ITEM 1. BUSINESS
A. GENERAL
In this report, when we refer to "us," "we," "our," or "ours," we are referring to WPS. References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
We are a Wisconsin corporation and a wholly owned subsidiary of Integrys Energy Group, Inc. We began operations in 1883. We are a regulated electric and natural gas utility company serving an approximate 12,000 square mile service territory in northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula. We have three reportable segments. In 2012, electric revenues accounted for 80% of our total revenues, while natural gas revenues accounted for 20% of our total revenues.
For more financial information about our electric and natural gas utility operations, see Note 22, "Segments of Business" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations."
Facilities
For information regarding our electric and natural gas utility facilities, see Item 2, "Properties." For our utility plant asset book value, see Note 4, "Property, Plant, and Equipment."
Available Information
Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, registration statements, and any amendments to these documents are available, free of charge, on Integrys Energy Group's website, www.integrysgroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Reports, statements, and amendments posted on Integrys Energy Group's website do not include access to exhibits and supplemental schedules electronically filed with the reports, statements, or amendments. We are not including the information contained on or available through the Integrys Energy Group website as a part of, or incorporating such information by reference into, this Annual Report on Form 10-K.
You may obtain materials we filed with or furnished to the SEC at the SEC Public Reference Room at 100 F Street, NE, Washington, DC 20549. To obtain information on the operation of the Public Reference Room, you may call the SEC at 1-800-SEC-0330. You may also view our reports, registration statements, and other information (including exhibits) filed or furnished electronically with the SEC, at the SEC's website at www.sec.gov.
B. ELECTRIC UTILITY OPERATIONS
Our electric utility operations provide service to approximately 443,000 residential, commercial and industrial, wholesale, and other customers. Our customers are located in northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula. Wholesale electric service is provided to various customers, including municipal utilities, electric cooperatives, energy marketers, other investor-owned utilities, and municipal joint action agencies. In 2012, retail revenues accounted for 86.4% of total electric revenues, while wholesale revenues accounted for 13.6% of total electric revenues.
In 2012, we reached a firm net design peak of 2,347 megawatts on July 16. At the time of this summer peak, our total firm resources (i.e., generation plus firm purchases) totaled 3,173 megawatts. The summer period is the most relevant for our electric utility capacity due to the air conditioning requirements of our customers. The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. The PSCW has a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO under Module E of its Open Access Transmission and Energy Markets Tariff. MISO has a 16.7% reserve margin requirement from January 1 through May 31, 2013, and 14.2% for the remainder of 2013. The MPSC does not have minimum guidelines for future supply reserves. We expect future supply reserves to meet the minimum planning reserve margin requirements for 2013.
Electric Supply
We are a member of MISO, a FERC-approved, independent, nonprofit organization, which operates a financial and physical electric wholesale market in the Midwest. We offer our generation and bid our customer load into the MISO market. MISO evaluates our and other market participants' energy offers into, and subsequent withdrawals from, the system to economically dispatch electricity within the system. MISO settles the participants' offers and bids based on locational marginal prices, which are market-driven values based on the specific time and location of the purchase and/or sale of energy.
Electric Generation and Supply Mix
The sources of our electric utility supply were as follows:
*
In September 2012, we entered into an agreement to acquire all of the equity interests in Fox Energy Company LLC. The purchase includes the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. We currently supply natural gas for the facility and purchase 500 megawatts of capacity and the associated energy output under a tolling arrangement. The transaction is expected to close by the end of March 2013.
Fuel Costs
The cost of fuel per generation of one million British thermal units was as follows:
Coal Supply
Coal is the primary fuel source for our electric generation facilities. Our regulated fuel portfolio strategy is to maintain a 35- to 45-day supply of coal at each plant site. Currently the coal supply is higher than the portfolio strategy due to lower coal burning rates as a result of decreased natural gas prices and economic conditions. The majority of the coal is purchased from Powder River Basin mines located in Wyoming. This low sulfur coal has been our lowest cost coal source of any of the subbituminous coal-producing regions in the United States. Historically, we have purchased coal directly from the producer for our wholly owned plants. We also purchase the coal for the jointly owned Weston 4 plant and Dairyland Power Cooperative reimburses us for their share of the coal costs. Wisconsin Power and Light Company purchases coal for the jointly owned Edgewater and Columbia plants and we reimburse them for our share of the coal costs. At December 31, 2012, we had coal transportation contracts in place for 100% of our 2013 coal transportation requirements. For more information on coal purchases and coal deliveries under contract, see Note 12, "Commitments and Contingencies."
Power Purchase Agreements
We enter into short-term and long-term power purchase agreements to meet a portion of our electric energy supply needs. For more information on power purchase obligations, see Note 12, "Commitments and Contingencies."
Regulatory Matters
Our retail electric rates are regulated by the PSCW and the MPSC. The FERC regulates our wholesale electric rates. We must also comply with mandatory electric system reliability standards developed by the North American Electric Reliability Corporation (NERC), the electric reliability organization certified by the FERC. The Midwest Reliability Organization is responsible for the enforcement of NERC's standards for us.
The PSCW sets rates through its ratemaking process, which is based on recovery of operating costs and a return on invested capital. One of the cost recovery components is fuel and purchased power, which is governed by a fuel window mechanism, as described in Note 1(f), "Summary of Significant Accounting Policies - Revenues and Customer Receivables." The MPSC and FERC ratemaking processes are similar to those of the PSCW, with the exception of fuel and purchased power, which are recovered on a one-for-one basis.
See Note 21, "Regulatory Environment," for information regarding our rate cases and decoupling mechanisms.
Hydroelectric Licenses
We and WRPC (a company in which we have 50% ownership) have long-term licenses from the FERC for our hydroelectric facilities.
Other Matters
Seasonality
Our electric utility sales are generally higher during the summer months due to the air conditioning requirements of customers.
Competition
The retail electric utility market in Wisconsin is regulated by the PSCW. Retail electric customers currently do not have the ability to choose their electric supplier. In order to increase sales, utilities work to attract new customers into their service territories. As a result, there is competition among utilities to keep energy rates low. Wisconsin utilities have continued to refine regulated tariffs in order to pass on the true cost of electricity to each class of customer by reducing or eliminating rate subsidies among different ratepayer classes. Although Wisconsin electric energy markets are regulated, utilities still face competition from other energy sources, such as self-generation by large industrial customers and alternative energy sources.
Michigan electric energy markets are open to competition.
C. NATURAL GAS UTILITY OPERATIONS
Our natural gas utility operations provide service to approximately 321,000 residential, commercial and industrial, transportation, and other customers. Our customers are located in northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula.
Natural Gas Supply
We manage a portfolio of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns at the lowest reasonable cost.
Our natural gas supply requirements are met through a combination of index price purchases, contracted storage, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.
For more information on our natural gas utility supply and transportation contracts, see Note 12, "Commitments and Contingencies."
We contract with various underground storage service providers for storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, thus providing a hedge against supply cost volatility. We further reduce our supply cost volatility through the use of financial instruments such as commodity futures and options as part of our hedging program.
