Edgar Filing: VECTREN UTILITY HOLDINGS INC

VUHI 10K 2013 DOC

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013



	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________________ to ________________________

Commission file number: 1-16739

VECTREN UTILITY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)



INDIANA		35-2104850
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)
One Vectren Square		47708
(Address of principal executive offices)		(Zip Code)

Registrant's telephone number, including area code: 812-491-4000

Securities registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Vectren Utility 6.10% SR NTS 12/1/2035		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:



Title of each class		Name of each exchange on which registered
Common – Without Par		None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. *Yes ý No ¨

*Utility Holdings is a majority owned subsidiary of a well-known seasoned issuer, and well-known seasoned issuer status depends in part on the type of security being registered by the majority-owned subsidiary.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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).

Yes ¨ No ý

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2013, was zero. All shares outstanding of the Registrant’s common stock were held by Vectren Corporation.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.



Common Stock - Without Par Value	10	February 28, 2014
Class	Number of Shares	Date

Omission of Information by Certain Wholly Owned Subsidiaries

The Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby.

Definitions



AFUDC: allowance for funds used during construction	MCF / BCF: thousands / billions of cubic feet
ASC: Accounting Standards Codification	MDth / MMDth: thousands / millions of dekatherms
BTU / MMBTU: British thermal units / millions of BTU	MISO: Midcontinent Independent System Operator (formerly Midwest Independent System Operator)
DOT: Department of Transportation	MW: megawatts
EPA: Environmental Protection Agency	MWh / GWh: megawatt hours / thousands of megawatt hours (gigawatt hours)
FASB: Financial Accounting Standards Board	NERC: North American Electric Reliability Corporation
FERC: Federal Energy Regulatory Commission	OCC: Ohio Office of the Consumer Counselor
IDEM: Indiana Department of Environmental Management	OUCC: Indiana Office of the Utility Consumer Counselor
IRC: Internal Revenue Code	PUCO: Public Utilities Commission of Ohio
IURC: Indiana Utility Regulatory Commission	Throughput: combined gas sales and gas transportation volumes
Kv: Kilovolt	XBRL: eXtensible Business Reporting Language

Access to Information

Vectren Corporation makes available all SEC filings and recent annual reports, including those of Vectren Utility Holdings, Inc., free of charge through its website at www.vectren.com as soon as reasonably practicable after electronically filing or furnishing the reports to the SEC, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows:



Mailing Address: One Vectren Square Evansville, Indiana 47708	Phone Number: (812) 491-4000	Investor Relations Contact: Robert L. Goocher Treasurer and Vice President, Investor Relations vvcir@vectren.com

Table of Contents



Item		Page
Number		Number
Part I

1	Business	5
1A	Risk Factors	10
1B	Unresolved Staff Comments	17
2	Properties	18
3	Legal Proceedings	19
4	Mine Safety Disclosures	19
Part II

5	Market for Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	19
6	Selected Financial Data	20
7	Management's Discussion and Analysis of Results of Operations and Financial Condition	21
7A	Quantitative and Qualitative Disclosures About Market Risk	43
8	Financial Statements and Supplementary Data	45
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	85
9A	Controls and Procedures, including Management’s Assessment of Internal Control over Financial Reporting Controls and Procedures	85
9B	Other Information	85

Part III

10	Directors, Executive Officers and Corporate Governance^(A)	85
11	Executive Compensation^(A)	86
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters^(A)	86
13	Certain Relationships, Related Transactions and Director Independence^(A)	86
14	Principal Accountant Fees and Services	86

Part IV

15	Exhibits and Financial Statement Schedules	87
	Signatures	94


(A)	– Omitted or amended as the Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby.

PART I

ITEM 1. BUSINESS

Description of the Business

Vectren Utility Holdings, Inc. (the Company, Utility Holdings or VUHI), 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 Vectren Energy Delivery of Ohio, Inc. (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 approximately 570,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 142,000 electric customers and approximately 110,000 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. VEDO provides energy delivery services to approximately 312,000 natural gas customers located near Dayton in west central 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, VEDO, 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, 2013, the Company had $4.1 billion in total assets, with approximately $2.3 billion (56 percent) attributed to Gas Utility Services, $1.7 billion (41 percent) attributed to Electric Utility Services, and $0.1 billion (3 percent) attributed to Other Operations. Net income for the year ended December 31, 2013, was $141.8 million, with $55.7 million attributed to Gas Utility Services, $75.8 million attributed to Electric Utility Services, and $10.3 million attributed to Other Operations. Net income for the year ended December 31, 2012, was $138.0 million. For further information regarding the activities and assets of operating segments, refer to Note 12 in the Company’s Consolidated Financial Statements included in Item 8.

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, 2013, the Company supplied natural gas service to approximately 1,005,900 Indiana and Ohio customers, including 919,000 residential, 85,200 commercial, and 1,700 industrial and other contract customers. Average gas utility customers served were approximately 992,100 in 2013, 986,100 in 2012, and 983,700 in 2011.

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 and 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 223.6 MMDth for the year ended December 31, 2013. Gas sold and transported to residential and commercial customers was 111.9 MMDth representing 50 percent of throughput. Gas transported or sold to industrial and other contract customers was 111.7 MMDth representing 50 percent of throughput. Rates for transporting gas generally provide for the same margins earned by selling gas under applicable sales tariffs. In 2012, natural gas began being transported to a natural gas fired power plant that was recently placed into service in the Vectren South service territory. Volumes were 6.6 MMDth in 2013 and 6.3 MMDth in 2012. Revenues associated with gas volumes delivered to the new plant are based on a monthly fixed charge.

For the year ended December 31, 2013, gas utility revenues were approximately $810.0 million, of which residential customers accounted for 67 percent and commercial accounted for 24 percent. Industrial and other contract customers accounted for only 9 percent of revenues.

Availability of Natural Gas

The volumes of gas sold is seasonal and affected by variations in weather conditions. To meet seasonal demand, the Company’s Indiana gas utilities have storage capacity at eight active underground gas storage fields and three propane 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 enter into short term and long term contracts with third party suppliers to ensure availability of gas. Prior to June 18, 2013, the Company contracted with a wholly-owned subsidiary of ProLiance Holdings, LLC (ProLiance). ProLiance is an unconsolidated, nonutility, energy marketing affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy) (See the discussion of Energy Marketing in Note 5 in the Company’s Consolidated Financial Statements included in Item 8 regarding transactions with ProLiance). The Company, through its utility subsidiaries, purchases all of its gas supply from third parties and 91 percent is from a single third party.

Natural Gas Purchasing Activity in Ohio

On April 30, 2008, the PUCO issued an order which approved the first two phases of a three phase plan to exit the merchant function in the Company's Ohio service territory. As a result, substantially all of the Company's Ohio customers now purchase natural gas directly from retail gas marketers rather than from the Company.

The PUCO provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the first two phases of the transition process. Exiting the merchant function has not had 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, for the most part, no longer purchases gas for resale.

Total Natural Gas Purchased Volumes

In 2013, Utility Holdings purchased 78.7 MMDth volumes of gas at an average cost of $4.60 per Dth. The average cost of gas per Dth purchased for the previous four years was $4.47 in 2012, $5.30 in 2011, $5.99 in 2010, and $5.97 in 2009.

Electric Utility Services

At December 31, 2013, the Company supplied electric service to approximately 142,900 Indiana customers, including approximately 124,300 residential, 18,400 commercial, and 200 industrial and other customers. Average electric utility customers served were approximately 142,300 in 2013, 141,700 in 2012, and 141,400 in 2011.

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, 2013, retail electricity sales totaled 5,479.1 GWh, resulting in revenues of approximately $567.8 million. Residential customers accounted for 36 percent of 2013 revenues; commercial 27 percent; industrial 35 percent; and other 2 percent. In addition, in 2013 the Company sold 514.4 GWh through wholesale activities principally to the MISO. Wholesale revenues, including transmission-related revenue, totaled $51.5 million in 2013.

System Load

Total load for each of the years 2009 through 2013 at the time of the system summer peak, and the related reserve margin, is presented below in MW.



Date of summer peak load	8/30/2013		7/24/2012		7/21/2011		8/4/2010		6/22/2009
Total load at peak	1,102		1,259		1,220		1,275		1,143

Generating capability	1,298		1,298		1,298		1,298		1,295
Firm purchase supply	38		136		136		136		136
Interruptible contracts & direct load control	48		60		60		62		62
Total power supply capacity	1,384		1,494		1,494		1,496		1,493
Reserve margin at peak	25	%	19	%	22	%	17	%	31	%

The winter peak load for the 2012-2013 season of approximately 832 MW occurred on February 1, 2013. The prior year winter peak load for the 2011-2012 season was approximately 895 MW, occurring on January 12, 2012.

Generating Capability

Installed generating capacity as of December 31, 2013, 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 2013 was fueled by coal (97 percent), natural gas (3 percent), and landfill gas (less than 1 percent). Oil was used only for testing of gas/oil-fired peaking units. The Company generated approximately 5,279 GWh in 2013. 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 1.9 million tons were purchased for generating electricity during 2013, of which approximately 95 percent was supplied by Vectren Fuels from its mines. This compares to 2.1 million tons and 2.3 million tons purchased in 2012 and 2011, respectively. The utility’s coal inventory was approximately 300 thousand tons and 1 million tons at December 31, 2013 and 2012, respectively.

Coal Purchases

The average cost of coal per ton purchased and delivered for the last five years was $58.38 in 2013, $68.65 in 2012, $75.04 in 2011, $70.47 in 2010, and $64.28 in 2009. Effective January 1, 2009, SIGECO began purchasing coal from Vectren Fuels under new coal purchase agreements. The term of these coal purchase agreements expire at various dates between 2014 and 2016 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. For contracts with price reopeners, amendments were finalized in 2011 for coal deliveries that began in 2012 at lower prices.

The Company received an order from the IURC on January 25, 2012 to allow for the lower prices that began late in 2012 and beyond to be reflected in customer bills beginning in early 2012. Because of the order the cost of coal expensed in 2012 was lower than amounts paid under existing contracts and included in the carrying amount of inventory at December 31, 2011. The IURC authorized the deferral of the difference between costs paid under these contracts and that charged to customers. See "Rate and Regulatory Matters" in Item 7 regarding coal procurement procedures and electric fuel cost reductions.

Firm Purchase Supply

The Company, through SIGECO, has a 1.5 percent interest in the Ohio Valley Electric Corporation (OVEC). OVEC is owned by 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 169 GWh from OVEC in 2013.

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 2013, the Company purchased approximately 61 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 134 GWh under this contract in 2013.

MISO Related Activity

The Company is a member of the MISO, a FERC approved regional transmission organization. The MISO serves the electric transmission needs of much of the Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region. The Company is an active participant in the MISO energy markets, where it bids its generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Pricing (LMP) as determined by the MISO market. 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 as purchased power in Cost of fuel & purchased power and net sales in a single hour are recorded in Electric utility revenues. During 2013, in hours when purchases from the MISO were in excess of generation sold to the MISO, the net purchases were 536 GWh. During 2013, in hours when sales to the MISO were in excess of purchases from the MISO, the net sales were 514 GWh.

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 expired on December 31, 2012. The Company has not replaced this contract.

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 671 MW during peak load periods. This interchange capability varies from season to season and has been impacted in recent years as a result of ongoing initiatives to improve the transmission grid throughout the Midwest. As an example, the 345 kV Vectren transmission project that was placed into service in December 2012 resulted in the ability to simultaneously interchange an additional 100 MW. The Company, as required as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets to MISO.

Competition

The utility industry has undergone structural changes 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. Substantially all of VEDO's customers receive gas from third-party suppliers and at December 31, 2013, approximately 131,000 customers in Vectren’s Ohio service territory had selected their supplier. In addition, VEDO’s service territory continues to transition toward exiting the merchant function. Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, is generally the same as that 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.

Increased competition, including those from cogeneration, solar, and other renewables opportunities for customers, create competitive pressures. In this regard, the deployment and commercialization of disruptive technologies, such as renewable energy sources and cogeneration facilities, have the potential to change the nature of the utility industry and reduce demand for the Company's electric and gas products and services. If the Company is not able to appropriately adapt to structural changes in the utility industry as a result of the development of disruptive technologies, this may have an adverse effect on the Company's financial condition and results of operations.

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, 2013, the Company and its consolidated subsidiaries had approximately 1,500 employees, of which 700 are subject to collective bargaining arrangements.

In June 2013, the Company reached a three year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 30, 2016. This labor agreement relates to employees of SIGECO.

In December 2012, the Company reached a three year agreement with Local 175 of the Utility Workers Union of America. The labor agreement was retroactively effective to November 1, 2012 and ends October 31, 2015. This labor agreement relates to employees of VEDO.

In September 2012, the Company reached a three year agreement with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers Union, ending September 23, 2015. This labor agreement relates to employees of SIGECO.

In December 2011, the Company reached a three year labor agreement, ending December 1, 2014, with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441. This labor agreement relates to employees of Indiana Gas.

ITEM 1A. RISK FACTORS

Investors should consider carefully the following factors that could cause the Company’s operating results and financial condition to be materially adversely affected. New risks may emerge at any time, and the Company cannot predict those risks or estimate the extent to which they may affect the Company’s businesses or financial performance.

Utility Holdings is a holding company and its assets consist primarily of investments in its subsidiaries.

The ability of Utility Holdings to receive dividends and repay indebtedness depends on the earnings, financial condition, capital requirements and cash flow of its subsidiaries, SIGECO, Indiana Gas, and VEDO and the distribution or other payment of earnings from those entities to Utility Holdings. Should the earnings, financial condition, capital requirements or cash flow of, or legal requirements applicable to them restrict their ability to pay dividends or make other payments to Utility Holdings, its ability to pay dividends to its parent could be limited. Utility Holdings’ results of operations, future growth, and earnings and dividend goals also will depend on the performance of its subsidiaries. Additionally, certain of the Company’s lending arrangements contain restrictive covenants, including the maintenance of a total debt to total capitalization ratio.

Deterioration in general economic conditions may have adverse impacts.

Economic conditions may have some negative impact on both gas and electric large customers and wholesale power sales. This impact may include volatility and unpredictability in the demand for natural gas and electricity, tempered growth strategies, significant conservation measures, and perhaps plant closures, production cutbacks, or bankruptcies. Economic conditions may also cause reductions in residential and commercial customer counts and lower revenues. It is also possible that an uncertain economy could affect costs including pension costs, interest costs, and uncollectible accounts expense.

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.

Utility Holdings has long-term and short-term debt guaranteed by its subsidiaries.

Utility Holdings currently has outstanding long-term and short-term debt that is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. These guarantees do not represent incremental consolidated obligations; rather, they represent guarantees of Utility Holdings' obligations.

A downgrade (or negative outlook) in or withdrawal of Utility Holdings’ credit ratings could negatively affect its ability to access capital and its cost.

The following table shows the current ratings assigned to certain outstanding debt by Moody’s and Standard & Poor’s:



	Current Rating
		Standard
	Moody’s	& Poor’s
Utility Holdings and Indiana Gas senior unsecured debt	A2	A-
Utility Holdings commercial paper program	P-1	A-2
SIGECO’s senior secured debt	Aa3	A

The current outlook for both Moody's and Standard and Poor’s is stable. The above table also reflects Moody's January 30, 2014 upgrades to each of the credit ratings shown. Both rating agencies 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.

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 and steel finishing; aluminum smelting and recycling; 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, including those from cogeneration, solar, and other renewables opportunities for customers, 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. In this regard, the deployment and commercialization of disruptive technologies, such as renewable energy sources and cogeneration facilities, have the potential to change the nature of the utility industry and reduce demand for the Company's electric and gas products and services. If the Company is not able to appropriately adapt to structural changes in the utility industry as a result of the development of disruptive technologies, this may have an adverse effect on the Company's financial condition and results of operations. Additionally, 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 but has recently begun to explore electric choice options. Ohio regulation also provides for choice of commodity providers for all gas customers. 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 of a normal temperature adjustment mechanism. Additionally, the implementation of a straight fixed variable rate design mitigates most weather variations related to Ohio residential gas sales.

Utility Holdings’ businesses are exposed to increasing regulation, including pipeline safety, environmental, and cybersecurity regulation.

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, the PUCO, the DOT, Department of Energy (DOE), and Department of Homeland

Security (DHS). These authorities regulate many aspects of its generation, transmission and distribution operations, including construction and maintenance of facilities, operations, and safety. In addition, the IURC, PUCO, and FERC approve its utility-related debt and equity issuances, regulate the rates that Vectren's utilities can charge customers, the rate of return that Utility Holdings' utilities are authorized to earn, and its ability to timely recover gas and fuel costs and investments in infrastructure. Further, there are consumer advocates and other parties that may intervene in regulatory proceedings and affect regulatory outcomes.

Trends Toward Stricter Standards

With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated that are subject to regulation, the Company's investment in infrastructure, and the associated operating costs have increased and are expected to increase in the future. As examples of the trend toward stricter regulation, the EPA is currently considering revisions to regulations involving fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases and continues to implement increasingly more stringent air quality standards.

Pipeline Safety Considerations

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe, efficient and reliable manner. Utility Holdings' natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and improvement. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law on January 3, 2012 and the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation. While certain of the compliance costs remain uncertain, the Pipeline Safety Law is expected to result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure; and therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses as evidenced by recent regulatory filings in Indiana and Ohio by Vectren North, Vectren South, and Vectren Energy Delivery of Ohio.

Environmental Considerations

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 the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO₂), nitrogen oxide (NOx), and mercury, among others. Environmental legislation/regulation also requires that facilities, sites, and other properties associated with Utility Holdings' 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.

Climate Change and Renewable Energy Considerations

While there have been a series of legislative 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, none have been finalized to date. The US Supreme Court has determined that the EPA has the authority to regulate greenhouse gases as a pollutant under the Clean Air Act. 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. 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. 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.

Evolving Cybersecurity Standards and Considerations

The frequency, size and variety of cybersecurity threats against critical infrastructure companies continues to grow, as do the evolving frameworks, standards and regulations intended to keep pace with and address these threats. In 2013, there was a marked increase in interest from both State and Federal regulatory agencies related to cybersecurity in general, and specifically in critical infrastructure sectors, including electric and natural gas. The Company has a dedicated cybersecurity team and maintains vigilance with regard to the assessment of cybersecurity risks, the measures employed to protect information technology assets, critical infrastructure, the Company and its customers from these threats. Cybersecurity threats, however, constantly evolve in attempts to identify and capitalize on any weakness or unprotected areas. If these measures were to fail or if a breach were to occur, it could result in impairment or loss of critical functions, operating reliability, customer or other confidential information. The ultimate effects of which are difficult to quantify with any certainty.

