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
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from __________________ to ________________________
Commission file number: 1-15467
VECTREN CORPORATION |
(Exact name of registrant as specified in its charter)
 | ||
INDIANA | 35-2086905 | |
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | |
One Vectren Square | 47708 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant's telephone number, including area code: 812-491-4000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common – Without Par | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(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. ¨
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 ý Accelerated filer ¨
Non-accelerated filer ¨ 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 $2,776,650,228.
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 | 82,418,221 | January 31, 2014 | ||
Class | Number of Shares | Date | ||
Documents Incorporated by Reference
Certain information in the Company's definitive Proxy Statement for the 2014 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year, is incorporated by reference in Part III of this Form 10-K.
Definitions
AFUDC: allowance for funds used during construction | MDth / MMDth: thousands / millions of dekatherms |
ASC: Accounting Standards Codification | MISO: Midcontinent Independent System Operator (formerly Midwest Independent System Operator) |
BTU / MMBTU: British thermal units / millions of BTU | MSHA: Mine Safety and Health Administration |
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 |
IURC: Indiana Utility Regulatory Commission | PUCO: Public Utilities Commission of Ohio |
IRC: Internal Revenue Code | Throughput: combined gas sales and gas transportation volumes |
Kv: Kilovolt | XBRL: eXtensible Business Reporting Language |
MCF / BCF: thousands / billions of cubic feet | |
Access to Information
Vectren Corporation makes available all SEC filings and recent annual reports 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 | ||
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Table of Contents
Item Number | Page Number | |
Part I | ||
1 | ||
1A | Risk Factors | |
1B | Unresolved Staff Comments | |
2 | Properties | |
3 | Legal Proceedings | |
4 | Mine Safety Disclosures | |
Part II | ||
5 | Market for the Company’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities | |
6 | Selected Financial Data | |
7 | Management's Discussion and Analysis of Results of Operations and Financial Condition | |
7A | Quantitative and Qualitative Disclosures About Market Risk | |
8 | Financial Statements and Supplementary Data | |
9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |
9A | Controls and Procedures, including Management’s Assessment of Internal Controls over Financial Reporting | |
9B | Other Information | |
Part III | ||
10 | Directors, Executive Officers and Corporate Governance | |
11 | Executive Compensation | |
12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |
13 | Certain Relationships, Related Transactions and Director Independence | |
14 | Principal Accountant Fees and Services | |
Part IV | ||
15 | Exhibits and Financial Statement Schedules | |
Signatures | ||
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PART I
ITEM 1. BUSINESS
Description of the Business
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three 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. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999.
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 sells excess power into the MISO. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. VEDO provides energy delivery services to over 312,000 natural gas customers located near Dayton in west central Ohio.
The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in three primary business areas: Infrastructure Services, Energy Services, and Coal Mining. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides performance contracting and renewable energy services. Coal Mining owns, and through its contract miners, mines and then sells coal. Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. Prior to June 18, 2013, the Company, through Enterprises, was involved in nonutility activities in its Energy Marketing business area. Energy Marketing marketed and supplied natural gas and provided energy management services through ProLiance Holdings, LLC (ProLiance) and Vectren Source (Source). Pursuant to service contracts, Energy Marketing provided the Company's regulated utilities natural gas supply services. All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services and coal.
Narrative Description of the Business
The Company segregates its operations into three groups: the Utility Group, the Nonutility Group, and Corporate and Other. At December 31, 2013, the Company had $5.1 billion in total assets, with $4.1 billion (80 percent) attributed to the Utility Group, and $1.0 billion (20 percent) attributed to the Nonutility Group. Net income for the year ended December 31, 2013, was $136.6 million, or $1.66 per share of common stock, with net income of $141.8 million attributed to the Utility Group, a loss of $4.5 million attributed to the Nonutility Group, and a loss of $0.7 million attributed to Corporate and Other. Net income for the year ended December 31, 2012, was $159.0 million, or $1.94 per share of common stock. For further information regarding the activities and assets of operating segments within these Groups, refer to Note 21 in the Company’s Consolidated Financial Statements included in Item 8. Following is a more detailed description of the Utility Group and Nonutility Group.
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Utility Group
The Utility Group consists of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment includes the operations of Indiana Gas, 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 transmission and distribution services to southwestern Indiana, and includes its power generating and wholesale power operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers. Following is a more detailed description of the Utility Group’s Gas Utility and Electric Utility operating segments.
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
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assets of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy) (See the discussion of Energy Marketing below and Note 7 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 to the MISO 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.
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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 the Company. 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 through 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
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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 Vectren’s electric and gas products and services. If Vectren 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.
Nonutility Group
The Company is involved in nonutility activities in three primary business areas: Infrastructure Services, Energy Services, and Coal Mining. Prior to June 18, 2013, the Company was involved in nonutility activities in its Energy Marketing business area.
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Infrastructure Services
Infrastructure Services provides underground pipeline construction and repair to utility infrastructure through its wholly owned subsidiaries Miller Pipeline, LLC (Miller) and Minnesota Limited, LLC (Minnesota Limited). The Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited on March 31, 2011 (see Note 5 in the Company’s Consolidated Financial Statements included in Item 8). Infrastructure Services provides services to many utilities, including the Company’s utilities, as well as other industries. Infrastructure Services generated approximately $784 million in gross revenues for 2013, compared to $664 million in 2012 and $421 million in 2011. Revenues in 2013 and 2012 have increased as a result of increased demand for services provided by both Miller and Minnesota Limited.
Backlog represents the amount of gross revenue the Company expects to realize from work to be performed in the future on uncompleted contracts, including new contractual agreements on which work has not begun. Infrastructure Services operates primarily under two types of contracts, blanket contracts and fixed price contracts. Using blanket contracts, customers are not contractually committed to specific volumes or specific time frames for project completion. These contracts are typically awarded on an annual basis. Under fixed price contracts, customers are contractually committed to a specific service to be performed for a specific price, whether in total for a project or on a per unit basis. At December 31, 2013, Infrastructure Services had an estimated backlog of blanket contracts of $458 million and a backlog of fixed price contracts of $77 million, for a total backlog of $535 million. The estimated backlog at December 31, 2012 was $278 million for blanket contracts and $101 million for fixed price contracts, for a total of $379 million.
The backlog amounts above reflect estimates of revenues to be realized under blanket contracts. Projects included in backlog can be subject to delays or cancellation as a result of regulatory requirements, adverse weather conditions, customer requirements, among other factors, which could cause actual revenue amounts to differ significantly from the estimates and/or revenues to be realized in periods other than originally expected.
Energy Services
Performance-based energy contracting operations and sustainable infrastructure projects are performed through Energy Systems Group, LLC (ESG). ESG assists schools, hospitals, governmental facilities, and other private institutions to reduce energy and maintenance costs by upgrading their facilities with energy-efficient equipment. ESG is also involved in developing sustainable infrastructure projects, including projects to process landfill gas into usable natural gas and electricity. ESG’s customer base is located throughout the Midwest, Mid-Atlantic, Southern and Southwestern United States. ESG generated revenues of approximately $91 million in 2013, compared to $118 million in 2012 and $162 million in 2011. ESG’s backlog at December 31, 2013 was $72 million, compared to $77 million at December 31, 2012.
Coal Mining
The Coal Mining group owns coal mines and sells coal to the Company’s utility operations and to other third parties through its wholly owned subsidiary, Vectren Fuels, Inc. The Company owns three underground mines (Prosperity, Oaktown 1, and Oaktown 2) and one reclaimed surface mine (Cypress Creek). All mines are located in Indiana. All coal is high-to-mid sulfur bituminous coal from the Illinois Basin. The Company engages contract mining companies to operate the coal mines. Coal mining generated approximately $293 million in gross revenues in 2013, compared to $236 million in 2012 and $286 million in 2011.
Oaktown Mine Expansion
In April 2006, Vectren Fuels announced plans to open two new underground mines. The first of two underground mines located near Vincennes, Indiana, began full operations in 2010. The second mine began operations during 2013. Reserves at the two mines are estimated at about 94 million tons of recoverable number-five coal at 11,200 BTU and less than 6-pound sulfur dioxide. At full production, the two mines are capable of producing about 5 million tons of coal per year.
The Oaktown mine infrastructure is located on 1,100 acres near Oaktown in Knox County, Indiana. Oaktown’s location is within 50 miles of multiple coal-fired power plants. It is estimated approximately 25,000 acres of coal will be mined during the life of
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both mines. Through December 31, 2013, approximately 2,353 acres of coal have been mined with approximately 22,647 acres remaining. Access to the Oaktown 1 mine was accomplished via a 90 foot deep box cut and a 2,200 foot slope on a 14 percent grade, reaching coal in excess of 375 feet below the surface. Access to the Oaktown 2 mine is via an 80 foot deep box cut and a 2,600 foot slope on a 14 percent grade, reaching coal in excess of 400 feet below the surface.
Both Oaktown mines are room and pillar underground mines meaning that main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof. Shuttle cars or similar transportation are used to transport coal to a conveyor belt for transport to the surface. The two Oaktown mines are separated by a sandstone channel. The coal seam thickness ranges from 4 feet to over 9 feet. The mine’s wash plant was originally sized to process 800 tons per hour and has been expanded to 1,600 tons per hour to accommodate the second mine. The two mines are connected to a railway equipped to handle 110 to 120 car unit trains. Coal is also transported via truck to customers, which include the Company’s power supply operations and other third party utilities. The total plant and development costs to date for the Oaktown mining complex are $291 million, inclusive of advance royalty payments. The remaining unamortized plant balance as of December 31, 2013 approximates $212 million, inclusive of $41 million of land and buildings, $169 million of mine development and equipment, and $2 million in advance royalty payments. Reserves, absent expansion, are expected to be completely exhausted over the next 20 years.
Prosperity Mine
Prosperity is an underground mine located on 1,100 surface acres outside of Petersburg in Pike County, Indiana. Prosperity is also a room and pillar mine where coal removal is accomplished with continuous mining machines. The mine entrance slopes gradually for 500 ft on a 9 degree grade and is more than 250 feet below ground level. The coal seam varies in thickness from 4-1/2 to 6 feet. The mine has a wash plant sized to process 1,000 tons per hour. The mine is connected to a railway and can handle 110 to 120 car unit trains. Coal is also transported via truck to customers, which include the Company's power supply operations and other third party utilities. The mine opened in 2001, and the total plant and development costs to date are $219 million. Through December 31, 2013, approximately 8,000 acres of coal have been mined, with approximately 12,000 acres remaining. Reserves at December 31, 2013 approximate 26.5 million tons. The remaining unamortized plant balance as of December 31, 2013 approximates $80 million, inclusive of $6 million of land and buildings and $74 million of mine development and equipment. Reserves, absent expansion, are expected to be exhausted by 2025.
Cypress Creek
Cypress Creek was an above-ground, or surface mine, located on 155 acres about 4 miles north of Boonville in Warrick County, Indiana. Cypress Creek was a combination truck/shovel, dozer push and high wall mining operation, meaning large shovels or front-end loaders removed earth and rock covering a coal seam and loading equipment placed the coal into trucks for transportation to a blending and loading area. The mine opened in 1998 and ceased operations in 2010. As of December 31, 2013, no significant reserves remain, the mine is substantially reclaimed, and the remaining carrying amount is not significant.
Following is summarized data regarding coal mining operations:
Prosperity | Oaktown Mine 1 | Oaktown Mine 2 | Totals | |||||||||
Type of Mining | Underground | Underground | Underground | |||||||||
Mining Technology | Room & Pillar | Room & Pillar | Room & Pillar | |||||||||
Tons Mined (in thousands) | ||||||||||||
2013 | 1,796 | 3,376 | 1,039 | 6,211 | ||||||||
2012 | 2,072 | 2,755 | — | 4,827 | ||||||||
2011 | 2,457 | 2,668 | — | 5,125 | ||||||||
County Located in Indiana | Pike | Knox | Knox | |||||||||
Coal Reserves (thousands of tons) | 26,547 | 56,733 | 37,737 | 121,017 | ||||||||
Average Heat Content (BTU/lb.) | 11,300 | 11,100 | 11,300 | |||||||||
Average Sulfur Content (lbs./ton) | 4.0 | 5.6 | 4.8 | |||||||||
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Mine Safety Information
The Company retains independent third party contract mining companies to operate its coal mines. Five Star Mining LLC ("Five Star") is the contract mining company at the Prosperity underground mine and Black Panther Mining LLC ("Black Panther") is the contract mining company at the Oaktown underground mines. The contract mining companies are the mine “operator”, as that term is used in both the Federal Mine Safety and Health Act of 1977 (the “Mine Act”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010. All employees at the coal mines are hired, supervised, and paid by the contract mining companies. As the mine operator, the contract mining companies make all regulatory filings required by the MSHA. In most circumstances, however, the cost of fines and penalties assessed by MSHA are contractually passed through from the contract mining company to Vectren Fuels. The process of settling such claims can take years in certain circumstances. During the years ended December 31, 2013 and 2012, the Company paid approximately $1.2 million and $0.7 million, respectively, related to assessments issued to the mine operators.
More detailed information about the Company’s mines, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Prosperity operates under the MSHA identification number 1202249; Oaktown 1 operates under the identification number 1202394; and Oaktown 2 operates under the identification number is 1202418. Mine safety-related data included on the MSHA website is influenced by the size of the mine, the level of activity at the mine, and the mine inspector’s judgment, among other factors. These factors can impact the comparability of information from mine to mine and time period to time period.
A significant increase in the frequency and scope of MSHA inspections continues generally. Over the twelve month period ended December 31, 2013 and as a direct result of continued focus on safe work practices, citations issued by MSHA have decreased significantly. While there has been a reduction in overall citations, on October 11, 2013, a Prosperity mine contract employee was fatally injured. Additionally, on October 23 and October 29, 2013, there were a significant number of unwarrantable failure citations written at Prosperity mine. Through the contract miner and consistent with past practice, the Company intends to fully evaluate the citations written. The process of review, challenge and resolution of any assessment could be lengthy. However, MSHA no longer is required to wait for final orders of citations before relying on those citations to place a mine on a Pattern of Violation (POV) status. If in the future, Prosperity mine were placed on POV status, any future elevated citation written would result in the affected area of the mine being temporarily idled until the issue causing the citation is resolved. While under POV status, citations written would result in more frequent downtime of portions or all of the mine, resulting in higher costs of production. Following the receipt of a number of citations written in the fourth quarter of 2013, and in a continuing effort to address compliance with MSHA requirements, Prosperity is in the process of finalizing a Corrective Action Program (CAP) to be submitted to MSHA which includes a framework of meaningful measures to address the multiple citations, a change in mine management, increased management oversight in problem areas, increased manpower dedicated to these problem areas, and a timetable for achieving reductions.
Energy Marketing
ProLiance
The Company has an investment in ProLiance, a nonutility affiliate of Vectren and 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. 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’s customers included, among others, Vectren’s Indiana utilities as well as Citizens’ utilities. Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member; and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting. The Company contracted for approximately 52 percent of its natural gas purchases through ProLiance in 2013. Additional information regarding the investment in ProLiance is included in Note 7 in the Company's Consolidated Financial Statements included in Item 8.
Vectren Source
Vectren Source, a former wholly owned subsidiary, provided natural gas and other related products and services in the Midwest and Northeast United States. On December 31, 2011, the Company sold Vectren Source for $84.3 million, excluding minor
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working capital adjustments. Gas sold by Vectren Source approximated 25.3 MMDth in 2011. Average customers served by Vectren Source were 254,000 in 2011. Vectren Source generated approximately $150 million in revenues for 2011.
Other Businesses
The Other Businesses group includes a variety of legacy, wholly owned operations and investments that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. Details of these investments is included in Note 8 in the Company's Consolidated Financial Statements included in Item 8.
Personnel
As of December 31, 2013, the Company and its consolidated subsidiaries had approximately 5,500 employees. Of those employees, 700 are subject to collective bargaining arrangements negotiated by Utility Holdings and 3,200 are subject to collective bargaining arrangements negotiated by Infrastructure Services.
Utility Holdings
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.
Infrastructure Services
The Company, through its Infrastructure Services subsidiaries, negotiates various trade agreements through contractor associations. The two primary associations are the Distribution Contractors Association (DCA) and the Pipeline Contractors Association (PLCA). These trade agreements are with a variety of construction unions including Laborer’s International Union of North America, International Union of Operating Engineers, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry, and Teamsters. The trade agreements through the DCA have varying expiration dates in 2015 and 2016. The trade agreements through the PLCA expire at various times in 2014. In addition, these subsidiaries have various project agreements and small local agreements. These agreements expire upon completion of a specific project or on various dates throughout the year.
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.
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Corporate Risks
Vectren is a holding company, and its assets consist primarily of investments in its subsidiaries.
Dividends on Vectren’s common stock depend on the earnings, financial condition, capital requirements and cash flow of its subsidiaries, principally Utility Holdings and Enterprises, and the distribution or other payment of earnings from those entities to Vectren. 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 the Company, its ability to pay dividends on its common stock could be limited and its stock price could be adversely affected. Vectren’s 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. Economic declines may be accompanied by a decrease in demand for products and services offered by nonutility operations and therefore lower revenues for those products and services. The economic conditions may have some negative impact on spending for utility and pipeline construction projects, demand for natural gas, electricity, and coal, and spending on performance contracting and renewable energy expansion. It is also possible that unfavorable conditions could lead to reductions in the value of certain nonutility real estate and other legacy investments.
Financial market volatility could have adverse impacts.
The capital and credit markets may experience volatility and disruption. If market disruption and volatility occurs, there can be no assurance that the Company will not experience adverse effects, which may be material. These effects may include, but are not limited to, difficulties in accessing the short and long-term debt capital markets and the commercial paper market, increased borrowing costs associated with current short-term debt obligations, higher interest rates in future financings, and a smaller potential pool of investors and funding sources. Finally, there is no assurance the Company will have access to the equity capital markets to obtain financing when necessary or desirable.
A downgrade (or negative outlook) in or withdrawal of Vectren’s credit ratings could negatively affect its ability to access capital and its cost.
The following table shows the current ratings assigned to the Company and its rated subsidiaries by Moody’s and Standard & Poor’s:
Current Rating | ||
Standard | ||
Moody’s | & Poor’s | |
Vectren Corporation's corporate credit rating | not rated | A- |
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.
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If the rating agencies downgrade the Company’s credit ratings, particularly below investment grade, or initiate negative outlooks thereon, or withdraw the Company's ratings or, in each case, the ratings of its subsidiaries, it may significantly limit the Company's access to the debt capital markets and the commercial paper market, and the Company’s borrowing costs would increase. In addition, the Company would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Finally, there is no assurance that the Company will have access to the equity capital markets to obtain financing when necessary or desirable.
Utility Operating Risks
Vectren’s gas and electric utility sales are concentrated in the Midwest.
The operations of the Company’s regulated utilities are concentrated in central and southern Indiana and west central Ohio and are therefore impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest. These industries include automotive assembly, parts and accessories; feed, flour and grain processing; metal castings, aluminum products, 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.
Vectren’s regulated utilities operate 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 Vectren’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 Vectren’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. Vectren 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 Vectren’s electric utility sales are space heating and cooling. Accordingly, its operating results may fluctuate with variability of weather.
Vectren’s electric utility sales are sensitive to variations in weather conditions. The Company forecasts utility sales on the basis of normal weather. Since Vectren does not have a weather-normalization mechanism for its electric operations, significant variations from normal weather could have a material impact on its earnings. However, the impact of weather on the gas operations in the Company’s Indiana territories has been significantly mitigated through the implementation 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.
Vectren’s utilities are exposed to increasing regulation, including pipeline safety, environmental, and cybersecurity regulation.
Vectren's utilities 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, Vectren is subject to regulation by the FERC, the
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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 Vectren's utilities are authorized to earn, and their 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
Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe, efficient, and reliable manner. Vectren'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 improvement. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Safety Law) was signed into law on January 3, 2012 and Vectren 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
Vectren's utility 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 Vectren'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.
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.
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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. Vectren 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 Vectren's utility rates charged to customers, its costs, and its profitability.
Any additional expenses or capital incurred by Vectren's utilities, 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, including industries in which the Company operates.
Vectren's utilities' 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 Vectren 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.
Vectren's regulated 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.
Vectren’s regulated 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.
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The Company participates in the MISO.
The Company is a member of the MISO, which serves the electric transmission needs of much of 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.
Vectren’s 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 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. 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
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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.
Nonutility Operating Risks
The performance of Vectren’s nonutility businesses is subject to certain risks.
Execution of the Company’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. These risks include, but are not limited to, the effects of weather; failure of installed performance contracting products to operate as planned; failure to properly estimate the cost to construct projects; failure to develop or obtain mining property; potential legislation or regulations that may limit CO2 and other greenhouse gases emissions; operating accidents that may require environmental remediation; failure to properly construct pipeline infrastructure; creditworthiness of customers and joint venture partners; changes in federal, state or local legal and regulatory requirements, such as changes in tax laws or rates; environmental or cybersecurity regulations, and changing market conditions.
Vectren’s nonutility businesses support its regulated 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.
Nonutility infrastructure services operations could be adversely affected by a number of factors.
Infrastructure Services results are dependent on a number of factors. The industry is competitive and many of the contracts are subject to a bidding process. Should Infrastructure Services be unsuccessful in bidding contracts, results of operations could be impacted. Infrastructure Services enters into a variety of contracts, some of which are fixed price. Through competitive bidding, the volume of contracted work could vary significantly from year to year. Further, to the extent there are unanticipated cost increases in completion of the contracted work, the profit margin realized on any single project could be reduced. Additionally, Infrastructure Services contributes to several multi-employer pension plans under collective bargaining agreements with unions representing employees covered by those agreements. A significant increase to the funding requirements could adversely impact financial condition, results of operations, and/or cash flows. Changes in legislation and regulations impacting the industries in which the customers served by Infrastructure Services operate could impact operating results. Other risks include, but are not limited to: the effects of weather; failure to properly estimate the cost to construct projects; the ability to attract and retain qualified employees; cancellation of projects by customers and/or reductions in the scope of the projects; credit worthiness of customers; ability to obtain materials and equipment required to perform services from suppliers and manufacturers; and changing market conditions.
Nonutility coal mining operations could be adversely affected by a number of factors.