We had adequate capacity to meet all firm natural gas demand obligations during 2012 and expect to have adequate capacity to meet all firm obligations during 2013. Our forecasted design peak-day throughput is 634 thousands of dekatherms (MDth) for the 2012 through 2013 heating season.
The sources of our deliveries to customers (including transportation customers) in MDth were as follows:
Regulatory Matters
Our natural gas retail rates are regulated by the PSCW and the MPSC. These commissions have general supervisory and regulatory powers over public utilities in Wisconsin and Michigan, respectively.
Sales are made and services are rendered pursuant to rate schedules on file with the PSCW and the MPSC. These rate schedules contain various service classifications, which largely reflect customers' different uses and levels of consumption. We bill customers for the distribution of natural gas as well as for a natural gas charge representing third-party costs for purchasing, transporting, and storing natural gas. This charge also includes gains, losses, and costs incurred under a hedging program, the amount of which is also subject to PSCW and MPSC authority. Prudently incurred natural gas costs are passed through to customers in current rates and, therefore, have no impact on margins. Commissions in respective jurisdictions conduct annual proceedings regarding the reconciliation of revenues from the natural gas charge and related natural gas costs.
Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. Under United States Department of Transportation regulations, the PSCW is responsible for monitoring our safety compliance program for our pipelines under 49 Code of Federal Regulations (CFR) Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards) and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).
We are required to provide service and grant credit (with applicable deposit requirements) to customers within our service territories. We are generally not allowed to discontinue service during winter moratorium months to residential customers who do not pay their bills. The Federal, Wisconsin, and Michigan governments have legislation that provides for a limited amount of funding for assistance to our low-income customers.
See Note 21, "Regulatory Environment," for information regarding our rate cases and decoupling mechanisms.
Other Matters
Seasonality
Our natural gas throughput is generally higher during the winter months because the heating requirements of customers are temperature driven. During 2012, the regulated natural gas utility segment recorded approximately 63% of its revenues in January, February, March, November, and December.
Competition
Although our natural gas retail rates are regulated by the PSCW and the MPSC, we still face competition from other entities and forms of energy available to consumers in varying degrees, particularly for large commercial and industrial customers who have the ability to switch between natural gas and alternate fuels. Due to the volatility of energy commodity prices, we have seen customers with dual fuel capability switch to alternate fuels for short periods of time, then switch back to natural gas as market rates change.
We offer natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution system to transport the natural gas to their facilities. We still earn a distribution charge for transporting the natural gas for these customers. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has no impact on our natural gas utility segment net income, as it is offset by an equal reduction to natural gas costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.
Working Capital Requirements
The working capital needs of our natural gas utility operations vary significantly over time due to volatility in levels of natural gas inventories and the price of natural gas. Our working capital needs are met by cash generated from operations and short-term debt. The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is
typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.
D. ENVIRONMENTAL MATTERS
For information on our environmental matters, see Note 12, "Commitments and Contingencies."
E. CAPITAL REQUIREMENTS
For information on our capital requirements, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources."
F. EMPLOYEES
At December 31, 2012, we had 1,283 full-time employees, of which approximately 70% were union employees represented by Local 420 of the International Union of Operating Engineers. The Local 420 collective bargaining agreement expired on October 13, 2012; however a new collective bargaining agreement is currently being negotiated.
ITEM 1A.
ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors, as well as the other information included or incorporated by reference in this Annual Report on Form 10-K,when making an investment decision.
We are subject to government regulation, which may have a negative impact on our business, financial position, and results of operations.
We are subject to comprehensive regulation by several federal and state regulatory agencies and local governmental bodies. This regulation significantly influences our operating environment and may affect our ability to recover costs from regulated utility customers. Many aspects of our operations are regulated, including, but not limited to, construction and operation of facilities, conditions of service, the issuance of securities, and the rates that we can charge customers. We are required to have numerous permits, approvals, and certificates from these agencies to operate our business. Failure to comply with any applicable rules or regulations may lead to penalties or customer refunds, which could have a material adverse impact on our financial results.
Existing statutes and regulations may be revised or reinterpreted by federal and state regulatory agencies, or these agencies may adopt new laws and regulations that apply to us. We are unable to predict the impact on our business and operating results of any such actions by these agencies. However, changes in regulations or the imposition of additional regulations may require us to incur additional expenses or change business operations, which may have an adverse impact on results of operations.
The rates that we are allowed to charge for retail and wholesale services are the most important factors influencing our business, financial position, results of operations, and liquidity. Rate regulation is premised on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, there is no assurance that regulatory commissions will consider all of our costs to have been prudently incurred. In addition, the regulatory process will not always result in rates that will produce full recovery of such costs or provide for a reasonable return on equity. Certain expense and revenue items are deferred as regulatory assets and liabilities for future recovery or refund to customers, as authorized by regulators. Future recovery of regulatory assets is not assured, and is generally subject to review by regulators in rate proceedings for prudence and reasonableness. If recovery of costs is not approved or is no longer deemed probable, regulatory assets would be recognized in current period expense and could have a material adverse impact on our financial results.
We are subject to environmental laws and regulations, compliance with which could be difficult and costly.
We are subject to numerous federal and state environmental laws and regulations that affect many aspects of our operations, including future operations. These laws and regulations relate to air emissions, water quality, wastewater discharges, and the generation, transport, and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections, and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, install pollution control equipment or environmental monitoring equipment at our facilities, incur fees for emissions and permits, and incur expenditures for cleanup costs, damages arising from contaminated properties, and monitoring obligations. In addition, there is uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Compliance with current and future environmental laws and regulations may result in increased capital, operating, and other costs. Noncompliance could result in fines, penalties, and injunctive measures affecting our facilities.
Existing environmental laws or regulations may also be revised and/or new laws or regulations seeking to protect the environment may be adopted or become applicable to us. These laws and regulations include, but are not limited to, regulation regarding mercury, sulfur dioxide, and nitrogen oxide emissions, and the management of coal combustion byproducts, including fly ash. The steps we could be required to take to ensure that our facilities are in compliance with any such laws and regulations could be prohibitively expensive. As a result, certain coal-fired electric generating facilities may become uneconomical to run and could result in early retirement of some of our units or may force us to convert the units to an alternative type of fuel. Costs associated with these potential actions could affect our results of operations and financial condition.
We are accruing liabilities and deferring costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all recoverable costs incurred to date, management's best estimates of future costs for investigation and remediation, and legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other entities. The ultimate costs to remediate these sites could also vary from the amounts currently accrued.
Citizen groups that feel environmental regulations are not being sufficiently enforced by environmental regulatory agencies may also bring citizen enforcement actions against us. Such actions could seek penalties, injunctive relief, and costs of litigation. There is also a risk that private citizens may bring lawsuits to recover environmental damages they believe they have incurred.
We may incur significant costs if laws or regulations are adopted to address climate change.