Increasing regulation and infrastructure replacement programs could affect Utility Holdings' utility rates charged to customers, its costs, and its profitability.

Any additional expenses or capital incurred by the Company, as it relates to complying with increasing regulation and other infrastructure replacement activities are expected to be borne by the customers in its service territories through increased rates. Increased rates have an impact on the economic health of the communities served. New regulations could also negatively impact industries in the Company's service territory.

The Company's ability to obtain rate increases and to maintain current authorized rates of return depends in part upon regulatory discretion, and there can be no assurance that the Company will be able to obtain rate increases or rate supplements or earn currently authorized rates of return. Both Indiana and Ohio have passed laws allowing utilities to recover at least some of the cost of complying with federal mandates or other infrastructure replacement expenditures, and in Ohio other capital investments, outside of a base rate proceeding. However, these activities may have at least a short-term adverse impact on the Company's cash flow and financial condition.

In addition, failure to comply with new or existing laws and regulations may result in fines, penalties, or injunctive measures and may not be recoverable from customers and could result in a material adverse effect on the Company's financial condition and results of operations.

Utility Holdings’ energy delivery 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 injury to or 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’ power supply 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 Company participates in the MISO.

The Company is a member of the MISO, which serves the electric transmission needs of much of the Midcontinent region and maintains operational control over SIGECO’s electric transmission facilities, as well as that of other utilities in the region. As a result of such control, 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, which is currently under review based on a joint complaint filed under Section 206 against MISO and various MISO transmission owners, including SIGECO. The FERC has yet to rule on the case and the Company is currently unable to predict the outcome of the proceeding.

Also, the MISO allocates operating costs and the cost of multi-value projects throughout the region to its participating utilities such as SIGECO and such costs are significant. Adjustments to these operating costs, including adjustments that result from participants entering or leaving the MISO, could cause increases or decreases to customer bills. The Company timely recovers its portion of MISO operating expenses as tracked costs.

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 $7.5 million per year 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.

Volatility 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 volatility 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 increased bad debt expenses.

Increased conservation efforts and technology advances, which result in improved energy efficiency or the development of alternative energy sources, may result in reduced demand for the Company’s energy products and services.

The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may reduce the demand for energy products. Prices for natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, the Company's prices generally increase which may lead to customer conservation. State and/or federal regulation may require mandatory conservation measures, which would reduce the demand for energy products. In addition, the Company's customers, especially large commercial and industrial customers, may choose to employ various technological advances to develop alternative energy sources, such as the construction and development of wind power, solar

technology, or electric cogeneration facilities. Increased conservation efforts and the utilization of technological advances to increase energy efficiency or to develop alternate energy sources could lead to a reduction in demand for the Company’s energy products and services, which could have an adverse effect on its revenues and overall results of operations.

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.

Increased derivative regulation could impact results.

The Company uses commodity derivative instruments in conjunction with procurement activities. The Company may also periodically use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances.

Regulations related to the use of derivatives that became law in 2010 under the Dodd-Frank Wall Street Reform and Consumer Protection Act continue to evolve and their ultimate application remains uncertain. Depending on the continued evolution of the regulations adopted by the Commodity Futures Trading Commission (CFTC) and other agencies, the Company may be required to post additional collateral with dealer counterparties for commitments and interest rates, physical or financial commodity derivative transactions and report or otherwise disclose such activity to dealer counterparties or other agencies. The law provides for an exception from these clearing and cash collateral requirements for commercial end-users. Requirements to post collateral could limit cash for investment and for other corporate purposes or could increase debt levels and resulting interest expense. 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 regulations may also limit the pool of potential counterparties and/or the liquidity in the respective markets for such transactions.

Significant rule-making by numerous governmental agencies, particularly the CFTC, continues to evolve and has been subject to a number of extensions and delays. The Company continues to evaluate the impacts as these rulemakings and interpretations become available and whether these rulemakings and interpretations affirm that exemptions 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, corporate reputation, 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 sponsored 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, such as terrorist attacks, acts of war, and acts of God, may adversely affect the Company’s facilities and operations and corporate reputation.

Catastrophic events such as fires, earthquakes, explosions, floods, ice storms, tornados, terrorist acts, cyber-attacks, or similar occurrences could adversely affect the Company's facilities, operations, corporate reputation, financial condition and results of operations. Either a direct act against company-owned generating facilities or transmission and distribution infrastructure or an act against the infrastructure of neighboring utilities or interstate pipelines that are used by the Company to transport power and natural gas could result in the Company being unable to deliver natural gas or electricity for a prolonged period. Further, the Company relies on information technology networks and systems to operate its generating facilities, engage in asset management activities, and process, transmit and store electronic information. Security breaches of this information technology infrastructure could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information. In the event of a severe disruption resulting from such events, the Company has contingency plans and employs crisis management to respond and recover operations. Despite these measures, if such an attack or security breach were to occur, results of operations and financial condition could be materially adversely affected.

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 and diverse 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 infrastructure services activities, Vectren Infrastructure Services Corporation (VISCO), is wholly owned by Vectren and provides underground pipeline construction and repair to Utility Holdings' utility infrastructure. Risks specific to VISCO's strategies include, but are not limited to, success in bidding contracts; variations in the volume of contract work; unanticipated cost increases in completion of the contracted work; increases to funding requirements associated with multiemployer pension plans; the ability to attract and retain qualified employees; cancellation of projects by customers and/or reductions in the scope of the projects; ability to obtain materials and equipment required to perform services from suppliers and manufacturers.

Related to Vectren’s nonutility coal mining activities, Vectren Fuels, Inc. is wholly owned by Vectren and is a 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 for the contract operator to operate owned mines in accordance with MSHA guidelines and regulations, recent interpretations of those guidelines and regulations, and any new guidelines or regulations that could be implemented and to respond to more frequent and broader inspections, including increased levels of citations which may result in coal mining operations being classified as having a Pattern of Violation (POV) and resulting in a significant decrease in productivity and increased costs; failure to negotiate and execute new sales contracts; failure to adapt to any new laws or rules, such as climate change or air quality legislation, that impact users of coal; failure to manage coal mining production and production costs and other risks in response to changes in demand; changes in market demand for Vectren Fuels' coal including impacts of fuel switching to alternative sources and coal specifications in terms of sulfur and mercury, among others; geologic, equipment, and operations risks; supplier and contract miner performance; the availability of miners, key equipment and commodities; availability of transportation; the ability to access/replace coal reserves; significant variations in weather that could impact coal sales and production; 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 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Gas Utility Services

Indiana Gas owns and operates four active gas storage fields located in Indiana covering 58,100 acres of land with an estimated ready delivery from storage capability of 5.6 BCF of gas with maximum peak day delivery capabilities of 143,500 MCF per day. Indiana Gas also owns and operates three propane plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery 33,000 MCF of manufactured gas per day. In addition to its company owned storage and propane capabilities, Indiana Gas has contracted for 15.1 BCF of interstate natural gas pipeline storage service with a maximum peak day delivery capability of 229,200 MMBTU per day. Indiana Gas’ gas delivery system includes 13,100 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 for 0.4 BCF of interstate pipeline storage service with a maximum peak day delivery capability of 16,800 MMBTU per day. SIGECO's gas delivery system includes 3,200 miles of distribution and transmission mains, all of which are located in Indiana.

VEDO has 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 VEDO’s customers with natural gas, and those suppliers are responsible for the demand charges. VEDO’s 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, 2013, 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 1,022 circuit miles of 345Kv, 138Kv and 69Kv lines. The transmission system also includes 36 substations with an installed capacity of 4,833 megavolt amperes (Mva). The electric distribution system includes 4,339 pole miles of lower voltage overhead lines and 390 trench miles of conduit containing 2,042 miles of underground distribution cable. The distribution system also includes 95 distribution substations with an installed capacity of 2,986 Mva and 52,200 distribution transformers with an installed capacity of 2,318 Mva.

SIGECO owns utility property outside of Indiana approximating 24 miles of 138Kv and 345Kv electric transmission lines, which are included in the 1,022 circuit miles discussed above. These assets are located in Kentucky and interconnect with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky and with Big Rivers Electric Cooperative at Sebree, Kentucky.

Property Serving as Collateral

SIGECO's properties are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932, between SIGECO and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures.

ITEM 3. LEGAL PROCEEDINGS

The Company is party to various legal proceedings and audits and reviews by taxing authorities and other government agencies arising in the normal course of business. In the opinion of management, there are no legal proceedings or other regulatory reviews or audits pending against the Company that are likely to have a material adverse effect on its financial position, results of operations, or cash flows. See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated financial statements are included in “Item 8 Financial Statements and Supplementary Data.”

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

PART II

ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS,

AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Stock Market Price

All of the outstanding shares of Utility Holdings’ common stock are owned by Vectren. Utility Holdings’ common stock is not traded. There are no outstanding options or warrants to purchase Utility Holdings’ common equity or securities convertible into Utility Holdings’ common equity. Additionally, Utility Holdings has no plans to publicly offer its common equity securities.

Dividends Paid to Parent

In the first quarter of 2014, Utility Holdings paid a $27.1 million dividend to its parent company.

During 2013, Utility Holdings paid dividends of $26.3 million to its parent company in each quarter.

During 2012, Utility Holdings paid dividends of $25.0 million to its parent company in the first quarter and $25.5 million in each of the second through fourth quarters.

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.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data is derived from the Company’s audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K.



	Year Ended December 31,
(In millions)	2013		2012		2011		2010		2009
Operating Data:
Operating revenues	$	1,429.6	$	1,333.6	$	1,457.0	$	1,563.7	$	1,596.2
Operating income	281.6		286.8		281.8		277.0		238.0
Net income	141.8		138.0		122.9		123.9		107.4
Balance Sheet Data:
Total assets	$	4,140.8	$	4,046.8	$	3,974.5	$	3,924.5	$	3,823.1
Long-term debt - net of current maturities
& debt subject to tender	1,257.1		1,103.4		1,208.2		1,024.8		1,254.8
Common shareholder's equity	1,432.8		1,390.0		1,346.6		1,315.4		1,274.7

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND

FINANCIAL CONDITION

Utility Holdings generates revenue primarily from the delivery of natural gas and electric service to its customers. Utility Holdings’ primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. Utility Holdings segregates its utility operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment.

Vectren has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of Utility Holdings’ SEC filings.

The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto.

Executive Summary of Consolidated Results of Operations

During 2013, Utility Holdings earned $141.8 million, compared to $138.0 million in 2012 and $122.9 million in 2011. The improved results in 2013 are primarily related to increased electric utility earnings, driven by higher margin and reduced interest expense associated with recent refinancing activity. Increased earnings in 2012 compared to 2011 reflect, among other things, the impacts of new electric base rates implemented on May 3, 2011.

Gas utility services

The gas utility segment earned $55.7 million during the year ended December 31, 2013, compared to earnings of $60.0 million in 2012 and $52.5 million in 2011. Though customer margin increased in 2013 from customer growth and return earned on increased investment in infrastructure replacements, particularly in Ohio, increased operating costs more than offset those margin increases. The increased operating costs were primarily the result of the acceleration of maintenance projects that were completed in the current year. Though higher in 2013, the total Utility Holdings' operating costs are being managed to be generally flat to the original 2012 targeted level of approximately $280 million on an annual basis, over time. Depreciation expense also increased, reflecting the additions of plant in service. Interest expense was favorably impacted in 2013 and 2012 by financing transactions completed in 2013 and 2011. In 2011, earnings were unfavorably impacted by increased operating expenses associated with planned maintenance activities, environmental remediation efforts, and a brief work stoppage related to bargaining unit labor negotiations.

Electric utility services

The electric operations earned $75.8 million during 2013, compared to $68.0 million in 2012 and $65.0 million in 2011. Results improved in 2013 due primarily to higher wholesale margins, net of sharing with customers, increased return on transmission investments, and lower interest expense. Results in 2012 and 2011 were positively impacted by new electric base rates implemented on May 3, 2011.

Other utility operations

In 2013, earnings from other utility operations were $10.3 million, compared to $10.0 million in 2012 and $5.4 million in 2011. Differences in the Utility Group's effective tax rate among the periods presented resulted in the lower earnings in 2011. The higher income tax rate in 2011 was primarily driven by the revaluation of Utility Group deferred income taxes related to the fourth quarter 2011 sale of Vectren Source, a nonutility retail gas marketer, which resulted in a charge to Utility Group income taxes of approximately $2.8 million. Earnings from 2011 also includes a $1.4 million unfavorable tax adjustment.

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 VEDO are subject to regulation by the PUCO.

Over the last seven years, regulatory orders establishing new base rates have been received by each utility. SIGECO’s electric territory received an order in April 2011, effective May 2011, and its gas territory received an order in August 2007. Indiana Gas received its most recent base rate order in February 2008 and VEDO in January 2009 with implementation in February 2009. The orders authorize a return on equity ranging from 10.15 percent to 10.40 percent. The authorized returns reflect the impact of rate design strategies that have been authorized by these state commissions. Outside of a full base rate proceeding, these approaches mitigate to some extent the impacts on results from increased investments in government-mandated and other infrastructure replacement projects, operating costs that are volatile, and changing consumption patterns.

Rate Design Strategies

Sales of natural gas and electricity to residential and commercial customers are largely seasonal and are impacted by weather. Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed and the Company’s utilities have implemented conservation programs. In the Company’s two Indiana natural gas service territories, normal temperature adjustment (NTA) and decoupling 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 for its residential customers. This rate design, which was fully implemented in February 2010, mitigates approximately 90 percent of the Ohio service territory’s weather risk and risk of decreasing consumption specific to its small customer classes. In all natural gas service territories, commissions have authorized bare steel and cast iron replacement programs. SIGECO’s electric service territory currently recovers certain transmission investments outside of base rates. The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs provide for 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 actual experience, subject to caps that are 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 The New York Mercantile Exchange (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. Since April 2010, the Company has not been the supplier of natural gas in its Ohio territory.

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. The FAC earnings test had some impact on the Company’s 2012 operating results, as discussed below.

In Indiana, gas pipeline integrity management operating 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 typical base rate recovery. Certain operating costs, including depreciation, associated with regional electric transmission assets not in base rates are also recovered by mechanisms outside of typical base rate recovery. In Ohio, expenses such as uncollectible accounts expense, costs associated with exiting the merchant function, and costs associated with a distribution rider replacement program and other capital expenditures 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.

Beginning in 2011, state laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects, and in Ohio other capital investment projects, outside of a base rate proceeding.

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.

Operating Trends

Margin

Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas sold. Electric Utility margin is calculated as Electric utility revenues less Cost of fuel & purchased power. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel and purchased power costs can be volatile and are generally collected on a dollar-for-dollar basis from customers.

In addition, the Company separately reflects regulatory expense recovery mechanisms within Gas utility margin and Electric utility margin. These amounts represent dollar-for-dollar recovery of operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility. Following is a discussion and analysis of margin generated from regulated utility operations.

Gas Utility Margin (Gas utility revenues less Cost of gas sold)

Gas utility margin and throughput by customer type follows:



	Year Ended December 31,
(In millions)	2013		2012		2011
Gas utility revenues	$	810.0	$	738.1	$	819.1
Cost of gas sold	358.1		301.3		375.4
Total gas utility margin	$	451.9	$	436.8	$	443.7
Margin attributed to:
Residential & commercial customers	$	341.1	$	333.9	$	331.2
Industrial customers	58.0		55.2		54.0
Other	9.7		9.5		11.3
Regulatory expense recovery mechanisms	43.1		38.2		47.2
Total gas utility margin	$	451.9	$	436.8	$	443.7
Sold & transported volumes in MMDth attributed to:
Residential & commercial customers	111.9		90.2		99.9
Industrial customers	111.7		105.8		97.0
Total sold & transported volumes	223.6		196.0		196.9

Gas utility margins were $451.9 million for the year ended December 31, 2013, and compared to 2012, increased $15.1 million. Customer margin increased approximately $8.7 million in 2013 from customer growth and returns from infrastructure replacement programs, particularly in Ohio. With rate designs that substantially limit the impact of weather on margin, heating degree days that were 103 percent of normal in Ohio and 102 percent of normal in Indiana during 2013, compared to 88 percent of normal in Ohio and 79 percent of normal in Indiana in 2012, had an approximate $0.8 million favorable impact on small customer margin.

For the year ended December 31, 2012, gas utility margins decreased $6.9 million compared to 2011. Gas utility margin decreased $10.9 million due to the impact of low natural gas prices and mild weather on revenue taxes, late and reconnect fees, and volumetric pass through costs in 2012 compared to 2011. Returns generated on investments in infrastructure replacement in Ohio increased margins $2.9 million in 2012 compared to the prior year. Excluding the impact of regulatory initiatives and pass through costs, large customer margins in 2012 compared to the prior year increased $1.0 million on increasing volumes. Large customer volumes in 2012 compared to 2011 significantly increased due to natural gas transported to a natural gas fired power plant that was placed into service in the Vectren South service territory.

Electric Utility Margin (Electric utility revenues less Cost of fuel & purchased power)

Electric utility margin and volumes sold by customer type follows:



	Year Ended December 31,
(In millions)	2013		2012		2011
Electric utility revenues	$	619.3	$	594.9	$	635.9
Cost of fuel & purchased power	202.9		192.0		240.4
Total electric utility margin	$	416.4	$	402.9	$	395.5
Margin attributed to:
Residential & commercial customers	$	255.8	$	255.8	$	251.2
Industrial customers	108.7		108.5		105.3
Other	4.8		1.6		4.3
Regulatory expense recovery mechanisms	10.5		4.9		5.1
Subtotal: Retail	379.8		370.8		365.9
Wholesale margin	36.6		32.1		29.6
Total electric utility margin	$	416.4	$	402.9	$	395.5
Electric volumes sold in GWh attributed to:
Residential & commercial customers	2,722.1		2,731.7		2,827.2
Industrial customers	2,735.2		2,710.5		2,744.8
Municipals & other	21.8		22.6		22.8
Total retail & firm wholesale volumes sold	5,479.1		5,464.8		5,594.8

Retail

Electric retail utility margins were $379.8 million for the year ended December 31, 2013 and, compared to 2012, increased by $9.0 million. Electric results are not protected by weather normalizing mechanisms. Cooling degree days in 2013 were 103 percent of normal compared to 130 percent of normal in 2012, resulting in lower small customer margin of $1.2 million, largely offset by an increase in customers. Large customer margins for 2013 were relatively flat when compared to 2012. Other margin was higher in 2013 by $3.2 million, due in part to $2.6 million in refunds to customers during 2012 resulting from statutory net operating income limits. Margin from regulatory expense recovery mechanisms increased $5.6 million in 2013 compared to 2012, driven by a corresponding increase in operating expenses associated with the electric state-mandated conservation programs.