The success of coal mining operations is predicated on the ability to fully access coal at company-owned mines; 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; to negotiate and execute new sales contracts; to adapt to any new laws or rules, such as climate change or air quality legislation, that impact users of coal; and to manage production and production costs and other risks in response to changes in demand. Other risks, which could adversely impact operating results, include but are not limited to: market demand for the Company's coal including impacts of fuel switching to alternative sources and coal specifications in terms of sulfur and mercury, among others; geologic, equipment, and operational risks; supplier and contract miner performance; the availability of miners, key equipment and commodities; availability of transportation; and the ability to access/replace coal reserves. Coal sales and production could be impacted by significant variations in weather and have a material impact on the Company’s earnings.
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In addition, coal mining operations have exposure to coal commodity prices. If coal commodity prices change in a direction or manner that is not anticipated, or if the forecasted sales transactions do not occur, losses may result. Although forecasted sales are hedged with owned coal inventory and known reserves, all exposure to both short and long-term coal price volatility is not hedged. Therefore, fluctuating coal prices are likely to cause the Company’s net income to be volatile.
The Company could be negatively impacted by declines in the market demand for coal.
With respect to its Coal Mining operations, the Company competes with coal producers in the Illinois Basin and in other coal producing regions of the United States. The domestic demand for, and prices for, the Company's coal primarily depend on the coal consumption patterns of the domestic electric utility industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments, and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric power, and other renewable energy sources. The domestic electric utility industry currently accounts for approximately 90 percent of domestic coal consumption. Moreover, in 2012 the Energy Information Administration estimated that coal consumption in the electric power sector totaled 829 million tons, the lowest amount since 1992 primarily due to historically low natural gas prices paid by the electric generators that led to a significant increase in the share of natural gas-fired power generation. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. Consequently, a decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact the Company's results of operations and liquidity. Additionally, during the last several years the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for or pricing of the Company's coal, which could adversely impact the Company's results of operations.
Mining in the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our mining operations and cost structures in these areas.
The geological characteristics of the Illinois Basin coal reserves, such as elevated sulfur content, depth of overburden, and coal seam thickness, among other factors, makes such reserves complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available may not be capable of being mined at costs comparable to those of the depleting mines. In addition, the composition of the Illinois Basin coal reserves compared to reserves from other regions of the United States or international sources may make such Illinois Basin coal less desirable as a fuel source. These factors could have a material adverse effect on the mining operations, cost structures, and the results of the operations of the Company's Coal Mining group.
Other Corporate Operating Risks
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.
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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.
Vectren’s subsidiaries have performance and warranty obligations, some of which are guaranteed by Vectren.
In the normal course of business, subsidiaries of Vectren issue performance bonds and other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations. Vectren Corporation, as the parent company, will from time to time guarantee its subsidiaries’ commitments. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary obligations in order to allow those subsidiaries the flexibility to conduct business without posting other forms of collateral. The Company has not been called upon to satisfy any obligations pursuant to these parental guarantees.
Certain of Vectren's nonutility operations face a customer concentration risk. The loss of such a customer would result in a decline in revenue and could have an adverse effect on the results of operations and cash flows.
For the year ended December 31, 2013, revenues from one customer of Infrastructure Services individually accounted for approximately 9 percent of the Company's consolidated operating revenues. The total outstanding receivable from this customer at December 31, 2013 was approximately 16 percent of the Company's total receivables, including accrued unbilled revenues. While the Company believes that the loss of any one customer would not have a material impact on its financial position or results of operations, the loss of this customer or a significant decline in customer related revenue could have an adverse effect on the results of operations and cash flows of Infrastructure Services.
From time to time, Vectren 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 Vectren’s business, prospects, corporate reputation, results of operations, or financial condition.
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The investment performance of pension plan holdings and other factors impacting pension plan costs could impact Vectren’s liquidity and results of operations.
The costs associated with the Company sponsored retirement plans, including certain multi-employer plans at Infrastructure Services, 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 regulations; and Company contributions. In addition, the Company could be required to provide for significant funding of these defined benefit pension 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 Vectren’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 Vectren’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, Vectren 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, Vectren 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 Vectren’s 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.
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
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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.
Nonutility and Other Properties
Subsidiaries other than the utility operations and Vectren Affiliated Utilities, Inc. have no significant properties other than the ownership of coal mining property in Indiana which is identified in Item 1.
Vectren Affiliated Utilities, Inc. owns and operates one active gas storage field located in Indiana covering 2,900 acres of land with an estimated ready delivery from storage capability of 0.8 BCF of gas with maximum peak day delivery capability of 8,000 MCF per day. In addition to the storage field, a compressor station with two 1,500 hp compressors is capable of moving gas from storage to one of two pipeline suppliers in the area, or compress unidirectionally from one pipeline supplier to the other pipeline supplier.
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.
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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.
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PART II
ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER
PURCHASES OF EQUITY SECURITIES
Market Data, Dividends Paid, and Holders of Record
The Company’s common stock trades on the New York Stock Exchange under the symbol ‘‘VVC.’’ For each quarter in 2013 and 2012, the high and low sales prices for the Company’s common stock as reported on the New York Stock Exchange and dividends paid are presented below.
Cash | Common Stock Price Range | |||||||
Dividend | High | Low | ||||||
2013 | ||||||||
First Quarter | $0.355 | $35.63 | $32.45 | |||||
Second Quarter | 0.355 | 37.88 | 31.83 | |||||
Third Quarter | 0.355 | 37.57 | 32.15 | |||||
Fourth Quarter | 0.360 | 35.45 | 29.47 | |||||
2012 | ||||||||
First Quarter | $0.350 | $30.69 | $28.21 | |||||
Second Quarter | 0.350 | 30.17 | 28.03 | |||||
Third Quarter | 0.350 | 30.75 | 27.78 | |||||
Fourth Quarter | 0.355 | 30.25 | 27.46 | |||||
On January 30, 2014 the board of directors declared a dividend of $0.36 per share, payable on March 3, 2014, to common shareholders of record on February 14, 2014.
As of January 31, 2014, there were 8,557 registered shareholders of the Company’s common stock.
Quarterly Share Purchases
Periodically, the Company purchases shares from the open market to satisfy share requirements associated with the Company’s share-based compensation plans; however, no such open market purchases were made during the quarter ended December 31, 2013.
Dividend Policy
Common stock dividends are payable at the discretion of the board of directors, out of legally available funds. The Company’s policy is to distribute approximately 65 percent of earnings over time. On an annual basis, this percentage has varied and could continue to vary due to short-term earnings volatility. The Company has increased its dividend for 54 consecutive years. While the Company is under no contractual obligation to do so, it intends to continue to pay dividends and increase its annual dividend consistent with historical practice. Nevertheless, should the Company’s financial condition, operating results, capital requirements, or other relevant factors change, future dividend payments, and the amounts of these dividends, will be reassessed.
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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, except per share data) | 2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
Operating Data: | ||||||||||||||||||||
Operating revenues | $ | 2,491.2 | $ | 2,232.8 | $ | 2,325.2 | $ | 2,129.5 | $ | 2,088.9 | ||||||||||
Operating income | $ | 333.6 | $ | 352.5 | $ | 370.0 | $ | 316.8 | $ | 280.1 | ||||||||||
Net income | $ | 136.6 | $ | 159.0 | $ | 141.6 | $ | 133.7 | $ | 133.1 | ||||||||||
Average common shares outstanding | 82.3 | 82.0 | 81.8 | 81.2 | 80.7 | |||||||||||||||
Fully diluted common shares outstanding | 82.4 | 82.1 | 81.8 | 81.3 | 81.0 | |||||||||||||||
Basic earnings per share | ||||||||||||||||||||
on common stock | $ | 1.66 | $ | 1.94 | $ | 1.73 | $ | 1.65 | $ | 1.65 | ||||||||||
Diluted earnings per share | ||||||||||||||||||||
on common stock | $ | 1.66 | $ | 1.94 | $ | 1.73 | $ | 1.64 | $ | 1.64 | ||||||||||
Dividends per share on common stock | $ | 1.425 | $ | 1.405 | $ | 1.385 | $ | 1.365 | $ | 1.345 | ||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Total assets | $ | 5,102.6 | $ | 5,089.1 | $ | 4,878.9 | $ | 4,764.2 | $ | 4,671.8 | ||||||||||
Long-term debt, net | $ | 1,777.1 | $ | 1,553.4 | $ | 1,559.6 | $ | 1,435.2 | $ | 1,540.5 | ||||||||||
Common shareholders' equity | $ | 1,554.3 | $ | 1,526.1 | $ | 1,465.5 | $ | 1,438.9 | $ | 1,397.2 | ||||||||||
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Executive Summary of Consolidated Results of Operations
In this discussion and analysis, the Company analyzes contributions to consolidated earnings and earnings per share from its Utility Group and Nonutility Group separately since each operates independently requiring distinct competencies and business strategies, offers different energy and energy related products and services, and experiences different opportunities and risks.
The Utility Group generates revenue primarily from the delivery of natural gas and electric service to its customers. The primary source of cash flow for the Utility Group results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. The Company segregates its regulated utility operations between a Gas Utility Services operating segment and an Electric Utility Services operating segment. The activities of, and revenues and cash flows generated by, the Nonutility Group are closely linked to the utility industry, and the results of those operations are generally impacted by factors similar to those impacting the overall utility industry. In addition, there are other operations, referred to herein as Corporate and Other, that include unallocated corporate expenses such as advertising and charitable contributions, among other activities.
The Company has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of the Company’s SEC filings.
Results for the year ended December 31, 2013 were earnings of $136.6 million, or $1.66 per share, compared to earnings of $159.0 million, or $1.94 per share for the year ended December 31, 2012 and $141.6 million, or $1.73 per share for the year ended December 31, 2011. In June 2013, ProLiance Holdings, LLC exited the gas marketing business through the disposition of certain of the net assets of its energy marketing subsidiary, ProLiance Energy, LLC. In December 2011, the Company sold Vectren Source, a wholly owned gas marketer. Excluding ProLiance results in 2013 totaling $37.5 million, or $0.46 per share, consolidated net income for the year ended December 31, 2013 was $174.1 million, or $2.12 per share. In 2012, excluding ProLiance results, totaling $17.6 million, or $0.21 per share, consolidated net income for the year ended December 31, 2012 was $176.6 million, or $2.15 per share. In 2011, excluding the results of ProLiance and Source, including the gain on disposition of Source, totaling $4.2 million, or $.05 per share, consolidated net income for the year ended December 31, 2011 was $145.8 million, or $1.78 per share.
Losses Related to the Exit of the Gas Marketing Business by ProLiance
Through June 18, 2013, the Company recorded its share of losses related to the sale of certain assets of ProLiance's subsidiary, ProLiance Energy. In the Consolidated Statements of Income, the loss on the disposition of these assets is a $41.9 million impact to Equity in losses of unconsolidated affiliates, a $1.7 million charge to Operating expense, and an income tax benefit reflected in Income taxes of $16.8 million. More detailed information about ProLiance Energy's sale of certain assets is included in Note 7 to the Company's Consolidated Financial Statements included in Item 8. In addition to the losses associated with the sale of certain assets, the Company recorded its share of operating losses from ProLiance through June 18, 2013 totaling $10.7 million, net of tax. In total, the Company's share of ProLiance's results reflects a net loss of $37.5 million, net of tax, for the period January 1, 2013 through June 18, 2013. Operating losses for ProLiance totaled $17.6 million, net of tax, for the year ended December 31, 2012 and $22.9 million for the year ended December 31, 2011. Subsequent to the sale and through December 31, 2013, there were minor charges related to the wind down of the ProLiance operations. This final true-up from the ProLiance sale and other minor operating results of the remaining ProLiance investments is reflected in Other Businesses.
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Consolidated Results Excluding the Results From Energy Marketing (See Page 29, regarding the Use of Non-GAAP Measures)
Net income and earnings per share, excluding results from Energy Marketing, in total and by group, for the years ended December 31, 2013, 2012, and 2011 follow:
Year Ended December 31, | ||||||||||||
(In millions, except per share data) | 2013 | 2012 | 2011 | |||||||||
Net income, excluding Energy Marketing results | $ | 174.1 | $ | 176.6 | $ | 145.8 | ||||||
Attributed to: | ||||||||||||
Utility Group | $ | 141.8 | $ | 138.0 | $ | 122.9 | ||||||
Nonutility Group, excluding Energy Marketing results | 33.0 | 39.3 | 28.0 | |||||||||
Corporate & Other | (0.7 | ) | (0.7 | ) | (5.1 | ) | ||||||
Basic EPS, excluding Energy Marketing results | $ | 2.12 | $ | 2.15 | $ | 1.78 | ||||||
Attributed to: | ||||||||||||
Utility Group | $ | 1.72 | $ | 1.68 | $ | 1.50 | ||||||
Nonutility Group, excluding Energy Marketing results | 0.41 | 0.47 | 0.34 | |||||||||
Corporate & Other | (0.01 | ) | — | (0.06 | ) | |||||||
Utility Group
For the year ended December 31, 2013, the Utility Group earnings were $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.
Gas utility services
The gas utility segment earned $55.7 million during the year ended December 31, 2013, compared to $60.0 million in 2012 and $52.5 million in 2011. Though customer margin increased in 2013 from customer growth and returns 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 Group 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.
Nonutility Group
Excluding results for Energy Marketing, the Nonutility Group earned $33.0 million in 2013, compared to earnings of $39.3 million in 2012 and $28.0 million in 2011. Results over the periods presented were favorably impacted by the March 31, 2011
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acquisition of Minnesota Limited and significantly higher demand for pipeline construction and repair. Results also reflect losses at Coal Mining of $16.0 million in 2013 and $3.5 million in 2012, compared to earnings of $16.6 million in 2011. Finally, results were impacted by charges related to legacy investments totaling $1.2 million, $2.2 million and $9.2 million in 2013, 2012 and 2011, respectively.
Corporate & Other
The results in Corporate and Other during 2011 primarily reflect a contribution to the Vectren Foundation, a 501(c)(3) charitable organization, totaling $6.0 million, or $3.9 million after tax. The contribution is reflected in Other operating expenses in the consolidated financial statements.
Dividends
Dividends declared for the year ended December 31, 2013 were $1.425 per share, compared to $1.405 per share in 2012 and $1.385 per share in 2011. In November 2013, the Company’s board of directors increased its quarterly dividend to $0.360 per share from $0.355 per share. The increase marks the 54th consecutive year Vectren and predecessor companies’ have increased annual dividends paid.
Use of Non-GAAP Performance Measures and Per Share Measures
Results Excluding Energy Marketing
This discussion and analysis contains non-GAAP financial measures that exclude the results related to the Company's Energy Marketing business area.
Management uses consolidated net income, consolidated earnings per share, and Nonutility Group net income, excluding the results from Energy Marketing, to evaluate its results. The Energy Marketing business area is comprised of ProLiance and Source. Management believes analyzing underlying and ongoing business trends is aided by the removal of the Energy Marketing results and the rationale for using such non-GAAP measures is that, through the disposition by ProLiance of certain ProLiance Energy assets as well as the sale of Source in 2011, the Company has now exited the gas marketing business.
A material limitation associated with the use of these measures is that the measures that exclude ProLiance and Source results do not include all costs recognized in accordance with GAAP. Management compensates for this limitation by prominently displaying a reconciliation of these non-GAAP performance measures to their closest GAAP performance measures. This display also provides financial statement users the option of analyzing results as management does or by analyzing GAAP results.
Contribution to Vectren's basic EPS
Per share earnings contributions of the Utility Group, Nonutility Group excluding Energy Marketing results, and Corporate and Other are presented and are non-GAAP measures. Such per share amounts are based on the earnings contribution of each group included in Vectren’s consolidated results divided by Vectren’s basic average shares outstanding during the period. The earnings per share of the groups do not represent a direct legal interest in the assets and liabilities allocated to the groups, but rather represent a direct equity interest in Vectren Corporation's assets and liabilities as a whole. These non-GAAP measures are used by management to evaluate the performance of individual businesses. In addition, other items giving rise to period over period variances, such as weather, may be presented on an after tax and per share basis. These amounts are calculated at a statutory tax rate divided by Vectren’s basic average shares outstanding during the period. Accordingly, management believes these measures are useful to investors in understanding each business’ contribution to consolidated earnings per share and in analyzing consolidated period to period changes and the potential for earnings per share contributions in future periods. Reconciliations of the non-GAAP measures to their most closely related GAAP measure of consolidated earnings per share are included throughout this discussion and analysis. The non-GAAP financial measures disclosed by the Company should not be considered a substitute for, or superior to, financial measures calculated in accordance with GAAP, and the financial results calculated in accordance with GAAP.
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The following table reconciles consolidated net income, consolidated basic EPS, and Nonutility Group net income to those results excluding Energy Marketing results.
Twelve Months Ended December 31, 2013 | |||||||||
(In millions, except EPS) | GAAP Measure | Add back Energy Marketing Losses | Non-GAAP Measure | ||||||
Consolidated | |||||||||
Net Income | $ | 136.6 | $ | 37.5 | $ | 174.1 | |||
Basic EPS | $ | 1.66 | $ | 0.46 | $ | 2.12 | |||
Nonutility Group Net Income (Loss) | $ | (4.5 | ) | $ | 37.5 | $ | 33.0 | ||
Twelve Months Ended December 31, 2012 | |||||||||
(In millions, except EPS) | GAAP Measure | Add back Energy Marketing Losses | Non-GAAP Measure | ||||||
Consolidated | |||||||||
Net Income | $ | 159.0 | $ | 17.6 | $ | 176.6 | |||
Basic EPS | $ | 1.94 | $ | 0.21 | $ | 2.15 | |||
Nonutility Group Net Income | $ | 21.7 | $ | 17.6 | $ | 39.3 | |||
Twelve Months Ended December 31, 2011 | |||||||||
(In millions, except EPS) | GAAP Measure | Add back Energy Marketing Losses | Non-GAAP Measure | ||||||
Consolidated | |||||||||
Net Income | $ | 141.6 | $ | 4.2 | $ | 145.8 | |||
Basic EPS | $ | 1.73 | $ | 0.05 | $ | 1.78 | |||
Nonutility Group Net Income | $ | 23.8 | $ | 4.2 | $ | 28.0 | |||
Detailed Discussion of Results of Operations
Following is a more detailed discussion of the results of operations of the Company’s Utility and Nonutility operations. The detailed results of operations for these groups are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company’s Consolidated Statements of Income.
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Results of Operations of the Utility Group
The Utility Group is comprised of Utility Holdings’ operations, which consists of the Company’s regulated utility operations and other operations that provide information technology and other support services to those regulated operations. Regulated operations consist of a natural gas distribution business that provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio and an electric transmission and distribution business, which provides electric distribution services primarily to southwestern Indiana, and its power generating and wholesale power operations. In total, these regulated operations supply natural gas and/or electricity to over one million customers. Utility Group operating results before certain intersegment eliminations follow:
Year Ended December 31, | ||||||||||||
(In millions, except per share data) | 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 | ||||||
CONTRIBUTION TO VECTREN BASIC EPS | $ | 1.72 | $ | 1.68 | $ | 1.50 | ||||||
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
29
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.
Utility Group Margin
Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas 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.
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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.
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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 power & transmission system 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 | |||||||||
Other customers | 21.8 | 22.6 | 22.8 | |||||||||
Total retail 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
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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 | |||||||||
MISO Transmission system margin | $ | 29.4 | $ | 26.4 | $ | 23.5 | ||||||
MISO 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.
Utility Group 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.
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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 Group 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
Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. Vectren'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
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 million. During 2013, 2012, and 2011 gas operating revenues associated with the
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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. Of this total amount, $34.8 million relates to expenditures that potentially could be recoverable under the pending DRR discussed above. If this amount is found by the PUCO to not be recoverable through the DRR, the order granted deferral for future recovery through a House Bill 95 mechanism. 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.
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.
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
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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 April 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.
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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 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
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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 return would equate to approximately $0.8 million of net income on an annual basis.
Environmental Matters
The Company's utility 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 to 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 SO2 and NOx allowances, CSAPR reduced the ability of facilities to meet emission
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reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO2 and 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 (SCRs) 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
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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 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.
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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.
Vectren is 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.
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Current Initiatives to Increase Conservation & Reduce Emissions
The Company is committed to a policy that reduces greenhouse gas emissions and conserves energy usage. Evidence of this commitment includes:
• | 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; |
• | Reducing the Company’s carbon footprint by measures such as utilizing hybrid vehicles and optimizing generation efficiencies by utilizing dense pack technology; and |
• | Developing renewable energy and energy efficiency performance contracting projects through its wholly owned subsidiary, Energy Systems Group. |
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, nonutility coal mining operations, 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.
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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.
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Results of Operations of the Nonutility Group
The Nonutility Group operates in three primary business areas: Infrastructure Services, Energy Services, and Coal Mining. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides performance contracting and sustainable infrastructure services. Coal Mining owns, and through its contract miners, mines and then sells coal. There are also other legacy businesses that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. The Nonutility Group supports the Company’s regulated utilities by providing infrastructure services and coal. Prior to June 18, 2013, the Company, through Enterprises, was involved in nonutility activities in its Energy Marketing business area. Energy Marketing marketed and supplied natural gas and provided energy management services through ProLiance and in 2011, through Vectren Source. Pursuant to service contracts, Energy Marketing provided the Company's Indiana regulated utilities natural gas supply services. The Nonutility Group results were losses of $4.5 million for the year ended December 31, 2013, and earnings of $21.7 million and $23.8 million for the years ended December 31, 2012 and 2011, respectively. Nonutility Group earnings, excluding the results from Energy Marketing, for the years ended December 31, 2013, 2012, and 2011, follow:
Year Ended December 31, | ||||||||||||
(In millions, except per share amounts) | 2013 | 2012 | 2011 | |||||||||
NET INCOME EXCLUDING ENERGY MARKETING RESULTS | $ | 33.0 | $ | 39.3 | $ | 28.0 | ||||||
CONTRIBUTION TO VECTREN BASIC EPS, EXCLUDING ENERGY MARKETING RESULTS | $ | 0.41 | $ | 0.47 | $ | 0.34 | ||||||
NET INCOME (LOSS) ATTRIBUTED TO: | ||||||||||||
Infrastructure Services | $ | 49.0 | $ | 40.5 | $ | 14.9 | ||||||
Energy Services | 1.0 | 5.7 | 6.7 | |||||||||
Coal Mining | (16.0 | ) | (3.5 | ) | 16.6 | |||||||
Other Businesses | (1.0 | ) | (3.4 | ) | (10.2 | ) | ||||||
Infrastructure Services
Infrastructure Services provides underground pipeline construction and repair services through wholly-owned subsidiaries Miller Pipeline, LLC (Miller) and Minnesota Limited, LLC (Minnesota Limited), which was acquired on March 31, 2011. Inclusive of holding company costs, earnings from Infrastructure Services' operations for the year ended December 31, 2013 were $49.0 million, compared to $40.5 million in 2012 and $14.9 million in 2011. The increased earnings in 2013 reflect the continuation of strong demand for infrastructure services. Total Infrastructure Services gross revenues in 2013 were $784 million, compared to gross revenues of $664 million in 2012 and $421 million in 2011. Construction activity generally is expected to remain strong as utilities, municipalities and pipeline operators replace their aging natural gas and oil pipelines and related infrastructure. In addition, construction activity is expected to be favorably impacted as pipeline operators construct new pipelines due to the continued strong demand for shale gas and oil infrastructure.