Political interest in climate change and the effects of greenhouse gas emissions, most notably carbon dioxide, are a concern for the energy industry. Although no legislation is currently pending that would affect us, state or federal legislation could be passed in the future to regulate greenhouse gas emissions. In addition, the EPA began regulating greenhouse gas emissions under the Clean Air Act (CAA) by applying the Best Available Control Technology (BACT) requirements, which are associated with the New Source Review Program. These requirements apply to new and modified larger greenhouse gas emitters. The EPA has issued a proposed rule that would impose a carbon dioxide emission rate limit on new electric generating units, but the EPA has delayed proposing performance standards for existing units. Until legislation is passed at the federal or state level or the EPA adopts final rules for electric utility steam generating units, it remains unclear as to (1) which industry sectors will be impacted, (2) when compliance will be required, (3) the magnitude of the greenhouse gas emissions reductions that will be required, and (4) the costs and opportunities associated with compliance.
It is possible that future carbon regulation will increase the cost of electricity produced at fossil fuel-fired generation units. Future regulation may also affect the capital expenditures we would make at our generation units, including costs to further limit the greenhouse gas emissions from our operations through carbon capture and storage technology. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could also affect the availability or cost of fossil fuels. Future legislation designed to reduce greenhouse gas emissions could make some generating units uneconomical to maintain or operate and could impact future results of operations, cash flows, and financial condition if such costs are not recoverable through regulated rates.
Our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair of natural gas delivery systems. Fugitive gas typically vents to the atmosphere and consists primarily of methane, a greenhouse gas. Carbon dioxide is also a byproduct of natural gas consumption. As a result, future legislation to regulate greenhouse gas emissions could increase the price of natural gas, restrict the use of natural gas, adversely affect our ability to operate our natural gas facilities, and/or reduce natural gas demand, which could have a material adverse impact on our results of operations and financial condition.
Our operations are subject to various conditions which can result in fluctuations in the number of customers and their usage.
Our operations are affected by the demand for electricity and natural gas, which can vary greatly based upon:
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Fluctuations in general economic conditions and growth in the service areas in which we operate;
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Weather conditions;
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The amount of energy available from current or new competitors; and
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Our customers' continued focus on energy efficiency.
Our operations are subject to risks arising from the reliability of our electric generation, transmission and distribution facilities, natural gas infrastructure facilities and other facilities, as well as the reliability of third-party transmission providers.
The operation of electric generation and natural gas and electric distribution facilities involves many risks, including the risk of potential breakdown or failure of equipment or processes, which may occur due to storms, natural disasters, or other catastrophic events. Other risks include aging infrastructure, fuel supply or transportation disruptions, accidents, employee labor disputes, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, and performance below expected levels. Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by unexpected or uncontrollable events occurring on the systems of these third parties.
Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs, and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems may occur and are an inherent risk of our business. Unplanned outages may reduce our revenues or may require us to incur significant costs by forcing us to operate our higher cost electric generators or obtain replacement power from third parties in the open market to satisfy our power sales obligations. Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of the lost revenues or increased expenses.
New and pending environmental regulations may force many generation facility owners in the Midwest, including us, to retire a significant number of older coal-fired generation facilities, resulting in a potential reduction in the region's capacity reserve margin to below acceptable risk levels. This could also impair the reliability of the Midwest portion of the grid, especially during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.
We are obligated to provide safe and reliable service to customers within our service territories. Meeting this commitment requires significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards could adversely affect our operating results through the imposition of penalties and fines or other adverse regulatory outcomes.
Our operations are subject to risks beyond our control, including but not limited to, cyber security attacks, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.
Any future terrorist attack, cyber security attack, and/or act of war affecting our facilities and operations could have an adverse impact on our results of operations, financial condition, and cash flows. The energy industry uses sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems with other third parties. A cyber security attack may occur despite our security measures or those that we require our vendors to take, including compliance with reliability standards and critical infrastructure protection standards. Cyber security attacks, including those targeting information systems and electronic control systems used at generating facilities and electric and natural gas transmission and distribution systems, could severely disrupt our operations and result in loss of service to customers. The risk of such attacks may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.
Our business requires the collection and retention of personally identifiable information of our customers, shareholders, and employees, who expect that we will adequately protect such information. A significant theft, loss, or fraudulent use of personally identifiable information may cause our business reputation to be adversely impacted, may lead to potentially large costs to notify and protect the impacted persons, and/or may cause us to become subject to legal claims, fines, or penalties, any of which could adversely impact our results of operations.
The costs of repairing damage to our facilities, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.
Counterparties and customers may not meet their obligations.
We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, coal, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to replace the underlying commitment at then-current market prices or we may be unable to meet all of our customers' natural gas and electric requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.
Some of our customers are experiencing, or may experience, financial problems that could have a significant impact on their creditworthiness. We cannot provide assurance that financially distressed customers will not default on their obligations to us and that such defaults will not have a material adverse impact on our business, financial position, results of operations, or cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, could adversely impact our receivable collections or increase our bad debt allowances for these customers, which could adversely affect our operating results. In addition, such events might force customers to reduce their future use of our products and services, which could have a material adverse impact on our results of operations and financial condition.
Poor investment performance of retirement plan investments and other factors impacting retirement plan costs could unfavorably impact our liquidity and results of operations.
We participate in employee benefit plans that cover substantially all of our employees and retirees. Our cost of providing these benefit plans varies depending upon actual plan experience and assumptions concerning the future. These assumptions include earnings on and/or valuations of plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and required or voluntary contributions to the plans. Depending on the investment performance over time and other factors impacting our costs, we could be required to make larger contributions in the future to fund these plans. These additional funding obligations could have a material adverse impact on our cash flows, financial condition, and/or results of operations. Changes made to the plans may also impact current and future pension and other postretirement benefit costs.
Adverse capital and credit market conditions could negatively affect our ability to meet liquidity needs, access capital, and/or grow or sustain our current business. Cost of capital and disruptions, uncertainty, and/or volatility in the financial markets could adversely impact our results of operations and financial condition.
Having access to the credit and capital markets, at a reasonable cost, is necessary for us to fund our operations and capital requirements. The capital and credit markets provide us with liquidity to operate and grow our business that is not otherwise provided from operating cash flows. Disruptions, uncertainty, and/or volatility in those markets could increase our cost of capital or limit the availability of capital. If we or Integrys Energy Group are unable to access the credit and capital markets on terms that are reasonable, we may have to delay raising capital, issue shorter-term securities, and/or bear an increased cost of capital. This, in turn, could impact our ability to grow or sustain our current business, cause a reduction in earnings, and/or result in a credit rating downgrade.
A reduction in our credit ratings could materially and adversely affect our business, financial position, results of operations, and liquidity.
We cannot be sure that any of our credit ratings will not be lowered by a rating agency if, in the rating agency's judgment, circumstances in the future so warrant. Any downgrade could:
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Require the payment of higher interest rates in future financings and possibly reduce the potential pool of creditors;
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Increase borrowing costs under certain existing credit facilities;
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Limit access to the commercial paper market;
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Require provision of additional credit assurance, including cash margin calls, to contract counterparties.
Fluctuating commodity prices may impact energy margins and result in changes to liquidity requirements.