In 2012, electric retail utility margins were $370.8 million for the year compared to 2011, an increase of $4.9 million. The impact year over year of new retail base rates that were effective May 3, 2011 was an increase in margin in 2012 of approximately $10.0 million. Offsetting a portion of the increase was a decline in small customer usage that lowered margin by $2.6 million in 2012 as a result of energy conservation, net of an approved lost margin recovery mechanism. Weather also impacted margin and, compared to normal temperatures, increased results $2.7 million and $3.0 million, in 2012 and 2011, respectively. Due in part to the favorable weather in both periods, the Company provided refunds to customers in 2012 totaling $2.6 million pursuant to the statutory net operating income limits. Indiana regulation includes a statutory mechanism that can limit a utility's rolling twelve month net operating income to that authorized in its last general rate order, as adjusted for previous net operating income levels that were below authorized levels. Should weather or other factors continue to increase net operating income in future periods, the full benefit of those favorable impacts on the Company's electric utility may continue to be limited by the statutory earnings test. Finally, though volumes sold to large customers during 2012 decreased compared to the prior year, the impact on margin was small as certain large customers have rate structures that include both a daily peak usage component, as well as a volumetric component.

On December 3, 2013, SABIC Innovative Plastics (SABIC), a large industrial utility customer of the Company, announced its plans to build a cogeneration (cogen) facility to be operational in mid-2016, in order to generate power to meet a significant portion of its ongoing power needs. Electric service is currently provided to SABIC by the Company under a long-term contract that expires in 2016, which coincides with the expected completion of the new cogen facility. SABIC's historical peak electric usage has been 120 megawatts (MW). The cogen facility is expected to provide 80 MW of capacity. Therefore, the Company

will continue to provide all of SABIC's power requirements above the 80 MW capacity of the cogen, which is projected to be between 20 and 30 MW and slightly lower than their peak usage due to expected energy efficiency efforts. The Company also expects to provide back-up power, when required. While the full impact of the lost margin on earnings has not been determined, there should be no impact until mid-2016. The Company is evaluating approaches to mitigate the impact of any lost margin on its future financial results.

Margin from Wholesale Electric Activities

The Company earns 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 and also markets and sells its generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load. Further detail of MISO off-system margin and transmission system margin follows:



	Year Ended December 31,
(In millions)	2013		2012		2011
Transmission system margin	$	29.4	$	26.4	$	23.5
Off-system margin	7.2		5.7		6.1
Total wholesale margin	$	36.6	$	32.1	$	29.6

Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $29.4 million during 2013, compared to $26.4 million in 2012 and $23.5 million in 2011. Increases are primarily due to increased investment in qualifying projects. To date, the Company has invested $157.5 million in qualifying projects. The net plant balance for these projects totaled $146.8 million at December 31, 2013. These projects include an interstate 345 Kv transmission line that connects Vectren’s A.B. Brown Generating Station to a generating station in Indiana owned by Duke Energy to the north and to a generating station in Kentucky owned by Big Rivers Electric Corporation to the south; a substation; and another transmission line. Although currently being challenged as discussed below, once placed into service, these projects earn a FERC approved equity rate of return of 12.38 percent on the net plant balance, and operating expenses are also recovered. The 345 Kv project is the largest of these qualifying projects, with a cost of $106.6 million that earned the FERC approved equity rate of return, including while under construction. The last segment of that project was placed into service in December 2012.

For the year ended December 31, 2013, margin from off-system sales was $7.2 million, compared to $5.7 million in 2012 and $6.1 million in 2011. The base rate changes implemented in May 2011 require that wholesale margin from off-system sales earned above or below $7.5 million per year are shared equally with customers. Results for the periods presented reflect the impact of that sharing. Off-system sales were 514.4 GWh in 2013, compared to 336.7 GWh in 2012, and 586.7 GWh in 2011. The lower volumes sold in 2012 compared to 2013 and 2011 from the Company's primarily coal-fired generation result from increased sales of power in MISO from gas-fired electric generation due to lower natural gas prices and more wind generation.

Operating Expenses

Other Operating

For the year ended December 31, 2013, Other operating expenses were $333.4 million, and compared to 2012, increased $23.3 million. Excluding operating expenses recovered through margin, expenses increased $15.9 million, primarily associated with additional maintenance projects that were completed in the current year. Though higher in 2013, operating costs are being managed to be generally flat to the 2012 targeted levels of approximately $280 million on an annual basis, over time.

For the year ended December 31, 2012, Other operating expenses decreased $3.0 million compared to 2011. The decrease was primarily attributable to continuous improvement initiatives throughout the Utility Group, which were implemented to limit growth in operating expenses and provide sustainable savings.

Depreciation & Amortization

For the year ended December 31, 2013, Depreciation and amortization expense was $196.4 million, compared to $190.0 million in 2012 and $192.3 million in 2011. The periods presented reflect increased utility plant investments placed into service. However, in 2012 regulatory orders in Ohio allowing for deferral of depreciation on capital investments previously placed into service were received that more than offset the impact of utility plant increases.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $3.8 million in 2013 compared to 2012 and decreased $0.6 million in 2012 compared to 2011. The increase in 2013 was primarily due to higher revenue taxes associated with increased consumption and higher gas costs. The decrease in 2012 is primarily attributable to lower usage taxes associated with lower gas and fuel costs. These taxes are primarily revenue-related taxes and are offset dollar-for-dollar through lower gas utility revenues.

Other Income-Net

Other income-net reflects income of $10.5 million in 2013, compared to $8.0 million in 2012 and $4.3 million in 2011. Results include increased AFUDC of approximately $1.9 million in 2013 and $2.2 million in 2012. AFUDC reflects the impact of recent regulatory orders related to infrastructure replacement investments. In addition, results in 2013 and 2012 reflect increased returns on assets that fund benefit plans.

Interest Expense

For the year ended December 31, 2013, Interest expense was $65.0 million, compared to $71.5 million in 2012 and $80.3 million in 2011. The decreases are due to refinancing activity, yielding favorable interest rates. During 2013, the Company issued $385.9 million in utility related long-term debt with a weighted average interest rate of 3.59 percent and retired $337.9 million of long-term debt that matured or was called for early redemption with a weighted average interest rate of 5.58 percent. During 2012 and 2011, the Company issued $100.0 million and $150.0 million in utility related long-term debt with weighted average interest rates of 5.0 percent and 5.12 percent, respectively. Also during 2012 and 2011, the Company retired $96.0 million and $250.0 million of long-term debt that matured or was called for early redemption with weighted average interest rates of 5.95 percent and 6.63 percent, respectively.

Income Taxes

Utility Holdings' federal and state income taxes were $85.3 million in both 2013 and 2012, and $82.9 million in 2011. The effective tax rate in 2013 is slightly lower than 2012 due to tax credits associated with research and development expenditures. Changes in income taxes between 2012 and 2011 are driven by changes in pre-tax income. In addition, the effective income tax rate in 2011 was higher primarily due to the revaluation of Utility Group deferred income taxes from the fourth quarter sale of Vectren Source which resulted in a $2.8 million charge, and a $1.4 million unfavorable tax adjustment recognized earlier in 2011.

Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

The Company monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. The Company's natural gas utilities are currently engaged in replacement programs in both Indiana and Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. Laws in both Indiana and Ohio were passed that expand the ability of utilities to recover certain costs of federally mandated projects and other infrastructure improvement projects, outside of a base rate proceeding. Utilization of these recovery mechanisms is discussed below.

Ohio Recovery and Deferral Mechanisms

qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR. The order also established a prospective bill impact evaluation on the annual deferrals, limiting the deferrals at a level which would equal a change over the prior year rate of $1.00 per residential and small general service customer per month. To date, the Company has made capital investments under this rider totaling $109 million. During 2013, 2012, and 2011 gas operating revenues associated with the DRR were $9.8 million, $6.5 million, and $3.6 million, respectively. Other income associated with the debt-related post in service carrying costs totaled $2.0 million, $1.8 million, and $2.0 million for 2013, 2012, and 2011, respectively. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $9.3 million, $6.5 million, and $3.0 million at December 31, 2013, 2012, and 2011 respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order approved the Company's five-year capital expenditure plan for calendar years 2013 through 2017 totaling $187 million related to these infrastructure investments, along with savings credits associated with reduced operations and maintenance expenses for each mile of aging infrastructure replaced. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case.

In June 2011, Ohio House Bill 95 was signed into law. Outside of a base rate proceeding, this legislation permits a natural gas company to apply for recovery of much of its capital expenditure program. The legislation also allows for the deferral of costs, such as depreciation, property taxes, and debt-related post in service carrying costs. On December 12, 2012, the PUCO issued an order approving the Company's initial application using this law, reflecting its $23.5 million capital expenditure program covering the fifteen month period ending December 31, 2012. Such capital expenditures include infrastructure expansion and improvements not covered by the DRR as well as expenditures necessary to comply with PUCO rules, regulations, orders, and system expansion to some new customers. The order also established a prospective bill impact evaluation on the cumulative deferrals, limiting the total deferrals at a level which would equal $1.50 per residential and small general service customer per month. On December 4, 2013, the Company received an order granting the accounting authority described above on its capital expenditure program for the 2013 calendar year totaling $61.5 million. In addition, the order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. During 2013 and 2012, these approved capital expenditure programs under House Bill 95 generated Other income associated with the debt-related post in service carrying costs totaling $2.2 million and $0.9 million, respectively. Deferral of depreciation and property tax expenses related to these programs in 2013 and 2012 totaled $1.7 million and $0.6 million, respectively.

Based on the deferral of costs and continuing recognition of debt-related post in service carrying costs using the 2009 capital structure, regulatory assets associated with these Ohio infrastructure programs increased $6.7 million in 2013. Regulatory assets are expected to continue to increase in future periods as post in service carrying costs are recognized in the statement of income and operating costs are deferred. Historical relationships between rate base growth and depreciation expense and property taxes will also be impacted.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20 million annually at Vectren North and $3 million annually at Vectren South. The debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North. At December 31, 2013 and 2012, the Company has regulatory assets totaling $12.1 million and $8.5 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

In April 2013, Senate Bill 560 was signed into law. This legislation supplements Senate Bill 251 described above, which addressed federally-mandated investment, and provides for cost recovery outside of a base rate proceeding for projects that either improve electric and gas system reliability and safety or are economic development projects that provide rural areas with access to gas service. Provisions of the legislation require that, among other things, requests for recovery include a seven-year project plan. Once the plan is approved by the IURC, 80 percent of such costs are eligible for recovery using a periodic rate adjustment mechanism. Recoverable costs include a return on and of the investment, as well as property taxes and operating expenses. The remaining 20 percent of project costs are to be deferred for future recovery in the Company's next general rate case. The adjustment mechanism is capped at an annual increase in retail revenues of no more than two percent.

Pipeline Safety Law

On January 3, 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law. The Pipeline Safety Law, which reauthorizes federal pipeline safety programs through fiscal year 2015, provides for enhanced safety, reliability, and environmental protection in the transportation of energy products by pipeline. The law increases federal enforcement authority; grants the federal government expanded authority over pipeline safety; provides for new safety regulations and standards; and authorizes or requires the completion of several pipeline safety-related studies. The DOT is required to promulgate a number of new regulatory requirements over the next two years. Those regulations may eventually lead to further regulatory or statutory requirements.

While the Company continues to study the impact of the Pipeline Safety Law and potential new regulations associated with its implementation, it is expected that the law will result in further investment in pipeline inspections, and where necessary, additional investments in pipeline infrastructure and, therefore, result in both increased levels of operating expenses and capital expenditures associated with the Company's natural gas distribution businesses.

Requests for Recovery Under Indiana Regulatory Mechanisms

The Company filed in November 2013 for authority to recover appropriate costs related to its gas infrastructure replacement and improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. The combined Vectren South and Vectren North Indiana filing requests recovery of the capital expenditures associated with the infrastructure replacement and improvement plan pursuant to the legislation, estimated to be approximately $865 million combined over the seven year period beginning in 2014, along with approximately $13 million combined annual operating costs associated with pipeline safety rules. A hearing in this proceeding is scheduled for the second quarter of 2014, and an order is expected later in 2014.

Vectren South Electric Environmental Compliance Filing

On January 17, 2014, Vectren South filed a request with the IURC for approval of capital investments estimated to be between $70 million and $90 million on its coal-fired generation units to comply with new EPA mandates related to mercury and air toxin standards effective in 2016. Roughly half of the investment will be made to control mercury in both air and water emissions. The remaining investment will be made to address EPA concerns on alleged increases in sulfur trioxide emissions. Although the Company believes these investments are recoverable as a federally mandated investment under Senate Bill 251, the Company has requested deferred accounting treatment in lieu of timely recovery to avoid immediate customer impacts. The accounting treatment request seeks deferral of depreciation and property tax expense related to these investments, accrual of post in service carrying costs, and deferral of incremental operating expenses related to compliance with these standards. The company will file its case-in-chief testimony on March 14, 2014 and a hearing is scheduled for July 9, 2014.

Vectren South Electric Base Rate Filing

The IURC issued an order on April 27, 2011, providing for a revenue increase to recover costs associated with approximately $325 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses. The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent, and an overall rate of return of 7.29 percent. The new rates were effective May 3, 2011. The

IURC, in its order, provided for deferred accounting treatment related to the Company's investment in dense pack technology, of which approximately $28.7 million was spent as of December 31, 2013. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated and is discussed below.

Coal Procurement Procedures

Vectren South submitted a request for proposal (RFP) in April 2011 regarding coal purchases for a four year period beginning in 2012. After negotiations with bidders, Vectren South reached an agreement in principle for multi-year purchases with two suppliers, one of which is Vectren Fuels, Inc. Consistent with the IURC direction in the electric rate case, a sub docket proceeding was established to review the Company’s prospective coal procurement procedures, and the Company submitted evidence related to its 2011 RFP. In March 2012, the IURC issued its order in the sub docket which concluded that Vectren South’s 2011 RFP process resulted in the lowest fuel cost reasonably possible. In late 2012, Vectren South terminated its contract with one of the suppliers due to coal quality issues that were identified during test burns of the coal. In addition to coal purchased under these contracts, Vectren South also contracted with Vectren Fuels, Inc. in 2012 to purchase lower priced spot coal. This spot purchase, which was completed in 2012, was found to be reasonable in a recent fuel adjustment clause (FAC) order issued in July 2012. The IURC will continue to regularly monitor Vectren South’s procurement process in future fuel adjustment proceedings.

Delivery to Vectren's power plants of lower priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and will be recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total deferred balance as of December 31, 2013 was $42.4 million. Recovery of this deferred balance began in February 2014.

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 electric 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 were 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, and include some for 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.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. For the twelve months ended December 31, 2013, the Company recognized Electric revenue of $5.0 million associated with this approved lost margin recovery mechanism.

Vectren North Pipeline Safety Investigation

On April 11, 2012, the IURC's pipeline safety division filed a complaint against Vectren North alleging several violations of safety regulations pertaining to damage that occurred at a residence in Vectren North's service territory during a pipeline replacement project. The Company negotiated a settlement with the IURC's pipeline safety division, agreeing to a fine and several modifications to the Company's operating policies. The amount of the fine was not material to the Company's financial results. The IURC approved the settlement but modified certain terms of the settlement and added a requirement that Company employees conduct inspections of pipeline excavations. The Company sought and was granted a request for rehearing on the sole issue related to the requirement to use Company employees to inspect excavations. A settlement in the case was reached between the IURC's pipeline safety division and Vectren North that allowed Vectren North to continue to use its risk based approach to inspecting excavations and to allow the Company to continue using a mix of highly trained and qualified contractors and employees to perform inspections. On January 15, 2014, the IURC issued a Final Order in the case approving the settlement agreement, without modification.

Vectren North & Vectren South Gas Decoupling Extension Filing

On August 18, 2011, the IURC issued an order granting the extension of the current decoupling mechanism in place at both gas companies and recovery of new conservation program costs through December 2015.

FERC Return on Equity Complaint

On November 12, 2013, certain parties representing a group of industrial customers filed a joint complaint with the FERC under Section 206 of the Federal Power Act against MISO and various MISO transmission owners, including SIGECO. The joint parties seek to reduce the 12.38 percent return on equity used in the MISO transmission owners’ rates, including SIGECO’s formula transmission rates, to 9.15 percent, and to set a capital structure in which the equity component does not exceed 50 percent. In the event a refund is required upon resolution of the complaint, the parties are seeking a refund calculated as of the filing date of the complaint. The MISO transmission owners filed their response to the complaint on January 6, 2014, opposing any change to the return. In addition to the group response, the Company filed a supplemental response, stating that if FERC allows the complaint to go forward, the complaint should not be applied to the Company’s recently completed Gibson-Brown-Reid 345 Kv transmission line investment.

FERC has no deadline for action. This joint complaint is similar to a complaint against the New England Transmission Owners (NETO) filed in September 2011, which requested that the 11.14 percent incentive return granted on qualifying investments in NETO be lowered. In August 2013, a FERC administrative law judge recommended in that proceeding that the return be lowered to 9.7 percent, retroactive to the date of the complaint filing. The FERC has yet to rule on that case.

The Company is unable to predict the outcome of the proceeding. A 100 basis point change in the incentive rate of return would equate to approximately $0.8 million of net income on an annual basis.

Environmental Matters

The Company's 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 the storage, transportation, treatment, and disposal of hazardous substances and limit airborne emissions from electric generating facilities including particulate matter, sulfur dioxide (SO₂), nitrogen oxide (NOx), and mercury, among others. Environmental legislation/regulation 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.

With the trend toward stricter standards, greater regulation, and more extensive permit requirements, the Company's investment in compliant infrastructure, and the associated operating costs have increased and are expected to increase in the future. Similar to the costs associated with federal mandates in the Pipeline Safety Law, Indiana Senate Bill 251 is also applicable to

federal environmental mandates impacting Vectren South's electric operations. The Company continues to evaluate the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA’s response to the US Court of Appeals for the District of Columbia’s (the Court) remand of the Clean Air Interstate Rule (CAIR). CAIR was originally established in 2005 as 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. In an effort to address the Court’s finding that CAIR did not adequately ensure attainment of pollutants in certain downwind states due to unlimited trading of SO₂and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO₂and NOx emissions. However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision. A decision by the Supreme Court is expected in 2014. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Environmental Regulations").

