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 Groupand Nonutility Groupseparately 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 Groupgenerates revenue primarily from the delivery of natural gas and electric service to its customers. The primary source of cash flow for the Utility Groupresults 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 Groupare 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
Results for the year ended
December 31, 2013were earnings of $136.6 million, or $1.66per share, compared to earnings of $159.0 million, or $1.94per share for the year ended December 31, 2012and $141.6 million, or $1.73per share for the year ended December 31, 2011. In June 2013, ProLiance Holdings, LLCexited 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 $0.46per share, consolidated net income for the year ended December 31, 2013was $174.1 million, or $2.12per share. In 2012, excluding ProLiance results, totaling $17.6 million, or $0.21per share, consolidated net income for the year ended December 31, 2012was $176.6 million, or $2.15per share. In 2011, excluding the results of ProLiance and Source, including the gain on disposition of Source, totaling $4.2 million, or $.05per share, consolidated net income for the year ended December 31, 2011was $145.8 million, or $1.78per share.
Losses Related to the Exit of the Gas Marketing Business by ProLiance
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 millionimpact to Equity in losses of unconsolidated affiliates, a $1.7 millioncharge to Operating expense, and an income tax benefit reflected in Income taxes of $16.8 million. More detailed information about ProLiance Energy'ssale 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, 2013totaling $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, 2013through June 18, 2013. Operating losses for ProLiance totaled $17.6 million, net of tax, for the year ended December 31, 2012and $22.9 millionfor 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. 25 --------------------------------------------------------------------------------
Consolidated Results Excluding the Results From Energy Marketing (
Net income and earnings per share, excluding results from Energy Marketing, in total and by group, for the years ended
Year Ended December 31, (In millions, except per share data) 2013 2012
Net income, excluding Energy Marketing results
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
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 Groupearnings were $141.8 million, compared to $138.0 millionin 2012 and $122.9 millionin 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 millionduring the year ended December 31, 2013, compared to $60.0 millionin 2012 and $52.5 millionin 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 Groupoperating costs are being managed to be generally flat to the original 2012 targeted level of approximately $280 millionon 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 millionduring 2013, compared to $68.0 millionin 2012 and $65.0 millionin 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 millionin 2012 and $5.4 millionin 2011. Differences in the Utility Group'seffective 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 Groupdeferred income taxes related to the fourth quarter 2011 sale of Vectren Source, a nonutility retail gas marketer, which resulted in a charge to Utility Groupincome taxes of approximately $2.8 million. Earnings from 2011 also includes a $1.4 millionunfavorable tax adjustment. Nonutility GroupExcluding results for Energy Marketing, the Nonutility Groupearned $33.0 millionin 2013, compared to earnings of $39.3 millionin 2012 and $28.0 millionin 2011. Results over the periods presented were favorably impacted by the March 31, 201126 -------------------------------------------------------------------------------- acquisition of Minnesota Limitedand significantly higher demand for pipeline construction and repair. Results also reflect losses at Coal Mining of $16.0 millionin 2013 and $3.5 millionin 2012, compared to earnings of $16.6 millionin 2011. Finally, results were impacted by charges related to legacy investments totaling $1.2 million, $2.2 millionand $9.2 millionin 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 millionafter tax. The contribution is reflected in Other operating expenses in the consolidated financial statements.