The margins and liquidity requirements of our business are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services. Changes in price could result in:
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Higher working capital costs, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;
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Increased liquidity requirements due to potential counterparty margin calls related to the use of derivative instruments to manage commodity price and volume exposure;
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Reduced profitability to the extent that reduced margins, increased bad debt, and interest expenses are not recovered through rates;
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Higher rates charged to our customers, which could impact the company's competitive position;
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Reduced demand for energy, which could impact margins and operating expenses; and
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Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Electric Facilities
The following table summarizes information on our electric generation facilities, including owned and jointly owned facilities, as of December 31, 2012:
(1)
Based on capacity ratings for July 2013, which can differ from nameplate capacity, especially on wind projects. The summer period is the most relevant for capacity planning purposes as a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.
(2)
We jointly own these facilities with various other utilities. The capacity indicated for each of these units is equal to our portion of total plant capacity based on our percent of ownership.
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Wisconsin Power and Light Company operates the Columbia and Edgewater units, and we hold a 31.8% ownership interest in these facilities.
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We operate the Weston 4 facility and hold a 70% ownership in this facility, while Dairyland Power Cooperative holds the remaining 30%.
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WRPC owns and operates the Juneau unit. We hold a 50% ownership interest in WRPC.
(3)
WRPC owns and operates the Castle Rock and Petenwell units. We hold a 50% ownership interest in WRPC; however, we are entitled to 66.6% of total capacity at Castle Rock and Petenwell. Our share of capacity for Castle Rock is 11.6 megawatts, and our share of capacity for Petenwell is 13.4 megawatts.
In September 2012, we entered into an agreement to purchase the Fox Energy Center, a 593-megawatt combined-cycle electric generating natural gas facility in Wisconsin. The transaction is expected to close by the end of March 2013.
As of December 31, 2012, our electric utility owned approximately 21,700 miles of electric distribution lines located in Michigan and Wisconsin and 124 distribution substations.
Natural Gas Facilities
At December 31, 2012, our natural gas properties were located in northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula and consisted of the following:
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Approximately 7,700 miles of natural gas distribution mains,
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Approximately 250 miles of natural gas transmission mains,
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86 natural gas distribution and transmission gate stations, and
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Approximately 299,000 natural gas lateral services.
General
Substantially all of our utility plant is subject to a first mortgage lien.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
For information on material legal proceedings and matters related to us and our subsidiary, see Note 12, "Commitments and Contingencies."
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Integrys Energy Group is the sole holder of our common stock; therefore, there is no established public trading market for our common stock. We made no purchases of equity securities during the fourth quarter of 2012. For information on dividends paid and dividend restrictions, see Note 16, "Common Equity."
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
WISCONSIN PUBLIC SERVICE CORPORATION
COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS
*
Normal heating and cooling degree days are based on a 20-year average of monthly temperatures from the Green Bay Weather Station. Daily degree days are calculated by subtracting the 24-hour average daily temperature from 65° Fahrenheit. Heating degree days result if temperatures are less than 65° Fahrenheit and cooling degrees result if temperatures are more than 65° Fahrenheit.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
We are a regulated electric and natural gas utility and a wholly owned subsidiary of Integrys Energy Group, Inc. We derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers. We also provide wholesale electric service to numerous municipal utilities and cooperatives for resale.
Strategic Overview
The focus of our business plan is the creation of long-term value for Integrys Energy Group's shareholders and our customers through growth, operational excellence, customer focus, risk management, and the continued emphasis on safe, reliable, competitively priced, and environmentally sound energy services.
The essential components of our business strategy are:
Providing Safe, Reliable, Competitively Priced, and Environmentally Sound Energy Services - Our mission is the same as Integrys Energy Group's: to provide customers with the best value in energy and related services. We strive to effectively operate a mixed portfolio of generation assets and prudently invest in new generation and distribution assets to grow our regulated utility base and meet our customers' needs. Our pending purchase of the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, in 2013, is a good example of this, as well as our continued investment in environmental projects to improve air quality and meet or exceed the requirements set by environmental regulators. Capital projects to construct and/or upgrade equipment are planned each year to enhance safety, reliability, and value for our customers and Integrys Energy Group's shareholders. In addition, we expect to begin undergrounding electric distribution lines in northern Wisconsin in 2014 under our proposed System Modernization and Reliability Project.
Integrating Resources to Provide Operational Excellence and Customer Focus - We are committed to integrating resources and finding the best, most efficient processes while meeting all applicable legal and regulatory requirements. We strive to provide value to our customers and Integrys Energy Group's shareholders by embracing change, leveraging capabilities and expertise, and using creative solutions to meet or exceed our customers' expectations. "Operational Excellence" initiatives have been implemented to reduce costs and encourage top performance in the areas of project management, process improvement, contract administration, and compliance.
Placing Strong Emphasis on Risk Management - Our risk management strategy includes the management of market, credit, liquidity, and operational risks through the normal course of business. Forward purchases of electric capacity, energy, natural gas, and other commodities, and the use of derivative financial instruments, including commodity options, provide tools to reduce the risk associated with price movement in a volatile energy market. The risk profile related to these instruments is managed in a manner consistent with Integrys Energy Group's risk management policy for regulated affiliates, which is approved by the Integrys Energy Group Board of Directors. The Integrys Energy Group Corporate Risk Management Group, which reports through Integrys Energy Group's Chief Financial Officer, provides oversight for us. We also implemented formula-based market tariffs to manage risk in the wholesale market.
RESULTS OF OPERATIONS
Earnings Summary
2012 Compared with 2011
We recognized earnings of $131.7 million in 2012 compared with $122.8 million in 2011. The $8.9 million increase in earnings was driven by:
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A $7.5 million positive year-over-year impact driven by the reversal in 2012 of $5.9 million of deferred income taxes that had been expensed in prior years due to the implementation of federal health care reform. We were authorized recovery of this amount in our 2013 rate case settlement received in December 2012.
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A $5.7 million after-tax decrease in other expense, driven by lower interest expense resulting from the repayment of long-term debt in 2011.
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A $2.8 million after-tax decrease in operating expenses, excluding the impact of the Focus on Energy Program, which is offset in margins.
These decreases were partially offset by a $9.2 million after-tax decrease in electric utility margins driven by rate case effects, excluding the impact of the Focus on Energy program, which is offset in operating expenses.
2011 Compared with 2010
We recognized earnings of $122.8 million in 2011 compared with $131.9 million in 2010. The $9.1 million decrease in earnings was driven by:
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A $10.9 million after-tax decrease in electric utility margins mainly caused by differences in the 2011 rate order, compared with the previous rate order.
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A $10.4 million after-tax decrease in natural gas utility margins driven by the negative impact of the 2011 rate order.
These decreases were partially offset by a $9.4 million after-tax decrease in operating expenses, driven by decreases in natural gas utility depreciation and amortization expense and employee benefit costs.
Electric Utility Segment Operations
2012 Compared with 2011
Margins
Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric operating revenues. To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.
Electric utility segment margins decreased $26.6 million, driven by:
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An approximate $21 million decrease in margins related to rate case effects. Although the PSCW approved a rate increase effective January 1, 2012, it was driven by anticipated increases in fuel and purchased power costs that did not materialize. Under the fuel rules, we deferred a portion of the difference between the fuel window costs included in rates and the actual fuel window costs. This portion will be refunded to customers.