Mercury and Air Toxics (MATS) Rule

On December 21, 2011, the EPA finalized the Utility MATS Rule. The MATS Rule sets emission limits for hazardous air pollutants for existing and new coal-fired power plants and identifies the following broad categories of hazardous air pollutants: mercury, non-mercury hazardous air pollutants (primarily arsenic, chromium, cobalt, and selenium), and acid gases (hydrogen cyanide, hydrogen chloride, and hydrogen fluoride). The rule imposes mercury emission limits for two sub-categories of coal, and proposed surrogate limits for non-mercury and acid gas hazardous air pollutants. The EPA did not grant blanket compliance extensions, but asserted that states have broad authority to grant one year extensions for individual electric generating units where potential reliability impacts have been demonstrated. Reductions are to be achieved within three years of publication of the final rule in the Federal register (April 2015). Initiatives to suspend CSAPR’s implementation by Congress also apply to the implementation of the MATS rule. Multiple judicial challenges were filed and briefing is proceeding. The EPA agreed to reconsider MATS requirements for new construction. Such requirements are more stringent than those for existing plants. Utilities planning new coal-fired generation had argued standards outlined in the MATS could not be attained even using the best available control technology. The EPA issued its revised emission limits for new construction in March 2013.

Notice of Violation for A.B. Brown Power Plant

The Company received a notice of violation (NOV) from the EPA in November 2011 pertaining to its A.B. Brown power plant. The NOV asserts that when the power plant was equipped with Selective Catalytic Reduction (SCR) systems, the correct permits were not obtained or the best available control technology to control incidental sulfuric acid mist was not installed. The Company is currently in discussions with the EPA to resolve this NOV.

Information Request

SIGECO and Alcoa Generating Corporation (AGC), a subsidiary of ALCOA, own a 300 MW Unit 4 at the Warrick Power Plant as tenants in common. AGC and SIGECO also share equally in the cost of operation and output of the unit. In January 2013, AGC received an information request from the EPA under Section 114 of the Clean Air Act for historical operational information on the Warrick Power Plant. In April 2013, ALCOA filed a timely response to the information request.

Water

Section 316(b) of the Clean Water Act requires that generating facilities use the “best technology available” to minimize adverse environmental impacts in a body of water. More specifically, Section 316(b) is concerned with impingement and entrainment of aquatic species in once-through cooling water intake structures used at electric generating facilities. In April 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 generating facilities. The regulation was remanded back to the EPA for further consideration. In March 2011, the EPA released its proposed Section 316(b) regulations. The EPA did not mandate the retrofitting of cooling towers in the proposed regulation, but if finalized, the regulation will leave it to each state to determine whether cooling towers should be required on a case by case basis. A final rule is expected in 2014. Depending on the final rule and on the Company’s facts and circumstances, capital investments could approximate $40 million if new infrastructure, such as new cooling water towers, is required. Costs for compliance with these final regulations should qualify as federally mandated regulatory requirements and be recoverable under Indiana Senate Bill 251 referenced above.

Under the Clean Water Act, EPA sets technology-based guidelines for water discharges from new and existing facilities. EPA is currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water discharge limits for the electric power industry. EPA is focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPA released proposed rules on April 19, 2013 and the Company is reviewing the proposal. At this time, it is not possible to estimate what potential costs may be required to meet these new water discharge limits, however costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Conclusions Regarding Environmental Regulations

To comply with Indiana’s implementation plan of the Clean Air Act, and other federal air quality standards, the Company obtained authority from the IURC to invest in clean coal technology. Using this authorization, the Company invested approximately $411 million starting in 2001 with the last equipment being placed into service on January 1, 2010. The pollution control equipment included SCR systems, fabric filters, and an SO₂ scrubber at its generating facility that is jointly owned with AGC (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. The unamortized portion of the $411 million clean coal technology investment was included in rate base for purposes of determining SIGECO’s new electric base rates approved in the latest base rate order obtained April 27, 2011. SIGECO’s coal-fired generating fleet is 100 percent scrubbed for SO₂ and 90 percent controlled for NOx.

Utilization of the Company’s NOx and SO₂ allowances can be impacted as regulations are revised and implemented. 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.

The Company continues to review the sufficiency of its existing pollution control equipment in relation to the requirements described in the MATS Rule, the recent renewal of water discharge permits, and the NOV discussed above. Some operational modifications to the control equipment are likely. The Company is continuing to evaluate potential technologies to address compliance and what the additional costs may be associated with these efforts. Currently, it is expected that the capital costs could be between $70 million and $90 million. Compliance is required by government regulation, and the Company believes that such additional costs, if incurred, should be recoverable under Senate Bill 251 referenced above. On January 17, 2014, the Company filed its request with the IURC seeking approval to upgrade its existing emissions control equipment to comply with the MATS Rule, take steps to address EPA's allegations in the NOV and comply with new mercury limits to the waste water discharge permits at the Culley and Brown generating stations. In that filing, the Company has proposed to defer recovery of the costs until 2020 in order to mitigate the impact on customer rates in the near term.

Coal Ash Waste Disposal & Ash Ponds

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

alternatives include regulating coal combustion by-products that are not being beneficially reused as hazardous waste. The EPA did not offer a preferred alternative, but took public comment on multiple alternative regulations. Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently the EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation.

At this time, the majority of the Company’s ash is being beneficially reused. However, the alternatives proposed would require modification to, or closure of, existing ash ponds. 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 only slightly or be impacted by as much as $5 million. Costs for compliance with these regulations should qualify as federally mandated regulatory requirements and be recoverable under Senate Bill 251 referenced above.

Climate Change

Legislative Actions & Other Climate Change Initiatives

In April 2007, the US Supreme Court determined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPA to determine whether GHG emissions from motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare. In April 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 2009, and is the first step toward the EPA regulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress.

The EPA has promulgated two GHG regulations that apply to the Company’s generating facilities. In 2009, the EPA finalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPA has also 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 GHG's a year to obtain a PSD permit for new construction or a significant modification of an existing facility. The EPA's PSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPA proposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under the Clean Air Act Section 111(b). On October 15, 2013, the US Supreme Court agreed to review a focused appeal on the issue of whether the GHG rule applicable to mobile sources triggered PSD permitting for all stationary sources such as Vectren's power plants. A decision is expected in 2014.

In July 2013, the President announced a Climate Action Plan, which calls on the EPA to re-propose and finalize the new source rule expeditiously, and by June 2014 propose, and by June 2015 finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren's power plants. States must have their implementation plans to the EPA no later than June 2016. The President's Climate Action Plan did not provide any detail as to actual emission targets or compliance requirements. The Company anticipates that these initial standards will focus on power plant efficiency and other coal fleet carbon intensity reduction measures. The Company believes that such additional costs, if necessary, should be recoverable under Indiana Senate Bill 251 referenced above.

Numerous competing federal 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 also slowed.

As a wholly owned subsidiary of Vectren, Utility Holdings is also committed to responsible environmental stewardship and conservation efforts and if a national climate change policy is implemented believes it should have the following elements:


•	An inclusive scope that involves all sectors of the economy and sources of greenhouse gases, and recognizes early actions and investments made to mitigate greenhouse gas emissions;


•	Provisions for enhanced use of renewable energy sources as a supplement to base load coal generation including effective energy conservation, demand side management, and generation efficiency measures;


•	Inclusion of incentives for investment in advanced clean coal technology and support for research and development; and


•	A strategy supporting alternative energy technologies and biofuels and continued increase in the domestic supply of natural gas to reduce dependence on foreign oil.

The Company emits greenhouse gases (GHG) primarily from its fossil fuel electric generation plants. The Company uses the 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. Based on data made available through the Electronic Greenhouse Gas Reporting Tool (e-GRRT) 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. Emissions from other Company operations, including those from its natural gas distribution operations and the greenhouse gas emissions the Company is required to report on behalf of its end use customers, are similarly available through the EPA’s e-GRRT.

Current Initiatives to Increase Conservation & Reduce Emissions

The Company is committed to a policy that reduces greenhouse gas emissions and conserves energy usage. Evidence of this commitment includes:


•	Focusing the Company’s mission statement and purpose on corporate sustainability and the need to help customers conserve and manage energy costs;


•	Building a renewable energy portfolio to complement base load coal-fired generation even though there are no mandated renewable energy portfolio standards;


•	Implementing conservation initiatives in the Company’s Indiana and Ohio gas utility service territories;


•	Implementing conservation and demand side management initiatives in the electric service territory;


•	Evaluating potential carbon requirements with regard to new generation, other fuel supply sources, and future environmental compliance plans; and


•	Reducing the Company’s carbon footprint by measures such as utilizing hybrid vehicles and optimizing generation efficiencies by utilizing dense pack technology.

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 GHG's 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. At this time and in the absence of final legislation or rulemaking, compliance costs and other effects associated with reductions in GHG emissions or obtaining renewable energy sources remain uncertain. The Company has gathered preliminary estimates of the costs to control GHG 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 GHG 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 GHG emissions or expenditures made to control emissions should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 referenced above.

Senate Bill 251 also established a voluntary clean energy portfolio standard that provides incentives to Indiana electricity suppliers participating in the program. The goal of the program is that by 2025, at least 10 percent of the total electricity obtained by the supplier to meet the energy needs of Indiana retail customers will be provided by clean energy sources, as defined. In advance of a federal portfolio standard and Senate Bill 251, 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 connected to the Company's distribution system. In 2008 and 2009, the Company executed long-term purchase power commitments for a total of 80 MW of wind energy. The Company currently has approximately 5 percent of its electricity being provided by clean energy sources due to the long-term wind contracts and landfill gas investment.

Manufactured Gas Plants

In the past, the Company operated facilities to manufacture natural gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under current 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.

In the Indiana Gas service territory, the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which the Company may have some remedial responsibility. A remedial investigation/feasibility study (RI/FS) was completed 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. The remaining sites have been submitted to the IDEM's Voluntary Remediation Program (VRP). The Company has identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.

The Company has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, the Company has recorded cumulative costs that it has incurred or reasonably expects to incur totaling approximately $43.4 million ($23.2 million at Indiana Gas and $20.2 million at SIGECO). The estimated accrued costs are limited to the Company’s share of the remediation efforts and are therefore net of exposures of other potentially responsible parties (PRP).

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. Likewise, SIGECO has settlement agreements with all known insurance carriers and has received to date approximately $14.3 million of the expected $15.8 million in insurance recoveries.

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 remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2013 and 2012, approximately $5.7 million and $4.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gas and SIGECO sites.

Impact of Recently Issued Accounting Guidance

Offsetting Assets and Liabilities

In January 2013, the FASB issued new accounting guidance on disclosures of offsetting assets and liabilities. This guidance amends prior requirements to add clarification to the scope of the offsetting disclosures. The amendment clarifies that the scope applies to derivative instruments accounted for in accordance with reporting topics on derivatives and hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with US GAAP or subject to an enforceable master netting arrangement or similar agreement. This guidance is effective for fiscal years beginning on or after January 1, 2013 and interim periods within annual periods. The Company adopted this guidance as of January 1, 2013. The adoption of this guidance did not have a material impact on the Company's financial statements.

Accumulated Other Comprehensive Income (AOCI)

effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

Unrecognized Tax Benefit Presentation

In July 2013, the FASB issued new accounting guidance on presenting an unrecognized tax benefit when net operating loss carryforwards exist. The new standard was issued in an effort to eliminate diversity in practice resulting from a lack of guidance on this topic in the current US GAAP. The update provides that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. This update is consistent with how the Company currently presents unrecognized tax benefits, therefore, adoption of this guidance resulted in no material impact on the Company's financial statements.

Critical Accounting Policies

Management is required to make judgments, assumptions, and estimates that affect the amounts reported in the consolidated financial statements and the related disclosures that conform to accounting principles generally accepted in the United States. The footnotes to the consolidated financial statements describe the significant accounting policies and methods used in their preparation. Certain estimates are subjective and use variables that require judgment. These include the estimates to perform goodwill and other asset impairments tests and to allocate Vectren's support services, assets, and its pension and postretirement benefit obligations. The Company makes other estimates related to 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, and estimating uncollectible accounts, unbilled revenues, and deferred income taxes, 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 to be the level at which impairment is tested as its components are similar. An impairment test requires fair value be estimated. The Company used a discounted cash flow model and other market based information to estimate the fair value of its Gas Utility Services operating segment, and that estimated fair value was compared to its carrying amount, including goodwill. The estimated fair value has been substantially in excess of the carrying amount in each of the last three years and therefore resulted in no impairment.

Estimating fair value using a discounted cash flow model is subjective and requires significant judgment in applying a discount rate, growth assumptions, company expense allocations, and longevity of cash flows. A 100 basis point increase in the discount rate utilized to calculate the Gas Utility Services segment’s fair value also would have resulted in no impairment charge.

Intercompany Allocations

Support Services

Vectren provides corporate, general, and administrative services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers, and/or the level of payroll, revenue contribution, and capital expenditures. Allocations are at cost. Management believes that the allocation methodology is reasonable and approximates the costs that would have been incurred had the Company secured those services on a stand-alone basis. The allocation methodology is not subject to near term changes.

Pension and Other Postretirement Obligations

Vectren satisfies the future funding requirements of its pension and other postretirement plans and the payment of benefits from general corporate assets 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 periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries. Periodic cost, comprised of service cost and interest on that service cost, is directly charged to Utility Holdings based on labor at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method. Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren Corporate operations are charged to subsidiaries through the allocation process discussed above. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs. 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 2013 periodic benefit cost: a discount rate of approximately 4.00 percent, an expected return on plan assets of 7.75 percent, a rate of compensation increase of 3.50 percent, and an inflation assumption of 2.75 percent. Due to low interest rates, the discount rate is 80 basis points lower from the assumption used in 2012. To estimate 2014 costs, the discount rate, expected return on plan assets, rate of compensation increase, and inflation assumption were approximately 4.74 percent, 7.75 percent, 3.50 percent, and 2.75 percent respectively, reflecting an increase in interest rates. Vectren’s management currently estimates a pension and postretirement cost of approximately $6 million in 2014, compared to approximately $14 million in 2013, $12 million in 2012, and $13 million in 2011. 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 increase in the discount rate used to estimate retirement costs generally decreases periodic benefit cost by approximately $2.0 million.

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 its utility subsidiary operations. Vectren does not guarantee Utility Holdings’ debt. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors. Information about the subsidiary guarantors as a group is included in Note 14 to the consolidated financial statements. Utility Holdings’ long-term debt and short-term obligations outstanding at December 31, 2013 approximated $875 million and $29 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. Total Indiana Gas and SIGECO long-term debt, including current maturities, outstanding at December 31, 2013 was $382.5 million.

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, 2013, 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. On January 30, 2014, Moody's upgraded the senior unsecured credit ratings or Utility Holdings and Indiana Gas to A2 from A3. In addition, Utility Holdings' commercial paper was upgraded to P-1 from P-2, and SIGECO's senior secured debt was upgraded to Aa3 from 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 50-60 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 53 percent of long-term capitalization at both December 31, 2013 and 2012, respectively. Long-term capitalization includes long-term debt, including current maturities, 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, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2013, the Company was in compliance with all debt covenants.

Available Liquidity in Current Credit Conditions

The Company’s A-/A2 investment grade credit ratings have allowed it to access the capital markets as needed, and the Company believes it will have the ability to continue to do so. Given the Company's intent to maintain a balanced long-term capitalization ratio, it anticipates funding future capital expenditures and dividends principally through internally generated funds, which have been enhanced by bonus depreciation legislation, and refinancing maturing debt using the capital markets. However, the resources required for capital investment remain uncertain for a variety of factors including pending legislative and regulatory initiatives involving gas pipeline infrastructure replacement; and expanded EPA regulations for air, water, and fly ash. These regulations may result in the need to raise additional capital in the coming years. The timing and amount of such investments depends on a variety of factors, including available liquidity. Specifically for 2013, the Company has accessed the capital markets to refinance debt maturities or debt that is callable.

Long-term debt transactions completed in 2013, 2012, and 2011 include issuances by Utility Holdings totaling $525 million and issuances by SIGECO totaling $111 million. These transactions are more fully described below (see Financing Cash Flow).

Consolidated Short-Term Borrowing Arrangements

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.



(In millions)	2013			2012			2011
Year End
Balance Outstanding	$	28.6		$	116.7		$	242.8
Weighted Average Interest Rate	0.29		%	0.40		%	0.57		%
Annual Average
Balance Outstanding	$	119.6		$	77.6		$	39.6
Weighted Average Interest Rate	0.34		%	0.47		%	0.48		%
Maximum Month End Balance Outstanding	$	176.1		$	214.2		$	242.8

Throughout 2013, 2012, and 2011, the Company placed commercial paper without any significant issues and did not borrow from its backup credit facility in any of these periods.

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 in 2013 and 2012 contributed to Utility Holdings added additional liquidity of $6.1 million and $7.0 million, respectively. There were no new issuances contributed to Utility Holdings in 2011.

Potential Uses of Liquidity

Planned Capital Expenditures

During 2013, capital expenditures approximated $260 million, compared to $250 million in 2012 and $230 million in 2011. Planned capital expenditures, including contractual purchase commitments, for the five-year period 2014 – 2018 are expected to total approximately (in millions): $365, $365, $355, $345, and $355, respectively. This plan contains the best estimate of the resources required for known regulatory compliance; however, many environmental and pipeline safety standards are subject to change in the near term. Such changes could materially impact planned capital expenditures.

Pension and Postretirement Funding Obligations

As of December 31, 2013, Vectren’s assets related to its qualified pension plans were approximately 101 percent of the projected benefit obligation on a GAAP basis and 112 percent of the target liability for ERISA purposes. Vectren’s management currently anticipates making no contributions to qualified pension plans in 2014, due to the plans being at or above 100 percent funded levels. As such, Utility Holdings will make no funding contribution to Vectren in 2014.

Contractual Obligations

The following is a summary of contractual obligations at December 31, 2013:



	Total		2014		2015		2016		2017		2018		Thereafter
Long-term debt	$	1,257.1	$	—	$	104.8	$	13.0	$	—	$	100.0	$	1,039.3
Short-term debt	28.6		28.6		—		—		—		—		—
Long-term debt interest commitments	905.1		62.7		62.1		56.6		56.1		53.7		613.9
Plant purchase commitments	0.5		0.5		—		—		—		—		—
Operating leases	2.0		0.8		0.4		0.3		0.3		0.2		—
Total ⁽¹⁾	$	2,193.3	$	92.6	$	167.3	$	69.9	$	56.4	$	153.9	$	1,653.2

(1)

The Company has other long-term liabilities that total approximately $84 million. This amount is comprised of the following: allocated portions of Vectren's deferred compensation and share-based compensation $30 million, asset retirement obligations $29 million, allocated portions of Vectren's postretirement obligations totaling $11 million, investment tax credits $3 million, environmental remediation $6 million, and other obligations including unrecognized tax benefits totaling $5 million. Based on the nature of these items their expected settlement dates cannot be estimated.