Dividends declared for the year ended
December 31, 2013were $1.425per share, compared to $1.405per share in 2012 and $1.385per share in 2011. In November 2013, the Company's board of directors increased its quarterly dividend to $0.360per share from $0.355per share. The increase marks the 54th consecutive year Vectrenand 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 Groupnet 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 Energyassets 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'sbasic EPS Per share earnings contributions of the Utility Group, Nonutility Groupexcluding 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'sconsolidated results divided by Vectren'sbasic 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'sassets 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'sbasic 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. 27 -------------------------------------------------------------------------------- The following table reconciles consolidated net income, consolidated basic EPS, and Nonutility Groupnet income to those results excluding Energy Marketing results. Twelve Months Ended December 31, 2013 GAAP Add back Energy Marketing Non-GAAP (In millions, except EPS) Measure Losses 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 GAAP Add back Energy Marketing Non-GAAP (In millions, except EPS) Measure Losses 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 GAAP Add back Energy Marketing Non-GAAP (In millions, except EPS) Measure Losses 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. 28 -------------------------------------------------------------------------------- Results of Operations of the Utility Group
The Utility Groupis 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 Indianaand to west central Ohioand 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 Groupoperating 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 $ 819.1Electric 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
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
Indianacustomers (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 Gasreceived its most recent base rate order in February 2008and VEDO in January 2009with 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 Indiananatural 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 Ohionatural 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 Ohioservice 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 Indianacustomers are two of the Company's most significant operating expenses. Rates charged to natural gas customers in Indianacontain 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 Ohioterritory. 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 Indianaand Ohiowere passed that expand the ability of utilities to recover certain costs of federally mandated projects, and in Ohioother 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. 30 --------------------------------------------------------------------------------
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 $ 819.1Cost 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
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 millionfor the year ended December 31, 2013, and compared to 2012, increased $15.1 million. Customer margin increased approximately $8.7 millionin 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 Ohioand 102 percent of normal in Indianaduring 2013, compared to 88 percent of normal in Ohioand 79 percent of normal in Indianain 2012, had an approximate $0.8 millionfavorable impact on small customer margin. For the year ended December 31, 2012, gas utility margins decreased $6.9 millioncompared to 2011. Gas utility margin decreased $10.9 milliondue 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 Ohioincreased margins $2.9 millionin 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 millionon 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. 31 -------------------------------------------------------------------------------- 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 $ 635.9Cost of fuel & purchased power 202.9 192.0
Total electric utility margin
$ 416.4 $ 402.9 $ 395.5Margin attributed to: Residential & commercial customers $ 255.8 $ 255.8 $ 251.2Industrial customers 108.7 108.5 105.3 Other 4.8 1.6 4.3 Regulatory expense recovery mechanisms 10.5 4.9
$ 379.8 $ 370.8
Wholesale power & transmission system margin 36.6 32.1
Total electric utility margin
$ 416.4 $ 402.9 $ 395.5Electric 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 millionfor the year ended December 31, 2013and, 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 millionin refunds to customers during 2012 resulting from statutory net operating income limits. Margin from regulatory expense recovery mechanisms increased $5.6 millionin 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 millionfor 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, 2011was 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 millionin 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 millionand $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 millionpursuant to the statutory net operating income limits. Indianaregulation 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 32 -------------------------------------------------------------------------------- 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 $ 23.5MISO Off-system margin 7.2 5.7 6.1 Total wholesale margin $ 36.6 $ 32.1 $ 29.6Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms, and other transmission system operations, totaled $29.4 millionduring 2013, compared to $26.4 millionin 2012 and $23.5 millionin 2011. Increases are primarily due to increased investment in qualifying projects. To date, the Company has invested $157.5 millionin qualifying projects. The net plant balance for these projects totaled $146.8 millionat December 31, 2013. These projects include an interstate 345 Kv transmission line that connects Vectren's A.B. Brown Generating Stationto a generating station in Indianaowned by Duke Energy to the north and to a generating station in Kentuckyowned by Big Rivers Electric Corporationto 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 millionthat 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 millionin 2012 and $6.1 millionin 2011. The base rate changes implemented in May 2011require that wholesale margin from off-system sales earned above or below $7.5 millionper 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 millionon an annual basis, over time. For the year ended December 31, 2012, Other operating expenses decreased $3.0 millioncompared 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 millionin 2012 and $192.3 millionin 2011. The periods presented reflect increased utility plant investments placed into service. 33 -------------------------------------------------------------------------------- However, in 2012 regulatory orders in Ohioallowing 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 millionin 2013 compared to 2012 and decreased $0.6 millionin 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 millionin 2013, compared to $8.0 millionin 2012 and $4.3 millionin 2011. Results include increased AFUDC of approximately $1.9 millionin 2013 and $2.2 millionin 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 millionin 2012 and $80.3 millionin 2011. The decreases are due to refinancing activity, yielding favorable interest rates. During 2013, the Company issued $385.9 millionin utility related long-term debt with a weighted average interest rate of 3.59 percent and retired $337.9 millionof 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 millionand $150.0 millionin 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 millionand $250.0 millionof 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 Groupfederal and state income taxes were $85.3 millionin both 2013 and 2012, and $82.9 millionin 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 Groupdeferred income taxes from the fourth quarter sale of Vectren Source which resulted in a $2.8 millioncharge, and a $1.4 millionunfavorable tax adjustment recognized earlier in 2011. Rate & Regulatory Matters
Regulatory Treatment of Investments in Natural Gas Infrastructure Replacement
