ||||||||||
|
Net change in short-term borrowings
|
- | 30.6 | - | 30.6 | ||||||||||||
|
Net cash flows from financing activities
|
(36.2 | ) | (57.3 | ) | 39.1 | (54.4 | ) | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds from
|
||||||||||||||||
|
Consolidated subsidiary distributions
|
- | 70.4 | (70.4 | ) | - | |||||||||||
| Long-term intercompany notes receivable | - | 1.8 | (1.8 | ) | - | |||||||||||
|
Other investing activities
|
2.8 | 0.2 | - | 3.0 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital expenditures, excluding AFUDC equity
|
(206.3 | ) | (22.8 | ) | - | (229.1 | ) | |||||||||
|
Consolidated subsidiary investments
|
- | (4.7 | ) | 4.7 | - | |||||||||||
|
Other investing activities
|
(1.1 | ) | - | - | (1.1 | ) | ||||||||||
|
Net change in short-term intercompany notes receivable
|
2.9 | (31.3 | ) | 28.4 | - | |||||||||||
|
Net cash flows from investing activities
|
(201.7 | ) | 13.6 | (39.1 | ) | (227.2 | ) | |||||||||
|
Net change in cash & cash equivalents
|
(3.6 | ) | (0.2 | ) | - | (3.8 | ) | |||||||||
|
Cash & cash equivalents at beginning of period
|
5.6 | 0.6 | - | 6.2 | ||||||||||||
|
Cash & cash equivalents at end of period
|
$ | 2.0 | $ | 0.4 | $ | - | $ | 2.4 | ||||||||
Consolidating Statement of Cash Flows for the year ended December 31, 2009 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 350.6 | $ | 6.2 | $ | - | $ | 356.8 | ||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Additional capital contribution from parent
|
6.9 | 6.9 | (6.9 | ) | 6.9 | |||||||||||
|
Long-term debt - net of issuance costs & hedging proceeds
|
136.3 | 99.5 | (74.5 | ) | 161.3 | |||||||||||
|
Requirements for:
|
||||||||||||||||
|
Dividends to parent
|
(82.5 | ) | (82.5 | ) | 82.5 | (82.5 | ) | |||||||||
|
Retirement of long-term debt, including premiums paid
|
(3.0 | ) | (3.0 | ) | 3.0 | (3.0 | ) | |||||||||
|
Net change in intercompany short-term borrowings
|
(152.5 | ) | (35.1 | ) | 187.6 | - | ||||||||||
|
Net change in short-term borrowings
|
(0.4 | ) | (175.1 | ) | - | (175.5 | ) | |||||||||
|
Net cash flows from financing activities
|
(95.2 | ) | (189.3 | ) | 191.7 | (92.8 | ) | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Consolidated subsidiary distributions
|
- | 82.5 | (82.5 | ) | - | |||||||||||
|
Other investing activities
|
- | 0.2 | - | 0.2 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital expenditures, excluding AFUDC equity
|
(291.0 | ) | (15.9 | ) | - | (306.9 | ) | |||||||||
|
Consolidated subsidiary investments
|
- | (6.9 | ) | 6.9 | - | |||||||||||
|
Other investing activities
|
(3.6 | ) | - | - | (3.6 | ) | ||||||||||
|
Net change in long-term intercompany notes receivable
|
- | (71.5 | ) | 71.5 | - | |||||||||||
|
Net change in short-term intercompany notes receivable
|
35.1 | 152.5 | (187.6 | ) | - | |||||||||||
|
Net cash flows from investing activities
|
(259.5 | ) | 140.9 | (191.7 | ) | (310.3 | ) | |||||||||
|
Net change in cash & cash equivalents
|
(4.1 | ) | (42.2 | ) | - | (46.3 | ) | |||||||||
|
Cash & cash equivalents at beginning of period
|
9.7 | 42.8 | - | 52.5 | ||||||||||||
|
Cash & cash equivalents at end of period
|
$ | 5.6 | $ | 0.6 | $ | - | $ | 6.2 | ||||||||
-74-
Consolidating Statement of Cash Flows for the year ended December 31, 2008 (in millions):
|
Subsidiary
|
Parent
|
|||||||||||||||
|
Guarantors
|
Company
|
Eliminations
|
Consolidated
|
|||||||||||||
|
NET CASH FLOWS FROM OPERATING ACTIVITIES