Backlog represents the amount of gross revenue the Company expects to realize from work to be performed in the future on uncompleted contracts, including new contractual agreements on which work has not begun. Infrastructure Services operates primarily under two types of contracts, blanket contracts and fixed price contracts. Using blanket contracts, customers are not contractually committed to specific volumes or specific time frames for project completion. These contracts are typically awarded on an annual basis. Under fixed price contracts, customers are contractually committed to a specific service to be performed for a specific price, whether in total for a project or on a per unit basis. At December 31, 2013, Infrastructure Services had an estimated backlog of blanket contracts of $458 million and a backlog of fixed price contracts of $77 million, for a total backlog of $535 million. The estimated backlog at December 31, 2012 was $278 million for blanket contracts and $101 million for fixed price contracts, for a total of $379 million.
The backlog amounts above reflect estimates of revenues to be realized under blanket contracts. Projects included in backlog can be subject to delays or cancellation as a result of regulatory requirements, adverse weather conditions, customer requirements, among other factors, which could cause actual revenue amounts to differ significantly from the estimates and/or revenues to be realized in periods other than originally expected.
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Acquisition of Minnesota Limited
On March 31, 2011, the Company purchased Minnesota Limited, excluding certain assets. Minnesota Limited is a specialty contractor focusing on natural gas and oil transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing. Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region. The purchase price was approximately $83.4 million and included $14.8 million of net working capital, $34.4 million of property plant and equipment and $39.4 million of intangible assets, including goodwill.
Energy Services
Energy Services provides energy performance contracting and sustainable infrastructure projects through its wholly owned subsidiary, Energy Systems Group, LLC (ESG). Inclusive of holding company costs, Energy Services’ operations contributed earnings of $1.0 million in 2013, compared to $5.7 million in 2012 and $6.7 million in 2011.
Results in 2013 reflect continued lower revenues from slow demand for performance contracting projects due primarily to budgetary constraints for state, municipal, and school customers. The unfavorable earnings impact due to continued slow demand in 2013 was partially offset by tax deductions associated with energy efficiency projects. Total deductions in 2013 were $19.3 million compared to $17.8 million in 2012 and $6.2 million in 2011. The impact of these tax deductions on earnings in 2013 was $7.8 million, compared to $7.2 million in 2012, and $2.5 million in 2011. Under current tax legislation, these deductions expired on December 31, 2013. Results in 2012 reflect decreased earnings compared to 2011 associated with an increase in the sales force.
As of December 31, 2013, the performance contracting backlog was $72 million, compared to $77 million at December 31, 2012 and $82 million at December 31, 2011. ESG continues to develop strategies to position it for growth as the national focus on energy conservation and sustainable infrastructure continues for the long-term given the increase in power prices across the country.
Coal Mining
Coal Mining owns mines that produce and sell coal to the Company’s utility operations and to third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Vectren Fuels). Results from Coal Mining, inclusive of holding company costs, were losses of $16.0 million in 2013 and $3.5 million in 2012, compared to earnings of $16.6 million in 2011.
Coal Mining revenues were $293 million in 2013 compared to $236 million in 2012, and $286 million in 2011. While coal sales and related revenues were higher in 2013 compared to 2012 due to additional volumes sold of 1.8 million tons, results in 2013 were lower due to higher production costs associated with a thin coal seam and other unfavorable mining conditions at Prosperity mine. In the second half of the year, substantial progress was made in the execution of a revised mining plan at Prosperity mine, resulting in lower production costs. While the revised mining plan has resulted in lower costs of production at Prosperity, and with continued focus on safety, further cost reductions are necessary and remain a priority for 2014. Lower 2013 results were also driven by reduced pricing for customers associated with contracts that had price reopener clauses during 2012 and the overall softness in the coal market. Coal sales increased in 2013 to 6.2 million tons, compared to 4.5 million tons in 2012. Tons sold in 2012 were unfavorably impacted by the low cost of natural gas and mild winter weather. These factors significantly reduced the demand for coal.
Vectren Fuels' expects production of 7.3 million tons and sales of 7.6 million tons in 2014. Expected production increases in 2014 primarily relate to having a full year of operation at the second mine at the Company's Oaktown mining complex, which opened during the second quarter of 2013. The increased sales in 2014 include 0.3 million tons under contract carried over from 2013 that were not sold due to weather related delivery issues. These tons were held in inventory at December 31, 2013. Approximately 90 percent of the expected 2014 sales are committed and priced. Longer term, the Company continues to believe that reduced coal volumes available from Central Appalachia due to increased regulation and the large number of scrubbers to be installed throughout the United States, including the Midwest, coupled with moderate increases in natural gas prices from the very low levels experienced in 2012, should drive stronger demand for Illinois Basin coal. Changes in market conditions or other circumstances could cause actual results to be materially different from these expectations.
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Coal Reserves
As of December 31, 2013, management estimates the Company’s total Illinois Basin coal reserves to be approximately 121 million tons. Vectren Fuels' three underground mines are capable of producing up to 7.5 million tons of coal per year.
Mine Safety Information
The Company retains independent third party contract mining companies to operate its coal mines. Five Star Mining LLC ("Five Star") is the contract mining company at the Prosperity underground mine and Black Panther Mining LLC ("Black Panther") is the contract mining company at the Oaktown underground mines. The contract mining companies are the mine “operator”, as that term is used in both the Federal Mine Safety and Health Act of 1977 (the “Mine Act”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010. All employees at the coal mines are hired, supervised, and paid by the contract mining companies. As the mine operator, the contract mining companies make all regulatory filings required by the MSHA. In most circumstances, however, the cost of fines and penalties assessed by MSHA are contractually passed through from the contract mining company to Vectren Fuels. The process of settling such claims can take years in certain circumstances. During the year ended December 31, 2013, the Company paid approximately $1.2 million related to assessments issued to the mine operators.
More detailed information about the Company’s mines, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Prosperity operates under the MSHA identification number 1202249; Oaktown 1 operates under the identification number 1202394; and Oaktown 2 operates under the identification number 1202418. Mine safety-related data included on the MSHA website is influenced by the size of the mine, the level of activity at the mine, and the mine inspector’s judgment, among other factors. These factors can impact the comparability of information from mine to mine and time period to time period.
A significant increase in the frequency and scope of MSHA inspections continues generally. Over the twelve month period ended December 31, 2013 and as a direct result of continued focus on safe work practices, citations issued by MSHA have decreased significantly. While there has been a reduction in overall citations, on October 11, 2013, a Prosperity mine contract employee was fatally injured. Additionally, on October 23 and October 29, 2013, there were a significant number of unwarrantable failure citations written at Prosperity mine. Through the contract miner and consistent with past practice, the Company intends to fully evaluate the citations written. The process of review, challenge and resolution of any assessment could be lengthy. However, MSHA no longer is required to wait for final orders of citations before relying on those citations to place a mine on a Pattern of Violation (POV) status. If in the future, Prosperity mine were placed on POV status, any future elevated citation written would result in the affected area of the mine being temporarily idled until the issue causing the citation is resolved. While under POV status, citations written would result in more frequent downtime of portions or all of the mine, resulting in higher costs of production. Following the receipt of a number of citations written in the fourth quarter of 2013, and in a continuing effort to address compliance with MSHA requirements, Prosperity is in the process of finalizing a Corrective Action Program (CAP) to be submitted to MSHA which includes a framework of meaningful measures to address the multiple citations, a change in mine management, increased management oversight in problem areas, increased manpower dedicated to these problem areas, and a timetable for achieving reductions.
Energy Marketing
ProLiance
The Company 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. Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however, governance and voting rights remain at 50 percent for each member; and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.
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Vectren Energy Marketing and Services, Inc (EMS), a wholly owned subsidiary, holds the Company’s investment in ProLiance. EMS is responsible for certain financing costs associated with ProLiance and is also responsible for income taxes and allocated corporate expenses related to the Company’s portion of ProLiance’s results. For the year ended December 31, 2013, EMS results related to the Company’s share of ProLiance’s results, which include financing costs, income taxes, and other holding company costs and inclusive of the loss associated with exiting the business as discussed below, were a loss of $37.5 million, compared to losses of $17.6 and $22.9 million in 2012 and 2011, respectively.
On June 18, 2013, ProLiance exited the natural gas marketing business by disposing of certain of the net assets, along with the long-term pipeline and storage commitments, of its gas marketing subsidiary, ProLiance Energy to a subsidiary of Energy Transfer Partners, ETC Marketing, Ltd (ETC). As a result of this transaction, the Company recorded its share of the loss on the disposition, termination of long-term pipeline and storage commitments, and related transaction and other costs totaling $43.6 million pre-tax, or $26.8 million net of tax, during the second quarter of 2013. ProLiance funded an estimated equity shortfall at ProLiance Energy of $16.6 million at the time of the sale. To fund this estimated shortfall, the Company issued a note to ProLiance for its 61 percent ownership share of the $16.6 million shortfall, or $10.1 million, which was utilized by ProLiance to invest additional equity in ProLiance Energy. This interest-bearing note is classified as Other nonutility investments in the Consolidated Balance Sheets. After consideration of cash generated from the tax benefit of losses, the net impact on cash to the Company was generally neutral. In addition to the losses associated with the disposition of certain of the net assets, the Company recorded its share of operating losses from ProLiance totaling $10.7 million, net of tax, for the year.
With FERC approval, ETC has taken assignment of the Portfolio Administration Agreements (PAAs) pursuant to which the utilities receive gas supply. With the receipt of the FERC waivers and with pipeline contracts having been transferred to the utilities, the utilities entered into an Asset Management Agreement (AMA) with ETC on September 1, 2013 and have temporarily released the pipeline contracts to ETC. ETC will fulfill the requirements of the PAAs through their remaining term ending in March 2016.
For the years ended December 31, 2013, 2012, and 2011 the amounts recorded to Equity in (losses) of unconsolidated affiliates related to ProLiance's results totaled a pre-tax loss of $57.7 million, $22.7 million, and $28.6 million respectively. At December 31, 2013, ProLiance had approximately $50.7 million of capitalization remaining on its balance sheet, comprised of $34.1 million in member's equity and $16.6 million in a note payable. The remaining capitalization is supported by its investment in LA Storage, formerly named Liberty Gas Storage, LLC (Liberty) of $35.4 million, one other midstream asset, $12.5 million in cash, and a small amount of other working capital. The Company's remaining investment in ProLiance at December 31, 2013 totals $30.9 million and is comprised of $20.8 million of equity and a $10.1 million note receivable.
LA Storage, LLC Storage Asset Investment, Formerly Referred to as Liberty Gas Storage
ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage, LLC (LA Storage). PT&S is the minority member with a 25 percent interest, which it accounts for using the equity method. The project was expected to include 17 Bcf of capacity in its North site, and an additional capacity of at least 17 Bcf at the South site. The South site also has the potential for further expansion. The LA Storage pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines & Storage, and will connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities.
In late 2008, the project at the North site was halted due to subsurface and well-completion problems, which resulted in the joint venture recording a $132 million impairment charge. The Company, through ProLiance, recorded its share of the charge in 2009. As a result of the issues encountered at the North site, FERC approved the separation of the North site from the South site. Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to connect the caverns to the pipeline system. ProLiance's investment in the joint venture at December 31, 2013 is approximately $35.4 million.
The joint venture received a demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between the joint venture and Williams at the North site. Williams alleges that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns. Williams alleges damages of $56.7 million. The joint venture intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. As such, as of December 31, 2013, ProLiance has
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no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.
Vectren Source
Vectren Source, a former wholly owned subsidiary, provided natural gas and other related products and services to customers opting for choice among energy providers. On December 31, 2011, the Company sold Vectren Source receiving proceeds of approximately $84.3 million, excluding minor working capital adjustments recorded in 2012. The sale, net of transaction costs, resulted in a pretax gain included in Other operating expenses of $25.4 million, or $12.4 million after all associated tax impacts. VEDO continues doing business with the third party purchaser of Vectren Source. This third party continues to sell natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from the third party. Prior to the sale, Vectren Source earned $2.8 million in 2011.
Other Businesses
Within the Nonutility business segment, there are legacy investments involved in energy-related opportunities and services, real estate, a leveraged lease, and other ventures. As of December 31, 2013, remaining legacy investments included in the Other Businesses portfolio total $26.5 million, of which $23.7 million are included in Other nonutility investments and $2.8 million are included in Investments in unconsolidated affiliates. The investment is made up of the following: commercial real estate, $8.0 million; a leveraged lease, $14.4 million ($4.0 million net of related deferred taxes); and other investments, $4.1 million. Net of deferred taxes, the net investment associated with these legacy investments at December 31, 2013 was $16.1 million.
Other Businesses results were a loss of $1.0 million in 2013, compared to a loss of $3.4 million in 2012 and a loss of $10.2 million in 2011. Results in 2013 reflect the final true-up from the ProLiance sale and other minor operating results of the remaining ProLiance investments, as well as a charge related to a legacy receivable. Results in 2012 reflect after tax charges of $2.2 million related to the carrying value of an energy-related investment originally made in 1999. Results in 2011 include charges totaling $9.2 million after tax associated with legacy real estate holdings.
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)
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.
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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 determine 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, deferred income taxes, and coal reserves, among others. Actual results could differ from these estimates.
Impairment Review of Investments and Long-Lived Assets
The Company has both debt and equity investments in unconsolidated entities. When events occur that may cause an investment to be impaired, the Company performs both a qualitative and quantitative review of that investment and when necessary performs an impairment analysis. An impairment analysis of notes receivable usually involves the comparison of the investment’s estimated free cash flows to the stated terms of the note, or in certain cases for notes that are collateral dependent, a comparison of the collateral’s fair value, to the carrying amount of the note. An impairment analysis of equity investments involves comparison of the investment’s estimated fair value to its carrying amount and an assessment of whether any decline in fair value is “other than temporary.” Fair value is estimated using market comparisons, appraisals, and/or discounted cash flow analysis.
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). There were no impairments related to property, plant and equipment or other long-lived assets during the periods presented.
Specific to the Company’s investment in its owned coal mines, in 2013, as a result of continued operating losses at the Company’s Prosperity mine, increased production costs as a result of various factors, including poor mining conditions, and an overall decline in market prices for Illinois Basin coal, the Company performed a more detailed analysis to support the carrying value of that mine. Specifically, several third party-prepared price curves were obtained and were used to develop revenue forecasts for the remainder of the mine life, using estimated production volumes. Additionally, cost estimates were developed that considered prior actual costs, annualized current costs, and projected future costs. The various revenue scenarios were used in conjunction with estimated costs to derive estimated net operating cash flows for the remaining life of the mine. These estimates are highly subjective and may differ materially from actual results, but the results of the various analyses indicate that there is no impairment related to the coal mine assets, specifically the Prosperity mine assets, at December 31, 2013.
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Calculating free cash flows and fair value using the above methods is subjective and requires judgment concerning growth assumptions, longevity of cash flows, and discount rates (for fair value calculations), among others.
Over the year’s presented, the Company has recorded charges associated with legacy commercial real estate and other investments using the methods described above.
Goodwill & Intangible Assets
The Company performs an annual impairment analysis of its goodwill, most 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. Nonutility Group impairment testing for its Infrastructure Services and Energy Services segments are also performed at the operating segment level. An impairment test requires fair value to 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. Goodwill related to the Nonutility Group is also tested using market comparable data, if readily available, or a discounted cash flow model. 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.
The Company also annually tests non-amortizing intangible assets for impairment and amortizing intangible assets are tested on an event and circumstance basis. During the last three years, these tests yielded no impairment charges.
Pension & Other Postretirement Obligations
The Company estimates the expected return on plan assets, discount rate, rate of compensation increase, and future health care costs, among other inputs, and obtains actuarial estimates to assess the future potential liability and funding requirements of the Company's pension and postretirement plans. The Company 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. The rate of return and inflation rates remained the same from 2012 to 2013. 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. Management currently estimates a pension and postretirement cost of approximately $6 million in 2014. Future changes in health care costs, work force demographics, interest rates, asset values or plan changes could significantly affect the estimated cost of these future benefits.
Management estimates that a 50 basis point 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.
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Financial Condition
Within Vectren’s consolidated group, Utility Holdings primarily funds the short-term and long-term financing needs of the Utility Group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the Nonutility Group and corporate operations. Vectren Corporation guarantees Vectren Capital’s debt, but does not guarantee Utility Holdings’ debt. Vectren Capital’s long-term debt, including current maturities, and short-term obligations outstanding at December 31, 2013 approximated $550 million and $40 million, respectively. Utility Holdings’ outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by its wholly owned subsidiaries and regulated utilities Indiana Gas, SIGECO, and VEDO. 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.
The Company’s common stock dividends are primarily funded by utility operations. Nonutility operations have demonstrated profitability and the ability to generate cash flows. These cash flows are primarily reinvested in other nonutility ventures, but are also used to fund a portion of the Company’s dividends, and from time to time may be reinvested in utility operations or used for corporate expenses.
Vectren Corporation's corporate credit rating is A-, as rated by Standard and Poor's Ratings Services (Standard and Poor's). Moody's Investors Services (Moody's) does not provide a rating for Vectren Corporation. The credit ratings of the senior unsecured debt of Utility Holdings and Indiana Gas, at December 31, 2013, were A-/A3 as rated by Standard and Poor's and Moody’s, respectively. The credit ratings on SIGECO's secured debt are A/A1. Utility Holdings’ commercial paper had a credit rating of A-2/P-2. On January 30, 2014, Moody's upgraded the senior unsecured credit ratings of Utility Holdings and Indiana Gas from A3 to A2. 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 45-55 percent of long-term capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, execution of long-term financing plans, and seasonal factors that affect the Company’s operations. The Company’s equity component was 46 percent and 48 percent of long-term capitalization at December 31, 2013 and 2012, respectively. Long-term capitalization includes long-term debt, including current maturities, as well as common shareholders’ equity. The decrease in 2013 is the result of short-term debt due at December 31, 2012, being refinanced with long-term debt during 2013.
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 recently been enhanced by bonus depreciation legislation supplemented with a modest amount of incremental long-term debt, 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; coal mine safety; expanded EPA regulations for air, water, and fly ash; and growth of Infrastructure Services and Energy Services. These factors may result in the need to raise additional capital in the coming years. In addition,
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the Company may expand its businesses through acquisitions and/or joint venture investment. The timing and amount of such investments depends on a variety of factors, including the availability of acquisition targets and available liquidity. The Company may also consider disposing of certain assets, investments, or businesses to enhance or accelerate internally generated cash flow.
Long-term debt transactions completed in 2013, 2012, and 2011 include issuances by Vectren Capital totaling $200 million, issuances by Vectren 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
At December 31, 2013, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations. As reduced by borrowings currently outstanding, approximately $321 million was available for the Utility Group operations and approximately $210 million was available for the wholly owned Nonutility Group and corporate operations. Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016. The maximum limit of both facilities remained unchanged. These facilities are 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 of Utility Holdings’ operations through the commercial paper market and expects to use the Utility Holdings short-term borrowing facility in instances where the commercial paper market is not efficient. Following is certain information regarding these short-term borrowing arrangements.
Utility Group Borrowings | Nonutility Group Borrowings | |||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
As of Year End | ||||||||||||||||||||||||
Balance Outstanding | $ | 28.6 | $ | 116.7 | $ | 242.8 | $ | 40.0 | $ | 162.1 | $ | 84.3 | ||||||||||||
Weighted Average Interest Rate | 0.29 | % | 0.40 | % | 0.57 | % | 1.27 | % | 1.35 | % | 1.45 | % | ||||||||||||
Annual Average | ||||||||||||||||||||||||
Balance Outstanding | $ | 119.6 | $ | 77.6 | $ | 39.6 | $ | 119.3 | $ | 151.5 | $ | 124.9 | ||||||||||||
Weighted Average Interest Rate | 0.34 | % | 0.47 | % | 0.48 | % | 1.35 | % | 1.44 | % | 1.92 | % | ||||||||||||
Maximum Month End Balance Outstanding | $ | 176.1 | $ | 214.2 | $ | 242.8 | $ | 173.8 | $ | 216.1 | $ | 180.1 | ||||||||||||
Throughout 2013, 2012, and 2011, Utility Holdings has placed commercial paper without any significant issues and did not borrow from its backup credit facility in any of these periods.
New Share Issues
The Company may periodically issue new common shares to satisfy the dividend reinvestment plan, stock option plan and other employee benefit plan requirements. New issuances added additional liquidity of $6.9 million in 2013, $7.2 million in 2012, and $7.9 million in 2011.
Potential Uses of Liquidity
Pension & Postretirement Funding Obligations
As of December 31, 2013, assets related to the Company’s 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. The Company currently anticipates making no contributions to qualified pension plans in 2014, due to the plans being at or above 100 percent funded levels.
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Corporate Guarantees
The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral. At December 31, 2013, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $45 million of other project guarantees. The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below. In addition, the parent company has approximately $25 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $19 million represent letters of credit supporting other nonutility operations. As disclosed in Note 7 to the Consolidated Financial Statements included in Item 8, a guarantee issued and outstanding to an unrelated party in connection with ProLiance's disposition of certain of the net assets of ProLiance Energy totaled $15.3 million at December 31, 2013. Although there can be no assurance that these guarantees will not be called upon, the Company believes that the likelihood the Company will be called upon to satisfy any obligations pursuant to these guarantees is remote.
Performance Guarantees & Product Warranties
In the normal course of business, wholly owned subsidiaries, including ESG, issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations. Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented.
Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2013, there are 57 open surety bonds supporting future performance. The average face amount of these obligations is $4.4 million, and the largest obligation has a face amount of $57.3 million. The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At December 31, 2013, approximately 47 percent of work was completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. The Company has no significant accruals for these warranty obligations as of December 31, 2013. In addition, ESG has an $8 million stand-alone letter of credit facility and as of December 31, 2013, $3.4 million was outstanding.
Planned Capital Expenditures & Investments
During 2013 capital expenditures and other investments approximated $411 million, of which approximately $268 million related to Utility Group expenditures. This compares to 2012 where consolidated investments were approximately $370 million with $250 million attributed to the Utility Group and 2011 where consolidated investments were approximately $320 million with $230 million attributed to the Utility Group. Planned Utility Group 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.
Planned Nonutility Group capital expenditures for recurring infrastructure investments, including contractual purchase commitments, for the five-year period 2014 - 2018 are expected to total (in millions): $110, $100, $80, $90, and $70, respectively.
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Contractual Obligations
The following is a summary of contractual obligations at December 31, 2013:
(In millions) | Total | 2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | |||||||||||||||||||||
Long-term debt (1) | $ | 1,807.1 | $ | 30.0 | $ | 279.8 | $ | 173.0 | $ | 75.0 | $ | 100.0 | $ | 1,149.3 | ||||||||||||||
Short-term debt | 68.6 | 68.6 | — | — | — | — | — | |||||||||||||||||||||
Long-term debt interest commitments | 987.7 | 82.8 | 81.4 | 67.4 | 65.3 | 60.4 | 630.4 | |||||||||||||||||||||
Plant and nonutility plant purchase commitments | 19.6 | 19.6 | — | — | — | — | — | |||||||||||||||||||||
Operating leases | 22.3 | 6.9 | 5.0 | 2.9 | 1.3 | 1.2 | 5.0 | |||||||||||||||||||||
Total (2) | $ | 2,905.3 | $ | 207.9 | $ | 366.2 | $ | 243.3 | $ | 141.6 | $ | 161.6 | $ | 1,784.7 | ||||||||||||||
(1) | The debt due in 2014 is comprised of debt issued by Vectren Capital. |
(2) | The Company has other long-term liabilities that total approximately $166 million. This amount is comprised of the following: pension obligations $20 million; postretirement obligations $47 million; deferred compensation and share-based compensation obligations $41 million; asset retirement obligations $41 million; investment tax credits $5 million; environmental remediation obligations $6 million; and other obligations including unrecognized tax benefits totaling $6 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, electricity, and coal 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 capital requirements has been cash generated from operations, which totaled $587.0 million in 2013, compared to $387.4 million in 2012 and $416.9 million in 2011.
The $199.6 million increase in operating cash flow in 2013 compared to 2012 is primarily due to a greater level of cash from working capital in 2013 as compared to 2012 mostly due to higher inventories at SIGECO and an increase in accounts receivable in 2012. The change in noncurrent assets was primarily driven by the deferral for future recovery of certain coal costs pursuant to a regulatory order in the prior year. In addition, contributions to benefit plans were $6.8 million lower during 2013 compared to 2012.
In 2012, operating cash flows decreased $29.5 million compared to 2011. This decrease was primarily due to greater working capital needs to support growth in the Infrastructure Services segment and lower cash generated by the Coal Mining segment. The deferral for future recovery of certain coal costs pursuant to a regulatory order is the primary use of cash impacting the change in noncurrent assets. Increased earnings overall, along with lower contributions to employee benefit plans in 2012, somewhat offset these decreases.
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 100 percent for 2011, 50 percent for 2012, and 50 percent for 2013. A significant portion of the Company’s capital expenditures qualified for this bonus treatment.
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Financing Cash Flow
Net cash flow required for financing activities was $179.9 million, $19.6 million, and $99.0 million for the years ending December 31, 2013, 2012, and 2011, respectively. Financing activity across all periods reflects the Company’s utilization of the long-term capital markets in the current low interest rate environment. Since 2011, the Company has issued $836 million in long-term debt, of which $744 million was used to refinance maturing or called long-term debt and $92 million was used to meet its incremental debt financing requirements. 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, over 80 percent in 2012, and over 95 percent in 2011. Recently completed long-term financing transactions are more fully described below.
Vectren Capital 2013 Term Loan
On August 6, 2013, Vectren Capital entered into a $100 million three year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus an additional margin which is based on the Company's credit rating. Interest periods are variable and may range from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. The Company received net proceeds of approximately $100 million in August 2013.
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 December 31, 2038, and $39.6 million at 4.05 percent per annum due December 31, 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 Utility Holdings' $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.
Vectren Capital 2012 Term Loan
On November 1, 2012, Vectren Capital entered into a $100 million three year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus an additional margin which is based on the Company's credit rating. Interest periods are variable and may range from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. The Company received net proceeds of approximately $100 million in November 2012.
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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 Utility Holdings' $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 $149.0 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 $405.1 million in 2013, $356.9 million in 2012, and $319.7 million in 2011. Capital expenditures are the primary component of investing activities and totaled $393.4 million in 2013, $365.8 million in 2012 and $321.3 million in 2011. Utility Group capital expenditures increased approximately $15 million in 2013 compared to 2012 and is attributable to greater expenditures for bare/steel cast iron replacement and regional electric transmission projects. In addition, capital expenditures for nonutility equipment have increased approximately $13 million in 2013 compared to 2012, primarily due to continued growth in the Infrastructure Services segment. The increase in capital expenditures in 2012 compared to 2011 of $32 million is primarily due to growth in the Infrastructure Services segment.
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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, electricity, coal, and other nonutility products and services; impacts on both gas and electric large customers; lower residential and commercial customer counts; higher operating expenses; and further reductions in the value of certain nonutility real estate and other legacy investments. |
• | 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. |
• | The performance of projects undertaken by the Company’s nonutility businesses and the success of efforts to realize value from, invest in and develop new opportunities, including but not limited to, the Company’s infrastructure services, energy services, and coal mining, and remaining energy marketing assets. |
• | Factors affecting infrastructure services, including the level of success in bidding contracts; fluctuations in volume of contracted work; unanticipated cost increases in completion of the contracted work; funding requirements associated with multi-employer pension and benefit plans; changes in legislation and regulations impacting the industries in which the customers served operate; the effects of weather; failure to properly estimate the cost to construct projects; the ability to attract and retain qualified employees in a fast growing market where skills are critical; cancellation and/or reductions in |
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the scope of projects by customers; credit worthiness of customers; ability to obtain materials and equipment required to perform services; and changing market conditions.
• | Factors affecting coal mining operations and their cost structure, including MSHA guidelines and interpretations of those guidelines, as well as additional mine regulations and more frequent and broader inspections that could result from mining incidents at coal mines; geologic conditions, including coal seam thickness, equipment, and operational risks; the ability to execute and negotiate new sales contracts and resolve contract interpretations; volatile coal market prices and demand; supplier and contract miner performance; the availability of key equipment, contract miners and commodities; availability of transportation; coal quality, including its sulfur and mercury content; and the ability to access coal reserves. |
• | 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 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 AND 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 Vectren’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.
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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.
Other Operations
Other commodity-related operations are exposed to commodity price risk associated with gasoline/diesel and coal through third party suppliers. Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described below with frequent management reporting.
The Company purchases and sells coal to meet customer demands. Forward contracts commit coal operations to purchase and sell commodities in the future. Price risk from forward sell positions is mitigated using stored inventory and expected reserves. Coal mining contracts are expected to be settled by physical receipt or delivery of the commodity. Occasionally, the Company will hedge a portion of its gasoline requirements using financial instruments. However, during the years presented such utilization has not been significant.
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 $421 million and $287 million, respectively. At December 31, 2013, combined borrowings under these arrangements were $309 million. As of December 31, 2012 combined borrowings under these arrangements were $420 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 approximately $4.2 million in 2013 and $2.9 million in 2012.
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.
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The Company’s customer receivables associated with utility operations are primarily derived from residential, commercial, and industrial customers located in Indiana and west central Ohio. However, some exposure from nonutility operations extends throughout the United States. 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 for the Company's utilities 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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
Vectren Corporation’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, comprehensive income, cash flows, and common shareholders’ equity, and related footnotes contained herein.
These consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of these consolidated financial statements, including required estimates and judgments, is the responsibility of management.
These consolidated financial statements are also subject to an evaluation of internal control over financial reporting conducted under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer. Based on that evaluation, conducted under the framework in Internal Control — Integrated Framework (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.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Vectren Corporation:
We have audited the accompanying consolidated balance sheets of Vectren Corporation and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, common shareholders’ 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 listed 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 Corporation 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2014 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 20, 2014
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Vectren Corporation:
We have audited the internal control over financial reporting of Vectren Corporation and subsidiaries (the “Company”) as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2013 of the Company and our report dated February 20, 2014 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
Indianapolis, Indiana
February 20, 2014
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VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31, | ||||||||
2013 | 2012 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash & cash equivalents | $ | 21.5 | $ | 19.5 | ||||
Accounts receivable - less reserves of $6.8 & $6.8, respectively | 259.2 | 216.7 | ||||||
Accrued unbilled revenues | 134.2 | 185.0 | ||||||
Inventories | 134.4 | 158.6 | ||||||
Recoverable fuel & natural gas costs | 5.5 | 25.3 | ||||||
Prepayments & other current assets | 75.6 | 73.3 | ||||||
Total current assets | 630.4 | 678.4 | ||||||
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 | 24.0 | 78.1 | ||||||
Other utility & corporate investments | 38.1 | 34.6 | ||||||
Other nonutility investments | 33.8 | 24.9 | ||||||
Nonutility plant - net | 657.2 | 598.0 | ||||||
Goodwill - net | 262.3 | 262.3 | ||||||
Regulatory assets | 193.4 | 252.7 | ||||||
Other assets | 39.1 | 40.5 | ||||||
TOTAL ASSETS | $ | 5,102.6 | $ | 5,089.1 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In millions)
At December 31, | ||||||||
2013 | 2012 | |||||||
LIABILITIES & SHAREHOLDERS' EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 227.2 | $ | 180.6 | ||||
Accounts payable to affiliated companies | — | 29.7 | ||||||
Refundable fuel & natural gas costs | 2.6 | — | ||||||
Accrued liabilities | 182.1 | 198.8 | ||||||
Short-term borrowings | 68.6 | 278.8 | ||||||
Current maturities of long-term debt | 30.0 | 106.4 | ||||||
Total current liabilities | 510.5 | 794.3 | ||||||
Long-term Debt - Net of Current Maturities | 1,777.1 | 1,553.4 | ||||||
Deferred Income Taxes & Other Liabilities | ||||||||
Deferred income taxes | 707.4 | 637.2 | ||||||
Regulatory liabilities | 387.3 | 364.2 | ||||||
Deferred credits & other liabilities | 166.0 | 213.9 | ||||||
Total deferred credits & other liabilities | 1,260.7 | 1,215.3 | ||||||
Commitments & Contingencies (Notes 7, 17-19) | ||||||||
Common Shareholders' Equity | ||||||||
Common stock (no par value) – issued & outstanding 82.4 & 82.2 shares, respectively | 709.3 | 700.5 | ||||||
Retained earnings | 845.7 | 829.9 | ||||||
Accumulated other comprehensive (loss) | (0.7 | ) | (4.3 | ) | ||||
Total common shareholders' equity | 1,554.3 | 1,526.1 | ||||||
TOTAL LIABILITIES & SHAREHOLDERS' EQUITY | $ | 5,102.6 | $ | 5,089.1 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
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 | |||||||||
Nonutility | 1,061.9 | 899.8 | 870.2 | |||||||||
Total operating revenues | 2,491.2 | 2,232.8 | 2,325.2 | |||||||||
OPERATING EXPENSES | ||||||||||||
Cost of gas sold | 358.1 | 301.3 | 375.4 | |||||||||
Cost of fuel & purchased power | 202.9 | 192.0 | 240.4 | |||||||||
Cost of nonutility revenues | 366.7 | 295.1 | 385.3 | |||||||||
Other operating | 891.6 | 781.0 | 652.2 | |||||||||
Depreciation & amortization | 277.8 | 254.6 | 244.3 | |||||||||
Taxes other than income taxes | 60.5 | 56.3 | 57.6 | |||||||||
Total operating expenses | 2,157.6 | 1,880.3 | 1,955.2 | |||||||||
OPERATING INCOME | 333.6 | 352.5 | 370.0 | |||||||||
OTHER INCOME (EXPENSE) | ||||||||||||
Equity in (losses) of unconsolidated affiliates | (59.7 | ) | (23.3 | ) | (32.0 | ) | ||||||
Other income (expense) – net | 17.7 | 8.3 | (3.5 | ) | ||||||||
Total other expense | (42.0 | ) | (15.0 | ) | (35.5 | ) | ||||||
Interest expense | 87.9 | 96.0 | 106.5 | |||||||||
INCOME BEFORE INCOME TAXES | 203.7 | 241.5 | 228.0 | |||||||||
Income taxes | 67.1 | 82.5 | 86.4 | |||||||||
NET INCOME | $ | 136.6 | $ | 159.0 | $ | 141.6 | ||||||
AVERAGE COMMON SHARES OUTSTANDING | 82.3 | 82.0 | 81.8 | |||||||||
DILUTED COMMON SHARES OUTSTANDING | 82.4 | 82.1 | 81.8 | |||||||||
EARNINGS PER SHARE OF COMMON STOCK: | ||||||||||||
BASIC | $ | 1.66 | $ | 1.94 | $ | 1.73 | ||||||
DILUTED | $ | 1.66 | $ | 1.94 | $ | 1.73 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
Year Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
NET INCOME | $ | 136.6 | $ | 159.0 | $ | 141.6 | ||||||
Accumulated other comprehensive income (AOCI) of unconsolidated affiliates | ||||||||||||
Net amount arising during the year before tax | 4.6 | 11.3 | (9.3 | ) | ||||||||
Income taxes | (1.8 | ) | (4.6 | ) | 3.8 | |||||||
AOCI of unconsolidated affiliates, net of tax | 2.8 | 6.7 | (5.5 | ) | ||||||||
Pension & other benefits | ||||||||||||
Amounts arising during the year before tax | 61.4 | (3.3 | ) | (41.6 | ) | |||||||
Reclassifications to periodic cost before tax | 9.1 | 7.1 | 6.4 | |||||||||
Deferrals to regulatory assets | (69.1 | ) | 0.2 | 33.5 | ||||||||
Income taxes | (0.6 | ) | (1.6 | ) | 0.7 | |||||||
Pension & other benefits costs, net of tax | 0.8 | 2.4 | (1.0 | ) | ||||||||
Cash flow hedges | ||||||||||||
Unrealized gains & losses before tax | — | — | (3.6 | ) | ||||||||
Reclassifications to net income before tax | — | (0.1 | ) | (0.3 | ) | |||||||
Income taxes | — | — | 1.5 | |||||||||
Cash flow hedges, net of tax | — | (0.1 | ) | (2.4 | ) | |||||||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | 3.6 | 9.0 | (8.9 | ) | ||||||||
TOTAL COMPREHENSIVE INCOME | $ | 140.2 | $ | 168.0 | $ | 132.7 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Year Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
Net income | $ | 136.6 | $ | 159.0 | $ | 141.6 | ||||||
Adjustments to reconcile net income to cash from operating activities: | ||||||||||||
Depreciation & amortization | 277.8 | 254.6 | 244.3 | |||||||||
Deferred income taxes & investment tax credits | 43.3 | 84.3 | 71.7 | |||||||||
Equity in losses of unconsolidated affiliates | 59.7 | 23.3 | 32.0 | |||||||||
Provision for uncollectible accounts | 6.8 | 8.2 | 11.8 | |||||||||
Expense portion of pension & postretirement benefit cost | 9.9 | 8.7 | 9.0 | |||||||||
Other non-cash expense - net | 5.8 | 9.8 | (0.1 | ) | ||||||||
Changes in working capital accounts: | ||||||||||||
Accounts receivable & accrued unbilled revenues | 1.5 | (67.1 | ) | (17.5 | ) | |||||||
Inventories | 24.2 | 3.3 | (26.1 | ) | ||||||||
Recoverable/refundable fuel & natural gas costs | 22.4 | (12.9 | ) | (4.5 | ) | |||||||
Prepayments & other current assets | 12.8 | (5.1 | ) | 17.9 | ||||||||
Accounts payable, including to affiliated companies | 6.8 | (14.8 | ) | (21.2 | ) | |||||||
Accrued liabilities | (1.2 | ) | 3.4 | 6.4 | ||||||||
Unconsolidated affiliate dividends | 1.1 | 0.1 | 0.1 | |||||||||
Employer contributions to pension & postretirement plans | (13.7 | ) | (20.5 | ) | (38.8 | ) | ||||||
Changes in noncurrent assets | (2.1 | ) | (35.3 | ) | 0.3 | |||||||
Changes in noncurrent liabilities | (4.7 | ) | (11.6 | ) | (10.0 | ) | ||||||
Net cash provided by operating activities | 587.0 | 387.4 | 416.9 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Proceeds from: | ||||||||||||
Long-term debt, net of issuance costs | 481.7 | 199.5 | 148.9 | |||||||||
Dividend reinvestment plan & other common stock issuances | 6.9 | 7.2 | 7.9 | |||||||||
Requirements for: | ||||||||||||
Dividends on common stock | (117.3 | ) | (115.3 | ) | (113.2 | ) | ||||||
Retirement of long-term debt | (338.9 | ) | (62.7 | ) | (349.1 | ) | ||||||
Other financing activities | (2.1 | ) | — | (2.3 | ) | |||||||
Net change in short-term borrowings | (210.2 | ) | (48.3 | ) | 208.8 | |||||||
Net cash used in financing activities | (179.9 | ) | (19.6 | ) | (99.0 | ) | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Proceeds from: | ||||||||||||
Sale of business | — | — | 84.3 | |||||||||
Unconsolidated affiliate distributions | — | 0.2 | 0.5 | |||||||||
Other collections | 5.6 | 9.9 | 1.1 | |||||||||
Requirements for: | ||||||||||||
Capital expenditures, excluding AFUDC equity | (393.4 | ) | (365.8 | ) | (321.3 | ) | ||||||
Business acquisition, net of cash acquired | — | — | (83.4 | ) | ||||||||
Other investments | (17.3 | ) | (1.2 | ) | (0.9 | ) | ||||||
Net cash used in investing activities | (405.1 | ) | (356.9 | ) | (319.7 | ) | ||||||
Net change in cash & cash equivalents | 2.0 | 10.9 | (1.8 | ) | ||||||||
Cash & cash equivalents at beginning of period | 19.5 | 8.6 | 10.4 | |||||||||
Cash & cash equivalents at end of period | $ | 21.5 | $ | 19.5 | $ | 8.6 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VECTREN CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(In millions, except per share amounts)
Accumulated | ||||||||||||||||||
Common Stock | Other | |||||||||||||||||
Shares | Amount | Retained Earnings | Comprehensive Income (Loss) | Total | ||||||||||||||
Balance at January 1, 2011 | 81.7 | $ | 683.4 | $ | 759.9 | $ | (4.4 | ) | $ | 1,438.9 | ||||||||
Net income | 141.6 | 141.6 | ||||||||||||||||
Other comprehensive income | (8.9 | ) | (8.9 | ) | ||||||||||||||
Common stock: | ||||||||||||||||||
Issuance: option exercises & dividend reinvestment plan | 0.2 | 7.9 | 7.9 | |||||||||||||||
Dividends ($1.385 per share) | (113.2 | ) | (113.2 | ) | ||||||||||||||
Other | 1.3 | (2.1 | ) | (0.8 | ) | |||||||||||||
Balance at December 31, 2011 | 81.9 | 692.6 | 786.2 | (13.3 | ) | 1,465.5 | ||||||||||||
Net income | 159.0 | 159.0 | ||||||||||||||||
Other comprehensive income | 9.0 | 9.0 | ||||||||||||||||
Common stock: | ||||||||||||||||||
Issuance: option exercises & dividend reinvestment plan | 0.3 | 7.2 | 7.2 | |||||||||||||||
Dividends ($1.405 per share) | (115.3 | ) | (115.3 | ) | ||||||||||||||
Other | 0.7 | 0.7 | ||||||||||||||||
Balance at December 31, 2012 | 82.2 | 700.5 | 829.9 | (4.3 | ) | 1,526.1 | ||||||||||||
Net income | 136.6 | 136.6 | ||||||||||||||||
Other comprehensive income | 3.6 | 3.6 | ||||||||||||||||
Common stock: | ||||||||||||||||||
Issuance: option exercises & dividend reinvestment plan | 0.2 | 6.9 | 6.9 | |||||||||||||||
Dividends ($1.425 per share) | (117.3 | ) | (117.3 | ) | ||||||||||||||
Other | 1.9 | (3.5 | ) | (1.6 | ) | |||||||||||||
Balance at December 31, 2013 | 82.4 | $ | 709.3 | $ | 845.7 | $ | (0.7 | ) | $ | 1,554.3 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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VECTREN CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy holding company headquartered in Evansville, Indiana. The Company’s wholly owned subsidiary, Vectren Utility Holdings, Inc. (Utility Holdings), serves as the intermediate holding company for three 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. Utility Holdings’ consolidated operations are collectively referred to as the Utility Group. Both Vectren and Utility Holdings are holding companies as defined by the Energy Policy Act of 2005 (Energy Act). Vectren was incorporated under the laws of Indiana on June 10, 1999.
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 over 312,000 natural gas customers located near Dayton in west central Ohio.
The Company, through Vectren Enterprises, Inc. (Enterprises), is involved in nonutility activities in three primary business areas: Infrastructure Services, Energy Services, and Coal Mining. Infrastructure Services provides underground pipeline construction and repair services. Energy Services provides performance contracting and renewable energy services. Coal Mining owns, and through its contract miners, mines and then sells coal. Enterprises also has other legacy businesses that have invested in energy-related opportunities and services, real estate, and a leveraged lease, among other investments. Prior to June 18, 2013, the Company, through Enterprises, was involved in nonutility activities in its Energy Marketing business area. Energy Marketing marketed and supplied natural gas and provided energy management services through ProLiance Holdings, LLC and Vectren Source. Pursuant to service contracts, Energy Marketing provided the Company's regulated utilities natural gas supply services. All of the above are collectively referred to as the Nonutility Group. Enterprises supports the Company's regulated utilities by providing infrastructure services and coal.
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 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.
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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 and coal inventory at the Company’s nonutility coal mines are 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. Nonutility inventory is valued at the lower of cost or market.