Vectrenmonitors and maintains its natural gas distribution system to ensure that natural gas is delivered in a safe and efficient manner. Vectren'snatural gas utilities are currently engaged in replacement programs in both Indianaand Ohio, the primary purpose of which is preventive maintenance and continual renewal and operational improvement. Laws in both Indianaand Ohiowere 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 Ohioservice 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 $1.00per 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 34 -------------------------------------------------------------------------------- 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 millionfor 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 millionat 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 2013to 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 millionrelated 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 millioncapital 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 $1.50per 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 millionrelates 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 millionand $0.9 million, respectively. Deferral of depreciation and property tax expenses related to these programs in 2013 and 2012 totaled $1.7 millionand $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 Ohioinfrastructure programs increased $6.7 millionin 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 Indiananatural 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 millionannually at Vectren North and $3 millionannually 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, 2013and 2012, the Company has regulatory assets totaling $12.1 millionand $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 Indianalaw. 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 35 -------------------------------------------------------------------------------- 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 Companyfiled in November 2013for 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 millioncombined over the seven year period beginning in 2014, along with approximately $13 millioncombined 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 millionand $90 millionon its coal-fired generation units to comply with new EPAmandates 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 EPAconcerns 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, 2014and 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 millionin system upgrades that were completed in the three years leading up to the December 2009filing 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 millionwas 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. 36 -------------------------------------------------------------------------------- Coal Procurement Procedures Vectren South submitted a request for proposal (RFP) in April 2011regarding 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'spower plants of lower priced contract coal from the April 2011RFP process began during 2012. On December 5, 2011within 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, 2013was $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, 2009order issued by the IURC, which, among other actions, defined long-term conservation objectives and goals of DSM programs for all Indianaelectric 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 Indianaelectric 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, 2011the 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 millionin 2012 and $1 millionin 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 millionassociated 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 37 --------------------------------------------------------------------------------
and employees to perform inspections. On
Vectren North & Vectren South Gas Decoupling Extension Filing On
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 millionof net income on an annual basis.
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,
IndianaSenate 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 EPAis 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 EPAfinalized the Cross-State Air Pollution Rule (CSAPR). CSAPR was the EPA'sresponse 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, 2009and 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 38 -------------------------------------------------------------------------------- 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 EPAto continue to administer CAIR. In October 2012, the EPAfiled its request for a hearing before the full federal appeals court that struck down the CSAPR. EPA'srequest for rehearing was denied by the Court on January 24, 2013. In March 2013, the EPAfiled a petition for review with the US Supreme Court, and in June 2013the Supreme Courtagreed to review the lower court decision. A decision by the Supreme Courtis 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 EPAfinalized 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 EPAdid 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 Congressalso apply to the implementation of the MATS rule. Multiple judicial challenges were filed and briefing is proceeding. The EPAagreed 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 EPAissued its revised emission limits for new construction in March 2013. Notice of Violation for A.B. Brown Power Plant The Companyreceived a notice of violation (NOV) from the EPAin November 2011pertaining to its A.B. Brownpower 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 EPAto 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 EPAunder 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.
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 Courtaffirmed that the EPAcould, 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 EPAfor further consideration. In March 2011, the EPAreleased its proposed Section 316(b) regulations. The EPAdid 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 millionif 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 IndianaSenate Bill 251 referenced above. Under the Clean Water Act, EPAsets technology-based guidelines for water discharges from new and existing facilities. EPAis currently in the process of revising the existing steam electric effluent limitation guidelines that set the technology-based water 39 -------------------------------------------------------------------------------- discharge limits for the electric power industry. EPAis focusing its rulemaking on wastewater generated primarily by pollution control equipment necessitated by the comprehensive air regulations. The EPAreleased proposed rules on April 19, 2013and 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'simplementation 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 millionstarting 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 millionclean 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 millionand $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'sallegations 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 EPAissued 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 EPAdid 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 EPAentered into a consent decree in which it agreed to finalize by December 2014its 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 millionif 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. 40 -------------------------------------------------------------------------------- Climate Change Legislative Actions & Other Climate Change Initiatives In April 2007, the US Supreme Courtdetermined that greenhouse gases (GHG's) meet the definition of "air pollutant" under the Clean Air Act and ordered the EPAto 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 EPApublished 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 EPAregulating carbon emissions through the existing Clean Air Act in the absence of specific carbon legislation from Congress. The EPAhas promulgated two GHG regulations that apply to the Company's generating facilities. In 2009, the EPAfinalized a mandatory GHG emissions registry which requires the reporting of emissions. The EPAhas 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'sPSD and Title V permitting rules for GHG's were upheld by the US Court of Appeals for the District of Columbia. In 2012, the EPAproposed New Source Performance Standards (NSPS) for GHG's for new electric generating facilities under the Clean Air Act Section111(b). On October 15, 2013, the US Supreme Courtagreed 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'spower plants. A decision is expected in 2014. In July 2013, the President announced a Climate Action Plan, which calls on the EPAto re-propose and finalize the new source rule expeditiously, and by June 2014propose, and by June 2015finalize, NSPS standards for GHG's for existing electric generating units which would apply to Vectren'spower plants. States must have their implementation plans to the EPAno 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 IndianaSenate 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 Stateshas also slowed.