The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, coal, and electricity as well as certain transportation and storage rights. Costs arising from these commitments, while significant, are pass-through costs,

generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. Because of the pass through nature of these costs, they have not been included in the listing of contractual obligations.

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 $399.9 million in 2013, compared to $373.4 million in 2012 and $334.3 million in 2011. The $26.5 million increase in operating cash flow in 2013 compared to 2012 is primarily due to increased cash flow from working capital and a change in noncurrent assets. The change in noncurrent assets was primarily driven by a deferral in 2012 for future rate recovery of certain coal costs pursuant to a regulatory order. Partially offsetting this change was a lower operating cash flow from the change in deferred taxes.

The $39.1 million increase in operating cash flow in 2012 compared to 2011 is primarily due to increased earnings, increased cash flow from working capital, and reduced cash needs for contributions to Vectren's pension plan in 2012 compared to 2011.

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 allowing bonus depreciation on qualifying capital expenditures was increased to 100 percent for 2011, 50 percent for 2012, and continued at 50 percent for 2013. A significant portion of the Company’s capital expenditures qualify for this bonus treatment.

Financing Cash Flow

Net cash flow required for financing activities was $142.9 million, $121.1 million, and $95.0 million during the years ending December 31, 2013, 2012, and 2011, respectively. Financing activity reflects the Company’s utilization of the long-term capital markets in the current low interest rate environment. Since 2011, the Company has refinanced at lower rates approximately $684 million of maturing or callable long-term debt. These lower rates began to favorably impact interest expense in the fourth quarter of 2011, and more noticeably decreased interest expense in 2012 and 2013. The Company’s operating cash flow funded 100 percent of capital expenditures and dividends in 2013, 2012, and 2011. Recently completed long-term financing transactions are more fully described below.

SIGECO 2013 Debt Refund and Reissuance

During the second quarter of 2013, approximately $111 million of SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest. Approximately $62 million of tax-exempt long-term debt was reissued on April 26, 2013 at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million. The terms are $22.2 million at 4.00 percent per annum due in 2038, and $39.6 million at 4.05 percent per annum due in 2043.

The remaining approximately $49 million of the called debt was remarketed on August 13, 2013. The remarketed tax-exempt debt has a fixed interest rate of 1.95 percent per annum until September 13, 2017. SIGECO closed on this remarketing and received net proceeds of $48.3 million on August 28, 2013.

Utility Holdings 2013 Debt Call and Reissuance

On April 1, 2013, VUHI exercised a call option at par on $121.6 million 6.25 percent senior unsecured notes due in 2039. This debt was refinanced on June 5, 2013, with proceeds from a private placement note purchase agreement entered into on December 20, 2012 with a delayed draw feature. It provides for the following tranches of notes: (i) $45 million, 3.20 percent senior guaranteed notes, due June 5, 2028 and (ii) $80 million, 4.25 percent senior guaranteed notes, due June 5, 2043. Total proceeds received from these notes, net of issuance costs, were $44.8 million and $79.6 million, respectively. The notes are unconditionally guaranteed by Indiana Gas, SIGECO and VEDO.

On August 22, 2013, VUHI entered into a private placement note purchase agreement with a delayed draw feature, pursuant to which institutional investors agreed to purchase $150 million of senior guaranteed notes with a fixed interest rate of 3.72 percent per annum, due December 5, 2023. The notes were unconditionally guaranteed by Indiana Gas, SIGECO, and VEDO. On December 5, 2013, the Company received net proceeds of $149.1 million from the issuance of the senior guaranteed notes,

which were used to refinance $100 million of 5.25 percent senior notes that matured August 1, 2013, for capital expenditures, and for general corporate purposes.

Utility Holdings 2012 Debt Transactions

On February 1, 2012, Utility Holdings issued $100 million of senior unsecured notes at an interest rate of 5.00 percent per annum and with a maturity date of February 3, 2042. The notes were sold to various institutional investors pursuant to a private placement note purchase agreement executed in November 2011 with a delayed draw feature. These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO. The proceeds from the sale of the notes, net of issuance costs, totaled approximately $99.5 million. These notes have no sinking fund requirements and interest payments are due semi-annually. These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.

Utility Holdings 2011 Debt Issuance

On November 21, 2011, the Company exercised a call option on $96.2 million 5.95 percent senior notes due in 2036. This debt was refinanced on November 30, 2011. On that date, Utility Holdings closed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes: (i) $55 million of 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 million of 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 million of 5.99 percent Senior Guaranteed Notes, due December 2, 2041. These senior notes are unsecured and jointly and severally guaranteed by Utility Holdings’ regulated utility subsidiaries, SIGECO, Indiana Gas, and VEDO. The proceeds from the sale of the notes, net of issuance costs, totaled approximately $149 million. These notes have no sinking fund requirements and interest payments are due semi-annually. These notes contain customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Utility Holdings’ borrowing arrangements.

Long-Term Debt Puts, Calls, and Mandatory Tenders

Certain long-term debt issues contain optional put and call provisions that can be exercised on various dates before maturity. During 2013, the Company had no repayments related to investor put provisions and at December 31, 2013, the only debt with investor puts were two series of SIGECO variable rate demand bonds, aggregating $41.3 million, with a variable interest rate that is reset weekly. This SIGECO debt is fully supported by letters of credit that are available should any of the debt holders decide to put the debt to SIGECO and the remarketing agent is unable to remarket it to other investors.

Certain other series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017.

In April and May, 2013, the Company exercised call options on six issues of SIGECO's tax exempt long-term debt totaling $110.9 million with interest rates ranging from 4.50 percent to 5.45 percent, and with maturity dates from 2020 to 2041.

Investing Cash Flow

Cash flow required for investing activities was $261.7 million in 2013, $245.0 million in 2012, and $235.7 million in 2011. Capital expenditures are the primary component of investing activities and totaled $262.5 million in 2013, compared to $247.6 million in 2012 and $235.3 million in 2011. The primary use of cash in both years reflect expenditures for utility plant. Increased capital expenditures in 2013 compared to 2012 primarily related to increased expenditures for bare steel/cast iron replacement and regional electric transmission 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 coal and natural gas 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, tornadoes, terrorist acts, cyber attacks, 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, unbundling, and other sources of energy.


•	Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases.

•

Financial, regulatory or accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight.


•	Economic conditions including the effects of inflation rates, commodity prices, and monetary fluctuations.

•

Economic conditions surrounding the current economic uncertainty, including increased potential for 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.


•	Risks associated with material business transactions such as mergers, acquisitions and divestitures, including, without limitation, legal and regulatory delays; the related time and costs of implementing such transactions; integrating operations as part of these transactions; and possible failures to achieve expected gains, revenue growth and/or expense savings from such transactions.


•	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, pipeline safety regulations, 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 realize value from, invest in and develop new opportunities, including but not limited to, Vectren's infrastructure services, energy services, and coal mining, and remaining energy marketing assets.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements.

ITEM 7A. QUANTITATIVE & QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company’s risk management program includes, among other things, the use of derivatives. The Company executes derivative contracts in the normal course of operations while buying and selling commodities and occasionally when managing interest rate risk.

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 and coal prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered. Vectren North and Vectren South hedge up to 60 percent of annual purchases for each Company via the use of physical fixed-price purchases and financial products, including call options. Such contracts are generally short term in nature and are insignificant in terms of value and volume at December 31, 2013. However, it is possible that the utilization of these instruments may grow in the future.

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 generation into the MISO Day Ahead and Real-time markets. The Company accounts for any energy contracts that are derivatives at fair value with the offset marked to market through earnings. No derivative positions were outstanding on December 31, 2013 and 2012.

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.

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 further manage this exposure, the Company may also 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 2013 and 2012, the weighted average combined borrowings under these arrangements approximated $161 million and $119 million, respectively. At December 31, 2013, combined borrowings under these arrangements were $69 million. As of December 31, 2012, combined borrowings under these

arrangements were $158 million. Based upon average borrowing rates under these facilities during the years ended December 31, 2013 and 2012, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $1.6 million and $1.2 million, respectively.

Other Risks

By using financial instruments to manage risk, the Company creates exposure to counter-party credit risk and market risk. The Company manages exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract. Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk. Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk. Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices or interest rates. The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by establishing parameters and monitoring those parameters that limit the types and degree of market risk that may be undertaken.

The Company’s customer receivables from gas and electric sales and gas transportation services are primarily derived from residential, commercial, and industrial customers located in Indiana and west central Ohio. The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits or refunds cash deposits based on that review. Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral. In addition, credit risk is mitigated by regulatory orders that allow recovery of all uncollectible accounts expense in Ohio and the gas cost portion of uncollectible accounts expense in Indiana based on historical experience.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS

Vectren Utility Holdings, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Those control procedures underlie the preparation of the consolidated balance sheets, statements of income, cash flows, and common shareholder’s equity, and related footnotes contained herein.

These consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of these consolidated financial statements, including required estimates and judgments, is the responsibility of management.

These consolidated financial statements are also subject to an evaluation of internal control over financial reporting conducted under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, conducted under the framework in Internal Control — Integrated Framework (1992) 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, 2013. Management certified this in its Sarbanes Oxley Section 302 certifications, which are attached as exhibits to this 2013 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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana

March 5, 2014

VECTREN UTILITY HOLDINGS. INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(In millions)



	At December 31,
	2013		2012
ASSETS
Current Assets
Cash & cash equivalents	$	8.6	$	13.3
Accounts receivable - less reserves of $5.0 & $5.0, respectively	112.1		81.8
Accrued unbilled revenues	113.5		93.6
Inventories	89.9		114.0
Recoverable fuel & natural gas costs	5.5		25.3
Prepayments & other current assets	42.4		52.3
Total current assets	372.0		380.3
Utility Plant
Original cost	5,389.6		5,176.8
Less: accumulated depreciation & amortization	2,165.3		2,057.2
Net utility plant	3,224.3		3,119.6
Investments in unconsolidated affiliates	0.2		0.2
Other investments	27.3		32.6
Nonutility plant - net	150.5		146.9
Goodwill - net	205.0		205.0
Regulatory assets	136.2		126.5
Other assets	25.3		35.7
TOTAL ASSETS	$	4,140.8	$	4,046.8

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,
	2013		2012
LIABILITIES & SHAREHOLDER'S EQUITY
Current Liabilities
Accounts payable	$	172.1	$	121.0
Accounts payable to affiliated companies	—		29.7
Payables to other Vectren companies	24.6		25.1
Accrued liabilities	127.4		139.3
Short-term borrowings	28.6		116.7
Current maturities of long-term debt	—		105.0
Total current liabilities	352.7		536.8
Long-Term Debt - Net of Current Maturities	1,257.1		1,103.4

Deferred Income Taxes & Other Liabilities
Deferred income taxes	627.4		578.5
Regulatory liabilities	387.3		364.2
Deferred credits & other liabilities	83.5		73.9
Total deferred credits & other liabilities	1,098.2		1,016.6
Commitments & Contingencies (Notes 8-10)
Common Shareholder's Equity
Common stock (no par value)	787.7		781.6
Retained earnings	645.1		608.4
Total common shareholder's equity	1,432.8		1,390.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	4,140.8	$	4,046.8

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,
	2013		2012		2011
OPERATING REVENUES
Gas utility	$	810.0	$	738.1	$	819.1
Electric utility	619.3		594.9		635.9
Other	0.3		0.6		2.0
Total operating revenues	1,429.6		1,333.6		1,457.0
OPERATING EXPENSES
Cost of gas sold	358.1		301.3		375.4
Cost of fuel & purchased power	202.9		192.0		240.4
Other operating	333.4		310.1		313.1
Depreciation & amortization	196.4		190.0		192.3
Taxes other than income taxes	57.2		53.4		54.0
Total operating expenses	1,148.0		1,046.8		1,175.2
OPERATING INCOME	281.6		286.8		281.8
Other income - net	10.5		8.0		4.3
Interest expense	65.0		71.5		80.3
INCOME BEFORE INCOME TAXES	227.1		223.3		205.8
Income taxes	85.3		85.3		82.9
NET INCOME	$	141.8	$	138.0	$	122.9

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,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	141.8		$	138.0		$	122.9
Adjustments to reconcile net income to cash from operating activities:
Depreciation & amortization	196.4			190.0			192.3
Deferred income taxes & investment tax credits	26.4			72.3			64.6
Expense portion of pension & postretirement periodic benefit cost	5.6			5.0			4.6
Provision for uncollectible accounts	6.5			7.4			11.4
Other non-cash expense	2.5			5.6			11.0
Changes in working capital accounts:
Accounts receivable, including to Vectren companies
& accrued unbilled revenue	(56.8		)	3.7			36.7
Inventories	24.1			18.5			(15.0		)
Recoverable/refundable fuel & natural gas costs	22.4			(12.9		)	(4.5		)
Prepayments & other current assets	15.5			2.6			28.2
Accounts payable, including to Vectren companies
& affiliated companies	10.1			(7.4		)	(50.3		)
Accrued liabilities	4.9			(1.6		)	(14.8		)
Changes in noncurrent assets	11.4			(33.2		)	(46.5		)
Changes in noncurrent liabilities	(10.9		)	(14.6		)	(6.3		)
Net cash flows from operating activities	399.9			373.4			334.3
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Long-term debt - net of issuance costs	381.7			99.5			148.9
Additional capital contribution	6.1			7.0			—
Requirements for:
Dividends to parent	(105.1		)	(101.5		)	(91.6		)
Retirement of long-term debt	(337.5		)	—			(347.0		)
Other financing activities	—			—			(1.1		)
Net change in short-term borrowings	(88.1		)	(126.1		)	195.8
Net cash flows from financing activities	(142.9		)	(121.1		)	(95.0		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from other investing activities	0.8			2.6			0.4
Requirements for:
Capital expenditures, excluding AFUDC equity	(262.5		)	(247.6		)	(235.3		)
Other investments	—			—			(0.8		)
Net cash flows from investing activities	(261.7		)	(245.0		)	(235.7		)
Net change in cash & cash equivalents	(4.7		)	7.3			3.6
Cash & cash equivalents at beginning of period	13.3			6.0			2.4
Cash & cash equivalents at end of period	$	8.6		$	13.3		$	6.0

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)



	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income			Total
Balance at January 1, 2011	$	774.6	$	540.7		$	0.1		$	1,315.4
Net income			122.9						122.9
Other comprehensive income						(0.1		)	(0.1		)
Common stock:
Dividends			(91.6		)				(91.6		)
Balance at December 31, 2011	774.6		572.0			—			1,346.6
Net income			138.0						138.0
Common stock:
Additional capital contribution	7.0								7.0
Dividends			(101.5		)				(101.5		)
Other			(0.1		)				(0.1		)
Balance at December 31, 2012	781.6		608.4			—			1,390.0
Net income			141.8						141.8
Common stock:
Additional capital contribution	6.1								6.1
Dividends			(105.1		)				(105.1		)
Balance at December 31, 2013	$	787.7	$	645.1		$	—		$	1,432.8

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, Utility Holdings or VUHI), 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 Vectren Energy Delivery of Ohio, Inc. (VEDO). 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).

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 – net in the Consolidated Statements of Income.

When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, resulting in no gain or loss. Costs to dismantle and remove retired property are recovered through the depreciation rates as determined by the IURC and PUCO.

The Company’s portion of jointly-owned Utility Plant, along with that plant’s related operating expenses, is presented in these financial statements in proportion to the ownership percentage.

Nonutility Plant & Related Depreciation

The depreciation of Nonutility Plant is charged against income over its estimated useful life, using the straight-line method of depreciation. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.

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. There were no impairments related to property, plant and equipment during the periods presented.

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 an operating segment level because the components within the segments are similar. These tests are performed at least annually and that test is performed at the beginning of each year. Impairment reviews consist of a comparison of fair value to the carrying amount. If the fair value is less than the 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, and wind farm and other electric generating 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 in Accrued Unbilled Revenues.

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 Midcontinent region and maintains operational control over the Company’s electric transmission facilities as well as that of other utilities in the region. The Company is 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 $29.6 million in 2013, $26.9 million in 2012, and $29.0 million in 2011. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.

Operating Segments

The Company's chief operating decision maker is the Chief Executive Officer. The Company uses net income calculated in accordance with generally accepted accounting principles as its most relevant performance measure. 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.

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 retirement plans and other postretirement benefits, 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)	2013				2012
	Original Cost		Depreciation Rates as a Percent of Original Cost		Original Cost		Depreciation Rates as a Percent of Original Cost
Gas utility plant	$	2,762.2	3.5	%	$	2,614.3	3.5	%
Electric utility plant	2,519.8		3.3	%	2,463.6		3.3	%
Common utility plant	53.4		3.0	%	52.0		3.0	%
Construction work in progress	54.2		—		46.9		—
Total original cost	$	5,389.6			$	5,176.8

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, 2013, is $186.3 million with accumulated depreciation totaling $84.4 million. AGC and SIGECO also share equally in the cost of operation and output of the unit. SIGECO's share of operating costs is included in Other operating expenses in the Consolidated Statements of Income.

Nonutility plant, net of accumulated depreciation and amortization follows:



	At December 31,
(In millions)	2013		2012
Computer hardware & software	$	102.3	$	96.6
Land & buildings	38.3		38.6
All other	9.9		11.7
Nonutility plant - net	$	150.5	$	146.9

Nonutility plant is presented net of accumulated depreciation and amortization totaling $209.2 million and $201.5 million as of December 31, 2013 and 2012, respectively. For the years ended December 31, 2013, 2012, and 2011, the Company capitalized interest totaling $0.4 million, $0.2 million, and $0.3 million, respectively, on nonutility plant construction projects.

4. Regulatory Assets & Liabilities

Regulatory Assets

Regulatory assets consist of the following:



	At December 31,
(In millions)	2013			2012
Future amounts recoverable from ratepayers related to:
Deferred income taxes (See Note 5) - net	$	(5.8	)	$	(3.9	)
Asset retirement obligations & other	2.3			2.6
	(3.5		)	(1.3		)
Amounts deferred for future recovery related to:
Deferred coal costs (See Note 9)	42.4			42.4
Cost recovery riders & other	18.6			10.2
	61.0			52.6
Amounts currently recovered in customer rates related to:
Unamortized debt issue costs & hedging proceeds	34.6			32.6
Demand side management programs	2.5			4.4
Indiana authorized trackers	30.8			32.1
Ohio authorized trackers	7.9			1.5
Premiums paid to reacquire debt	2.2			2.7
Other base rate recoveries	0.7			1.9
	78.7			75.2
Total regulatory assets	$	136.2		$	126.5

Of the $78.7 million currently being recovered in customer rates, $2.5 million that is associated with demand side management programs is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $40 million, is 23 years. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. 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, 2013 and 2012, the Company has approximately $387.3 million and $364.2 million, respectively, in Regulatory liabilities. Of these amounts, $373.0 million and $349.5 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 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 purchased for the years ended December 31, 2013, 2012 and 2011, totaled $103.7 million, $115.6 million, and $144.1 million, respectively. Amounts owed to Vectren Fuels at December 31, 2013 and 2012 are included in Payables to other Vectren companies.