|
$ | 379.6 | $ | 55.4 | $ | - | $ | 435.0 | ||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Long-term debt - net of issuance costs & hedging proceeds
|
171.1 | 111.1 | (111.1 | ) | 171.1 | |||||||||||
|
Issuance of common stock
|
- | 124.8 | - | 124.8 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Dividends to parent
|
(83.2 | ) | (83.2 | ) | 83.2 | (83.2 | ) | |||||||||
|
Retirement of long-term debt, including premiums paid
|
(104.6 | ) | (1.6 | ) | 1.6 | (104.6 | ) | |||||||||
|
Net change in intercompany short-term borrowings
|
(80.9 | ) | 103.9 | (23.0 | ) | - | ||||||||||
|
Net change in short-term borrowings
|
0.4 | (194.4 | ) | - | (194.0 | ) | ||||||||||
|
Net cash flows from financing activities
|
(97.2 | ) | 60.6 | (49.3 | ) | (85.9 | ) | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||||||
|
Proceeds from:
|
||||||||||||||||
|
Consolidated subsidiary distributions
|
- | 83.2 | (83.2 | ) | - | |||||||||||
|
Other investing activities
|
2.3 | 0.2 | - | 2.5 | ||||||||||||
|
Requirements for:
|
||||||||||||||||
|
Capital expenditures, excluding AFUDC equity
|
(277.0 | ) | (29.3 | ) | - | (306.3 | ) | |||||||||
|
Other investing activities
|
(4.5 | ) | - | - | (4.5 | ) | ||||||||||
|
Net change in long-term intercompany notes receivable
|
- | (109.5 | ) | 109.5 | - | |||||||||||
|
Net change in notes receivable from other Vectren companies
|
- | (23.0 | ) | 23.0 | - | |||||||||||
|
Net cash flows from investing activities
|
(279.2 | ) | (78.4 | ) | 49.3 | (308.3 | ) | |||||||||
|
Net change in cash & cash equivalents
|
3.2 | 37.6 | - | 40.8 | ||||||||||||
|
Cash & cash equivalents at beginning of period
|
6.5 | 5.2 | - | 11.7 | ||||||||||||
|
Cash & cash equivalents at end of period
|
$ | 9.7 | $ | 42.8 | $ | - | $ | 52.5 | ||||||||
-75-
|
16.
|
Impact of Recently Issued Accounting Guidance
|
Variable Interest Entities
In June 2009, the FASB issued new accounting guidance regarding variable interest entities (VIE’s). This new guidance is effective for annual reporting periods beginning after November 15, 2009. This guidance requires a qualitative analysis of which holder of a variable interest controls the VIE and if that interest holder must consolidate a VIE. Additionally, it requires additional disclosures and an ongoing reassessment of who must consolidate a VIE. The Company adopted this guidance on January 1, 2010. The adoption did not have any impact on the consolidated financial statements.
Fair Value Measurements & Disclosures
In January 2010, the FASB issued new accounting guidance on improving disclosures about fair market value. This guidance amends prior disclosure requirements involving fair value measurements to add new requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. The guidance also clarifies existing fair value disclosures in regard to the level of disaggregation and about inputs and valuation techniques used to measure fair value. The guidance also amends prior disclosure requirements regarding postretirement benefit plan assets to require that disclosures be provided by classes of assets instead of major categories of assets. This guidance is effective for the first reporting period beginning after December 15, 2009. The Company adopted this guidance for its 2010 reporting. Due to the low level of items carried at fair value in the Company’s financial statements, the adoption has not had any material impact.