• 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 Statesfrom 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'se-GRRT. 41 --------------------------------------------------------------------------------
Current Initiatives to Increase Conservation & Reduce Emissions
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
• Implementing conservation initiatives in the Company's
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,
Impact of Legislative Actions & Other Initiatives is Unknown If regulations are enacted by the
EPAor 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 Indianaelectricity 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 Indianaretail 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 Gasservice 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 Gasand 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. 42 -------------------------------------------------------------------------------- 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 millionat Indiana Gasand $20.2 millionat 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 Gashas received approximately $20.8 millionfrom 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 millionof the expected $15.8 millionin 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, 2013and 2012, approximately $5.7 millionand $4.6 million, respectively, of accrued, but not yet spent, costs are included in Other Liabilities related to the Indiana Gasand SIGECO sites. 43
-------------------------------------------------------------------------------- Results of Operations of the
Nonutility Group The Nonutility Groupoperates 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 Groupsupports 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 VectrenSource. Pursuant to service contracts, Energy Marketing provided the Company's Indianaregulated utilities natural gas supply services. The Nonutility Groupresults were losses of $4.5 millionfor the year ended December 31, 2013, and earnings of $21.7 millionand $23.8 millionfor the years ended December 31, 2012and 2011, respectively. Nonutility Groupearnings, 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
CONTRIBUTION TO VECTREN BASIC EPS, EXCLUDING ENERGY MARKETING RESULTS
$ 0.41 $ 0.47 $ 0.34NET INCOME (LOSS) ATTRIBUTED TO: Infrastructure Services $ 49.0 $ 40.5 $ 14.9Energy 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, 2013were $49.0 million, compared to $40.5 millionin 2012 and $14.9 millionin 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 millionin 2012 and $421 millionin 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 millionand a backlog of fixed price contracts of $77 million, for a total backlog of $535 million. The estimated backlog at December 31, 2012was $278 millionfor blanket contracts and $101 millionfor 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. 44 -------------------------------------------------------------------------------- Acquisition of Minnesota LimitedOn March 31, 2011, the Company purchased Minnesota Limited, excluding certain assets. Minnesota Limitedis 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 Limitedis headquartered in Big Lake, Minnesotaand the majority of its customers are generally located in the northern Midwest region. The purchase price was approximately $83.4 millionand included $14.8 millionof net working capital, $34.4 millionof property plant and equipment and $39.4 millionof intangible assets, including goodwill.