Vectren Infrastructure Services Corporation (VISCO)

VISCO, 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. In addition, VISCO also provides transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing to customers generally in the northern Midwest region. VISCO’s customers include Utility Holdings’ utilities. Fees incurred by Utility Holdings and its subsidiaries totaled $54.2 million in 2013, $46.6 million in 2012, and $43.1 million in 2011. Amounts owed to VISCO at December 31, 2013 and 2012 are included in Payables to other Vectren companies.

ProLiance Holdings, LLC (ProLiance)

Vectren has an investment in ProLiance, a nonutility affiliate of Vectren and Citizens Energy Group (Citizens). On June 18, 2013, ProLiance exited the natural gas marketing business through the disposition of certain of the net assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy). ProLiance Energy provided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance Energy's customers included, among others, Vectren's Indiana utilities as well as Citizens’ utilities.

Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2013, 2012 and 2011 totaled $200.5 million, $274.5 million, and $375.7 million, respectively. The Company did not have any amounts owed to ProLiance for purchases at December 31, 2013, and amounts owed to ProLiance at December 31, 2012 were $29.7 million and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. The Company purchased approximately 52 percent of its gas through ProLiance in 2013, and 97 percent in 2012 and 2011. Amounts charged by ProLiance for gas supply services were established by supply agreements with each utility. After the exit of the energy marketing business by ProLiance, the Company purchases gas supply from third parties and 91 percent is from a single third party.

Vectren Source

Vectren Source, a former wholly owned and nonutility subsidiary of Vectren that was sold on December 31, 2011, provided natural gas and other related products and services in the Midwest and Northeast United States to approximately 283,000 residential and commercial customers as of the date of sale. This customer base reflected approximately 143,000 customers in VEDO’s service territory that had either voluntarily opted to choose their natural gas supplier or were supplied natural gas by Vectren Source but remained customers of the regulated utility as part of VEDO’s exit the merchant function process. From January 2010 through the date of sale, Vectren Source sold gas commodity directly to customers in VEDO’s service territory and VEDO purchased receivables from Vectren Source to include those sales in one customer bill similar to the receivables purchased from Vectren Source related to customers that voluntarily chose Vectren Source as their supplier. Total receivables purchased from Vectren Source in the year ended December 31, 2011 totaled $66.5 million.

Support Services & Purchases

Vectren provides corporate and general and administrative services to the Company and allocates certain 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 are 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 $50.9 million, $44.8 million, and $46.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Retirement Plans & Other Postretirement Benefits

At December 31, 2013, Vectren maintains three qualified defined benefit pension plans (Vectren Corporation Non-Bargaining Retirement Plan, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan, Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company), a nonqualified supplemental executive retirement plan, and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, 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. 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 and did not contribute to Vectren's defined benefit pension plans during 2013 or 2012. For the year ended December 31, 2011, Utility Holdings contributed $33.4 million, to Vectren’s defined benefit pension plans. Such contributions were made to Vectren in total and are not plan specific. The combined funded status of Vectren’s plans was approximately 101 percent at December 31, 2013 and 82 percent at December 31, 2012. Vectren’s management currently anticipates making no contributions to qualified pension plans in 2014, due to the plans being at or above 100 percent funded levels.

Vectren allocates the periodic cost of its retirement plans calculated pursuant to US GAAP to its subsidiaries. Periodic cost, comprised of service cost and interest on that service cost, is directly charged to Utility Holdings based on labor at each measurement date and that cost is charged to operating expense and capital projects, using labor charges as the allocation method. For the years ended December 31, 2013, 2012 and 2011, costs totaling $8.0 million, $7.2 million and $6.6 million, respectively, were directly charged to Utility Holdings. Other components of periodic costs (such as interest cost, asset returns, and amortizations) and the service cost related to Vectren Corporate operations are charged to subsidiaries through the allocation process discussed above. Any difference between funding requirements and allocated periodic costs is recognized as an asset or liability until reflected in periodic costs.

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, 2013 and 2012, $11.2 million and $10.7 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. As impacted by increased funding of pension plans in 2011, at December 31, 2013 and 2012, the Company has $23.6 million, and $31.1 million, respectively, included in Other Assets representing defined benefit funding by the Company that is yet to be reflected in costs.

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, 2013 and 2012, $29.6 million and $23.6 million, respectively, is included in Deferred credits & other liabilities and represents obligations that are yet to be funded to Vectren.

Income Taxes

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. Pursuant to a subsidiary tax sharing agreement and for financial reporting purposes, Vectren subsidiaries record income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of Vectren's consolidated tax group are recorded at the parent company level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns.

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 amortization of investment tax credits follow:



	Year Ended December 31,
(In millions)	2013			2012			2011
Current:
Federal	$	48.0		$	6.1		$	10.4
State	11.0			6.9			7.9
Total current taxes	59.0			13.0			18.3
Deferred:
Federal	26.8			68.7			58.6
State	0.1			4.2			6.6
Total deferred taxes	26.9			72.9			65.2
Amortization of investment tax credits	(0.6		)	(0.6		)	(0.6		)
Total income tax expense	$	85.3		$	85.3		$	82.9

A reconciliation of the federal statutory rate to the effective income tax rate follows:



	Year Ended December 31,
	2013		2012		2011
Statutory rate	35.0	%	35.0	%	35.0	%
State and local taxes-net of federal benefit	3.5		3.7		3.9
Amortization of investment tax credit	(0.3	)	(0.3	)	(0.3	)
State apportionment impacts	—		—		0.9
All other - net	(0.6	)	(0.2	)	0.8
Effective tax rate	37.6	%	38.2	%	40.3	%

Significant components of the net deferred tax liability follow:



	At December 31,
(In millions)	2013			2012
Noncurrent deferred tax liabilities (assets):
Depreciation & cost recovery timing differences	$	627.9		$	597.1
Regulatory assets recoverable through future rates	22.8			23.5
Alternative minimum tax carryforward	(18.5		)	(44.0		)
Employee benefit obligations	5.2			13.4
Regulatory liabilities to be settled through future rates	(18.7		)	(18.3		)
Other – net	8.7			6.8
Net noncurrent deferred tax liability	627.4			578.5
Current deferred tax liabilities (assets):
Deferred fuel costs - net	22.9			25.7
Alternative minimum tax carryforward	(36.4		)	(2.7		)
Demand side management programs	0.1			2.7
General business credit carryforwards	(1.2		)	—
Other – net	9.1			(5.9		)
Net current deferred tax liability (asset)	(5.5		)	19.8
Net deferred tax liability	$	621.9		$	598.3

At December 31, 2013 and 2012, investment tax credits totaling $3.2 million and $3.8 million, respectively, are included in Deferred credits & other liabilities. At December 31, 2013, the Company has alternative minimum tax carryforwards of $54.9 million, which do not expire. In addition, the Company has $1.2 million in general business credit carryfowards, which will expire in 5 years.

Indiana House Bill 1004

In May 2011, House Bill 1004 was signed into law. This legislation phases in over four years a 2 percent rate reduction to the Indiana Adjusted Gross Income Tax for corporations. Pursuant to House Bill 1004, the tax rate will be lowered by 0.5 percent each year beginning on July 1, 2012, to the final rate of 6.5 percent effective July 1, 2015. Pursuant to FASB guidance, the Company accounted for the effect of the change in tax law on its deferred taxes in the second quarter of 2011, the period of enactment. The remeasurement of these temporary differences at the lower tax rate was recorded as a reduction of a regulatory asset.

Uncertain Tax Positions

Following is a roll forward of the total amount of unrecognized tax benefits for the three years ended December 31, 2013:



(In millions)	2013			2012			2011
Unrecognized tax benefits at January 1	$	3.7		$	11.0		$	11.8
Gross increases - tax positions in prior periods	—			0.1			3.3
Gross decreases - tax positions in prior periods	(0.2		)	(9.3		)	(4.4		)
Gross increases - current period tax positions	1.2			1.9			0.6
Settlements	—			—			(0.3		)
Unrecognized tax benefits at December 31	$	4.7		$	3.7		$	11.0

Of the change in unrecognized tax benefits during 2013, 2012, and 2011, almost none impacted the effective rate. The amount of unrecognized tax benefits, which if recognized, that would impact the effective tax rate was almost none at December 31, 2013 , 2012, and 2011. As of December 31, 2013, the unrecognized tax benefit relates to tax positions for which the ultimate deductibility is more likely than not 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.

In 2013, the Company recognized no expense related to interest and penalties. In 2012, the Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling $0.7 million, and recognized expense related to interest and penalties totaling approximately $0.4 million in 2011. The Company had approximately $0.2 million for the payment of interest and penalties accrued as of December 31, 2013 and 2012.

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 $4.5 million and $3.6 million, respectively, at December 31, 2013 and 2012.

The Internal Revenue Service (IRS) has concluded examinations of Vectren's U.S. federal income tax returns for tax years through December 31, 2008. The primary focus of the 2008 IRS examination was certain repairs and maintenance deductions, an area of particular focus by the IRS throughout the utility industry. In 2012, the IRS suspended all examinations related to this issue generally, resulting in the elimination of the audit risk in this area for Vectren through 2012. The Company does not expect any changes to this liability for unrecognized income tax benefits within the next 12 months that would significantly impact the Company's results of operations or financial condition. The State of Indiana, Vectren's primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2008. The statutes of limitations for assessment of federal income tax and Indiana income tax have expired with respect to tax years through 2008.

Final Federal Income Tax Regulations

In September 2013, the Internal Revenue Service (IRS) released final tangible property regulations regarding the deduction and capitalization of expenditures related to tangible property. The final regulations are generally effective for tax years beginning on or after January 1, 2014, but may be adopted for 2013 tax years. The Company intends to adopt the guidance for its 2014 tax year. The IRS has been working with the utility industry to provide industry specific guidance concerning the deductibility and capitalization of expenditures related to tangible property. The IRS has indicated that it expects to issue guidance with respect to natural gas transmission and distribution assets during 2014. The Company continues to evaluate the impact adoption of the regulations and industry guidance will have on its consolidated financial statements. As of this date, the Company does not expect the adoption of the regulations to have a material impact on its consolidated financial statements.

6. Borrowing Arrangements

Short-Term Borrowings

At December 31, 2013, the Company has $350 million of short-term borrowing capacity. As reduced by borrowings outstanding at December 31, 2013, approximately $321 million was available. This short-term credit facility was renewed in November 2011 and is available through September 2016. The maximum limit of the facility remained unchanged. 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. 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:



(In millions)	2013			2012			2011
Year End
Balance Outstanding	$	28.6		$	116.7		$	242.8
Weighted Average Interest Rate	0.29		%	0.40		%	0.57		%
Annual Average
Balance Outstanding	$	119.6		$	77.6		$	39.6
Weighted Average Interest Rate	0.34		%	0.47		%	0.48		%
Maximum Month End Balance Outstanding	$	176.1		$	214.2		$	242.8

Throughout 2013, 2012, and most of 2011, the Company placed commercial paper without any significant issues and did not borrow from its backup credit facility in any of these periods.

Long-Term Debt

Long-term senior unsecured obligations and first mortgage bonds outstanding by subsidiary follow:



	At December 31,
(In millions)	2013			2012
Utility Holdings
Fixed Rate Senior Unsecured Notes
2013, 5.25%	$	—		$	100.0
2015, 5.45%	75.0			75.0
2018, 5.75%	100.0			100.0
2020, 6.28%	100.0			100.0
2021, 4.67%	55.0			55.0
2023, 3.72%	150.0			—
2026, 5.02%	60.0			60.0
2028, 3.20%	45.0			—
2035, 6.10%	75.0			75.0
2039, 6.25%	—			121.6
2041, 5.99%	35.0			35.0
2042, 5.00%	100.0			100.0
2043, 4.25%	80.0			—
Total Utility Holdings	875.0			821.6
SIGECO
First Mortgage Bonds
2015, 1985 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
2013 weighted average: 0.10%	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
2022, 2013 Series C, 1.95%, tax exempt	4.6			—
2023, 1993 Environmental Improvement Series B, 5.15%, tax exempt	—			22.6
2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt	—			22.5
2024, 2013 Series D, 1.95%, tax exempt	22.5			—
2025, 1998 Pollution Control Series A, current adjustable rate 0.05%, tax exempt,
2013 weighted average: 0.10%	31.5			31.5
2029, 1999 Series, 6.72%	80.0			80.0
2030, 1998 Pollution Control Series B, 5.00%, tax exempt	—			22.0
2030, 1998 Pollution Control Series C, 5.35%, tax exempt	—			22.2
2037, 2013 Series E, 1.95%, tax exempt	22.0			—
2038, 2013 Series A, 4.0%, tax exempt	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
2043, 2013 Series B, 4.05%, tax exempt	39.6			—
Total SIGECO	267.5			267.5
Indiana Gas
Senior Unsecured Notes
2013, Series E, 6.69%	—			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	116.0			121.0
Total long-term debt outstanding	1,258.5			1,210.1
Current maturities of long-term debt	—			(105.0		)
Unamortized debt premium & discount - net	(1.4		)	(1.7		)
Total long-term debt-net	$	1,257.1		$	1,103.4

SIGECO 2013 Debt Refund and Reissuance

Utility Holdings 2013 Debt Call and Reissuance

Utility Holdings 2012 Debt Transactions

Utility Holdings 2011 Debt Issuance

Long-Term Debt Puts, Calls, and Mandatory Tenders

Certain other series of SIGECO bonds, aggregating $49.1 million, currently bear interest at fixed rates and are subject to mandatory tender in September 2017.

In March and April, 2013, the Company notified holders of six issues of SIGECO's tax exempt long-term debt totaling $110.9 million with interest rates ranging from 4.50 percent to 5.45 percent, and with maturity dates from 2020 to 2041 of its intent to call this debt. The call options were exercised at par in April and May, 2013.

Letters of Credit Supporting Long-Term Debt

As of December 31, 2013, the Company 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 credit facility that expires in September 2016. Due to the long-term nature of the credit agreement, such debt is classified as long-term at December 31, 2013.

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 2013 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2013 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2013, $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 $2.9 billion at December 31, 2013.

Consolidated maturities of long-term debt during the years following 2013 (in millions) are zero in 2014, $104.8 in 2015, $13.0 in 2016, zero in 2017, $100.0 in 2018, and $1,039.3 thereafter.

Debt Guarantees

Utility Holdings’ currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Utility Holdings’ long-term debt and short-term debt outstanding at December 31, 2013, totaled $875 million and $29 million, respectively.

Covenants

7. Common Shareholder’s Equity

During the years ended December 31, 2013, 2012, and 2011, the Company has cumulatively received additional capital of $13.1 million from Vectren which was funded by new share issues from Vectren’s dividend reinvestment plan and other stock plans.

8. 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 2013 and thereafter (in millions) are $0.8 in 2014, $0.4 in 2015, $0.3 in 2016, $0.3 in 2017, $0.2 in 2018, and zero thereafter. Total lease expense (in millions) was $1.1 in 2013, $1.2 in 2012, and $0.6 in 2011. Firm purchase commitments for utility plant total $0.5 million in 2014 and zero in 2015 and 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 and certain contracts are firm commitments under five and ten year arrangements. 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.

9. Rate & Regulatory Matters

Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement

Ohio Recovery and Deferral Mechanisms

The PUCO order approving the Company's 2009 base rate case in the Ohio service territory authorized a distribution replacement rider (DRR). The DRR's primary purpose is recovery of investments in utility plant and related operating expenses associated with replacing bare steel and cast iron pipelines and certain other infrastructure. This rider is updated annually for qualifying capital expenditures and allows for a return to be earned on those capital expenditures based on the rate of return approved in the 2009 base rate case. In addition, deferral of depreciation and the ability to accrue debt-related post in service carrying costs is also allowed until the related capital expenditures are recovered through the DRR. The order also established a prospective bill impact evaluation on the annual deferrals, limiting the deferrals at a level which would equal a change over the prior year rate of $1.00 per residential and small general service customer per month. To date, the Company has made capital investments under this rider totaling $109.0 million. During 2013, 2012, and 2011 gas operating revenues associated with the DRR were $9.8 million, $6.5 million, and $3.6 million, respectively. Other income associated with the debt-related post in service carrying costs totaled $2.0 million, $1.8 million, and $2.0 million for 2013, 2012, and 2011, respectively. Regulatory assets associated with post in service carrying costs and depreciation deferrals were $9.3 million, $6.5 million, and $3.0 million at December 31, 2013, 2012, and 2011 respectively. Due to the expiration of the initial five year term for the DRR in early 2014, the Company filed a request in August 2013 to extend and expand the DRR. On February 19, 2014, the PUCO approved a Stipulation entered into by the PUCO Staff and the Company which provided for the extension of the DRR through 2017 and expanded the types of investment covered by the DRR to include recovery of other infrastructure investments. The Order approved the Company's five-year capital expenditure plan for calendar years 2013 through 2017 totaling $187 million related to these infrastructure investments, along with savings credits associated with reduced operations and maintenance expenses for each mile of aging infrastructure replaced. In addition, the Order approved the Company's commitment that the DRR can only be further extended as part of a base rate case.

expenditure program for the 2013 calendar year totaling $61.5 million. In addition, the order approved the Company's proposal that subsequent requests for accounting authority will be filed annually in April. During 2013 and 2012, these approved capital expenditure programs under House Bill 95 generated Other income associated with the debt-related post in service carrying costs totaling $2.2 million and $0.9 million, respectively. Deferral of depreciation and property tax expenses related to these programs in 2013 and 2012 totaled $1.7 million and $0.6 million, respectively.

Indiana Recovery and Deferral Mechanisms

The Company's Indiana natural gas utilities received orders in 2008 and 2007 associated with the most recent base rate cases. These orders authorized the deferral of financial impacts associated with bare steel and cast iron replacement activities. The orders provide for the deferral of depreciation and post in service carrying costs on qualifying projects totaling $20.0 million annually at Vectren North and $3.0 million annually at Vectren South. The debt-related post in service carrying costs are recognized in the Consolidated Statements of Income currently. The recording of post in service carrying costs and depreciation deferral is limited by individual qualifying project to three years after being placed into service at Vectren South and four years after being placed into service at Vectren North. At December 31, 2013 and 2012, the Company has regulatory assets totaling $12.1 million and $8.5 million, respectively, associated with the deferral of depreciation and debt-related post in service carrying cost activities.