|
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 2010 and 2009 follows:
|
(In millions)
|
Q1
|
Q2
|
Q3
|
Q4
|
||||||
|
2010
|
||||||||||
|
Results of Operations:
|
||||||||||
|
Operating revenues
|
$ 613.4
|
$ 274.3
|
$ 275.4
|
$ 400.6
|
||||||
|
Operating income
|
107.2
|
45.4
|
49.6
|
74.8
|
||||||
|
Net income
|
55.4
|
16.2
|
18.7
|
33.6
|
||||||
|
2009
|
||||||||||
|
Results of Operations:
|
||||||||||
|
Operating revenues
|
$ 652.8
|
$ 272.2
|
$ 236.8
|
$ 434.4
|
||||||
|
Operating income
|
105.2
|
27.6
|
32.1
|
73.1
|
||||||
|
Net income
|
56.2
|
6.6
|
8.7
|
35.9
|
||||||
None.
Changes in Internal Controls over Financial Reporting
During the quarter ended December 31, 2010, 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, 2010, 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, 2010, to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is:
|
1)
|
recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and
|
|
2)
|
accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
|
Management’s Report on Internal Control over Financial Reporting
Vectren Utility Holdings, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation under the framework in Internal Control — Integrated Framework, the Company concluded that its internal control over financial reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of Utility Holdings’ registered public accounting firm regarding internal control over financial reporting. Management's report is not subject to attestation by Utility Holdings’ registered public accounting firm pursuant to rules of the Securities and Exchange Commission.
None.
PART III
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
Vectren’s Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Benefits and Nominating and Corporate Governance Committees, and its Corporate Code of Conduct that covers the Company’s directors, officers and employees are available in the Corporate Governance section of the Company’s website, www.vectren.com. The Corporate Code of Conduct (titled “Corp Code of Conduct”) covers all employees, including the CEO and senior financial officers. The website also contains a separate code of ethics and code of conduct for members of Vectren’s Board of Directors. Copies will be mailed upon request to Vectren Corporation Investor Relations, Attention: Robert L. Goocher, One Vectren Square, Evansville, Indiana 47708. Vectren intends to disclose any amendments to the Corporate Code of Conduct or waivers of the Corporate Code of Conduct on behalf of its directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions for Utility Holdings on its website at the internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to the address listed above.
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.
The following tabulation shows the audit and non-audit fees incurred and payable to Deloitte & Touche LLP (Deloitte) for the years ending December 31, 2010 and 2009. The fees presented below represent total Vectren fees, the majority of which are allocated to Utility Holdings.
|
2010
|
2009
|
|||||||
|
Audit Fees(1)
|
$ | 1,343,080 | $ | 1,374,906 | ||||
|
Audit-Related Fees(2)
|
347,314 | 283,413 | ||||||
|
Tax Fees(3)
|
109,912 | 122,145 | ||||||
|
Total Fees Paid to Deloitte(4)
|
$ | 1,800,306 | $ | 1,780,464 | ||||
|
(1)
|
Aggregate fees incurred and payable to Deloitte for professional services rendered for the audits of Vectren’s and Utility Holdings’ 2010 and 2009 fiscal year annual financial statements and the review of financial statements included in their Forms 10-K or 10-Q filed during the Company’s 2010 and 2009 fiscal years. The amount includes fees related to the attestation to the Company’s assertion pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $95,830 and $106,406 in 2010 and 2009, respectively.
|
|
(2)
|
Audit-related fees consisted principally of reviews related to various financing transactions, regulatory filings, consultation on various accounting issues, and audit fees related to the stand-alone audits of two of the Company’s consolidated subsidiaries. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $12,314 and $15,013 in 2010 and 2009, respectively.
|
|
(3)
|
Tax fees consisted of fees paid to Deloitte for the review of tax returns and consultation on other tax matters of the Company and of its consolidated subsidiaries. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $9,912 and $13,205 in 2010 and 2009, respectively.
|
|
(4)
|
Pursuant to its charter, the Audit Committee is responsible for selecting, approving professional fees and overseeing the independence, qualifications and performance of the independent registered public accounting firm. The Audit Committee has adopted a formal policy with respect to the pre-approval of audit and permissible non-audit services provided by the independent registered public accounting firm. Pre-approval is assessed on a case-by-case basis. In assessing requests for services to be provided by the independent registered public accounting firm, the Audit Committee considers whether such services are consistent with the auditors’ independence, whether the independent registered public accounting firm is likely to provide the most effective and efficient service based upon the firm’s familiarity with the Vectren and its consolidated subsidiaries, and whether the service could enhance Vectren’s ability to manage or control risk or improve audit quality. The audit-related, tax and other services provided by Deloitte in the last year and related fees were approved by the Audit Committee in accordance with this policy.
|
PART IV
List of Documents Filed as Part of This Report
Consolidated Financial Statements
The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and Supplementary Data” of this Form 10-K.