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Excluding the impact from fuel and purchased power costs, the 2012 rate case re-opener resulted in a rate decrease. The rate decrease was primarily driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The approximate $11 million margin impact from the reduction in contributions to the Focus on Energy Program was offset by lower operating expenses due to reduced payments to the program in 2012.
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Fuel costs not included in the fuel window were lower relative to the rate case-approved amounts in 2011. This resulted in an approximate $9 million negative year-over-year impact on margins.
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An approximate $4 million decrease in wholesale margins, driven by a decrease in sales volumes. The decrease was primarily due to a reduction in sales to one large customer.
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The margin impact from changes in retail sales volumes was essentially offset by the impact from the decoupling mechanism.
Operating Income
Operating income at the electric utility segment decreased $13.4 million. The decrease was driven by the $26.6 million decrease in margins discussed above, offset by a $13.2 million decrease in operating expenses. The decrease in operating expenses was driven by:
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An $11.3 million decrease in customer assistance expense, driven by reduced payments to the Focus on Energy program. These payments are recovered in rates.
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A $2.0 million decrease in asset usage charges from IBS driven by certain computer hardware that was fully depreciated in 2011.
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A $1.3 million decrease in the amortization of various regulatory deferrals.
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A $1.2 million decrease in injuries and damages expenses.
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These decreases were partially offset by a $2.8 million increase in employee-benefit related expenses. The increase was primarily due to an increase in postretirement medical expenses as well as the year-over-year change in the fair value of amounts owed to plan participants under deferred compensation plans. Partially offsetting these increases was lower pension expense driven by an increase in contributions, which increased plan assets.
Other Expense
Other expense decreased $7.7 million, driven by a decrease in interest expense due to the maturity and repayment of $150 million of long-term debt in August 2011. Also contributing to the decrease in other expense was an increase in AFUDC, primarily related to environmental compliance projects at the Columbia plant.
2011 Compared with 2010
Margins
Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating utility operations than electric operating revenues. To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues. Any significant changes in fuel and purchased power costs that are not recovered from customers are explained in the margin discussion below.
Electric utility segment margins decreased $18.1 million, driven by:
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An approximate $18 million decrease in retail margins due to differences between our 2011 rate order and the previous rate order. Although our 2011 rate order included a lower authorized return on common equity, lower rate base, and other reduced costs, which resulted in lower total revenues and margins, the rate order also projected lower total sales volumes, which led to a rate increase on a per-unit basis. The 2011 rate increase, calculated on a per-unit basis, was more than offset by the decoupling mechanism due to changes in the rate order that impact the decoupling calculation. For more details on our 2011 rate order, see Note 21, "Regulatory Environment."
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An approximate $4 million decrease in margins from wholesale customers. The decrease was due to lower sales volumes and lower nonfuel revenue requirements driven by a lower return on common equity, lower rate base, and other reduced costs.
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A partially offsetting approximate $3 million increase in margins due to a year-over-year positive impact from the 2010 amortization of a regulatory asset related to energy efficiency legislation implemented in a prior year.
Operating Income
Operating income at the electric utility segment decreased $15.7 million. The decrease was driven by the $18.1 million decrease in margins, partially offset by a $2.4 million decrease in operating expenses. The decrease in operating expenses was primarily related to:
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A $7.7 million decrease in employee benefit costs. The decrease was partially due to lower pension expense driven by an increase in contributions, which increased plan assets.
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A $7.4 million decrease in depreciation and amortization expense. The PSCW approved lower depreciation rates effective January 1, 2011, and we had lower software amortization in 2011.
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These decreases were partially offset by
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A $4.1 million increase in the amortization of various regulatory deferrals. This increase was offset in revenues, resulting in no impact on earnings.
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A $3.7 million increase in customer assistance expense related to payments made to the Focus on Energy program. The program promotes residential and small business energy efficiency and renewable energy products.
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A $2.2 million increase in electric transmission expense.
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A $1.8 million increase in taxes other than income taxes driven by an increase in gross receipts taxes.
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A $1.8 million increase in injuries and damages expenses.
Other Expense
Other expense decreased $2.4 million, driven by a decrease in interest expense due to the maturity and repayment of $150 million of long-term debt in August 2011.
Natural Gas Utility Segment Operations
2012 Compared with 2011
Margins
Natural gas utility margins are defined as natural gas utility operating revenues less the cost of natural gas purchased for resale. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 17% decrease in the average per-unit cost of natural gas sold during 2012, which had no impact on margins.
Natural gas utility segment margins decreased $7.6 million, driven by:
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An approximate $5 million decrease in margins related to our rate order effective January 1, 2012. The rate decrease was driven by reduced contributions to the Focus on Energy Program, which promotes residential and small business energy efficiency and renewable energy products. The margin impact from the reduction in contributions is offset by lower operating and maintenance expenses. See Note 21, "Regulatory Environment," for more information on this rate order.
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An approximate $2 million net decrease in margins, including the impact of decoupling, due to a 5.1% decrease in volumes sold.
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Substantially warmer weather during 2012 drove an approximate $12 million decrease in margins. Heating degree days decreased 15.5%.
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Lower sales volumes excluding the impact of weather resulted in an approximate $1 million decrease in margins. Sales volumes were lower due to lower use per residential customer.
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The decrease in margins due to lower volumes sold was partially offset by an approximate $11 million increase in decoupling recovery. During 2012, decoupling lessened the negative impact from some of the decreased sales volumes through higher future recoveries from customers. This was limited by an $8.0 million decoupling cap that was reached during the second quarter of 2012. During 2011, decoupling lessened the positive impact from some of the increased sales volumes through higher future refunds to customers. Decoupling does not cover all jurisdictions or customer classes.
Operating Income
Operating income at the natural gas utility segment increased $1.6 million. This increase was primarily driven by a $9.4 million decrease in operating and maintenance expenses, partially offset by the $7.6 million decrease in margins discussed above.
The decrease in operating and maintenance expenses was primarily related to:
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A $7.3 million decrease in customer assistance expense, driven by reduced payments to the Focus on Energy Program. Costs for the program are recovered in rates.
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A $1.0 million decrease in bad debt expense, primarily related to the impact lower volumes and lower natural gas prices had on overall accounts receivable balances. Balances in past due accounts have also decreased.
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A $0.8 million decrease in asset usage charges from IBS driven by certain computer hardware that was fully depreciated in 2011.
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A $0.8 million decrease in customer accounts expense driven by a decrease in maintenance costs related to our customer billing system.
Other Expense
Other expense decreased $1.3 million, driven by a decrease in interest expense, primarily due to the maturity and repayment of $150.0 million of long-term debt in August 2011.
2011 Compared with 2010
Margins
Natural gas utility margins are defined as natural gas utility operating revenues less the cost of natural gas purchased for resale. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates. There was an approximate 6% decrease in the average per-unit cost of natural gas sold during 2011, which had no impact on margins.
Natural gas utility segment margins decreased $17.4 million, driven by:
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An approximate $16 million decrease in margins related to our rate order effective January 14, 2011. See Note 21, "Regulatory Environment," for more information on this rate order.