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 or units-of-production method of amortization for certain coal mining assets. When nonutility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income, typically impacting operating expenses.
Impairment Reviews
Property, plant and equipment along with other long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This impairment review involves the comparison of an asset’s (or group of assets’) carrying value to the estimated future cash flows the asset (or asset group) is expected to generate over a remaining life. If this evaluation were to conclude that the carrying value is impaired, an impairment charge would be recorded based on the difference between the carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. There were no impairments related to property, plant and equipment or other long-lived assets during the periods presented.
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Specific to the Company’s investment in its owned coal mines, in 2013, as a result of continued operating losses at the Company’s Prosperity mine, increased production costs as a result of various factors, including poor mining conditions, and an overall decline in market prices for Illinois Basin coal, the Company performed a more detailed analysis to support the carrying value of that mine. Specifically, several third party-prepared price curves were obtained and were used to develop revenue forecasts for the remainder of the mine life, using estimated production volumes. Additionally, cost estimates were developed that considered prior actual costs, annualized current costs, and projected future costs. The various revenue scenarios were used in conjunction with estimated costs to derive estimated net operating cash flows for the remaining life of the mine. These estimates are highly subjective and may differ materially from actual results, but the results of the various analyses indicate that there is no impairment related to the coal mine assets, specifically the Prosperity mine assets, at December 31, 2013.
Investments in Unconsolidated Affiliates
Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company’s share of net income or loss from these investments is recorded in Equity in (losses) of unconsolidated affiliates. Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting. Dividends associated with cost method investments are recorded as Other – net when received. Investments, when necessary, include adjustments for declines in value judged to be other than temporary.
Goodwill
Goodwill recorded on the Consolidated Balance Sheets results from business acquisitions and is based on a fair value allocation of the businesses’ purchase price at the time of acquisition. Goodwill is charged to expense only when it is impaired. The Company tests its goodwill for impairment at 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.
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Postretirement Obligations & Costs
The Company recognizes the funded status of its pension plans and postretirement plans on its balance sheet. The funded status of a defined benefit plan is its assets (if any) less its projected benefit obligation (PBO), which reflects service accrued to date and includes the impact of projected salary increases (for pay-related benefits). The funded status of a postretirement plan is its assets (if any) less its accumulated postretirement benefit obligation (APBO), which reflects accrued service to date. To the extent this obligation exceeds amounts previously recognized in the statement of income, the Company records a Regulatory asset for that portion related to its rate regulated utilities. To the extent that excess liability does not relate to a rate regulated utility, the offset is recorded as a reduction to equity in Accumulated other comprehensive income.
The annual cost of all postretirement plans is recognized in operating expenses or capitalized to plant following the direct labor of current employees. Specific to pension plans, the Company uses the projected unit credit actuarial cost method to calculate service cost and the PBO. This method projects the present value of benefits at retirement and allocates that cost over the projected years of service. Annual service cost represents one year’s benefit accrual while the PBO represents benefits allocated to previously accrued service. For other postretirement plans, service cost is calculated by dividing the present value of a participant’s projected postretirement benefits into equal parts based upon the number of years between a participant’s hire date and first eligible retirement date. Annual service cost represents one year’s benefit accrual while the APBO represents benefit allocated to previously accrued service. To calculate the expected return on pension plan assets, the Company uses the plan assets’ market-related value and an expected long-term rate of return. For the majority of the Company’s pension plans, the fair market value of the assets at the balance sheet date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five-year period. Interest cost represents the annual accretion of the PBO and APBO at the discount rate. Actuarial gains and losses outside of a corridor (equal to 10 percent of the greater of the benefit obligation and the market-related value of assets) are amortized over the expected future working lifetime of active participants (except for plans where almost all participants are inactive). Prior service costs related to plan changes are amortized over the expected future working lifetime (or to full eligibility date for postretirement plan other than pensions) of the active participants at the time of the amendment.
Asset Retirement Obligations
A portion of removal costs related to interim retirements of gas utility pipeline and utility poles, certain asbestos-related issues, and reclamation activities meet the definition of an asset retirement obligation (ARO). The Company records the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, regulatory assets and liabilities result when accretion and amortization is adjusted to match rates established by regulators and any gain or loss is subject to deferral.
Product Warranties, Performance Guarantees & Other Guarantees
Liabilities and expenses associated with product warranties and performance guarantees are recognized based on historical experience at the time the associated revenue is recognized. Adjustments are made as changes become reasonably estimable. The Company does not recognize the fair value of an obligation at inception for these guarantees because they are guarantees of the Company’s own performance and/or product installations.
While not significant at December 31, 2013 or 2012, the Company does recognize the fair value of an obligation at the inception of a guarantee in certain circumstances. These circumstances would include executing certain indemnification agreements and guaranteeing operating lease residual values, the performance of a third party, or the indebtedness of a third party.
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.
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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.
Income Taxes
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. 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.
Revenues
Most revenues are recognized as products and services are delivered to customers. Some nonutility revenues are recognized using the percentage of completion method. The Company records revenues for services and goods delivered but not billed at the end of an accounting period in Accrued unbilled revenues. The goods and services delivered by the Company subject to unbilled revenue accruals include gas, electricity, and infrastructure services.
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
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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 the 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.
Share-Based Compensation
The Company grants share-based awards to certain employees and board members. Liability classified share-based compensation awards are re-measured at the end of each period based on their expected settlement date fair value. Equity classified share-based compensation awards are measured at the grant date, based on the fair value of the award. Expense associated with share-based awards is recognized over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible.
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 $29.3 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 has three operating segments within its Utility Group, five operating segments in its Nonutility Group, and a Corporate and Other segment.
Fair Value Measurements
Certain assets and liabilities are valued and/or disclosed at fair value. Financial assets include securities held in trust by the Company’s pension plans. 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 that the Company has the ability to access. |
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. |
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The asset 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.
3. Utility & Nonutility Plant
The original cost of Utility plant, together with depreciation rates expressed as a percentage of original cost, follows:
At 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 | ||||||
Coal mine development costs & equipment | $ | 242.0 | $ | 241.9 | ||||
Computer hardware & software | 102.7 | 97.3 | ||||||
Land & buildings | 129.3 | 120.4 | ||||||
Vehicles & equipment | 165.2 | 119.8 | ||||||
All other | 18.0 | 18.6 | ||||||
Nonutility plant - net | $ | 657.2 | $ | 598.0 | ||||
Nonutility plant is presented net of accumulated depreciation and amortization totaling $541.7 million and $468.4 million as of December 31, 2013 and 2012, respectively. For the years ended December 31, 2013, 2012, and 2011, the Company capitalized interest totaling $0.5 million, $1.8 million, and $2.1 million, respectively, on nonutility plant construction projects.
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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: | ||||||||
Benefit obligations (See Note 11) | $ | 57.1 | $ | 126.2 | ||||
Net deferred income taxes (See Note 10) | (5.8 | ) | (3.9 | ) | ||||
Asset retirement obligations & other | 2.4 | 2.6 | ||||||
53.7 | 124.9 | |||||||
Amounts deferred for future recovery related to: | ||||||||
Deferred coal costs (See Note 18) | 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 | $ | 193.4 | $ | 252.7 | ||||
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.
Assets arising from benefit obligations represent the funded status of retirement plans less amounts previously recognized in the statement of income. The decrease in 2013 of approximately $69 million is a result of plan asset performance and an increase in discount rate used to value the projected benefit obligation. The Company records a Regulatory asset for that portion related to its rate regulated utilities. If the cost is ultimately recognized as a periodic cost, it will be recovered through rates charged to customers. See Note 11.
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. Acquisition of Minnesota Limited, LLC
On March 31, 2011, the Company, through its wholly owned subsidiary Vectren Infrastructure Services Company, Inc., purchased Minnesota Limited, LLC, excluding certain assets. Minnesota Limited is a specialty contractor focusing on transmission pipeline construction and maintenance; pump station, compressor station, terminal and refinery construction; and hydrostatic testing. Minnesota Limited is headquartered in Big Lake, Minnesota and the majority of its customers are generally located in the northern Midwest region.
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Along with the Company’s wholly owned subsidiary, Miller Pipeline LLC, Minnesota Limited is included in the Infrastructure Services operating segment.
The Company accounted for the cash acquisition in accordance with FASB authoritative guidance for business combinations, which requires the Company to recognize the assets acquired and the liabilities assumed, measured at their fair values as of the date of acquisition.
The cash paid at acquisition, net of cash acquired, was $83.4 million. For the period from April 1, 2011 through December 31, 2011, Minnesota Limited contributed approximately $116.5 million and $9.4 million to the Company's revenue and net income, respectively.
The following table presents the Company's unaudited proforma results of operations for the year ended December 31, 2011 as if the acquisition had occurred on January 1, 2011.
(In millions, except per share data) | 2011 | |||
Total operating revenues | $ | 2,346.3 | ||
Net income | $ | 141.4 | ||
Basic earnings per share | $ | 1.73 | ||
Diluted earnings per share | $ | 1.73 | ||
In addition to the incremental revenues and expenses recorded by Minnesota Limited during this period, the proforma financial data contain several adjustments including the following: recording the additional amortization expense from the identifiable intangible assets; adjusting the estimated tax provision of the proforma combined results; and adjusting for the issuance of short-term debt to facilitate the acquisition. The Company prepared the proforma financial information for the combined entities for comparative purposes only, and it may not be indicative of what actual results would have been if the acquisition had taken place on the proforma date or of future results.
Concurrent with the purchase agreement, the Company executed a lease arrangement at fair value for the Minnesota Limited corporate headquarters, which is owned by a member of the Minnesota Limited management team and certain family members. The lease obligates the Company to pay approximately $83,333 per month for ten years along with certain executory costs for taxes and other operating expenses. In 2013, $1.5 million of leasehold improvements were made to the facility. Pursuant to FASB guidance, the Company accounts for the obligation as an operating lease, expensing the lease payments and executory costs as incurred.
6. Sale of Retail Gas Marketing Operations
On December 31, 2011, the Company sold its retail gas marketing operations performed through Vectren Source, receiving cash proceeds of approximately $84.3 million, excluding minor working capital adjustments. The sale, net of transaction costs, resulted in a pre-tax gain of approximately $25.4 million, which is included in Other operating expenses in the Consolidated Statements of Income. VEDO continues doing business with the third party purchaser of Vectren Source. This third party continues to sell natural gas directly to customers in VEDO’s service territory, and VEDO purchases receivables and natural gas from the third party. Vectren Source was a component of the Energy Marketing operating segment.
7. Investment in ProLiance Holdings, LLC
The Company 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, along with the long-term pipeline and storage commitments, of its energy marketing business, ProLiance Energy, LLC (ProLiance Energy), to a subsidiary of Energy Transfer Partners, ETC Marketing, Ltd (ETC). 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. Consistent with its ownership percentage, Vectren is allocated 61 percent of ProLiance’s profits and losses; however,
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governance and voting rights remain at 50 percent for each member, and therefore, the Company accounts for its investment in ProLiance using the equity method of accounting.
As a result of ProLiance exiting the natural gas marketing business on June 18, 2013, the Company recorded its share of the loss on the disposition, termination of long-term pipeline and storage commitments, and related transaction and other costs totaling $43.6 million pre-tax, or $26.8 million net of tax, during the second quarter of 2013. ProLiance funded an estimated equity shortfall at ProLiance Energy of $16.6 million at the time of the sale. To fund this estimated shortfall, the Company issued a note to ProLiance for its 61 percent ownership share of the $16.6 million shortfall, or $10.1 million, which was utilized by ProLiance to invest additional equity in ProLiance Energy. This interest-bearing note is classified as Other nonutility investments in the Consolidated Balance Sheets.
In addition, in connection with the sale, the Company and Citizens issued a guarantee to ETC. The guarantee issued by the Company and Citizens is a backup guarantee to the $50 million guarantee issued by ProLiance to ETC, and provides for a maximum guarantee of $25.0 million, or $15.3 million for the Company's 61 percent ownership share, and extends until 2016. This guarantee will be called upon only in the event of default as defined in the asset sale agreement and only if the ProLiance guarantee is not sufficient to satisfy the relevant obligations. Although there can be no assurance that these guarantees will not be called upon, the Company believes that the likelihood that the Company or ProLiance will be called upon to satisfy any obligations pursuant to these guarantees is remote.
As part of the transaction discussed above, ProLiance filed two petitions with the FERC seeking waivers of certain capacity release regulations. Under the first petition ProLiance sought to permanently release pipeline capacity to ETC that is used to provide service to retail customers. Under the second petition, ProLiance sought the same type of waiver in order to permanently release back to the utilities the pipeline contracts used to provide supply services to the utilities. The FERC has granted both requested waivers. ETC has taken assignment of the Portfolio Administration Agreements (PAAs) pursuant to which the utilities receive gas supply. With the receipt of the FERC waivers and with pipeline contracts having been transferred to the utilities, the utilities entered into an Asset Management Agreement (AMA) with ETC on September 1, 2013 and have temporarily released the pipeline contracts to ETC. ETC will fulfill the requirements of the PAAs through their remaining term ending in March 2016.
Vectren's remaining investment in ProLiance at December 31, 2013 is as follows and reflects that it relates primarily to ProLiance's investment in LA Storage, LLC (LA Storage) discussed below.
As of | |||
December 31, | |||
(In millions) | 2013 | ||
ProLiance Energy | $ | 1.5 | |
Midstream assets and cash from sale of | |||
storage assets | 7.8 | ||
LA Storage | 21.6 | ||
Total investment in ProLiance | $ | 30.9 | |
Included in: | |||
Investments in unconsolidated affiliates | 20.8 | ||
Other nonutility investments | 10.1 | ||
LA Storage, LLC Storage Asset Investment, Formerly Referred to as Liberty Gas Storage
ProLiance Transportation and Storage, LLC (PT&S), a subsidiary of ProLiance, and Sempra Energy International (SEI), a subsidiary of Sempra Energy (SE), through a joint venture, have a 100 percent interest in a development project for salt-cavern natural gas storage facilities known as LA Storage. PT&S is the minority member with a 25 percent interest, which it accounts for using the equity method. The project was expected to include 17 Bcf of capacity in its North site, and an additional capacity of at least 17 Bcf at the South site. The South site also has the potential for further expansion. The LA Storage pipeline system is currently connected with several interstate pipelines, including the Cameron Interstate Pipeline operated by Sempra Pipelines
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& Storage, and will connect area liquefied natural gas regasification terminals to an interstate natural gas transmission system and storage facilities.
In late 2008, the project at the North site was halted due to subsurface and well-completion problems, which resulted in the joint venture recording a $132 million impairment charge. The Company, through ProLiance, recorded its share of the charge in 2009. As a result of the issues encountered at the North site, Liberty requested and the FERC approved the separation of the North site from the South site. Approximately 12 Bcf of the storage at the South site, which comprises three of the four FERC certified caverns, is fully tested but additional work is required to connect the caverns to the pipeline system. As of December 31, 2013 and December 31, 2012, ProLiance’s investment in the joint venture was $35.4 million and $35.5 million, respectively.
The joint venture received a demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc. (“Williams”) on February 8, 2011 related to a Sublease Agreement (“Sublease”) between the joint venture and Williams at the North site. Williams alleges that the joint venture was negligent in its attempt to convert certain salt caverns to natural gas storage and thereby damaged the caverns. Williams alleges damages of $56.7 million. The joint venture intends to vigorously defend itself and has asserted counterclaims substantially in excess of the amounts asserted by Williams. As such, as of December 31, 2013, ProLiance has no material reserve recorded related to this matter and this litigation has not materially impacted ProLiance's results of operations or statement of financial position.
Transactions with ProLiance
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 $378.7 million, respectively. The Company purchases from ProLiance all occurred prior to June 18, 2013 when ProLiance exited the natural gas marketing business. The amounts owed to ProLiance at December 31, 2012, for those purchases was $29.7 million and is included in Accounts payable to affiliated companies in the Consolidated Balance Sheets.
8. Nonutility Real Estate & Other Legacy Holdings
Within the nonutility group, there are legacy investments involved in real estate, a leveraged lease, and other ventures. As of December 31, 2013 and 2012, total remaining legacy investments included in the Other Businesses portfolio total $26.5 million and $28.7 million, respectively. Further separation of that 2013 investment by type of investment follows:
December 31, 2013 | ||||||||||||
Value Included In | ||||||||||||
(In millions) | Carrying Value | Other Nonutility Investments | Investments in Unconsolidated Affiliates | |||||||||
Commercial real estate investments | $ | 8.0 | $ | 8.0 | $ | — | ||||||
Leveraged lease | 14.4 | 14.4 | — | |||||||||
Other investments | 4.1 | 1.3 | 2.8 | |||||||||
$ | 26.5 | $ | 23.7 | $ | 2.8 | |||||||
Commercial Real Estate Charge
During the fourth quarter of 2011, the Company obtained new evidence confirming further weakness in markets where the Company holds legacy real estate investments. The Company holds real estate investments such as an office building and affordable housing projects. The evaluation of the evidence resulted in a $15.4 million charge in 2011. Of the $15.4 million charge, $8.8 million is reflected in Other-net, $3.6 million is reflected in Equity in (losses) of unconsolidated affiliates, and $3.0 million is reflected in Other operating expenses.
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Leveraged Lease
At December 31, 2013, the Company has an investment in a leveraged lease. The original cost for the leased facility was $27.5 million and was partially financed by non-recourse debt provided by lenders who were granted an assignment of rentals due and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee. Such remaining debt was approximately $19.6 million at December 31, 2013. The book value of this leverage lease is $4.0 million at December 31, 2013, net of related deferred taxes of $10.4 million.
Other Investments
Other investments totaled $4.1 million at December 31, 2013 and are comprised of investments in partnership-like structures involved in multifamily housing and an asset from an exited generation project. The investments involving multifamily housing are variable interest entities where the Company is a limited partner. The Company's exposure to loss is limited to its investment, and the Company does not consolidate any of these entities. The multifamily housing investments are accounted for using the equity method.
9. Intangible Assets
Intangible assets, which are included in Other assets, consist of the following:
(In millions) | At December 31, | |||||||||||||||
2013 | 2012 | |||||||||||||||
Amortizing | Non-amortizing | Amortizing | Non-amortizing | |||||||||||||
Customer-related assets | $ | 17.4 | $ | — | $ | 18.9 | $ | — | ||||||||
Market-related assets | 1.9 | 7.0 | 2.7 | 7.0 | ||||||||||||
Intangible assets, net | $ | 19.3 | $ | 7.0 | $ | 21.6 | $ | 7.0 | ||||||||
As of December 31, 2013, the weighted average remaining life for amortizing customer-related assets and all amortizing intangibles is 13 years. These amortizing intangible assets have no significant residual values. Intangible assets are presented net of accumulated amortization totaling $8.1 million for customer-related assets and $2.6 million for market-related assets at December 31, 2013 and $6.6 million for customer-related assets and $1.7 million for market-related assets at December 31, 2012. Annual amortization associated with intangible assets totaled $2.3 million in 2013, $2.6 million in 2012 and $2.3 million in 2011. Amortization should approximate (in millions) $2.3, $2.2, $1.6, $1.4, and $1.4 in 2014, 2015, 2016, 2017, and 2018, respectively. Intangible assets are primarily in the Nonutility Group.
10. Income Taxes
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 & local taxes-net of federal benefit | 4.6 | 4.0 | 4.2 | ||||||
Amortization of investment tax credit | (0.3 | ) | (0.3 | ) | (0.3 | ) | |||
Depletion | (1.5 | ) | (1.5 | ) | (1.9 | ) | |||
Energy efficiency building deductions | (3.8 | ) | (3.0 | ) | (1.1 | ) | |||
Other tax credits | (1.1 | ) | (0.1 | ) | (0.2 | ) | |||
Adjustment of income tax accruals and all other-net | 0.1 | 0.1 | 2.2 | ||||||
Effective tax rate | 33.0 | % | 34.2 | % | 37.9 | % | |||
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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 | $ | 725.2 | $ | 681.6 | ||||
Leveraged lease | 10.4 | 10.8 | ||||||
Regulatory assets recoverable through future rates | 22.8 | 23.5 | ||||||
Other comprehensive income | (1.6 | ) | (4.0 | ) | ||||
Alternative minimum tax carryforward | (23.5 | ) | (44.1 | ) | ||||
Employee benefit obligations | (6.7 | ) | (2.1 | ) | ||||
Net operating loss & other carryforwards | (1.2 | ) | (11.7 | ) | ||||
Regulatory liabilities to be settled through future rates | (18.7 | ) | (18.3 | ) | ||||
Impairments | (6.2 | ) | (6.1 | ) | ||||
Other – net | 6.9 | 7.6 | ||||||
Net noncurrent deferred tax liability | 707.4 | 637.2 | ||||||
Current deferred tax liabilities (assets): | ||||||||
Deferred fuel costs-net | 22.9 | 25.7 | ||||||
Demand side management programs | 0.1 | 2.7 | ||||||
Alternative minimum tax carryforward | (33.7 | ) | (2.7 | ) | ||||
Net operating loss & other carryforwards | (4.9 | ) | — | |||||
Other – net | 1.7 | (10.8 | ) | |||||
Net current deferred tax liability (asset) | (13.9 | ) | 14.9 | |||||
Net deferred tax liability | $ | 693.5 | $ | 652.1 | ||||
At December 31, 2013 and 2012, investment tax credits totaling $5.3 million and $3.7 million respectively, are included in Deferred credits & other liabilities. The investment tax credit generated in 2013 will expire in 20 years. At December 31, 2013, the Company has alternative minimum tax carryforwards which do not expire. In addition, the Company has $6.1 million in net operating loss and general business credit carryforwards, which will expire in 5 to 20 years. The net operating loss carryforward was reduced for the impacts of unrecognized tax benefits and a valuation allowance relating to state net operating loss carryforwards. At December 31, 2013 and 2012, the valuation allowance was $3.6 million and $1.3 million, respectively.
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.