Supplemental Schedules
For the years ended December 31, 2010, 2009, and 2008, the Company’s Schedule II -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein. The report of Deloitte & Touche LLP on the schedule may be found in Item 8. All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8.
SCHEDULE II
Vectren Utility Holdings, Inc. and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
|
Column A
|
Column B
|
Column C
|
Column D
|
Column E
|
||||||||||||||||
|
Additions
|
||||||||||||||||||||
|
Balance at
|
Charged
|
Charged
|
Deductions
|
Balance at
|
||||||||||||||||
|
Beginning
|
to
|
to Other
|
from
|
End of
|
||||||||||||||||
|
Description
|
Of Year
|
Expenses
|
Accounts
|
Reserves, Net
|
Year
|
|||||||||||||||
|
(In millions)
|
||||||||||||||||||||
|
VALUATION AND QUALIFYING ACCOUNTS:
|
||||||||||||||||||||
|
Year 2010 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible accounts
|
$ | 4.0 | $ | 16.2 | $ | - | $ | 15.7 | $ | 4.5 | ||||||||||
|
Year 2009 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible accounts
|
$ | 4.5 | $ | 14.6 | $ | - | $ | 15.1 | $ | 4.0 | ||||||||||
|
Year 2008 – Accumulated provision for
|
||||||||||||||||||||
|
uncollectible accounts
|
$ | 2.7 | $ | 15.8 | $ | - | $ | 14.0 | $ | 4.5 | ||||||||||
|
OTHER RESERVES:
|
||||||||||||||||||||
|
Year 2010 – Restructuring costs
|
$ | 0.5 | $ | - | $ | - | $ | 0.1 | $ | 0.4 | ||||||||||
|
Year 2009 – Restructuring costs
|
$ | 0.6 | $ | - | $ | - | $ | 0.1 | $ | 0.5 | ||||||||||
|
Year 2008 – Restructuring costs
|
$ | 0.6 | $ | - | $ | - | $ | - | $ | 0.6 | ||||||||||
List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified below pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company attached to this filing filed electronically with the SEC are listed below.
Vectren Utility Holdings, Inc.
Form 10-K
Attached Exhibits
The following Exhibits are included in this Annual Report on Form 10-K.
|
Exhibit
Number
|
Document
|
|
31.1
|
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31.2
|
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
The following Exhibits, as well as the Exhibits listed above, were filed electronically with the SEC with this filing.
|
Exhibit
Number
|
Document
|
|
12
|
Ratio of Earnings to Fixed Charges
|
|
21.1
|
List of Company’s Significant Subsidiaries
|
|
23.1
|
Consent of Independent Registered Public Accounting Firm
|
INDEX TO EXHIBITS
3. Articles of Incorporation and By-Laws
|
3.1
|
Articles of Incorporation of Vectren Utility Holdings, Inc. (Filed and designated in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit 3.1)
|
|
3.2
|
Bylaws of Vectren Utility Holdings, Inc. as most recently amended and restated as of June 24, 2009 (Filed and designated in Current Report on Form 8-K filed June 26, 2009, File No. 1-15467, as Exhibit 3.1.)