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An approximate $3 million net decrease in margins due to sales volume variances. Sales increased in 2011, but the financial impact relating to changes in the decoupling mechanism as a result of the rate order in effect during 2011 more than offset the increase.
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Colder weather during 2011 drove an approximate $4 million increase in margins. Heating degree days increased 6.3%.
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Higher sales volumes excluding the impact of weather resulted in an approximate $4 million increase in margins. We attribute this increase to a combination of higher use per customer, higher average customer counts, and improved economic conditions for certain customer classes.
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The increase in margins due to higher volumes sold was partially offset by an approximate $11 million decrease in decoupling recovery. During 2011, decoupling lessened the positive impact from some of the increased sales volumes through higher future refunds to customers. During 2010, decoupling lessened the negative impact from some of the decreased sales volumes through higher future recoveries from customers. Decoupling does not cover all jurisdictions or customer classes.
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A partially offsetting approximate $2 million increase in margins due to the year-over-year positive impact from the 2010 amortization of a regulatory asset related to energy efficiency legislation implemented in a prior year.
Operating Income
Operating income at the natural gas utility segment decreased $3.1 million. This decrease was primarily driven by the $17.4 million decrease in margins discussed above, partially offset by a $14.3 million decrease in operating expenses.
The decrease in operating expenses primarily related to:
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A $7.7 million decrease in depreciation and amortization expense. We received approval for lower depreciation rates from the PSCW, effective January 1, 2011.
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A $2.3 million decrease in customer assistance expense, driven by reduced payments to the Focus on Energy program. The program promotes residential and small business energy efficiency and renewable energy products. Costs for the program are recovered in rates.
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A $3.1 million decrease in employee benefits expense driven by lower pension expense. The decrease in pension expense was driven by an increase in contributions, which increased plan assets.
Other Segment Operations
2012 Compared with 2011
Income before taxes for other segment operations increased $1.1 million in 2012. The increase was due in part to higher earnings related to our ownership interest in WPS Investments, LLC.
2011 Compared with 2010
Income before taxes for other segment operations increased $2.2 million. The increase was driven by lower interest expense owed to participants in the deferred compensation plans.
Provision for Income Taxes
2012 Compared with 2011
Our effective tax rate decreased in 2012. The primary driver was a $5.9 million decrease in the provision for income taxes as a result of our 2013 rate case settlement agreement issued in December 2012. We recorded a regulatory asset after the settlement agreement authorized recovery of deferred income taxes expensed in previous years in connection with the 2010 federal health care reform. This legislation eliminated the tax deduction for retiree prescription drug payments that are paid by employers and are offset by the receipt of a federal Medicare Part D subsidy. The decrease was also partially related to an increase in our state income tax obligations in 2011, driven by a tax law change in Wisconsin. We increased our provision for income taxes by $1.6 million in 2011 when we increased our deferred income tax liabilities related to this tax law change.
For information on changes in the deferred income tax balances, see Note 11, "Income Taxes."
2011 Compared with 2010
Our effective tax rate increased slightly during 2011. In 2011, we increased our provision for income taxes by $1.6 million for the tax law change discussed above.
LIQUIDITY AND CAPITAL RESOURCES
We believe we have adequate resources to fund ongoing operations and future capital expenditures. These resources include cash balances, liquid assets, operating cash flows, access to debt markets, and available borrowing capacity. However, our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control. Our borrowing costs can be impacted by short-term and long-term debt ratings assigned by independent credit rating agencies, as well as the market rates for interest.
Operating Cash Flows
2012 Compared with 2011
During 2012, net cash provided by operating activities was $223.3 million, compared with $181.3 million during 2011. The $42.0 million increase in net cash provided by operating activities was largely driven by:
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A $41.4 million year-over-year decrease in taxes paid. This change was primarily caused by differences in estimated payments related to the prior years.
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A $32.2 million year-over-year increase in cash resulting from $19.1 million of fuel over-collections in 2012 compared with $13.1 million of net fuel amounts refunded in 2011.
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A $9.0 million decrease in cash paid for interest, primarily due to the maturity and repayment of long-term debt.
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Partially offsetting these increases in cash provided by operating activities was a $49.0 million increase in contributions to pension and other postretirement benefit plans.
2011 Compared with 2010
During 2011, net cash provided by operating activities was $181.3 million, compared with $268.1 million during 2010. The $86.8 million decrease in net cash provided by operating activities was largely driven by:
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Net cash paid for income taxes of $38.0 million in 2011, compared with $30.3 million of net cash received for income taxes in 2010. The year-over-year change was primarily due to a 2010 change in tax accounting related to capitalization of overhead costs.
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A $21.2 million repayment of related party payables in 2011 due to a change in the administration of the deferred compensation plan.
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A $15.0 million year-over-year increase in net cash used for working capital. The increase was driven by $26.2 million of cash used for inventory in 2011, compared with $0.8 million of cash generated from inventory in 2010. The year-over-year change was primarily due to increased coal freight costs in 2011.
Partially offsetting these decreases was a $20.8 million net decrease in contributions to pension and other postretirement benefit plans.
Investing Cash Flows
2012 Compared with 2011
Net cash used for investing activities was $172.2 million during 2012, compared with $86.1 million during 2011. The $86.1 million increase in net cash used for investing activities was primarily driven by an $88.0 million increase in cash used to fund capital expenditures (discussed below).
2011 Compared with 2010
Net cash used for investing activities was $86.1 million during 2011, compared with $78.1 million during 2010. The $8.0 million increase in net cash used for investing activities was primarily driven by a $6.0 million increase in cash used to fund capital expenditures (discussed below).
Capital Expenditures
Capital expenditures by business segment for the years ended December 31 were as follows:
The increase in capital expenditures at the electric utility segment in 2012 compared with 2011 was primarily due to environmental compliance projects at the Columbia plant in 2012.
The increase in capital expenditures at the electric utility segment in 2011 compared with 2010 was primarily due to the purchase of a combustion turbine, construction of temporary ash storage, and various projects at the Columbia plant. These expenditures were partially offset by the year-over-year impact of cash payments made in 2010 relating to the Crane Creek Wind Farm project, which was placed in service for accounting purposes in December 2009.
Financing Cash Flows
2012 Compared with 2011
Net cash used for financing activities was $50.1 million during 2012, compared with $161.1 million during 2011. The $111.0 million decrease in net cash used for financing activities was driven by the following:
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A $300.0 million issuance of long-term debt in 2012.
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A $39.3 million decrease in return of capital payments to Integrys Energy Group.
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A $20.0 million increase in equity contributions from Integrys Energy Group.
Partially offsetting these positive impacts was a $252.0 million year-over-year increase in net cash used for financing activities due to $78.3 million of net repayments of commercial paper in 2012, compared with $173.7 million of net borrowings of commercial paper in 2011.
2011 Compared with 2010
Net cash used for financing activities was $161.1 million during 2011, compared with $124.6 million during 2010. The $36.5 million increase in net cash used for financing activities was driven by:
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A $150.0 million increase due to the repayment of our 6.125% Senior Notes, which matured in 2011.