Energy Services provides energy performance contracting and sustainable infrastructure projects through its wholly owned subsidiary,
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 millioncompared to $17.8 millionin 2012 and $6.2 millionin 2011. The impact of these tax deductions on earnings in 2013 was $7.8 million, compared to $7.2 millionin 2012, and $2.5 millionin 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 millionat December 31, 2012and $82 millionat 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 owns mines that produce and sell coal to the Company's utility operations and to third parties through its wholly owned subsidiary
Coal Mining revenues were
$293 millionin 2013 compared to $236 millionin 2012, and $286 millionin 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 Oaktownmining 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 Basincoal. Changes in market conditions or other circumstances could cause actual results to be materially different from these expectations. 45 -------------------------------------------------------------------------------- Coal Reserves As of December 31, 2013, management estimates the Company's total Illinois Basincoal 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 Oaktownunderground 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 MSHAare 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 millionrelated to assessments issued to the mine operators. More detailed information about the Company's mines, including safety-related data, can be found at MSHA'swebsite, www.MSHA.gov. Prosperity operates under the MSHAidentification number 1202249; Oaktown1 operates under the identification number 1202394; and Oaktown2 operates under the identification number 1202418. Mine safety-related data included on the MSHAwebsite 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 MSHAinspections continues generally. Over the twelve month period ended December 31, 2013and as a direct result of continued focus on safe work practices, citations issued by MSHAhave 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 23and 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, MSHAno 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 MSHArequirements, Prosperity is in the process of finalizing a Corrective Action Program (CAP) to be submitted to MSHAwhich 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 Vectrenand 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 Energyprovided services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance Energy'scustomers included, among others, Vectren's Indianautilities as well as Citizens' utilities. Consistent with its ownership percentage, Vectrenis 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. 46 -------------------------------------------------------------------------------- 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 $17.6and $22.9 millionin 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 Energyto 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 millionpre-tax, or $26.8 millionnet of tax, during the second quarter of 2013. ProLiance funded an estimated equity shortfall at ProLiance Energyof $16.6 millionat 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 millionshortfall, 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 AdministrationAgreements (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, 2013and 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 millionrespectively. At December 31, 2013, ProLiance had approximately $50.7 millionof capitalization remaining on its balance sheet, comprised of $34.1 millionin member's equity and $16.6 millionin 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 millionin cash, and a small amount of other working capital. The Company's remaining investment in ProLiance at December 31, 2013totals $30.9 millionand is comprised of $20.8 millionof equity and a $10.1 millionnote 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 millionimpairment 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, 2013is approximately $35.4 million. The joint venture received a demand for Arbitration from Williams Midstream Natural Gas Liquids, Inc.("Williams") on February 8, 2011related 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 47 -------------------------------------------------------------------------------- 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 millionafter 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 millionin 2011.
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 millionare included in Other nonutility investments and $2.8 millionare 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 millionnet 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, 2013was $16.1 million. Other Businesses results were a loss of $1.0 millionin 2013, compared to a loss of $3.4 millionin 2012 and a loss of $10.2 millionin 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 millionrelated to the carrying value of an energy-related investment originally made in 1999. Results in 2011 include charges totaling $9.2 millionafter tax associated with legacy real estate holdings. Impact of Recently Issued Accounting Guidance
Offsetting Assets and Liabilities
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, 2013and 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)
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. 48 --------------------------------------------------------------------------------
Unrecognized Tax Benefit Presentation
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 Basincoal, 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. 49
-------------------------------------------------------------------------------- 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 Groupimpairment 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 Groupis 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 millionin 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
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. 50 -------------------------------------------------------------------------------- Financial Condition Within
Vectren'sconsolidated group, Utility Holdingsprimarily funds the short-term and long-term financing needs of the Utility Groupoperations, and Vectren Capital Corp( Vectren Capital) funds short-term and long-term financing needs of the Nonutility Groupand corporate operations. Vectren Corporationguarantees Vectren Capital'sdebt, but does not guarantee Utility Holdings'debt. Vectren Capital'slong-term debt, including current maturities, and short-term obligations outstanding at December 31, 2013approximated $550 millionand $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, 2013approximated $875 millionand $29 million, respectively. Additionally, prior to Utility Holdings'formation, Indiana Gasand 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 Gasand 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'scorporate 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 Holdingsand 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 Holdingsand Indiana Gasfrom 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, 2013and 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
EPAregulations 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, 51 -------------------------------------------------------------------------------- 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 Capitaltotaling $200 million, issuances by Vectren Utility Holdingstotaling $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
December 31, 2013, the Company has $600 millionof short-term borrowing capacity, including $350 millionfor the Utility Groupand $250 millionfor the wholly owned Nonutility Groupand corporate operations. As reduced by borrowings currently outstanding, approximately $321 millionwas available for the Utility Groupoperations and approximately $210 millionwas available for the wholly owned Nonutility Groupand corporate operations. Both Vectren Capital's and Utility Holdings'short-term credit facilities were renewed in November 2011and 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 Holdingsshort-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 $ 84.3Weighted 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 $ 124.9Weighted 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,
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 millionin 2013, $7.2 millionin 2012, and $7.9 millionin 2011.
Potential Uses of Liquidity
Pension & Postretirement Funding Obligations
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. 52 --------------------------------------------------------------------------------
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 millionof ESG's performance contracting commitments and warranty obligations and $45 millionof 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 millionof other guarantees outstanding supporting other consolidated subsidiary operations, of which $19 millionrepresent 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 Energytotaled $15.3 millionat 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 millionstand-alone letter of credit facility and as of December 31, 2013, $3.4 millionwas outstanding.