In April 2011, Senate Bill 251 was signed into Indiana law. The law provides a framework to recover 80 percent of federally mandated costs through a periodic rate adjustment mechanism outside of a general rate case. Such costs include a return on the federally mandated capital investment, along with recovery of depreciation and other operating costs associated with these mandates. The remaining 20 percent of those costs are to be deferred for future recovery in the utility's next general rate case.

Pipeline Safety Law

Requests for Recovery Under Regulatory Mechanisms

The Company filed in November 2013 for authority to recover appropriate costs related to its gas infrastructure replacement and

improvement programs in Indiana, including costs associated with existing pipeline safety regulations, using the mechanisms allowed under Senate Bill 251 and Senate Bill 560. The combined Vectren South and Vectren North Indiana filing requests recovery of the capital expenditures associated with the infrastructure replacement and improvement plan pursuant to the legislation, estimated to be approximately $865 million combined over the seven year period beginning in 2014, along with approximately $13 million combined annual operating costs associated with pipeline safety rules. A hearing in this proceeding is scheduled for the second quarter of 2014, and an order is expected later in 2014.

Vectren South Electric Environmental Compliance Filing

Vectren South Electric Base Rate Filing

The IURC issued an order on April 27, 2011, providing for a revenue increase to recover costs associated with approximately $325.0 million in system upgrades that were completed in the three years leading up to the December 2009 filing and modest increases in maintenance and operating expenses. The approved revenue increase is based on rate base of $1,295.6 million, return on equity of 10.4 percent, and an overall rate of return of 7.29 percent. The new rates were effective May 3, 2011. The IURC, in its order, provided for deferred accounting treatment related to the Company's investment in dense pack technology, of which approximately $28.7 million was spent as of December 31, 2013. Addressing issues raised in the case concerning coal supply contracts and related costs, the IURC found that current coal contracts remain effective and that a prospective review process of future procurement decisions would be initiated and is discussed below.

Coal Procurement Procedures

Delivery to Vectren's power plants of lower priced contract coal from the April 2011 RFP process began during 2012. On December 5, 2011 within the quarterly FAC filing, Vectren South submitted a joint proposal with the OUCC to reduce its fuel costs billed to customers by accelerating into 2012 the impact of lower cost coal under these new term contracts effective after 2012. The cost difference was deferred to a regulatory asset and will be recovered over a six-year period without interest beginning in 2014. The IURC approved this proposal on January 25, 2012, with the reduction to customer’s rates effective February 1, 2012. The total deferred balance as of December 31, 2013 was $42.4 million Recovery of this deferred balance began in February 2014.

Vectren South Electric Demand Side Management Program Filing

criteria on all programs. The DSM Programs proposed were 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, and include some for 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.

On August 31, 2011 the IURC issued an order approving an initial three year DSM plan in the Vectren South service territory that complied with the IURC’s energy saving targets. Consistent with the Company’s proposal, the order approved, among other items, the following: 1) recovery of costs associated with implementing the DSM Plan; 2) the recovery of a performance incentive mechanism based on measured savings related to certain DSM programs; 3) lost margin recovery associated with the implementation of DSM programs for large customers; and 4) deferral of lost margin up to $3 million in 2012 and $1 million in 2011 associated with small customer DSM programs for subsequent recovery under a tracking mechanism to be proposed by the Company. On June 20, 2012, the IURC issued an order approving a small customer lost margin recovery mechanism, inclusive of all previous deferrals. This mechanism is an alternative to the electric decoupling proposal that was denied by the IURC in the Company's last base rate proceeding discussed earlier. For the twelve months ended December 31, 2013, the Company recognized Electric revenue of $5 million associated with this approved lost margin recovery mechanism.

Vectren North Pipeline Safety Investigation

Vectren North & Vectren South Gas Decoupling Extension Filing

FERC Return on Equity Complaint

The Company is unable to predict the outcome of the proceeding. A 100 basis point change in the incentive rate of return would equate to approximately $0.8 million of net income on an annual basis.

10. Environmental Matters

Indiana Senate Bill 251 is also applicable to federal environmental mandates impacting Vectren South's electric operations. The Company continues to evaluate the impact Senate Bill 251 may have on its operations, including applicability of the stricter regulations the EPA is currently considering involving air quality, fly ash disposal, cooling tower intake facilities, waste water discharges, and greenhouse gases. These issues are further discussed below.

Air Quality

Clean Air Interstate Rule / Cross-State Air Pollution Rule

However, unlike CAIR in which states allocated allowances to generating units through state implementation plans, CSAPR allowances were allocated to individual units directly through the federal rule. CSAPR reductions were to be achieved with initial step reductions beginning January 1, 2012, and final compliance to be achieved in 2014. Multiple administrative and judicial challenges were filed. On December 30, 2011, the Court granted a stay of CSAPR and left CAIR in place pending its review. On August 21, 2012, the Court vacated CSAPR and directed the EPA to continue to administer CAIR. In October 2012, the EPA filed its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA's request for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPA filed a petition for review with the US Supreme Court, and in June 2013 the Supreme Court agreed to review the lower court decision. A decision by the Supreme Court is expected in 2014. The Company remains in full compliance with CAIR (see additional information below "Conclusions Regarding Environmental Regulations").

Mercury and Air Toxics (MATS) Rule

Notice of Violation for A.B. Brown Power Plant

Information Request

Water

Conclusions Regarding Environmental Regulations

Coal Ash Waste Disposal & Ash Ponds

did not offer a preferred alternative, but took public comment on multiple alternative regulations. Rules have not been finalized given oversight hearings, congressional interest, and other factors. Recently the EPA entered into a consent decree in which it agreed to finalize by December 2014 its determination whether to regulate ash as hazardous waste, or the less stringent solid waste designation.

Climate Change

Impact of Legislative Actions & Other Initiatives is Unknown

expenditures made to control emissions should be considered a federally mandated cost of providing electricity, and as such, the Company believes such costs and expenditures should be recoverable from customers through Senate Bill 251 referenced above.

Manufactured Gas Plants

11. Fair Value Measurements

The carrying values and estimated fair values using primarily Level 2 assumptions of the Company's other financial instruments follow:



	At December 31,
	2013				2012
(In millions)	Carrying Amount		Est. Fair Value		Carrying Amount		Est. Fair Value
Long-term debt	$	1,257.1	$	1,317.4	$	1,208.4	$	1,372.6
Short-term borrowings	28.6		28.6		116.7		116.7
Cash & cash equivalents	8.6		8.6		13.3		13.3

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.

12. 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)	2013			2012			2011
Revenues
Gas Utility Services	$	810.0		$	738.1		$	819.1
Electric Utility Services	619.3			594.9			635.9
Other Operations	38.1			40.1			43.9
Eliminations	(37.8		)	(39.5		)	(41.9		)
Total revenues	$	1,429.6		$	1,333.6		$	1,457.0
Profitability Measure - Net Income
Gas Utility Services	$	55.7		$	60.0		$	52.5
Electric Utility Services	75.8			68.0			65.0
Other Operations	10.3			10.0			5.4
Total net income	$	141.8		$	138.0		$	122.9
Amounts Included in Profitability Measures
Depreciation & Amortization
Gas Utility Services	$	90.5		$	85.4		$	84.3
Electric Utility Services	84.0			81.3			80.2
Other Operations	21.9			23.3			27.8
Total depreciation & amortization	$	196.4		$	190.0		$	192.3
Interest Expense
Gas Utility Services	$	30.6		$	31.8		$	37.1
Electric Utility Services	29.2			33.8			36.4
Other Operations	5.2			5.9			6.8
Total interest expense	$	65.0		$	71.5		$	80.3
Income Taxes
Gas Utility Services	$	36.6		$	39.1		$	34.5
Electric Utility Services	48.3			46.4			45.3
Other Operations	0.4			(0.2		)	3.1
Total income taxes	$	85.3		$	85.3		$	82.9
Capital Expenditures
Gas Utility Services	$	150.5		$	128.8		$	113.5
Electric Utility Services	100.0			108.8			102.2
Other Operations	25.8			16.2			17.8
Non-cash costs & changes in accruals	(13.8		)	(6.2		)	1.8
Total capital expenditures	$	262.5		$	247.6		$	235.3



	At December 31,
(In millions)	2013		2012		2011
Assets
Gas Utility Services	$	2,287.9	$	2,173.5	$	2,125.2
Electric Utility Services	1,679.0		1,705.1		1,656.5
Other Operations, net of eliminations	173.9		168.2		192.8
Total assets	$	4,140.8	$	4,046.8	$	3,974.5

13. Additional Balance Sheet & Operational Information

Inventories consist of the following:



	At December 31,
(In millions)	2013		2012
Gas in storage – at LIFO cost	$	33.2	$	22.4
Materials & supplies	39.0		38.4
Coal & oil for electric generation - at average cost	16.5		52.0
Other	1.2		1.2
Total inventories	$	89.9	$	114.0

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, 2013 and 2012 by approximately $9 million and $12 million, respectively.

Prepayments & other current assets in the Consolidated Balance Sheets consist of the following:



	At December 31,
(In millions)	2013		2012
Prepaid gas delivery service	$	32.9	$	28.5
Prepaid taxes	0.2		21.1
Deferred income taxes	5.5		—
Other prepayments & current assets	3.8		2.7
Total prepayments & other current assets	$	42.4	$	52.3

Other investments in the Consolidated Balance Sheets consist of the following:



	At December 31,
(In millions)	2013		2012
Cash surrender value of life insurance policies	$	22.3	$	27.4
Municipal bond	3.4		3.6
Restricted cash & other investments	1.6		1.6
Total other investments	$	27.3	$	32.6

Accrued liabilities in the Consolidated Balance Sheets consist of the following:



	At December 31,
(In millions)	2013		2012
Refunds to customers & customer deposits	$	50.2	$	53.1
Accrued taxes	32.3		30.7
Accrued interest	16.2		19.4
Deferred income taxes	—		19.8
Accrued salaries & other	28.7		16.3
Total accrued liabilities	$	127.4	$	139.3

Asset retirement obligations included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets roll forward as follows:



(In millions)	2013		2012
Asset retirement obligation, January 1	$	27.3	$	34.0
Accretion	1.6		2.2
Changes in estimates, net of cash payments	0.2		(8.9		)
Asset retirement obligation, December 31	$	29.1	$	27.3

Other – net in the Consolidated Statements of Income consists of the following:



	Year Ended December 31,
(In millions)	2013		2012		2011
AFUDC - borrowed funds	$	5.9	$	4.6	$	2.5
AFUDC - equity funds	0.8		0.4		0.2
Nonutility plant capitalized interest	0.4		0.2		0.3
Interest income	0.6		0.6		0.6
Cash surrender value of life insurance policies	1.7		1.4		0.1
Other income	1.1		0.8		0.6
Total other – net	$	10.5	$	8.0	$	4.3

Supplemental Cash Flow Information:



	Year Ended December 31,
(In millions)	2013		2012		2011
Cash paid (received) for:
Interest	$	68.2	$	69.6	$	82.5
Income taxes	30.9		30.1		(3.4		)

As of December 31, 2013 and 2012, the Company has accruals related to utility and nonutility plant purchases totaling approximately $13.1 million and $7.1 million, respectively.

14. Subsidiary Guarantor & Consolidating Information

The Company’s three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of Utility Holdings’ $350 million in short-term credit facilities, of which $29 million is outstanding at December 31, 2013, and Utility Holdings’ $875 million unsecured senior notes outstanding at December 31, 2013. 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, 2013 (in millions):



	Subsidiary Guarantors		Parent Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	810.0	$	—	$	—		$	810.0
Electric utility	619.3		—		—			619.3
Other	—		37.9		(37.6		)	0.3
Total operating revenues	1,429.3		37.9		(37.6		)	1,429.6
OPERATING EXPENSES
Cost of gas sold	358.1		—		—			358.1
Cost of fuel & purchased power	202.9		—		—			202.9
Other operating	369.2		—		(35.8		)	333.4
Depreciation & amortization	174.6		21.3		0.5			196.4
Taxes other than income taxes	55.6		1.5		0.1			57.2
Total operating expenses	1,160.4		22.8		(35.2		)	1,148.0
OPERATING INCOME	268.9		15.1		(2.4		)	281.6
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—		131.3		(131.3		)	—
Other – net	7.1		38.5		(35.1		)	10.5
Total other income (expense)	7.1		169.8		(166.4		)	10.5
Interest expense	59.8		42.7		(37.5		)	65.0
INCOME BEFORE INCOME TAXES	216.2		142.2		(131.3		)	227.1
Income taxes	84.9		0.4		—			85.3
NET INCOME	$	131.3	$	141.8	$	(131.3	)	$	141.8

Consolidating Statement of Income for the year ended December 31, 2012 (in millions):



	Subsidiary Guarantors		Parent Company			Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	738.1	$	—		$	—		$	738.1
Electric utility	594.9		—			—			594.9
Other	—		40.1			(39.5		)	0.6
Total operating revenues	1,333.0		40.1			(39.5		)	1,333.6
OPERATING EXPENSES
Cost of gas sold	301.3		—			—			301.3
Cost of fuel & purchased power	192.0		—			—			192.0
Other operating	348.5		0.4			(38.8		)	310.1
Depreciation & amortization	166.8		22.7			0.5			190.0
Taxes other than income taxes	51.7		1.6			0.1			53.4
Total operating expenses	1,060.3		24.7			(38.2		)	1,046.8
OPERATING INCOME	272.7		15.4			(1.3		)	286.8
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—		127.9			(127.9		)	—
Other – net	6.2		41.4			(39.6		)	8.0
Total other income (expense)	6.2		169.3			(167.5		)	8.0
Interest expense	65.6		46.8			(40.9		)	71.5
INCOME BEFORE INCOME TAXES	213.3		137.9			(127.9		)	223.3
Income taxes	85.4		(0.1		)	—			85.3
NET INCOME	$	127.9	$	138.0		$	(127.9	)	$	138.0

Consolidating Statement of Income for the year ended December 31, 2011 (in millions):



	Subsidiary Guarantors		Parent Company		Eliminations			Consolidated
OPERATING REVENUES
Gas utility	$	819.1	$	—	$	—		$	819.1
Electric utility	635.9		—		—			635.9
Other	—		43.9		(41.9		)	2.0
Total operating revenues	1,455.0		43.9		(41.9		)	1,457.0
OPERATING EXPENSES
Cost of gas sold	375.4		—		—			375.4
Cost of fuel & purchased power	240.4		—		—			240.4
Other operating	354.6		—		(41.5		)	313.1
Depreciation & amortization	164.6		27.1		0.6			192.3
Taxes other than income taxes	52.3		1.5		0.2			54.0
Total operating expenses	1,187.3		28.6		(40.7		)	1,175.2
OPERATING INCOME	267.7		15.3		(1.2		)	281.8
OTHER INCOME (EXPENSE)
Equity in earnings of consolidated companies	—		117.5		(117.5		)	—
Other – net	3.1		48.9		(47.7		)	4.3
Total other income (expense)	3.1		166.4		(165.2		)	4.3
Interest expense	73.5		55.7		(48.9		)	80.3
INCOME BEFORE INCOME TAXES	197.3		126.0		(117.5		)	205.8
Income taxes	79.8		3.1		—			82.9
NET INCOME	$	117.5	$	122.9	$	(117.5	)	$	122.9

Consolidating Balance Sheet as of December 31, 2013 (in millions):



ASSETS	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	8.2	$	0.4	$	—		$	8.6
Accounts receivable - less reserves	112.1		—		—			112.1
Intercompany receivables	0.3		84.8		(85.1		)	—
Accrued unbilled revenues	113.5		—		—			113.5
Inventories	89.9		—		—			89.9
Recoverable fuel & natural gas costs	5.5		—		—			5.5
Prepayments & other current assets	37.3		40.1		(35.0		)	42.4
Total current assets	366.8		125.3		(120.1		)	372.0
Utility Plant
Original cost	5,389.6		—		—			5,389.6
Less: accumulated depreciation & amortization	2,165.3		—		—			2,165.3
Net utility plant	3,224.3		—		—			3,224.3
Investments in consolidated subsidiaries	—		1,375.8		(1,375.8		)	—
Notes receivable from consolidated subsidiaries	—		696.4		(696.4		)	—
Investments in unconsolidated affiliates	0.2		—		—			0.2
Other investments	22.8		4.5		—			27.3
Nonutility plant - net	2.2		148.3		—			150.5
Goodwill - net	205.0		—		—			205.0
Regulatory assets	113.4		22.8		—			136.2
Other assets	32.2		1.0		(7.9		)	25.3
TOTAL ASSETS	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8

LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent
	Guarantors		Company		Eliminations			Consolidated
Current Liabilities
Accounts payable	$	161.6	$	10.5	$	—		$	172.1
Intercompany payables	11.7		—		(11.7		)	—
Payables to other Vectren companies	24.6		—		—			24.6
Accrued liabilities	150.3		12.1		(35.0		)	127.4
Short-term borrowings	—		28.6		—			28.6
Intercompany short-term borrowings	73.1		0.3		(73.4		)	—
Total current liabilities	421.3		51.5		(120.1		)	352.7
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.5		874.6		—			1,257.1
Long-term debt due to VUHI	696.4		—		(696.4		)	—
Total long-term debt - net	1,078.9		874.6		(696.4		)	1,257.1
Deferred Income Taxes & Other Liabilities
Deferred income taxes	616.9		10.5		—			627.4
Regulatory liabilities	385.7		1.6		—			387.3
Deferred credits & other liabilities	88.3		3.1		(7.9		)	83.5
Total deferred credits & other liabilities	1,090.9		15.2		(7.9		)	1,098.2
Common Shareholder's Equity
Common stock (no par value)	800.9		787.7		(800.9		)	787.7
Retained earnings	574.9		645.1		(574.9		)	645.1
Total common shareholder's equity	1,375.8		1,432.8		(1,375.8		)	1,432.8
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,966.9	$	2,374.1	$	(2,200.2	)	$	4,140.8

Consolidating Balance Sheet as of December 31, 2012 (in millions):