|
4. Instruments Defining the Rights of Security Holders, Including Indentures
|
4.1
|
Mortgage and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1, 1993. (Filed and designated in Form 8-K, dated April 13, 1993, File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit 4.) May 1, 1993. (Filed and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit 4(a).) March 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.) August 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.) April 1, 2005 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.1) March 1, 2006 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.2) December 1, 2007 (Filed and designated in Form 10-K for the year ended December 31, 2007, File No 1-15467, as Exhibit 4.3) August 1, 2009 (Filed and designated in Form 10-K for the year ended December 31, 2009, File No 1-15467, as Exhibit 4.1)
|
|
4.2
|
Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National Association (formerly know as First Trust National Association, which was formerly know as Bank of America Illinois, which was formerly know as Continental Bank, National Association. Inc.'s. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494.); First Supplemental Indenture thereto dated as of February 15, 1991. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture thereto dated as of September 15, 1991, (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(b).); Third supplemental Indenture thereto dated as of September 15, 1991 (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture thereto dated as of December 2, 1992, (Filed and designated in Current Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000, (Filed and designated in Current Report on Form 8-K filed December 27, 2000, File No. 1-6494, as Exhibit 4.)
|
|
4.3
|
Indenture dated October 19, 2001, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.2); Second Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated November 29, 2001, File No. 1-16739, as Exhibit 4.1); Third Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated July 24, 2003, File No. 1-16739, as Exhibit 4.1); Fourth Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated November 18, 2005, File No. 1-16739, as Exhibit 4.1). Form of Fifth Supplemental Indenture, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas & Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 16, 2006, File No. 1-16739, as Exhibit 4.1). Sixth Supplemental Indenture, dated March 10, 2008, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank National Association (Filed and designated in Form 8-K, dated March 10, 2008, File No. 1-16739, as Exhibit 4.1)
|
|
4.4
|
Note Purchase Agreement, dated April 7, 2009, among Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. and the purchasers named therein. (Filed and designated in Form 8-K dated April 7, 2009 File No. 1-15467, as Exhibit 4.5)
|
10. Material Contracts
|
10.1
|
Summary description of Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) First Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.).
|
|
10.2
|
Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and designated in Southern Indiana Gas and Electric Company's Proxy Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.)
|
|
10.3
|
Vectren Corporation At Risk Compensation Plan effective May 1, 2001,(as amended and restated s of May 1, 2006). (Filed and designated in Vectren Corporation’s Proxy Statement dated March 15, 2006, File No. 1-15467, as Appendix H.)
|
|
10.4
|
Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.)
|
|
10.5
|
Vectren Corporation Nonqualified Deferred Compensation Plan, effective January 1, 2005. (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.3.)
|
|
10.6
|
Vectren Corporation Unfunded Supplemental Retirement Plan for a Select Group of Management Employees (As Amended and Restated Effective January 1, 2005).(Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.1.)
|
|
10.7
|
Vectren Corporation Nonqualified Defined Benefit Restoration Plan (As Amended and Restated Effective January 1, 2005). (Filed and designated in Form 8-K dated December 17, 2008, File No. 1-15467, as Exhibit 10.2.)
|
|
10.8
|
Vectren Corporation Change in Control Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 1, 2005. (Filed and designated in Form 8-K dated March 1, 2005, File No. 1-15467, as Exhibit 99.1.). Amendment Number One to the Vectren Corporation Change in Control Agreement, effective as of March 1, 2005 between Vectren Corporation and Niel C. Ellerbrook (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.1.)
|
|
10.9
|
Vectren Corporation At Risk Compensation Plan specimen stock unit award agreement for non-employee members of the Board of Directors, effective January 1, 2009. (Filed and designated in Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit 10.1.)
|
|
10.10
|
Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2010. (Filed and designated in Form 8-K, dated January 7, 2010, File No. 1-15467, as Exhibit 10.1.)
|
|
10.11
|
Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 1, 2009. (Filed and designated in Form 8-K, dated February 17, 2009, File No. 1-15467, as Exhibit 10.1.)
|
|
10.12
|
Vectren Corporation At Risk Compensation Plan specimen restricted stock grant agreement for officers, effective January 1, 2008. (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.1.)
|
|
10.13
|
Vectren Corporation At Risk Compensation Plan specimen restricted stock units agreement for officers, effective January 1, 2008. (Filed and designated in Form 8-K, dated December 28, 2007, File No. 1-15467, as Exhibit 99.2.)
|
|
10.14
|
Vectren Corporation At Risk Compensation Plan specimen Stock Option Grant Agreement for officers, effective January 1, 2005. (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99.2.)