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A $74.3 million increase in return of capital payments to Integrys Energy Group.
Partially offsetting these increases was a $180.7 million decrease due to $173.7 million of net borrowings of commercial paper in 2011, compared with $7.0 million of net repayments in 2010.
Significant Financing Activities
See Note 8, "Short-Term Debt and Lines of Credit," and Note 9, "Long-Term Debt," for more information.
Credit Ratings
We use internally generated funds and commercial paper borrowings to satisfy most of our capital requirements. We periodically issue long-term debt and receive equity contributions from Integrys Energy Group to reduce short-term debt, fund future growth, and maintain capitalization ratios as authorized by the PSCW.
Our current credit ratings are listed in the table below.
Credit ratings are not recommendations to buy or sell securities. They are subject to change and each rating should be evaluated independent of any other rating.
Future Capital Requirements and Resources
Contractual Obligations
The following table shows our contractual obligations as of December 31, 2012, including those of our subsidiary.
(1)
Represents bonds and notes issued. We record all principal obligations on the balance sheet.
(2)
The costs of energy and transportation purchase obligations are expected to be recovered in future customer rates.
(3)
Includes obligations related to normal business operations and large construction obligations.
(4)
Obligations for pension and other postretirement benefit plans, other than the Integrys Energy Group Retirement Plan, cannot reasonably be estimated beyond 2017.
The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $68.8 million at December 31, 2012, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 12, "Commitments and Contingencies," for more information about environmental liabilities. The table also does not reflect estimated future payments for the December 31, 2012 liability of $0.3 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain. See Note 11, "Income Taxes," for more information about unrecognized tax benefits.
Capital Requirements
As of December 31, 2012, our capital expenditures by segment for 2013 through 2015 were expected to be as follows:
All projected capital and investment expenditures are subject to periodic review and may vary significantly from the estimates, depending on a number of factors. These factors include, but are not limited to, environmental requirements, regulatory constraints and requirements, changes in tax laws and regulations, market volatility, and economic trends.
Capital Resources
Management prioritizes the use of capital and debt capacity, determines cash management policies, uses risk management policies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage the liquidity and capital resource needs of the business segments. We plan to meet our capital requirements for the period 2013 through 2015 primarily through internally generated funds (net of forecasted dividend payments), debt financings, and equity infusions from Integrys Energy Group. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.
We currently have two shelf registration statements. Under these registration statements, we may issue up to $200.0 million of additional senior debt securities and up to $30.0 million of preferred stock. Amounts, prices, and terms will be determined at the time of future offerings.
At December 31, 2012, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future.
See Note 8, "Short-Term Debt and Lines of Credit," for more information on credit facilities and other short-term credit agreements, including short-term debt covenants. See Note 9, "Long-Term Debt," for more information on long-term debt and related covenants.
Other Future Considerations
Climate Change
The EPA began regulating greenhouse gas emissions under the Clean Air Act in January 2011 by applying the Best Available Control Technology (BACT) requirements (associated with the New Source Review program) to new and modified larger greenhouse gas emitters. Technology to remove and sequester greenhouse gas emissions is not commercially available at scale. Therefore, the EPA issued guidance that defines BACT in terms of improvements in energy efficiency as opposed to relying on pollution control equipment. In March 2012, the EPA issued a proposed rule that would impose a carbon dioxide emission rate limit on new electric generating units. The proposed limit may prevent the construction of new coal units until technology becomes commercially available. The EPA planned to propose performance standards for existing units in 2011 and finalize them in 2012; however, that proposal has been delayed.
A risk exists that any greenhouse gas legislation or regulation will increase the cost of producing energy using fossil fuels. However, we believe that capital expenditures being made at our plants are appropriate under any reasonable mandatory greenhouse gas program. We also believe that our future expenditures that may be required to control greenhouse gas emissions or meet renewable portfolio standards will be recoverable in rates. We will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas legislative or regulatory actions.
All of our generation and distribution facilities are located in the upper Midwest region of the United States. The same is true for all of our customers' facilities. The physical risks, if any, posed by climate change for these areas are not expected to be significant at this time. Ongoing evaluations will be conducted as more information on the extent of such physical changes becomes available.
Federal Health Care Reform
Since the Health Care and Education Reconciliation Act of 2010 (HCR) was enacted, we have worked to create a long-term strategy for its implementation. With the Supreme Court's decision in 2012 to uphold HCR's individual mandate, the implementation of this strategy continues. Our focus is on continued compliance with the law's many mandates, avoidance or reduction of adverse tax impacts, and cost management.
Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act)
The Dodd-Frank Act was signed into law in July 2010. Significant rulings essential to its framework are now becoming effective for certain companies. Since some of these final rules are being challenged in court, it is difficult to predict how they will ultimately affect us. Certain provisions of the Dodd-Frank Act relating to derivatives could increase capital and/or collateral requirements. We continue to monitor developments related to this act and their potential impacts on our future financial results. At this time, we are making the necessary system and process changes to comply with the known rules.
Federal Tax Law Changes
In January 2013, President Obama signed into law the American Taxpayer Relief Act of 2012. This act extends 50% bonus tax depreciation through 2013 for most capital expenditures. This bonus tax depreciation extension is anticipated to generate future cash flows in excess of approximately $29 million through 2015.
In December 2011, the National Defense Authorization Act (NDAA) was enacted. The most relevant provision of the NDAA was to retroactively eliminate the application of the tax normalization rule for cash grants taken by a regulated utility in lieu of investment tax credits or production tax credits. Prior to the enactment of NDAA, a regulated utility was required to amortize the grant in rates over the life of the renewable energy generating plant. Further, the allowed rate base on the generating plant could not be reduced by the unamortized grant balance during the life of the plant. In 2012, we elected to claim and subsequently received a $69.0 million Section 1603 Grant for our Crane Creek Wind Project in lieu of the production tax credit. The cost of eliminating the prior production tax credit was recorded as a regulatory asset at December 31, 2012. Therefore, we do not anticipate a significant financial impact as a result of this change.
OFF BALANCE SHEET ARRANGEMENTS
See Note 13, "Guarantees," for information regarding guarantees.
CRITICAL ACCOUNTING POLICIES
We have determined that the following accounting policies are critical to the understanding of our financial statements because their application requires significant judgment and reliance on estimations of matters that are inherently uncertain. Our management has discussed these critical accounting policies with the Audit Committee of the Board of Directors of Integrys Energy Group.
Goodwill Impairment
We completed our annual goodwill impairment test as of April 1, 2012. No impairment was recorded as a result of this test. The fair value calculated in step one of the test exceeded the carrying value by a substantial amount. The fair value was calculated using an equal weighting of the income approach and the market approach.
For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the fair value of a reporting unit. A fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair value to decrease.
Key assumptions used in the income approach included return on equity (ROE), long-term growth rates used to determine terminal values at the end of the discrete forecast period, and discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is determined based on the weighted-average cost of capital, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE is based on our current allowed ROE adjusted for forecasted disallowed costs and expectations regarding the direction and magnitude of movements in interest rates. The terminal growth rate is based on a combination of historical and forecasted statistics for real gross domestic product and personal income.