ASSETS	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
Current Assets
Cash & cash equivalents	$	12.5	$	0.8		$	—		$	13.3
Accounts receivable - less reserves	81.8		—			—			81.8
Intercompany receivables	—		145.1			(145.1		)	—
Accrued unbilled revenues	93.6		—			—			93.6
Inventories	114.0		—			—			114.0
Recoverable fuel & natural gas costs	25.3		—			—			25.3
Prepayments & other current assets	52.0		5.8			(5.5		)	52.3
Total current assets	379.2		151.7			(150.6		)	380.3
Utility Plant
Original cost	5,176.6		0.2			—			5,176.8
Less: accumulated depreciation & amortization	2,057.2		—			—			2,057.2
Net utility plant	3,119.4		0.2			—			3,119.6
Investments in consolidated subsidiaries	—		1,329.2			(1,329.2		)	—
Notes receivable from consolidated subsidiaries	—		679.7			(679.7		)	—
Investments in unconsolidated affiliates	0.2		—			—			0.2
Other investments	27.8		4.8			—			32.6
Nonutility plant - net	2.6		144.3			—			146.9
Goodwill - net	205.0		—			—			205.0
Regulatory assets	104.1		22.4			—			126.5
Other assets	40.4		1.7			(6.4		)	35.7
TOTAL ASSETS	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8

LIABILITIES & SHAREHOLDER'S EQUITY	Subsidiary		Parent
	Guarantors		Company			Eliminations			Consolidated
Current Liabilities
Accounts payable	$	114.8	$	6.2		$	—		$	121.0
Accounts payable to affiliated companies	29.7		—			—			29.7
Intercompany payables	10.6		—			(10.6		)	—
Payables to other Vectren companies	25.1		—			—			25.1
Accrued liabilities	131.3		13.5			(5.5		)	139.3
Short-term borrowings	—		116.7			—			116.7
Intercompany short-term borrowings	134.5		—			(134.5		)	—
Current maturities of long-term debt	5.0		100.0			—			105.0
Total current liabilities	451.0		236.4			(150.6		)	536.8
Long-Term Debt
Long-term debt - net of current maturities &
debt subject to tender	382.3		721.1			—			1,103.4
Long-term debt due to VUHI	679.7		—			(679.7		)	—
Total long-term debt - net	1,062.0		721.1			(679.7		)	1,103.4
Deferred Income Taxes & Other Liabilities
Deferred income taxes	595.4		(16.9		)	—			578.5
Regulatory liabilities	362.2		2.0			—			364.2
Deferred credits & other liabilities	78.9		1.4			(6.4		)	73.9
Total deferred credits & other liabilities	1,036.5		(13.5		)	(6.4		)	1,016.6
Common Shareholder's Equity
Common stock (no par value)	787.8		781.6			(787.8		)	781.6
Retained earnings	541.4		608.4			(541.4		)	608.4
Total common shareholder's equity	1,329.2		1,390.0			(1,329.2		)	1,390.0
TOTAL LIABILITIES & SHAREHOLDER'S EQUITY	$	3,878.7	$	2,334.0		$	(2,165.9	)	$	4,046.8

Consolidating Statement of Cash Flows for the year ended December 31, 2013 (in millions):



	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	371.0		$	28.9		$	—		$	399.9
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution from Parent	13.1			6.1			(13.1		)	6.1
Long-term debt - net of issuance costs	232.6			273.5			(124.4		)	381.7
Requirements for:
Dividends to parent	(97.9		)	(105.1		)	97.9			(105.1		)
Retirement of long-term debt, including premiums paid	(223.6		)	(221.6		)	107.7			(337.5		)
Net change in intercompany short-term borrowings	(61.5		)	0.3			61.2			—
Net change in short-term borrowings	—			(88.1		)	—			(88.1		)
Net cash flows from financing activities	(137.3		)	(134.9		)	129.3			(142.9		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			97.9			(97.9		)	—
Other investing activities	0.6			0.2			—			0.8
Requirements for:
Capital expenditures, excluding AFUDC equity	(238.3		)	(24.2		)	—			(262.5		)
Consolidated subsidiary investments	—			(13.1		)	13.1			—
Net change in long-term intercompany notes receivable	—			(16.7		)	16.7			—
Net change in short-term intercompany notes receivable	(0.3		)	61.5			(61.2		)	—
Net cash flows from investing activities	(238.0		)	105.6			(129.3		)	(261.7		)
Net change in cash & cash equivalents	(4.3		)	(0.4		)	—			(4.7		)
Cash & cash equivalents at beginning of period	12.5			0.8			—			13.3
Cash & cash equivalents at end of period	$	8.2		$	0.4		$	—		$	8.6

Consolidating Statement of Cash Flows for the year ended December 31, 2012 (in millions):



	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	335.6		$	37.8		$	—		$	373.4
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from:
Additional capital contribution from Parent	—			7.0			—			7.0
Long-term debt - net of issuance costs	—			99.5			—			99.5
Requirements for:
Dividends to parent	(70.9		)	(101.5		)	70.9			(101.5		)
Net change in intercompany short-term borrowings	(24.0		)	—			24.0			—
Net change in short-term borrowings	—			(126.1		)	—			(126.1		)
Net cash flows from financing activities	(94.9		)	(121.1		)	94.9			(121.1		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			70.9			(70.9		)	—
Other investing activities	0.3			2.3			—			2.6
Requirements for capital expenditures, excluding AFUDC equity	(233.8		)	(13.8		)	—			(247.6		)
Net change in short-term intercompany notes receivable	—			24.0			(24.0		)	—
Net cash flows from investing activities	(233.5		)	83.4			(94.9		)	(245.0		)
Net change in cash & cash equivalents	7.2			0.1			—			7.3
Cash & cash equivalents at beginning of period	5.3			0.7			—			6.0
Cash & cash equivalents at end of period	$	12.5		$	0.8		$	—		$	13.3

Consolidating Statement of Cash Flows for the year ended December 31, 2011 (in millions):



	Subsidiary Guarantors			Parent Company			Eliminations			Consolidated
NET CASH FLOWS FROM OPERATING ACTIVITIES	$	316.2		$	18.1		$	—		$	334.3
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt - net of issuance costs	248.4			148.9			(248.4		)	148.9
Requirements for:
Dividends to parent	(84.4		)	(91.6		)	84.4			(91.6		)
Retirement of long-term debt, including premiums paid	(337.4		)	(347.0		)	337.4			(347.0		)
Other financing activities	—			(1.1		)	—			(1.1		)
Net change in intercompany short-term borrowings	13.4			(277.6		)	264.2			—
Net change in short-term borrowings	—			195.8			—			195.8
Net cash flows from financing activities	(160.0		)	(372.6		)	437.6			(95.0		)
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from:
Consolidated subsidiary distributions	—			84.4			(84.4		)	—
Other investing activities	0.2			0.2			—			0.4
Requirements for:
Capital expenditures, excluding AFUDC equity	(218.2		)	(17.1		)	—			(235.3		)
Other investing activities	(0.8		)	—			—			(0.8		)
Net change in long-term intercompany notes receivable	—			89.0			(89.0		)	—
Net change in short-term intercompany notes receivable	65.9			198.3			(264.2		)	—
Net cash flows from investing activities	(152.9		)	354.8			(437.6		)	(235.7		)
Net change in cash & cash equivalents	3.3			0.3			—			3.6
Cash & cash equivalents at beginning of period	2.0			0.4			—			2.4
Cash & cash equivalents at end of period	$	5.3		$	0.7		$	—		$	6.0

15. Impact of Recently Issued Accounting Guidance

Offsetting Assets and Liabilities

Accumulated Other Comprehensive Income (AOCI)

In February 2013, the FASB issued new accounting guidance on the reporting of reclassifications from AOCI. The guidance requires an entity to report the effect of significant reclassification from AOCI on the respective line items in net income if the amount being reclassified is required under US GAAP to be reclassified in its entirety to net income. For other amounts that are not required under US GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference to other disclosures required that provide additional details about these amounts. The new guidance is effective for fiscal years, and interim periods within annual periods, beginning after December 15, 2012. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the company's results of operations, cash flows or financial position.

Unrecognized Tax Benefit Presentation

carryforward, a similar tax loss, or a tax credit carryforward, except under certain circumstances outlined in the update. The amendments in the update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. This update is consistent with how the Company currently presents unrecognized tax benefits, therefore, adoption of this guidance resulted in no material impact on the Company's financial statements.

16. 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 2013 and 2012 follows:



(In millions)		Q1		Q2		Q3		Q4
2013
	Results of Operations:
	Operating revenues	$	465.5	$	292.8	$	267.7	$	403.6
	Operating income	105.4		51.2		54.5		70.5
	Net income	55.1		24.2		25.3		37.2
2012
	Results of Operations:
	Operating revenues	$	432.1	$	265.8	$	267.7	$	368.0
	Operating income	105.9		49.8		57.1		74.0
	Net income	56.0		20.1		26.4		35.5

ITEM 9. CHANGE IN & DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING & FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS & PROCEDURES

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2013, there have been no changes to the Company’s internal control 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, 2013, 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, 2013, 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 (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation under the framework in Internal Control — Integrated Framework (1992), the Company concluded that its internal control over financial reporting was effective as of December 31, 2013.

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.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS & CORPORATE GOVERNANCE

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

Vectren’s Corporate Governance Guidelines; its charters for each committee of its Board of Directors; its Corporate Code of Conduct that covers Vectren's directors are available in the Corporate Governance section of Vectren's website, www.vectren.com/Corporate/Corporate_Governance.jsp. The Corporate Code of Conduct (titled “Corp Code of Conduct”) contains specific acknowledgments pertaining to executive officers. A separate code of conduct (titled “Board Code of Ethics & Code of Conduct”) contains specific codes of ethics pertaining to the Board of Directors. A copy 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/Board Code of Ethics & 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 Vectren's website at the internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to the address listed above.

ITEM 11. EXECUTIVE COMPENSATION

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS & MANAGEMENT & RELATED

STOCKHOLDER MATTERS

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

ITEM 13. CERTAIN RELATIONSHIPS & RELATED TRANSACTIONS & DIRECTOR INDEPENDENCE

Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation.

ITEM 14. PRINCIPAL ACCOUNTANT FEES & SERVICES

The following tabulation shows the audit and non-audit fees incurred and payable to Deloitte & Touche LLP (Deloitte) for the years ending December 31, 2013 and 2012. The fees presented below represent total Vectren fees, the majority of which are allocated to Utility Holdings.



	2013		2012
Audit Fees⁽¹⁾	$	1,415,807	$	1,369,148
Audit-Related Fees⁽²⁾	530,391		460,983
Tax Fees⁽³⁾	95,589		109,422
Total Fees Paid to Deloitte⁽⁴⁾	$	2,041,787	$	1,939,553

(1)

Aggregate fees incurred and payable to Deloitte for professional services rendered for the audits of Vectren’s and Utility Holdings’ 2013 and 2012 fiscal year annual financial statements and the review of financial statements included in their Forms 10-K or 10-Q filed during Vectren’s 2013 and 2012 fiscal years. The amount includes fees related to the attestation to Vectren’s assertion pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $128,607 and $100,498 in 2013 and 2012, respectively.

(2)

Audit-related fees consisted principally of reviews related to various financing transactions, regulatory filings, consultation on various accounting issues, and audit fees related to the stand alone audit of three of Vectren’s consolidated subsidiaries. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $12,141 and $8,944 in 2013 and 2012, respectively.


(3)	Tax fees consisted of fees paid to Deloitte for the review of tax returns and consultation on other tax matters of Vectren 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 $11,889 and $8,989 in 2013 and 2012, 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

ITEM 15. EXHIBITS & FINANCIAL STATEMENT SCHEDULES

List of Documents Filed as Part of This Report

Consolidated Financial Statements

The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, appear in Part II “Item 8 Financial Statements and Supplementary Data” of this Form 10-K.

Supplemental Schedules

For the years ended December 31, 2013, 2012, and 2011, 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 2013 – Accumulated provision for
uncollectible accounts	$	5.0	$	6.5	$	—	$	6.5	$	5.0
Year 2012 – Accumulated provision for
uncollectible accounts	$	5.9	$	7.4	$	—	$	8.3	$	5.0
Year 2011 – Accumulated provision for
uncollectible accounts	$	4.5	$	11.4	$	—	$	10.0	$	5.9
OTHER RESERVES:
Year 2013 – Restructuring costs	$	0.3	$	—	$	—	$	0.1	$	0.2
Year 2012 – Restructuring costs	$	0.4	$	—	$	—	$	0.1	$	0.3
Year 2011 – Restructuring costs	$	0.4	$	—	$	—	$	—	$	0.4

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

21.1	List of Company’s Significant Subsidiaries
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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) April 1, 2013 (Filed and designated in Form 8-K dated April 30, 2013, 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)



4.5	Note Purchase Agreement, dated April 5, 2011, 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 8, 2011 File No. 1-15467, as Exhibit 4.1)



4.6	Note Purchase Agreement, dated November 15, 2011, 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 November 17, 2011 File No. 1-15467, as Exhibit 4.1)



4.7	Note Purchase Agreement, dated December 20, 2012, 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 December 21, 2012 File No. 1-15467, as Exhibit 4.1)



4.8	Note Purchase Agreement, dated August 22, 2013, 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 August 2, 2013, File No. 1-15467, as Exhibit 4.1)

10. Material Contracts



10.1	Vectren Corporation At Risk Compensation Plan effective May 1, 2001, (as most recently amended and restated as of May 1, 2011). (Filed and designated in Form 8-K dated May 17, 2011, File No. 1-15467, as Exhibit 10.1.)



10.2	Vectren Corporation Nonqualified 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.)



10.3	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.)



10.4	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.)



10.5	Vectren Corporation Specimen Waiver, effective October 3, 2013, to the Vectren Corporation Unfunded Supplemental Retirement Plan for a Select Group of Management Employees. (Filed and designated in Form 10-Q for the quarter ended September 30, 2013, File No. 1-15467, as Exhibit 10.1.)



10.6	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.)



10.7	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.)



10.8	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.)



10.9	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.)



10.10	Vectren Corporation At Risk Compensation Plan specimen performance award 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.)



10.11	Vectren Corporation At Risk Compensation Plan specimen performance award 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.)



10.12	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.)



10.13	Vectren Corporation At Risk Compensation Plan stock unit award agreement for non-employee directors, effective May 1, 2009. (Filed and designated in Form 8-K, dated February 20, 2009, File No. 1-15467, as Exhibit 10.1)



10.14	Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 31, 2013. (Filed and designated in Form 10-K, for the year ended December 31, 2012, File No. 1-15467, as Exhibit 10.2)



10.15	Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 31, 2014. (Filed and designated in Form 10-K, for the year ended December 31, 2013, File No. 1-15467, as Exhibit 10.14)



10.16	Vectren Corporation specimen change in control agreement dated December 31, 2011. (Filed and designated in Form 8-K, dated January 5, 2012, File No. 1-15467, as Exhibit 10.1) The specimen agreement significantly differs among the named executive officers only to the extent change in control benefits are provided in the amount of three times base salary and bonus for Mr. Carl L. Chapman and two times base salary and bonus for Messer’s Jerome A. Benkert, Jr., Ronald E. Christian, and William S. Doty.



10.17	Amendment number one to Vectren Corporation specimen change in control agreement dated December 31, 2012. (Filed and designated in Form 10-K, for the year ended December 31, 2012, File No. 1-15467, as Exhibit 10.1)



10.18	Vectren Corporation specimen severance plan agreement dated December 31, 2011. (Filed and designated in Form 8-K, dated January 5, 2012 File No. 1-15467, as Exhibit 10.2) The severance plan differs among the named executive officers only to the extent where severance benefits are provided in the amount of two times base salary for Mr. Chapman and one and one half times base salary for Messer’s Benkert, Christian, and Doty.



10.19	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.)



10.20	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.)



10.21	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.)



10.22	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.)



10.23	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)



10.24	Amendment No. 1 to Coal Supply Agreement for Warrick 4 Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011. (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.1.) Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission which was granted.



10.25	Amendment No. 2 to Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011. (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.2.) Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission which was granted.



10.26	Amendment No. 2 to Coal Supply Agreement for A.B. Brown Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., effective October 31, 2011. (Filed and designated in Form 8-K dated November 1, 2011, File No. 1-15467, as Exhibit 10.3.) Portions of the document have been omitted and filed separately pursuant to a request for confidential treatment filed with the Securities and Exchange Commission which was granted.



10.27	Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective April 1, 2012. Contract assigned to ETC ProLiance Energy, LLC on June 18, 2013. (Filed and designated Form 10-K, for the year ended December 31, 2012, File No. 1-15467, as Exhibit 10.3.)



10.28	Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective April 1, 2012. Contract assigned to ETC ProLiance Energy, LLC on June 18, 2013. (Filed and designated Form 10-K, for the year ended December 31, 2012, File No. 1-15467, as Exhibit 10.4.)



10.29	Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Energy Group, Citizens Energy Services Corporation and ProLiance Energy, LLC, effective March 15, 1996. (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.)



10.30	Credit Agreement, 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)



10.31	First Amendment to Credit Agreement, dated November 10, 2011, among Vectren Utility Holdings, Inc., and each of the financial institutions named therein. (Filed and designated in Form 8-K dated November 14, 2011, File No. 1-15467, as Exhibit 10.1)

21. Subsidiaries of the Company

The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1. (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 September 5, 2012. (Filed and designated in Current Report on Form 8-K filed October 1, 2012, File No. 1-15467, as Exhibit 3.1.)

101 Interactive Data File

101.INS XBRL Instance Document (Furnished herewith.)

101.SCH XBRL Taxonomy Extension Schema (Furnished herewith.)

101.CAL XBRL Taxonomy Extension Calculation Linkbase (Furnished herewith.)

101.DEF XBRL Taxonomy Extension Definition Linkbase (Furnished herewith.)

101.LAB XBRL Taxonomy Extension Labels Linkbase (Furnished herewith.)

101.PRE XBRL Taxonomy Extension Presentation Linkbase (Furnished herewith.)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VECTREN UTILITY HOLDINGS, INC.

Dated March 5, 2014 /s/ Carl L. Chapman

Carl L. Chapman

Chief Executive Officer and Director

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in capacities and on the dates indicated.



Signature	Title	Date

/s/ Carl L. Chapman	Chief Executive Officer and Director	March 5, 2014
Carl L. Chapman	(Principal Executive Officer)
/s/ Jerome A. Benkert, Jr.	Executive Vice President , Chief Financial Officer, and Director	March 5, 2014
Jerome A. Benkert, Jr.	(Principal Financial Officer)
/s/ M. Susan Hardwick	Senior Vice President, Finance & Assistant Treasurer	March 5, 2014
M. Susan Hardwick	(Principal Accounting Officer)
/s/ William S. Doty	President and Director	March 5, 2014
William S. Doty
/s/ Ronald E. Christian	Executive Vice Pres., Chief Legal and External Affairs Officer, Secretary, and Director	March 5, 2014
Ronald E. Christian