|
|
10.15
|
Vectren Corporation At Risk Compensation Plan stock unit award agreement for non-employee directors, effective May 1, 2009. (Filed and designation in Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit 10.1)
|
|
10.16
|
Vectren Corporation specimen employment agreement dated February 1, 2005. (Filed and designated in Form 8-K, dated February 1, 2005, File No. 1-15467, as Exhibit 99.1.) Amendment Number One to the Specimen Vectren Corporation Employment Agreement between Vectren Corporation and Executive Officers (Filed and designated in Form 8-K dated September 29, 2008, File No. 1-15467, as Exhibit 10.2.) The specimen agreements and related amendments differ among named executive officers only to the extent severance and change in control benefits are provided in the amount of three times base salary and bonus for Messrs. Benkert, Chapman, and Christian and two times for Mr. Doty.
|
|
10.17
|
Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.1.)
|
|
10.18
|
Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.2.)
|
|
10.19
|
Coal Supply Agreement for A.B. Brown Generating Station for 410,000 tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.3.)
|
|
10.20
|
Coal Supply Agreement for A.B. Brown Generating Station for 1 million tons between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective January 1, 2009. (Filed and designated in Form 8-K dated January 5, 2009, File No. 1-15467, as Exhibit 10.4.)
|
|
10.21
|
Amendment to F.B. Culley and A.B. Brown Coal Supply Agreements dated December 21, 2009. (Filed and designated in Form 10-K, for the year ended December 31, 2009, File No. 1-15467, as exhibit 10.1)
|
|
10.22
|
Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.15.)
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10.23
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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.)
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10.24
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Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Energy Group, Citizens Energy Services Corporation and ProLiance Energy, LLC, effective March 15, 1996. (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)
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10.25
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Revolving Credit Agreement (5 year facility), dated November 10, 2005, among Vectren Utility Holdings, Inc., and each of the purchasers named therein. (Filed and designated in Form 10-Q, for the period ended September 30, 2009, File No. 1-15467, as Exhibit 10.24.)
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10.26
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Revolving Credit Agreement (3 year facility), dated September 30, 2010, among Vectren Utility Holdings, Inc., and each of the financial institutions named therein. (Filed and designated in Form 8-K dated October 5, 2010, File No. 1-15467, as Exhibit 10.1)
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10.27
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Niel C. Ellerbrook Retirement Agreement, dated February 3, 2010. (Filed and designated in Form 8-K dated February 4, 2010 File No. 1-15467, as Exhibit 99.2)
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21. Subsidiaries of the Company
The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1. (Filed herewith.)
23. Consent of Experts and Counsel
The consent of Deloitte & Touche LLP are attached hereto as Exhibits 23.1 (Filed herewith.)
31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1 (Filed herewith.)
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2 (Filed herewith.)
32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32 (Filed herewith.)
99. Additional Exhibits
99.1 Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31, 2000. (Filed and designated in Current Report on Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.)
99.2 Amended and Restated Code of By-Laws of Vectren Corporation as of February 2, 2011. (Filed and designated in Current Report on Form 8-K filed February 4, 2011, File No. 1-15467, as Exhibit 3.1.)
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 UTILITY HOLDINGS, INC.
Dated March 4, 2011 /s/ Carl L. Chapman
Carl L. Chapman
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.
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Signature
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Title
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Date
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/s/ Carl L. Chapman
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President, Chief Executive Officer, and Director
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March 4, 2011
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Carl L. Chapman
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(Principal Executive Officer)
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/s/ Jerome A. Benkert, Jr.
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Executive Vice President and Chief Financial Officer
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March 4, 2011
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Jerome A. Benkert, Jr.
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(Principal Financial Officer)
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/s/ M. Susan Hardwick
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Vice President, Controller and Assistant Treasurer
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March 4, 2011
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M. Susan Hardwick
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(Principal Accounting Officer)
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/s/ Ronald E. Christian
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Director
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March 4, 2011
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Ronald E. Christian
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/s/ William S. Doty
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Director
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March 4, 2011
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William S. Doty
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