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The components of income tax expense and utilization of investment tax credits follow:
Year Ended December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
Current: | ||||||||||||
Federal | $ | 12.4 | $ | (8.2 | ) | $ | 4.4 | |||||
State | 11.4 | 6.4 | 10.3 | |||||||||
Total current taxes | 23.8 | (1.8 | ) | 14.7 | ||||||||
Deferred: | ||||||||||||
Federal | 43.4 | 80.3 | 66.0 | |||||||||
State | 0.5 | 4.6 | 6.4 | |||||||||
Total deferred taxes | 43.9 | 84.9 | 72.4 | |||||||||
Amortization of investment tax credits | (0.6 | ) | (0.6 | ) | (0.7 | ) | ||||||
Total income tax expense | $ | 67.1 | $ | 82.5 | $ | 86.4 | ||||||
Uncertain Tax Positions
Following is a roll forward of unrecognized tax benefits for the three years ended December 31, 2013:
(In millions) | 2013 | 2012 | 2011 | |||||||||
Unrecognized tax benefits at January 1 | $ | 4.8 | $ | 12.4 | $ | 13.3 | ||||||
Gross increases - tax positions in prior periods | — | 0.2 | 3.3 | |||||||||
Gross decreases - tax positions in prior periods | (0.2 | ) | (9.4 | ) | (4.5 | ) | ||||||
Gross increases - current period tax positions | 1.2 | 1.9 | 0.6 | |||||||||
Settlements | — | (0.3 | ) | (0.3 | ) | |||||||
Lapse of statute of limitations | 0.1 | — | — | |||||||||
Unrecognized tax benefits at December 31 | $ | 5.9 | $ | 4.8 | $ | 12.4 | ||||||
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 $0.7 million at each of 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.
The Company recognized income related to a reversal of interest expense previously accrued and net of penalties totaling approximately $0.1 million in 2013 and $0.7 million in 2012. In 2011, the Company recognized expense related to interest and penalties totaling approximately $0.4 million . The Company had approximately $0.5 million and $0.6 million for the payment of interest and penalties accrued as of December 31, 2013 and 2012, respectively.
The net liability on the Consolidated Balance Sheet for unrecognized tax benefits inclusive of interest, penalties and net of secondary impacts which are a component of the Deferred income taxes and are benefits, totaled $3.8 million and $3.2 million, respectively, at December 31, 2013 and 2012.
The Company and/or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. The
Internal Revenue Service (IRS) has concluded examinations of the Company'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 the Company 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, the Company's primary state tax
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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.
11. Retirement Plans & Other Postretirement Benefits
At December 31, 2013, the Company maintains three qualified defined benefit pension plans, a nonqualified supplemental executive retirement plan (SERP), and a postretirement benefit plan. The defined benefit pension plans and postretirement benefit plan, which cover eligible full-time regular employees, are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The qualified pension plans and the SERP are aggregated under the heading “Pension Benefits.” The postretirement benefit plan is presented under the heading “Other Benefits.”
Net Periodic Benefit Costs
A summary of the components of net periodic benefit cost for the three years ended December 31, 2013 follows:
Pension Benefits | Other Benefits | |||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
Service cost | $ | 8.6 | $ | 7.7 | $ | 6.9 | $ | 0.5 | $ | 0.5 | $ | 0.5 | ||||||||||||
Interest cost | 14.7 | 15.5 | 15.9 | 2.0 | 2.8 | 4.3 | ||||||||||||||||||
Expected return on plan assets | (22.1 | ) | (21.2 | ) | (21.2 | ) | — | — | — | |||||||||||||||
Amortization of prior service cost (benefit) | 1.5 | 1.6 | 1.7 | (3.2 | ) | (2.5 | ) | (0.8 | ) | |||||||||||||||
Amortization of actuarial loss (gain) | 10.1 | 6.8 | 3.8 | 0.7 | 0.7 | 0.6 | ||||||||||||||||||
Amortization of transitional obligation | — | — | — | — | 0.5 | 1.1 | ||||||||||||||||||
Settlement (credit) charge | 1.3 | — | — | — | — | — | ||||||||||||||||||
Net periodic benefit cost | $ | 14.1 | $ | 10.4 | $ | 7.1 | $ | — | $ | 2.0 | $ | 5.7 | ||||||||||||
A portion of the net periodic benefit cost disclosed in the table above is capitalized as Utility plant. Costs capitalized in 2013, 2012, and 2011 are estimated at $4.2 million, $3.7 million, and $3.9 million, respectively.
The Company lowered the discount rate used to measure periodic cost from 4.82 percent in 2012 to 4.03 percent in 2013 due to lower benchmark interest rates that approximated the expected duration of the Company’s benefit obligations as of that valuation date. For fiscal year 2014, the weighted average discount rate assumption will increase to 4.74 percent for the defined benefit pension plans, based on increased benchmark interest rates.
The weighted averages of significant assumptions used to determine net periodic benefit costs follow:
Pension Benefits | Other Benefits | |||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||
Discount rate | 4.03 | % | 4.82 | % | 5.50 | % | 3.91 | % | 4.75 | % | 5.50 | % | ||||||
Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | N/A | N/A | N/A | |||||||||
Expected return on plan assets | 7.75 | % | 7.75 | % | 8.00 | % | N/A | N/A | 8.00 | % | ||||||||
Expected increase in Consumer Price Index | N/A | N/A | N/A | 2.75 | % | 2.75 | % | 3.00 | % | |||||||||
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Health care cost trend rate assumptions do not have a material effect on the service and interest cost components of benefit costs. The Company’s plans limit its exposure to increases in health care costs to annual changes in the Consumer Price Index (CPI). Any increase in health care costs in excess of the CPI increase is the responsibility of the plan participants.
Benefit Obligations
A reconciliation of the Company’s benefit obligations at December 31, 2013 and 2012 follows:
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Benefit obligation, beginning of period | $ | 377.3 | $ | 329.2 | $ | 54.4 | $ | 79.7 | ||||||||
Service cost – benefits earned during the period | 8.6 | 7.7 | 0.5 | 0.5 | ||||||||||||
Interest cost on projected benefit obligation | 14.7 | 15.5 | 2.0 | 2.8 | ||||||||||||
Plan participants' contributions | — | — | 0.8 | 1.6 | ||||||||||||
Plan amendments | — | 0.7 | (0.2 | ) | (26.6 | ) | ||||||||||
Actuarial loss (gain) | (32.7 | ) | 39.0 | (2.4 | ) | 2.8 | ||||||||||
Settlement loss (gain) | 1.5 | — | — | — | ||||||||||||
Medicare subsidy receipts | — | — | — | 0.5 | ||||||||||||
Benefit payments | (22.8 | ) | (14.8 | ) | (3.8 | ) | (6.9 | ) | ||||||||
Settlement payments | (8.2 | ) | — | — | — | |||||||||||
Benefit obligation, end of period | $ | 338.4 | $ | 377.3 | $ | 51.3 | $ | 54.4 | ||||||||
The accumulated benefit obligation for all defined benefit pension plans was $321.9 million and $354.5 million at December 31, 2013 and 2012, respectively.
Postretirement Benefit Change
Effective September 1, 2012, the Company no longer offers postretirement health coverage for participants 65 and older. Rather, the Company provides a subsidy to plan participants to purchase health coverage through a private Medicare exchange. This change in benefits provides a comparable benefit at a reduced cost made possible by current market pricing. Since this change in benefits was a significant event pursuant to GAAP, the Company remeasured its postretirement benefit obligations as of June 1, 2012, consistent with the notification date to participants. The change in benefits, net of the impacts associated with remeasuring the benefit obligations using a lower discount rate, resulted in a $23 million reduction in the postretirement liability. Substantially all of the amount was recorded as a reduction to Regulatory Assets, as the Company's retirement costs primarily relate to its regulated utilities. The discount rate used to remeasure the postretirement benefit obligation was 3.93 percent.
The benefit obligation as of December 31, 2013 and 2012 was calculated using the following weighted average assumptions:
Pension Benefits | Other Benefits | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
Discount rate | 4.74 | % | 4.03 | % | 4.66 | % | 3.91 | % | ||||
Rate of compensation increase | 3.50 | % | 3.50 | % | N/A | N/A | ||||||
Expected increase in Consumer Price Index | N/A | N/A | 2.75 | % | 2.75 | % | ||||||
To calculate the 2013 ending postretirement benefit obligation, medical claims costs in 2014 were assumed to be 7 percent higher than those incurred in 2013. That trend was assumed to reach its ultimate trending increase of 5 percent by 2018 and remain level thereafter. A one-percentage point change in assumed health care cost trend rates would have changed the benefit obligation by approximately $0.4 million.
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Plan Assets
A reconciliation of the Company’s plan assets at December 31, 2013 and 2012 follows:
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Plan assets at fair value, beginning of period | $ | 295.7 | $ | 261.0 | $ | — | $ | — | ||||||||
Actual return on plan assets | 48.4 | 33.8 | — | — | ||||||||||||
Employer contributions | 10.8 | 15.7 | 3.0 | 5.3 | ||||||||||||
Plan participants' contributions | — | — | 0.8 | 1.6 | ||||||||||||
Benefit payments | (22.8 | ) | (14.8 | ) | (3.8 | ) | (6.9 | ) | ||||||||
Settlement payments | (8.2 | ) | — | — | — | |||||||||||
Fair value of plan assets, end of period | $ | 323.9 | $ | 295.7 | $ | — | $ | — | ||||||||
The Company’s overall investment strategy for its retirement plan trusts is to maintain investments in a diversified portfolio, comprised of primarily equity and fixed income investments, which are further diversified among various asset classes. The diversification is designed to minimize the risk of large losses while maximizing total return within reasonable and prudent levels of risk. The investment objectives specify a targeted investment allocation for the pension plans of 60 percent equities, 35 percent debt, and 5 percent for other investments, including real estate. Both the equity and debt securities have a blend of domestic and international exposures. Objectives do not target a specific return by asset class. The portfolios’ return is monitored in total. Following is a description of the valuation methodologies used for trust assets measured at fair value.
Mutual Funds
The fair values of mutual funds are derived from quoted market prices or net asset values as these instruments have active markets (Level 1 inputs).
Common Collective Trust Funds (CTF’s)
The Company’s plans have investments in trust funds similar to mutual funds in that they are created by pooling of funds from investors into a common trust and such funds are managed by a third party investment manager. These trust funds typically give investors a wider range of investment options through this pooling of funds than that generally available to investors on an individual basis. However, unlike mutual funds, these trusts are not publicly traded in an active market. The fair values of these trusts are derived from Level 2 market inputs based on a daily calculated unit value as determined by the issuer. This daily calculated value is based on the fair market value of the underlying investments. These funds are primarily comprised of investments in equity and fixed income securities which represent approximately 53 percent and 42 percent, respectively, of their fair value as of December 31, 2013 and approximately 53 percent and 38 percent, respectively, as of December 31, 2012. Equity securities within these funds are primarily valued using quoted market prices as these instruments have active markets. From time to time, less liquid equity securities are valued using Level 2 inputs, such as bid prices or a closing price, as determined in good faith by the investment manager. Fixed income securities are valued at the last available bid prices quoted by an independent pricing service. When valuations are not readily available, fixed income securities are valued using primarily other Level 2 inputs as determined in good faith by the investment manager.
The fair value of these funds totals $161.7 million at December 31, 2013 and $145.0 million at December 31, 2012. In relation to these investments, there are no unfunded commitments. Also, the Plan can exchange shares with minimal restrictions, however, certain events may exist where share exchanges are restricted for up to 31 days.
Guaranteed Annuity Contract
One of the Company’s pension plans is party to a group annuity contract with John Hancock Life Insurance Company (John Hancock). At December 31, 2013 and 2012, the estimate of undiscounted funds necessary to satisfy John Hancock’s remaining obligation was $3.7 million and $3.6 million, respectively. If funds retained by John Hancock are not sufficient to satisfy retirement payments due these retirees, the shortfall must be funded by the Company. The composite investment return, net of manager fees and other charges for the years ended December 31, 2013 and 2012 was 4.75 percent and 5.17 percent, respectively. The Company values this illiquid investment using long-term interest rate and mortality assumptions, among others, and is therefore considered a Level 3 investment. There is no unfunded commitment related to this investment.
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The fair values of the Company’s pension and other retirement plan assets at December 31, 2013 and December 31, 2012 by asset category and by fair value hierarchy are as follows:
As of December 31, 2013 | ||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Domestic equities & equity funds | $ | 69.6 | $ | 85.6 | $ | — | $ | 155.2 | ||||||||
International equities & equity funds | 41.9 | — | — | 41.9 | ||||||||||||
Domestic bonds & bond funds | 40.4 | 55.4 | — | 95.8 | ||||||||||||
Inflation protected security fund | — | 12.1 | — | 12.1 | ||||||||||||
Real estate, commodities & other | 6.2 | 8.6 | 4.1 | 18.9 | ||||||||||||
Total plan investments | $ | 158.1 | $ | 161.7 | $ | 4.1 | $ | 323.9 | ||||||||
As of December 31, 2012 | ||||||||||||||||
(In millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Domestic equities & equity funds | $ | 62.8 | $ | 77.6 | $ | — | $ | 140.4 | ||||||||
International equities & equity funds | 34.3 | — | — | 34.3 | ||||||||||||
Domestic bonds & bond funds | 41.7 | 42.3 | — | 84.0 | ||||||||||||
Inflation protected security fund | — | 12.6 | — | 12.6 | ||||||||||||
Real estate, commodities & other | 8.0 | 12.5 | 3.9 | 24.4 | ||||||||||||
Total plan investments | $ | 146.8 | $ | 145.0 | $ | 3.9 | $ | 295.7 | ||||||||
A roll forward of the fair value of the guaranteed annuity contract calculated using Level 3 valuation assumptions follows:
(In millions) | 2013 | 2012 | ||||||
Fair value, beginning of year | $ | 3.9 | $ | 3.8 | ||||
Unrealized gains related to investments still held at reporting date | 0.2 | 0.2 | ||||||
Purchases, sales and settlements, net | — | (0.1 | ) | |||||
Fair value, end of year | $ | 4.1 | $ | 3.9 | ||||
Funded Status
The funded status of the plans as of December 31, 2013 and 2012 follows:
Pension Benefits | Other Benefits | |||||||||||||||
(In millions) | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Qualified Plans | ||||||||||||||||
Benefit obligation, end of period | $ | (321.0 | ) | $ | (360.0 | ) | $ | (51.4 | ) | $ | (54.4 | ) | ||||
Fair value of plan assets, end of period | 323.9 | 295.7 | — | — | ||||||||||||
Funded Status of Qualified Plans, end of period | 2.9 | (64.3 | ) | (51.4 | ) | (54.4 | ) | |||||||||
Benefit obligation of SERP Plan, end of period | (17.5 | ) | (17.3 | ) | — | — | ||||||||||
Total funded status, end of period | $ | (14.6 | ) | $ | (81.6 | ) | $ | (51.4 | ) | $ | (54.4 | ) | ||||
Accrued liabilities | $ | 1.0 | $ | 1.0 | $ | 4.9 | $ | 4.5 | ||||||||
Deferred credits & other liabilities | $ | 20.1 | $ | 80.6 | $ | 46.4 | $ | 49.9 | ||||||||
Other Assets | $ | 6.5 | $ | — | $ | — | $ | — | ||||||||
Expected Cash Flows
In 2014, the Company anticipates making no contributions to its qualified pension plans. In addition, the Company expects to make payments totaling approximately $1.0 million directly to SERP participants and approximately $3.7 million directly to those participating in the postretirement plan.
Estimated retiree pension benefit payments, including the SERP, projected to be required during the years following 2013 are approximately (in millions) $23.7 in 2014, $23.6 in 2015, $24.6 in 2016, $34.3 in 2017, $25.5 in 2018, and $140.4 in years
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2019-2023. Expected benefit payments projected to be required for postretirement benefits during the years following 2013 (in millions) are approximately $4.9 in 2014, $5.0 in 2015, $5.2 in 2016, $5.5 in 2017, $5.9 in 2018, and $31.9 in years 2019-2023.
Prior Service Cost, Actuarial Gains and Losses, and Transition Obligation Effects
Following is a roll forward of prior service cost, actuarial gains and losses, and transition obligations.
Pensions | Other Benefits | |||||||||||||||||||
(In millions) | Prior Service Cost | Net Gain or Loss | Prior Service Cost | Net Gain or Loss | Transition Obligation | |||||||||||||||
Balance at January 1, 2011 | $ | 7.1 | $ | 78.2 | $ | (2.0 | ) | $ | 10.3 | $ | 3.8 | |||||||||
Amounts arising during the period | — | 42.2 | — | (0.6 | ) | — | ||||||||||||||
Reclassification to benefit costs | (1.7 | ) | (3.8 | ) | 0.8 | (0.6 | ) | (1.1 | ) | |||||||||||
Balance at December 31, 2011 | $ | 5.4 | $ | 116.6 | $ | (1.2 | ) | $ | 9.1 | $ | 2.7 | |||||||||
Amounts arising during the period | 0.7 | 26.4 | (24.4 | ) | 2.8 | (2.2 | ) | |||||||||||||
Reclassification to benefit costs | (1.6 | ) | (6.8 | ) | 2.5 | (0.7 | ) | (0.5 | ) | |||||||||||
Balance at December 31, 2012 | $ | 4.5 | $ | 136.2 | $ | (23.1 | ) | $ | 11.2 | $ | — | |||||||||
Amounts arising during the period | — | (58.8 | ) | (0.2 | ) | (2.4 | ) | — | ||||||||||||
Reclassification to benefit costs | (1.5 | ) | (10.1 | ) | 3.2 | (0.7 | ) | — | ||||||||||||
Balance at December 31, 2013 | $ | 3.0 | $ | 67.3 | $ | (20.1 | ) | $ | 8.1 | $ | — | |||||||||
Following is a reconciliation of the amounts in Accumulated other comprehensive income (AOCI) and Regulatory assets related to retirement plan obligations at December 31, 2013 and 2012.
(In millions) | 2013 | 2012 | ||||||||||||||
Pensions | Other Benefits | Pensions | Other Benefits | |||||||||||||
Prior service cost | $ | 3.0 | $ | (20.1 | ) | $ | 4.5 | $ | (23.1 | ) | ||||||
Unamortized actuarial gain/(loss) | 67.3 | 8.1 | 136.2 | 11.2 | ||||||||||||
Transition obligation | — | — | — | — | ||||||||||||
70.3 | (12.0 | ) | 140.7 | (11.9 | ) | |||||||||||
Less: Regulatory asset deferral | (68.9 | ) | 11.8 | (137.9 | ) | 11.7 | ||||||||||
AOCI before taxes | $ | 1.4 | $ | (0.2 | ) | $ | 2.8 | $ | (0.2 | ) | ||||||
Related to pension plans, $1.1 million of prior service cost and $4.7 million of actuarial gain/loss is expected to be amortized to cost in 2014. Related to other benefits, $0.4 million of actuarial gain/loss is expected to be amortized to periodic cost in 2014, and $3.0 million of prior service cost is expected to reduce costs in 2014.
Multi-employer Benefit Plan
The Company, through its Infrastructure Services operating segment, participates in several industry wide multi-employer pension plans for its union employees which provide for monthly benefits based on length of service. The risks of participating in multi-employer pension plans are different from the risks of participating in single-employer pension plans in the following respects: 1) assets contributed to the multi-employer plan by one employer may be used to provide benefits to employees of other participating employers, 2) if a participating employer stops contributing to the plan, the unfunded obligations of the plan allocable to such withdrawing employer may be borne by the remaining participating employers, and 3) if the Company stops participating in some of its multi-employer pension plans, the Company may be required to pay those plans an amount based on its allocable share of the underfunded status of the plan, referred to as a withdrawal liability.
Expense is recognized as payments are accrued for work performed or when withdrawal liabilities are probable and estimable. Expense associated with multi-employer plans was $33.2 million, $27.6 million and $18.3 million for the years ended December 31, 2013, 2012, and 2011, respectively. The increase in expense is due primarily to the increase in work performed. During 2013, the Company, made contributions to these multi-employer plans on behalf of employees that participate in approximately 270 local unions. Contracts with these unions are negotiated with trade agreements through two primary
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contractor associations. These trade agreements have varying expiration dates ranging from 2014 through 2016. The average contribution related to these local unions was less than $0.2 million, and the largest contribution was $4.0 million. Multiple unions can contribute to a single multi-employer plan. The Company made contributions to at least sixty plans in 2013, four of which are considered significant plans based on, among other things, the amount of the contributions, the number of employees participating in the plan, and the funded status of the plan.
The Company's participation in the significant plans is outlined in the following table. The Employer Identification Number (EIN) / Pension Plan Number column provides the EIN and three digit pension plan numbers. The most recent Pension Protection Act Zone Status available in 2013 and 2012 is for the plan year end at January 31, 2012 and 2011 for the Central Pension Fund, December 31, 2012 and 2011 for the Pipeline Industry Benefit Fund, May 31, 2013 and 2012 for the Indiana Laborers Pension Fund, and December 31, 2012 and 2011 for the Minnesota Laborers Pension Fund, respectively. Generally, plans in the red zone are less than 65 percent funded, plans in the yellow zone are less than 80 percent funded and plans in the green zone are at least 80 percent funded. The FIP/RP Status Pending / Implemented column indicates plans for which a funding improvement plan ("FIP") or rehabilitation plan ("RP") is either pending or has been implemented. The multi-employer contributions listed in the table below are the Company's multi-employer contributions made in 2013, 2012, and 2011.
(In millions) | ||||||||||||||||
Pension Protection Act Zone Status | Multi-Employer Contributions | |||||||||||||||
Pension Fund | EIN/Pension Plan Number | 2013 | 2012 | FIP/RP Status Pending/Implemented | 2013 | 2012 | 2011 | Surcharge Imposed | ||||||||
Central Pension Fund | 36-6052390-001 | Green | Green | No | $8.5 | $4.0 | $2.3 | No | ||||||||
Pipeline Industry Benefit Fund | 73-0742835-001 | Green | Green | No | 5.3 | 3.9 | 1.0 | No | ||||||||
Indiana Laborers Pension Fund (1) | 35-6027150-001 | Yellow | Yellow | Implemented | 2.4 | 3.2 | 1.6 | No | ||||||||
Minnesota Laborers Pension Fund | 41-6159599-001 | Green | Green | No | 2.8 | 2.0 | 0.7 | No | ||||||||
Other | 14.2 | 14.5 | 12.7 | |||||||||||||
Total Contributions | $33.2 | $27.6 | $18.3 | |||||||||||||
(1) Federal law requires pension plans in endangered status to adopt a funding improvement plan aimed at restoring the financial health of the plan. Since this plan became endangered as of June 1, 2008, a funding improvement plan was previously set in place to begin June 1, 2009. The funding improvement plan requires that the plan's funded percentage improve at least thirty-three percent of the way to 100 percent over a ten-year period. The target for this plan under the law is a funded percentage of 78 percent by 2019. The plan must also meet the federal minimum funding requirements during this 10-year period. Based on the plan's most current actuarial projections, the plan is projected to meet or exceed these benchmarks.