Planned Capital Expenditures & Investments
During 2013 capital expenditures and other investments approximated
$411 million, of which approximately $268 millionrelated to Utility Groupexpenditures. This compares to 2012 where consolidated investments were approximately $370 millionwith $250 millionattributed to the Utility Groupand 2011 where consolidated investments were approximately $320 millionwith $230 millionattributed to the Utility Group. Planned Utility Groupcapital 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.
The following is a summary of contractual obligations at
(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 $ 1,149.3Short-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
(1) The debt due in 2014 is comprised of debt issued by
(2) The Company has other long-term liabilities that total approximately
million. This amount is comprised of the following: pension obligations
and share-based compensation 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
The Company's primary source of liquidity to fund capital requirements has been cash generated from operations, which totaled
$587.0 millionin 2013, compared to $387.4 millionin 2012 and $416.9 millionin 2011. The $199.6 millionincrease 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 millionlower during 2013 compared to 2012. In 2012, operating cash flows decreased $29.5 millioncompared 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.
Net cash flow required for financing activities was
$179.9 million, $19.6 million, and $99.0 millionfor 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 millionin long-term debt, of which $744 millionwas used to refinance maturing or called long-term debt and $92 millionwas 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 Capital2013 Term Loan On August 6, 2013, Vectren Capitalentered into a $100 millionthree 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'scredit facility. The loan agreement is guaranteed by Vectren Corporationand includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capitalborrowing arrangements. The Company received net proceeds of approximately $100 millionin August 2013. SIGECO 2013 Debt Refund and Reissuance During the second quarter of 2013, approximately $111 millionof SIGECO's tax-exempt long-term debt was redeemed at par plus accrued interest. Approximately $62 millionof tax-exempt long-term debt was reissued on April 26, 2013at interest rates that are fixed to maturity, receiving proceeds, net of issuance costs, of approximately $60 million. The terms are $22.2 millionat 4.00 percent per annum due December 31, 2038, and $39.6 millionat 4.05 percent per annum due December 31, 2043. The remaining approximately $49 millionof 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 millionon August 28, 2013. Utility Holdings2013 Debt Call and Reissuance On April 1, 2013, VUHI exercised a call option at par on Utility Holdings' $121.6 million6.25 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, 2012with a delayed draw feature. It provides for the following tranches of notes: (i) $45 million, 3.20 percent senior guaranteed notes, due June 5, 2028and (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 millionand $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 millionof 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 millionfrom the issuance of the senior guaranteed notes, which were used to refinance $100 millionof 5.25 percent senior notes that matured August 1, 2013, for capital expenditures, and for general corporate purposes. Vectren Capital2012 Term Loan On November 1, 2012, Vectren Capitalentered into a $100 millionthree 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'scredit facility. The loan agreement is guaranteed by Vectren Corporationand includes customary representations, warranties and covenants, including a leverage covenant consistent with leverage covenants contained in other Vectren Capitalborrowing arrangements. The Company received net proceeds of approximately $100 millionin November 2012. 55 -------------------------------------------------------------------------------- Utility Holdings2012 Debt Transactions On February 1, 2012, Utility Holdingsissued $100 millionof 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 2011with 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 Holdings2011 Debt Issuance On November 21, 2011, the Company exercised a call option on Utility Holdings' $96.2 million5.95 percent senior notes due in 2036. This debt was refinanced on November 30, 2011. On that date, Utility Holdingsclosed a financing under a private placement note purchase agreement pursuant to which various institutional investors purchased the following tranches of notes: (i) $55 millionof 4.67 percent Senior Guaranteed Notes, due November 30, 2021, (ii) $60 millionof 5.02 percent Senior Guaranteed Notes, due November 30, 2026, and (iii) $35 millionof 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
In April and May, 2013, the Company exercised call options on six issues of SIGECO's tax exempt long-term debt totaling
$110.9 millionwith interest rates ranging from 4.50 percent to 5.45 percent, and with maturity dates from 2020 to 2041. Investing Cash FlowCash flow required for investing activities was $405.1 millionin 2013, $356.9 millionin 2012, and $319.7 millionin 2011. Capital expenditures are the primary component of investing activities and totaled $393.4 millionin 2013, $365.8 millionin 2012 and $321.3 millionin 2011. Utility Groupcapital expenditures increased approximately $15 millionin 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 millionin 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 millionis primarily due to growth in the Infrastructure Services segment. 56 -------------------------------------------------------------------------------- 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'sfacilities, 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
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 57
-------------------------------------------------------------------------------- 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,
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.