While not considered significant to the Company, there are eight plans in red zone status receiving Company contributions and three other plans where Company contributions exceed 5 percent of each plan's total contributions.
Defined Contribution Plan
The Company also has defined contribution retirement savings plans that are qualified under sections 401(a) and 401(k) of the Internal Revenue Code and include an option to invest in Vectren common stock, among other alternatives. During 2013, 2012 and 2011, the Company made contributions to these plans of $7.5 million, $6.7 million, and $6.2 million, respectively.
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12. Borrowing Arrangements
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 | ||||||
Indiana Gas | ||||||||
Fixed Rate 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 | ||||||
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 | ||||||
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At December 31, | ||||||||
(In millions) | 2013 | 2012 | ||||||
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 | ||||||
Vectren Capital Corp. | ||||||||
Fixed Rate Senior Unsecured Notes | ||||||||
2014, 6.37% | 30.0 | 30.0 | ||||||
2015, 5.31% | 75.0 | 75.0 | ||||||
2016, 6.92% | 60.0 | 60.0 | ||||||
2017, 3.48% | 75.0 | 75.0 | ||||||
2019, 7.30% | 60.0 | 60.0 | ||||||
2025, 4.53% | 50.0 | 50.0 | ||||||
Variable Rate Term Loans | ||||||||
2015, current adjustable rate 1.17% | 100.0 | 100.0 | ||||||
2016, current adjustable rate 1.17% | 100.0 | — | ||||||
Total Vectren Capital Corp. | 550.0 | 450.0 | ||||||
Other Long-Term Notes Payable | — | 1.4 | ||||||
Total long-term debt outstanding | 1,808.5 | 1,661.5 | ||||||
Current maturities of long-term debt | (30.0 | ) | (106.4 | ) | ||||
Unamortized debt premium & discount - net | (1.4 | ) | (1.7 | ) | ||||
Total long-term debt-net | $ | 1,777.1 | $ | 1,553.4 | ||||
Vectren Capital 2013 Term Loan
On August 6, 2013, Vectren Capital entered into a $100 million three year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus an additional margin which is based on the Company's credit rating. Interest periods are variable and may range from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties, and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. The Company received net proceeds of approximately $100 million in August 2013.
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 December 31, 2038, and $39.6 million at 4.05 percent per annum due December 31, 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 Utility Holdings' $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
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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.
Vectren Capital 2012 Term Loan
On November 1, 2012, Vectren Capital entered into a $100 million three year term loan agreement. Loans under the term loan agreement bear interest at either a Eurodollar rate or base rate plus an additional margin which is based on the Company's credit rating. Interest periods are variable and may range from seven days to six months. The proceeds from this debt transaction were used to repay short-term borrowings outstanding under Vectren Capital's credit facility. The loan agreement is guaranteed by Vectren Corporation and includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capital borrowing arrangements. The Company received net proceeds of approximately $100 million in November 2012.
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 Utility Holdings' $96.2 million 5.95 percent senior notes due 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 $149.0 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.
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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 2041of 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, Utility Holdings has letters of credit outstanding in support of two SIGECO tax exempt adjustable rate first mortgage bonds totaling $41.7 million. In the unlikely event the letters of credit were called, the Company could settle with the financial institutions supporting these letters of credit with general assets or by drawing from its 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 five years following 2013 (in millions) are $30.0 in 2014, $279.8 in 2015, $173.0 in 2016, $75.0 in 2017, $100.0 in 2018, and $1,149.3 thereafter.
Debt Guarantees
Vectren Corporation guarantees Vectren Capital’s long-term debt, including current maturities, and short-term debt, which totaled $550 million and $40 million, respectively, at December 31, 2013. 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
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 financial covenants.
Short-Term Borrowings
At December 31, 2013, the Company has $600 million of short-term borrowing capacity, including $350 million for the Utility Group and $250 million for the wholly owned Nonutility Group and corporate operations. As reduced by borrowings currently outstanding, approximately $321 million was available for the Utility Group operations and approximately $210 million was available for the wholly owned Nonutility Group and corporate operations. Both Vectren Capital’s and Utility Holdings’ short-term credit facilities were renewed in November 2011 and are available through September 2016. The maximum limit of both facilities remained unchanged. These facilities are used to supplement working capital needs and also to fund capital investments and debt redemptions until financed on a long-term basis.
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Following is certain information regarding these short-term borrowing arrangements.
Utility Group Borrowings | Nonutility Group Borrowings | |||||||||||||||||||||||
(In millions) | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | ||||||||||||||||||
As of Year End | ||||||||||||||||||||||||
Balance Outstanding | $ | 28.6 | $ | 116.7 | $ | 242.8 | $ | 40.0 | $ | 162.1 | $ | 84.3 | ||||||||||||
Weighted Average Interest Rate | 0.29 | % | 0.40 | % | 0.57 | % | 1.27 | % | 1.35 | % | 1.45 | % | ||||||||||||
Annual Average | ||||||||||||||||||||||||
Balance Outstanding | $ | 119.6 | $ | 77.6 | $ | 39.6 | $ | 119.3 | $ | 151.5 | $ | 124.9 | ||||||||||||
Weighted Average Interest Rate | 0.34 | % | 0.47 | % | 0.48 | % | 1.35 | % | 1.44 | % | 1.92 | % | ||||||||||||
Maximum Month End Balance Outstanding | $ | 176.1 | $ | 214.2 | $ | 242.8 | $ | 173.8 | $ | 216.1 | $ | 180.1 | ||||||||||||
Throughout 2013, 2012, and 2011, the Company has placed commercial paper without any significant issues and did not borrow from Utility Holdings' backup credit facility in any of the periods presented.
13. Common Shareholders’ Equity
Authorized, Reserved Common and Preferred Shares
At December 31, 2013 and 2012, the Company was authorized to issue 480 million shares of common stock and 20 million shares of preferred stock. Of the authorized common shares, approximately 5.8 million shares at December 31, 2013 and 6.5 million shares at December 31, 2012, were reserved by the board of directors for issuance through the Company’s share-based compensation plans, benefit plans, and dividend reinvestment plan. At December 31, 2013 and 2012, there were 391.7 million and 391.3 million, respectively, of authorized shares of common stock and all authorized shares of preferred stock, available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions.
14. Earnings Per Share
The Company uses the two class method to calculate earnings per share (EPS). The two class method is an earnings allocation formula that treats a participating security as having rights to earnings that otherwise would have been available to common shareholders. Under the two class method, earnings for a period are allocated between common shareholders and participating security holders based on their respective rights to receive dividends as if all undistributed book earnings for the period were distributed.
Basic EPS is computed by dividing net income attributable to only the common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the impact of stock options and other equity based instruments to the extent the effect is dilutive.
The following table illustrates the basic and dilutive EPS calculations for the three years ended December 31, 2013:
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Year Ended December 31, | ||||||||||||
(In millions, except per share data) | 2013 | 2012 | 2011 | |||||||||
Numerator: | ||||||||||||
Numerator for basic EPS | $ | 136.6 | $ | 159.0 | $ | 141.6 | ||||||
Add back earnings attributable to participating securities | — | — | — | |||||||||
Reported net income (Numerator for Diluted EPS) | $ | 136.6 | $ | 159.0 | $ | 141.6 | ||||||
Denominator: | ||||||||||||
Weighted average common shares outstanding (Basic EPS) | 82.3 | 82.0 | 81.8 | |||||||||
Conversion of share based compensation arrangements | 0.1 | 0.1 | 0.0 | |||||||||
Adjusted weighted average shares outstanding and | ||||||||||||
assumed conversions outstanding (Diluted EPS) | 82.4 | 82.1 | 81.8 | |||||||||
Basic earnings per share | $ | 1.66 | $ | 1.94 | $ | 1.73 | ||||||
Diluted earnings per share | $ | 1.66 | $ | 1.94 | $ | 1.73 | ||||||
For the years ended December 31, 2013 , 2012, and 2011, all options and equity based instruments were dilutive.
15. Accumulated Other Comprehensive Income
A summary of the components of and changes in Accumulated other comprehensive income for the past three years follows:
2011 | 2012 | 2013 | ||||||||||||||||||||||||||
Beginning of Year | Changes During | End of Year | Changes During | End of Year | Changes During | End of Year | ||||||||||||||||||||||
(In millions) | Balance | Year | Balance | Year | Balance | Year | Balance | |||||||||||||||||||||
Unconsolidated affiliates | $ | (6.6 | ) | $ | (9.3 | ) | $ | (15.9 | ) | $ | 11.3 | $ | (4.6 | ) | $ | 4.6 | $ | — | ||||||||||
Pension & other benefit costs | (4.9 | ) | (1.7 | ) | (6.6 | ) | 4.0 | (2.6 | ) | 1.4 | (1.2 | ) | ||||||||||||||||
Cash flow hedges | 4.0 | (3.9 | ) | 0.1 | (0.1 | ) | — | — | — | |||||||||||||||||||
Deferred income taxes | 3.1 | 6.0 | 9.1 | (6.2 | ) | 2.9 | (2.4 | ) | 0.5 | |||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (4.4 | ) | $ | (8.9 | ) | $ | (13.3 | ) | $ | 9.0 | $ | (4.3 | ) | $ | 3.6 | $ | (0.7 | ) | |||||||||
Accumulated other comprehensive income arising from unconsolidated affiliates was previously primarily the Company’s portion of ProLiance Holdings, LLC’s accumulated comprehensive income related to use of cash flow hedges. (See Note 7 for more information on ProLiance.)
16. Share-Based Compensation & Deferred Compensation Arrangements
The Company has share-based compensation programs to encourage Company officers, key non-officer employees, and non-employee directors to remain with the Company and to more closely align their interests with those of the Company’s shareholders. Under these programs, the Company has in the past issued stock options and both performance-based and time-based awards. All share-based compensation programs are shareholder approved. Currently, awards issued to officers of the Company, which comprise a substantial majority of the awards issued, are performance-based, are settled in cash, and dividends that accrue are also subject to performance measures. In addition, the Company maintains a deferred compensation plan for executives and non-employee directors where participants can invest earned compensation and vested share-based awards in phantom Company stock units, among other options. Certain vesting grants provide for accelerated vesting if there is a change in control or upon the participant’s retirement.
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Following is a reconciliation of the total cost associated with share-based awards recognized in the Company’s financial statements to its after tax effect on net income:
Year Ended December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
Total cost of share-based compensation | $ | 14.8 | $ | 6.3 | $ | 5.8 | ||||||
Less capitalized cost | 2.8 | 1.2 | 0.8 | |||||||||
Total in other operating expense | 12.0 | 5.1 | 5.0 | |||||||||
Less income tax benefit in earnings | 4.8 | 2.1 | 2.0 | |||||||||
After tax effect of share-based compensation | $ | 7.2 | $ | 3.0 | $ | 3.0 | ||||||
Performance Based Awards & Other Awards
The vesting of awards issued to Company officers and other key non-officer employees is contingent upon meeting a total return and return on equity performance objectives. Grants to Company officers and key non-officer employees generally vest at the end of a four-year period, with performance measured at the end of the third year. Based on that performance, awards could double or could be entirely forfeited. However, a limited number of awards have also been time-vested awards that vest ratably over a three or five year period. In addition non-employee directors receive a portion of their fees in share based awards. These awards to non-employee directors are not performance based and generally vest over one year. Because Company officers and non-employee directors have the choice of settling awards in cash or deferring their receipt into a deferred compensation plan (where the value is eventually withdrawn in cash), these awards are accounted for as liability awards at their settlement date fair value. Certain share awards to key non-officer employees must be settled in shares and are therefore accounted for in equity at their grant date fair value.
A summary of the status of awards separated between those accounted for as liabilities and equity as of December 31, 2013, and changes during the year ended December 31, 2013, follows:
Equity Awards | ||||||||||||
Wtd. Avg. | ||||||||||||
Grant Date | Liability Awards | |||||||||||
Units | Fair value | Units | Fair value | |||||||||
Awards at January 1, 2013 | 70,493 | $ | 27.45 | 628,810 | ||||||||
Granted | 28,579 | 30.19 | 305,617 | |||||||||
Vested | (15,175) | 26.04 | (158,187) | |||||||||
Forfeited | (3,940) | 26.20 | (44,989) | |||||||||
Awards at December 31, 2013 | 79,957 | $ | 29.12 | 731,251 | $ | 35.50 | ||||||
As of December 31, 2013, there was $11.8 million of total unrecognized compensation cost associated with outstanding grants. That cost is expected to be recognized over a weighted-average period of 2.3 years. The total fair value of shares vested for liability awards during the years ended December 31, 2013, 2012, and 2011, was $5.7 million, $4.4 million, and $3.0 million, respectively. The total fair value of equity awards vesting during the year ended December 31, 2013, 2012, and 2011 was $0.4 million, $0.1 million, $0.2 million, respectively.
Stock Option Plans
In the past, option awards were granted to executives and other key employees with an exercise price equal to the market price of the Company’s stock at the date of grant; those option awards generally required three years of continuous service and have 10-year contractual terms. These awards generally vested on a pro-rata basis over three years. The last option grant occurred in 2005, and the Company does not intend to issue options in the future. All compensation cost has been recognized. A summary of the status of the Company’s stock option awards as of December 31, 2013, and changes during the year ended December 31, 2013, follows:
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Weighted average | Aggregate | ||||||||||||
Shares | Exercise Price | Remaining Contractual Term (years) | Intrinsic Value (In millions) | ||||||||||
Outstanding at January 1, 2013 | 386,565 | $ | 25.88 | ||||||||||
Exercised | (378,592 | ) | $ | 25.87 | |||||||||
Forfeited or expired | (727 | ) | $ | 22.57 | |||||||||
Outstanding at December 31, 2013 | 7,246 | $ | 26.70 | 1.0 | $ | 0.6 | |||||||
Exercisable at December 31, 2013 | 7,246 | $ | 26.70 | 1.0 | $ | 0.6 | |||||||
The total intrinsic value of options exercised during the year ended December 31, 2013 , 2012, and 2011 was $3.8 million, $0.1 million, and $2.4 million respectively. The actual tax benefit realized for tax deductions from option exercises was approximately $1.5 million , $0.1 million, and $1.0 million in 2013 , 2012, and 2011, respectively.
The Company periodically issues new shares and also from time to time repurchases shares to satisfy share option exercises. During the year ended December 31, 2013 , 2012, and 2011 the Company received cash upon exercise of stock options totaling approximately $9.7 million , $0.3 million, and $12.3 million respectively. During these periods, the Company repurchased shares totaling approximately $12.3 million , $0.1 million, and $12.8 million respectively.
The fair value of option awards granted in prior years was estimated on the date of grant using a Black-Scholes option valuation model. Expected volatilities were based on historical volatility of the Company’s stock and other factors. The Company used historical data to estimate the expected term and forfeiture patterns of the options. The risk-free rate for periods within the contractual life of the option was based on the U.S. Treasury yield curve in effect at the time of grant.
Deferred Compensation Plans
The Company has nonqualified deferred compensation plans, which permit eligible executives and non-employee directors to defer portions of their compensation and vested share-based compensation. A record keeping account is established for each participant, and the participant chooses from a variety of measurement funds for the deemed investment of their accounts. The measurement funds are similar to the funds in the Company's defined contribution plan and include an investment in phantom stock units of the Company. The account balance fluctuates with the investment returns on those funds. At December 31, 2013 and 2012, the liability associated with these plans totaled $26.1 million and $22.9 million, respectively. Other than $1.6 million and $1.3 million which are classified in Accrued liabilities at December 31, 2013 and 2012, respectively, the liability is included in Deferred credits & other liabilities. The impact of these plans on Other operating expenses was expense of $4.0 million in 2013, $1.7 million in 2012 and $2.1 million in 2011. The amount recorded in earnings related to the investment activities in Vectren phantom stock associated with these plans during the years ended December 31, 2013, 2012, and 2011, was a cost of $2.6 million, $0.6 million and $1.7 million, respectively.
The Company has certain investments currently funded primarily through corporate-owned life insurance policies. These investments, which are consolidated, are available to pay deferred compensation benefits. These investments are also subject to the claims of the Company's creditors. The cash surrender value of these policies included in Other corporate & utility investments on the Consolidated Balance Sheets were $32.9 million and $29.1 million at December 31, 2013 and 2012, respectively. Earnings from those investments, which are recorded in Other-net, were earnings of $4.8 million in 2013, $1.8 million in 2012, and $0.1 million in 2011.
17. 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 $6.9 in 2014, $5.0 in 2015, $2.9 in 2016, $1.3 in 2017, $1.2 in 2018, and $5.0 thereafter. Total lease expense (in millions) was $9.9 in 2013, $8.5 in 2012, and $6.9 in 2011.
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The Company’s regulated utilities have both firm and non-firm commitments to purchase natural gas, electricity, and coal 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.
Corporate Guarantees
The Company issues parent level guarantees to certain vendors and customers of its wholly owned subsidiaries and unconsolidated affiliates. These guarantees do not represent incremental consolidated obligations; rather, they represent parental guarantees of subsidiary and unconsolidated affiliate obligations in order to allow those subsidiaries and affiliates the flexibility to conduct business without posting other forms of collateral. At December 31, 2013, parent level guarantees support a maximum of $25 million of ESG’s performance contracting commitments and warranty obligations and $45 million of other project guarantees. The broader scope of ESG’s performance contracting obligations, including those not guaranteed by the parent company, are described below. In addition, the parent company has approximately $25 million of other guarantees outstanding supporting other consolidated subsidiary operations, of which $19 million represent letters of credit supporting other nonutility operations. As disclosed in Note 7, a guarantee issued and outstanding to an unrelated party in connection with ProLiance's disposition of certain of the net assets of ProLiance Energy totaled $15.3 million at December 31, 2013. Although there can be no assurance that these guarantees will not be called upon, the Company believes that the likelihood the Company will be called upon to satisfy any obligations pursuant to these guarantees is remote.
Performance Guarantees & Product Warranties
In the normal course of business, wholly owned subsidiaries, including ESG, issue performance bonds or other forms of assurance that commit them to timely install infrastructure, operate facilities, pay vendors or subcontractors, and/or support warranty obligations. Based on a history of meeting performance obligations and installed products operating effectively, no significant liability or cost has been recognized for the periods presented.
Specific to ESG, in its role as a general contractor in the performance contracting industry, at December 31, 2013, there are 57 open surety bonds supporting future performance. The average face amount of these obligations is $4.4 million, and the largest obligation has a face amount of $57.3 million. The maximum exposure from these obligations is limited by the level of work already completed and guarantees issued to ESG by various subcontractors. At December 31, 2013, approximately 47 percent of work was completed on projects with open surety bonds. A significant portion of these open surety bonds will be released within one year. In instances where ESG operates facilities, project guarantees extend over a longer period. In addition to its performance obligations, ESG also warrants the functionality of certain installed infrastructure generally for one year and the associated energy savings over a specified number of years. The Company has no significant accruals for these warranty obligations as of December 31, 2013. In addition, ESG has an $8 million stand-alone letter of credit facility and as of December 31, 2013, $3.4 million was outstanding.
Legal & Regulatory 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.
18. Rate & Regulatory Matters
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement
Vectren monitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. Vectren'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.
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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 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. Of this total amount, $34.8 million relates to expenditures that potentially could be recoverable under the pending DRR discussed above. If this amount is found by the PUCO to not be recoverable through the DRR, the order granted deferral for future recovery through a House Bill 95 mechanism. 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
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$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.
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 April 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. A procedural schedule in this case has not been set as the Company has not yet filed testimony in support of its request. The company will file its case-in-chief testimony on March 14, 2014 and a hearing is scheduled for July 9, 2014.
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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.
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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.
19. 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
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 SO2 and NOx allowances, CSAPR reduced the ability of facilities to meet emission reduction targets through allowance trading. Like CAIR, CSAPR set individual state caps for SO2 and NOx emissions.
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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
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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 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
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
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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.
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, nonutility coal mining operations, 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 as 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
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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.
20. 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 | $ | 1,807.1 | $ | 1,895.2 | $ | 1,659.8 | $ | 1,873.3 | ||||||||
Short-term borrowings & notes payable | 68.6 | 68.6 | 278.8 | 278.8 | ||||||||||||
Cash & cash equivalents | 21.5 | 21.5 | 19.5 | 19.5 | ||||||||||||
For the balance sheets presented, the Company had no material assets or liabilities marked to fair value.
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings and cash & cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could produce different fair value estimates at the reporting date.
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Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.
Because of the nature of certain other investments and lack of a readily available market, it is not practical to estimate the fair value of these financial instruments at specific dates without considerable effort and cost. At December 31, 2013 and 2012, the fair value for these financial instruments was not estimated. The carrying value of these investments was approximately $10.4 million and $2.1 million at December 31, 2013 and 2012, respectively.
21. Segment Reporting
The Company segregates its operations into three groups: 1) Utility Group, 2) Nonutility Group, and 3) Corporate and Other.
The Utility Group is comprised of Vectren Utility Holdings, Inc.’s operations, which consist of the Company’s regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations 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 Utility Group is comprised of three operating segments: Gas Utility Services, Electric Utility Services, and Other operations.
The Nonutility Group is comprised of five operating segments: Infrastructure Services, Energy Services, Coal Mining, Energy Marketing,and Other Businesses. Results in the Energy Marketing segment include the results of the Company's investment in ProLiance through June 18, 2013 when it exited the natural gas marketing business (see Note 7 for more details of this transaction). The acquisition of Minnesota Limited was completed on March 31, 2011 (See Note 5) and is included in the Infrastructure Services operating segment. The sale of Vectren Source was completed on December 31, 2011 (See Note 6) and the results of Vectren Source's operations are included in the Energy Marketing operating segment in 2011.
Corporate and Other includes unallocated corporate expenses such as advertising and charitable contributions, among other activities, that benefit the Company’s other operating segments. Net income is the measure of profitability used by management for all operations. Information related to the Company’s business segments is summarized as follows:
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Year Ended December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
Revenues | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 1,429.6 | 1,333.6 | 1,457.0 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 783.5 | 663.6 | 421.3 | |||||||||
Energy Services | 91.3 | 117.7 | 161.8 | |||||||||
Coal Mining | 292.8 | 235.8 | 285.6 | |||||||||
Energy Marketing | — | — | 149.9 | |||||||||
Other Businesses | — | 0.5 | — | |||||||||
Total Nonutility Group | 1,167.6 | 1,017.6 | 1,018.6 | |||||||||
Eliminations, net of Corporate & Other Revenues | (106.0 | ) | (118.4 | ) | (150.4 | ) | ||||||
Consolidated Revenues | $ | 2,491.2 | $ | 2,232.8 | $ | 2,325.2 | ||||||
Profitability Measures - Net Income | ||||||||||||
Utility Group 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 Utility Group Net Income | 141.8 | 138.0 | 122.9 | |||||||||
Nonutility Group Net Income (Loss) | ||||||||||||
Infrastructure Services | 49.0 | 40.5 | 14.9 | |||||||||
Energy Services | 1.0 | 5.7 | 6.7 | |||||||||
Coal Mining | (16.0 | ) | (3.5 | ) | 16.6 | |||||||
Energy Marketing | (37.5 | ) | (17.6 | ) | (4.2 | ) | ||||||
Other Businesses | (1.0 | ) | (3.4 | ) | (10.2 | ) | ||||||
Total Nonutility Group Net Income | (4.5 | ) | 21.7 | 23.8 | ||||||||
Corporate & Other Net Loss | (0.7 | ) | (0.7 | ) | (5.1 | ) | ||||||
Consolidated Net Income | $ | 136.6 | $ | 159.0 | $ | 141.6 | ||||||
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Year Ended December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
Amounts Included in Profitability Measures | ||||||||||||
Depreciation & Amortization | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 196.4 | 190.0 | 192.3 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 28.8 | 20.7 | 14.9 | |||||||||
Energy Services | 1.7 | 1.9 | 1.5 | |||||||||
Coal Mining | 50.8 | 41.8 | 35.1 | |||||||||
Energy Marketing | — | — | 0.5 | |||||||||
Other Businesses | 0.1 | 0.2 | — | |||||||||
Total Nonutility Group | 81.4 | 64.6 | 52.0 | |||||||||
Consolidated Depreciation & Amortization | $ | 277.8 | $ | 254.6 | $ | 244.3 | ||||||
Interest Expense | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 65.0 | 71.5 | 80.3 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 10.1 | 7.5 | 7.4 | |||||||||
Energy Services | 0.6 | 0.4 | 0.6 | |||||||||
Coal Mining | 9.8 | 11.5 | 11.3 | |||||||||
Energy Marketing | 2.2 | 4.8 | 6.4 | |||||||||
Other Businesses | 0.5 | 0.7 | 1.3 | |||||||||
Total Nonutility Group | 23.2 | 24.9 | 27.0 | |||||||||
Corporate & Other | (0.3 | ) | (0.4 | ) | (0.8 | ) | ||||||
Consolidated Interest Expense | $ | 87.9 | $ | 96.0 | $ | 106.5 | ||||||
Income Taxes | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 85.3 | 85.3 | 82.9 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 34.3 | 29.6 | 10.7 | |||||||||
Energy Services | (11.9 | ) | (9.0 | ) | 1.1 | |||||||
Coal Mining | (14.6 | ) | (8.6 | ) | 3.9 | |||||||
Energy Marketing | (23.3 | ) | (11.7 | ) | (2.4 | ) | ||||||
Other Businesses | (1.6 | ) | (2.0 | ) | (7.0 | ) | ||||||
Total Nonutility Group | (17.1 | ) | (1.7 | ) | 6.3 | |||||||
Corporate & Other | (1.1 | ) | (1.1 | ) | (2.8 | ) | ||||||
Consolidated Income Taxes | $ | 67.1 | $ | 82.5 | $ | 86.4 | ||||||
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Year Ended December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
Capital Expenditures | ||||||||||||
Utility Group | ||||||||||||
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 | (15.2 | ) | (7.8 | ) | (0.1 | ) | ||||||
Total Utility Group | 261.1 | 246.0 | 233.4 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 79.2 | 53.7 | 22.8 | |||||||||
Energy Services | 6.9 | 2.3 | 9.7 | |||||||||
Coal Mining | 46.2 | 63.8 | 55.1 | |||||||||
Energy Marketing | — | — | 0.3 | |||||||||
Total Nonutility Group | 132.3 | 119.8 | 87.9 | |||||||||
Consolidated Capital Expenditures | $ | 393.4 | $ | 365.8 | $ | 321.3 | ||||||
At December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
Assets | ||||||||||||
Utility Group | ||||||||||||
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 Utility Group | 4,140.8 | 4,046.8 | 3,974.5 | |||||||||
Nonutility Group | ||||||||||||
Infrastructure Services | 465.8 | 420.0 | 295.0 | |||||||||
Energy Services | 63.0 | 69.7 | 81.2 | |||||||||
Coal Mining | 433.0 | 380.0 | 352.8 | |||||||||
Energy Marketing | 33.9 | 73.9 | 112.5 | |||||||||
Other Businesses, net of eliminations and reclassifications | 34.9 | 37.1 | 46.8 | |||||||||
Total Nonutility Group | 1,030.6 | 980.7 | 888.3 | |||||||||
Corporate & Other | 828.1 | 785.6 | 727.3 | |||||||||
Eliminations | (896.9 | ) | (724.0 | ) | (711.2 | ) | ||||||
Consolidated Assets | $ | 5,102.6 | $ | 5,089.1 | $ | 4,878.9 | ||||||
22. 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 | ||||
Coal & oil for electric generation - at average cost | 16.5 | 52.0 | ||||||
Materials & supplies | 57.3 | 57.6 | ||||||
Nonutility coal - at LIFO cost | 26.2 | 25.4 | ||||||
Other | 1.2 | 1.2 | ||||||
Total inventories | $ | 134.4 | $ | 158.6 | ||||
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Based on the average cost of gas purchased and coal produced during December, the cost of replacing inventories carried at LIFO cost exceeded that carrying value at December 31, 2013, and 2012, by approximately $8.5 million and $12.7 million, respectively.
Prepayments & other current assets consist of the following:
At December 31, | ||||||||
(In millions) | 2013 | 2012 | ||||||
Prepaid gas delivery service | $ | 32.9 | $ | 28.5 | ||||
Deferred income taxes | 13.9 | — | ||||||
Prepaid taxes | 11.2 | 26.4 | ||||||
Other prepayments & current assets | 17.6 | 18.4 | ||||||
Total prepayments & other current assets | $ | 75.6 | $ | 73.3 | ||||
Investments in unconsolidated affiliates consist of the following:
At December 31, | ||||||||
(In millions) | 2013 | 2012 | ||||||
ProLiance Holdings, LLC | $ | 20.8 | $ | 73.9 | ||||
Other nonutility partnerships & corporations | 3.0 | 4.0 | ||||||
Other utility investments | 0.2 | 0.2 | ||||||
Total investments in unconsolidated affiliates | $ | 24.0 | $ | 78.1 | ||||
Other utility & corporate investments consist of the following:
At December 31, | ||||||||
(In millions) | 2013 | 2012 | ||||||
Cash surrender value of life insurance policies | $ | 32.9 | $ | 29.1 | ||||
Municipal bond | 3.4 | 3.6 | ||||||
Restricted cash & other investments | 1.8 | 1.9 | ||||||
Other utility & corporate investments | $ | 38.1 | $ | 34.6 | ||||
Goodwill by operating segment follows:
At December 31, | ||||||||
(In millions) | 2013 | 2012 | ||||||
Utility Group | ||||||||
Gas Utility Services | $ | 205.0 | $ | 205.0 | ||||
Nonutility Group | ||||||||
Infrastructure Services | 55.2 | 55.2 | ||||||
Energy Services | 2.1 | 2.1 | ||||||
Consolidated goodwill | $ | 262.3 | $ | 262.3 | ||||
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Accrued liabilities consist of the following:
At December 31, | ||||||||
(In millions) | 2013 | 2012 | ||||||
Refunds to customers & customer deposits | $ | 50.2 | $ | 53.1 | ||||
Accrued taxes | 36.2 | 34.4 | ||||||
Accrued interest | 20.0 | 23.1 | ||||||
Deferred compensation & post-retirement benefits | 7.5 | 6.8 | ||||||
Deferred income taxes | — | 14.9 | ||||||
Accrued salaries & other | 68.2 | 66.5 | ||||||
Total accrued liabilities | $ | 182.1 | $ | 198.8 | ||||
Asset retirement obligations roll forward as follows:
(In millions) | 2013 | 2012 | ||||||
Asset retirement obligation, January 1 | $ | 37.7 | $ | 43.7 | ||||
Accretion | 2.2 | 2.7 | ||||||
Changes in estimates, net of cash payments | 1.4 | (8.7 | ) | |||||
Asset retirement obligation, December 31 | 41.3 | 37.7 | ||||||
Equity in (losses) of unconsolidated affiliates consists of the following:
Year Ended December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
ProLiance Holdings, LLC | $ | (57.7 | ) | $ | (22.7 | ) | $ | (28.6 | ) | |||
Other | (2.0 | ) | (0.6 | ) | (3.4 | ) | ||||||
Total equity in (losses) of unconsolidated affiliates | $ | (59.7 | ) | $ | (23.3 | ) | $ | (32.0 | ) | |||
Other income (expense) – net 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 | 0.5 | 1.8 | 2.1 | |||||||||
Interest income, net | 1.1 | 1.1 | 1.4 | |||||||||
Other nonutility investment impairment charges | — | (2.7 | ) | (9.9 | ) | |||||||
Cash surrender value of life insurance policies | 4.8 | 1.8 | 0.1 | |||||||||
All other income | 4.6 | 1.3 | 0.1 | |||||||||
Total other income (expense) – net | $ | 17.7 | $ | 8.3 | $ | (3.5 | ) | |||||
Supplemental Cash Flow Information:
Year Ended December 31, | ||||||||||||
(In millions) | 2013 | 2012 | 2011 | |||||||||
Cash paid (received) for: | ||||||||||||
Interest | $ | 91.0 | $ | 94.6 | $ | 108.6 | ||||||
Income taxes | 6.8 | 21.8 | (9.0 | ) | ||||||||
As of December 31, 2013 and 2012, the Company has accruals related to utility and nonutility plant purchases totaling approximately $19.4 million and $11.1 million, respectively.
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23. 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)
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
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.
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24. 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, except per share amounts) | Q1 | Q2 | Q3 | Q4 | ||||||||||||||
2013 | ||||||||||||||||||
Operating revenues | $ | 700.6 | $ | 531.0 | $ | 579.6 | $ | 680.0 | ||||||||||
Operating income | 106.8 | 57.9 | 83.3 | 85.6 | ||||||||||||||
Net income (loss) | 49.8 | (5.8 | ) | 42.8 | 49.8 | |||||||||||||
Earnings (loss) per share: | ||||||||||||||||||
Basic | $ | 0.61 | $ | (0.07 | ) | $ | 0.52 | $ | 0.60 | |||||||||
Diluted | 0.61 | (0.07 | ) | 0.52 | 0.60 | |||||||||||||
2012 | ||||||||||||||||||
Operating revenues | $ | 604.6 | $ | 470.6 | $ | 513.5 | $ | 644.1 | ||||||||||
Operating income | 109.9 | 70.2 | 81.6 | 90.8 | ||||||||||||||
Net income | 51.3 | 25.6 | 39.3 | 42.8 | ||||||||||||||
Earnings per share: | ||||||||||||||||||
Basic | $ | 0.63 | $ | 0.31 | $ | 0.48 | $ | 0.52 | ||||||||||
Diluted | 0.62 | 0.31 | 0.48 | 0.52 | ||||||||||||||
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Changes in Internal Controls over Financial Reporting
During the quarter ended December 31, 2013, there have been no changes to the Company’s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 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 Corporation’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework (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.
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The effectiveness of internal control over financial reporting as of December 31, 2013, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included in Item 8 of this annual report.
ITEM 9B. OTHER INFORMATION
None.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by Part III, Item 10 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2014 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year. The Company’s executive officers are the same as those named executive officers detailed in the Proxy Statement.
Corporate Code of Conduct
The Company’s Corporate Governance Guidelines; the charters for each committee of the Board of Directors; its Corporate Code of Conduct that covers the Company’s officers and employees; and its Board Code of Ethics and Code of Conduct that covers the Company’s directors are available in the Corporate Governance section of the Company’s website, www.vectren.com. The Corporate Code of Conduct (titled “Corp Code of Conduct”) contains specific 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 Investor Relations, One Vectren Square, Evansville, Indiana 47708. The Company 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 the Company’s directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions on the Company’s website at the Internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to the address listed above.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Part III, Item 11 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2014 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Except with respect to equity compensation plan information of the Registrant, which is included herein, the information required by Part III, Item 12 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2014 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
Shares Issuable under Share-Based Compensation Plans
As of December 31, 2013, the following shares were authorized to be issued under share-based compensation plans:
A | B | C | ||||||||||||||||||
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||||||||||||
Equity compensation plans approved by | ||||||||||||||||||||
security holders | 7,246 | (1) | $ | 26.70 | (1) | 3,509,100 | (2) | |||||||||||||
Equity compensation plans not approved | ||||||||||||||||||||
by security holders | — | — | — | |||||||||||||||||
Total | 7,246 | $ | 26.70 | 3,509,100 | ||||||||||||||||
(1) | Under the Vectren At-Risk Compensation Plan, the Company may buy shares on the open market during periods when there are no restrictions on insider transactions to fulfill these obligations. |
(2) | Effective January 17, 2014, 212,570 performance-based units were issued to management by the Compensation and Benefits Committee of the Board of Directors. In addition, participants were granted an additional 41,330 performance awards measured during the three year performance period ending December 31, 2013 which do not vest, with limited exceptions, until December 31, 2014. These issuances are not included in the above table. |
The At-Risk Compensation plan was approved by Vectren Corporation common shareholders after the merger forming Vectren and was most recently amended and reapproved at the 2011 annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required by Part III, Item 13 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2014 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by Part III, Item 14 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's Proxy Statement for its 2014 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, within 120 days after the end of the fiscal year.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
List of Documents Filed as Part of This Report
Consolidated Financial Statements
The consolidated financial statements and related notes, together with the reports 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 Corporation and Subsidiaries
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions | ||||||||||||||||||||
Balance at | Charged | Charged | Deductions | Balance at | ||||||||||||||||
Beginning | to | to Other | from | End of | ||||||||||||||||
Description | of Year | Expenses | Accounts | Reserves, Net | Year | |||||||||||||||
(In millions) | ||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS: | ||||||||||||||||||||
Year 2013 – Accumulated provision for | ||||||||||||||||||||
uncollectible accounts | $ | 6.8 | $ | 6.8 | $ | — | $ | 6.8 | $ | 6.8 | ||||||||||
Year 2012 – Accumulated provision for | ||||||||||||||||||||
uncollectible accounts | $ | 6.7 | $ | 8.2 | $ | — | $ | 8.1 | $ | 6.8 | ||||||||||
Year 2011 – Accumulated provision for | ||||||||||||||||||||
uncollectible accounts | $ | 5.3 | $ | 11.8 | $ | — | $ | 10.4 | $ | 6.7 | ||||||||||
Year 2013 – Reserve for impaired | ||||||||||||||||||||
notes receivable | $ | 0.6 | $ | — | $ | — | $ | — | $ | 0.6 | ||||||||||
Year 2012 – Reserve for impaired | ||||||||||||||||||||
notes receivable | $ | 15.7 | $ | 0.5 | $ | — | $ | 15.6 | $ | 0.6 | ||||||||||
Year 2011 – Reserve for impaired | ||||||||||||||||||||
notes receivable | $ | 6.1 | $ | 9.6 | $ | — | $ | — | $ | 15.7 | ||||||||||
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 | ||||||||||
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List of Exhibits
The Company has incorporated by reference herein certain exhibits as specified below pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company attached to this filing filed electronically with the SEC are listed below. Exhibits for the Company are listed in the Index to Exhibits.
Vectren Corporation
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 |
10.14 | Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 17, 2014 |
21.1 | List of Company’s Significant Subsidiaries |
23.1 | Consent of Independent Registered Public Accounting Firm |
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 | 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.) |
3.2 | Code of By-Laws of Vectren Corporation as Most Recently Amended and Restated 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.) |
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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 known as First Trust National Association, which was formerly known as Bank of America Illinois, which was formerly known 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.) |
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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 October 11, 2005, between Vectren Capital Corp. and each of the purchasers named therein. (Filed designated in Form 10-K for the year ended December 31, 2005, File No. 1-15467, as Exhibit 4.4.) First Amendment, dated March 11, 2009, to Note Purchase Agreement dated October 11, 2005, among Vectren Corporation, Vectren Capital, Corp. and each of the holders named herein. (Filed and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit 4.6) |
4.5 | Note Purchase Agreement, dated March 11, 2009, among Vectren Corporation, Vectren Capital, Corp. and each of the purchasers named therein. (Filed and designated in Form 8-K dated March 16, 2009 File No. 1-15467, as Exhibit 4.5) |
4.6 | 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) |
4.7 | Note Purchase Agreement, dated September 9, 2010, among Vectren Capital, Corp. and the purchasers named therein. (Filed and designated in Form 8-K dated September 10, 2010 File No. 1-15467, as Exhibit 4.1) |
4.8 | 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) |
4.9 | 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) |
4.10 | 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) |
4.11 | 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.) |
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10.2 | Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.) |
10.3 | 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 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.) |
10.8 | 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.) |
10.9 | 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.) |
10.10 | Vectren Corporation At Risk Compensation Plan specimen performance award unit 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.) |
10.11 | 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.) |
10.12 | 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) |
10.13 | 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) |
10.14 | Vectren Corporation At Risk Compensation Plan specimen unit award agreement for officers, effective January 17, 2014. (Filed in Form 10-K herewith as Exhibit 10.14) |
10.15 | 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. |
10.16 | 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) |
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10.17 | 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. |
10.18 | 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.) |
10.19 | 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.) |
10.20 | 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.) |
10.21 | 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.) |
10.22 | 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) |
10.23 | 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. |
10.24 | 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. |
10.25 | 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. |
10.26 | 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 in Form 10-K for the year ended December 31, 2012, File No. 1-15467, as Exhibit 10.3) |
10.27 | 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 in Form 10-K for the year ended December 31, 2012, File No. 1-15467, as Exhibit 10.4) |
10.28 | 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.) |
10.29 | 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) |
10.30 | Credit Agreement, dated September 30, 2010, among Vectren Capital Corp., 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 10.2) |
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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) |
10.32 | First Amendment to Credit Agreement, dated September 30, 2010, among Vectren Capital Corp., and each of the financial institutions named therein. (Filed and designated in Form 10-K, for the year ended December 31, 2011, File No. 1-15467, as Exhibit 10.1) |
10.33 | Second Amendment to Credit Agreement, dated November 10, 2011, among Vectren Capital Corp., 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 10.2) |
10.34 | Vectren Capital Three Year Term Loan Agreement, dated November 1, 2012. (Filed and designated in Form 10-Q, for the period ended September 30, 2012, File No. 1-15467, as Exhibit 10.1) |
10.35 | Severance Agreement dated July 15, 2013 by and between Vectren Corporation and John Bohls. (Filed and designated in Form 8-K, dated July 18, 2013, File No. 1-15467, as Exhibit 10.1) |
10.36 | Consulting Agreement dated July 17, 2013 by and between Vectren Corporation and John M. Bohls. (Filed and designated in Form 8-K, dated July 18, 2013, File No. 1-5467, as Exhibit 10.2) |
10.37 | Term Loan Credit Agreement dated August 6, 2013 among Vectren Capital, Corp., as the Borrower, Vectren Corporation, as the Guarantor, Bank of America, N.A., as Agent, and the other lenders party thereto. (Filed and designated in Form 8-K, dated August 8, 2013, File No. 1-15467, as Exhibit 4.1) |
21. Subsidiaries of the Company
The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1. (Filed herewith.)
23. Consents of Experts and Counsel
The consents of Deloitte & Touche LLP are attached hereto as Exhibit 23.1. (Filed herewith.)
31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002
Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.1 (Filed herewith.)
Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 31.2 (Filed herewith.)
32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32 (Filed herewith.)
101 Interactive Data File
101.INS XBRL Instance Document (Filed herewith.)
101.SCH XBRL Taxonomy Extension Schema (Filed herewith.)
101.CAL XBRL Taxonomy Extension Calculation Linkbase (Filed herewith.)
101.DEF XBRL Taxonomy Extension Definition Linkbase (Filed herewith.)
101.LAB XBRL Taxonomy Extension Labels Linkbase (Filed herewith.)
101.PRE XBRL Taxonomy Extension Presentation Linkbase (Filed herewith.)
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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 CORPORATION
Dated February 20, 2014 /s/ Carl L. Chapman
Carl L. Chapman,
Chairman, President, and Chief Executive Officer
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 | Chairman, President, and Chief Executive Officer | February 20, 2014 | ||
Carl L. Chapman | (Principal Executive Officer) | |||
/s/ Jerome A. Benkert, Jr. | Executive Vice President and Chief Financial Officer | February 20, 2014 | ||
Jerome A. Benkert, Jr. | (Principal Financial Officer) | |||
/s/ M. Susan Hardwick | Senior Vice President, Finance & Assistant Treasurer | February 20, 2014 | ||
M. Susan Hardwick | (Principal Accounting Officer) | |||
/s/ James H. DeGraffenreidt | Director | February 20, 2014 | ||
James H. DeGraffenreidt | ||||
/s/ Niel C. Ellerbrook | Director | February 20, 2014 | ||
Niel C. Ellerbrook | ||||
/s/ John D. Engelbrecht | Director | February 20, 2014 | ||
John D. Engelbrecht | ||||
/s/ Anton H. George | Director | February 20, 2014 | ||
Anton H. George | ||||
/s/ Martin C. Jischke | Director | February 20, 2014 | ||
Martin C. Jischke | ||||
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/s/ Robert G. Jones | Director | February 20, 2014 | ||
Robert G. Jones | ||||
/s/ J. Timothy McGinley | Director | February 20, 2014 | ||
J. Timothy McGinley | ||||
/s/ R. Daniel Sadlier | Director | February 20, 2014 | ||
R. Daniel Sadlier | ||||
/s/ Michael L. Smith | Director | February 20, 2014 | ||
Michael L. Smith | ||||
/s/ Jean L. Wojtowicz | Director | February 20, 2014 | ||
Jean L. Wojtowicz | ||||
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