We used the guideline company method for the market approach. This method uses metrics from similar publicly traded companies in the same industry to determine how much a knowledgeable investor in the marketplace would be willing to pay for an investment in a similar company. We applied multiples derived from these guideline companies to the appropriate operating metric to determine an indication of fair value.
The underlying assumptions and estimates used in the impairment test are made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the test.
Accrued Unbilled Revenues
We accrue estimated amounts of revenues for services provided or energy delivered but not yet billed to customers. Estimated unbilled revenues are calculated using a variety of judgments and assumptions related to customer class, contracted rates, weather, and customer use. Significant changes in these judgments and assumptions could have a material impact on our results of operations. At December 31, 2012, and 2011, our unbilled revenues were $70.5 million and $68.2 million, respectively. The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer use patterns, commodity prices, and customer mix.
Pension and Other Postretirement Benefits
The costs of providing noncontributory defined benefit pension benefits and other postretirement benefits, described in Note 14, "Employee Benefit Plans," are dependent on numerous factors resulting from actual plan experience and assumptions regarding future experience.
Pension and other postretirement benefit costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and other postretirement benefit costs may be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and other postretirement benefit costs.
Pension and other postretirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. Management believes that such changes in costs would be recovered/refunded through the ratemaking process.
The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
The following table shows how a given change in certain actuarial assumptions would impact the accumulated other postretirement benefit obligation and the reported net periodic other postretirement benefit cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
The discount rates are selected based on hypothetical bond portfolios consisting of noncallable (or callable with make-whole provisions), noncollateralized, high-quality corporate bonds with maturities between 0 and 30 years. The bonds are generally rated "Aa" with a minimum amount outstanding of $50 million. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.
We establish our expected return on asset assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return was 8.25% in both 2012 and 2011, and 8.50% in 2010. For 2012, 2011, and 2010, the actual rates of return on pension plan assets, net of fees, were 14.4%, 1.4%, and 13.1%, respectively. . Beginning in 2013, the expected return on assets assumption for the plans is 8.00%.
The determination of expected return on qualified plan assets is based on a market-related valuation of assets, which reduces year-to-year volatility. Cumulative gains and losses in excess of 10% of the greater of the pension or other postretirement benefit obligation or market-related value are amortized over the average remaining future service period. In computing the expected return on plan assets, a market-related value of plan assets is used that recognizes changes in realized and unrealized investment gains and losses over the subsequent five years for plans sponsored by us, while the Integrys Energy Group Retirement Plan, sponsored by IBS, recognizes differences between actual investment returns and the expected return on plan assets over a five-year period. Because of this method, the future value of assets will be impacted as previously deferred gains or losses are included in market-related value.
In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for pension and other postretirement benefits, see Note 14, "Employee Benefit Plans."
Regulatory Accounting
Our electric and natural gas utility segments follow the guidance under the Regulated Operations Topic of the FASB ASC. Our financial statements reflect the effects of the ratemaking principles followed by the various jurisdictions regulating these segments. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured, and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery period. If recovery or refund of costs is not approved or is no longer deemed probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings at the natural gas and electric utility segments, and the status of any pending or potential deregulation legislation.
The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our electric and natural gas utility segment's operations no longer meet the criteria for application. Assets and liabilities recognized as a result of rate regulation would be written off as extraordinary items in income for the period in which the discontinuation occurred. A write-off of all our regulatory assets and regulatory liabilities at December 31, 2012, would result in a 16.0% decrease in total assets and a 13.1% decrease in total liabilities. The largest regulatory asset at December 31, 2012, related to unrecognized pension and other postretirement benefit costs. A write-off of that regulatory asset at December 31, 2012, would result in a 9.8% decrease in total assets. See Note 6, "Regulatory Assets and Liabilities," for more information.
Income Tax Provision
We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to the provision for income taxes in the income statements.
Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.
Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(p) "Income Taxes," and Note 11, "Income Taxes," for a discussion of accounting for income taxes.
IMPACT OF INFLATION
Our financial statements are prepared in accordance with GAAP. The statements provide a reasonable, objective, and quantifiable statement of financial results, but generally do not evaluate the impact of inflation. To the extent we are not recovering the effects of inflation, we will file rate cases as necessary in the various jurisdictions in which we operate.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We have potential market risk exposure related to commodity price risk, interest rate risk, and equity return and principal preservation risk. We have risk management policies in place to monitor and assist in controlling these risks, and we use derivative and other instruments to manage some of these exposures, as further described below.
Commodity Price Risk
Prudent fuel and purchased power costs and capacity payments are recovered from customers under one-for-one recovery mechanisms by the wholesale electric operations and Michigan retail electric operations. Prudently incurred costs of natural gas used by the natural gas operations are also recovered from customers under one-for-one recovery mechanisms. These recovery mechanisms greatly reduce commodity price risk for the utilities.
Our Wisconsin retail electric operations do not have a one-for-one recovery mechanism for price fluctuations. Instead, a "fuel window" mechanism substantially mitigates this price risk.
To manage commodity price risk for our customers, we enter into fixed-price contracts of various durations for the purchase and/or sale of natural gas, fuel for electric generation, and electricity. Pursuant to the risk plans approved by the PSCW, we also use risk management techniques which include derivative instruments such as futures and options.
See Note 1(f), "Summary of Significant Accounting Policies - Revenues and Customer Receivables," for more information.
Interest Rate Risk
We are exposed to interest rate risk resulting from our short-term commercial paper borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt.
Based on our variable rate debt outstanding at December 31, 2012, a hypothetical increase in interest rates of 100 basis points would have increased annual interest expense by $1.0 million. Comparatively, based on the variable rate debt outstanding at December 31, 2011, an increase in interest rates of 100 basis points would have increased interest expense by $1.7 million. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.
Equity Return and Principal Preservation Risk
We currently fund liabilities related to employee benefits through various external trust funds. The trust funds are managed by numerous investment managers and hold investments in debt and equity securities. Changes in the market value of these investments can have an impact on the future expenses related to these liabilities. Declines in the equity markets or declines in interest rates may result in increased future costs for the plans and require additional contributions into the plans. We monitor the trust fund portfolio by benchmarking the performance of the investments against certain security indices. The employee benefit costs are recovered in customers' rates, reducing the equity return and principal preservation risk on these exposures. Also, the likelihood of an increase in the employee benefit obligations, which the investments must fund, has been partially mitigated as a result of certain employee groups no longer being eligible to participate in, or accumulate benefits in, certain pension and other postretirement benefit plans. Our defined benefit pension plans are closed to all new hires.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our control systems were designed to provide reasonable assurance to our management and the Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this assessment, management believes that, as of December 31, 2012, our internal control over financial reporting is effective.
B. CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes to the consolidated financial statements are an integral part of these statements.
C. CONSOLIDATED BALANCE SHEETS
The accompanying notes to the consolidated financial statements are an integral part of these statements.
D. CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying notes to the consolidated financial statements are an integral part of these statements.
E. CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
The accompanying notes to the consolidated financial statements are an integral part of these statements.
F. CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes to the consolidated financial statements are an integral part of these statements.
G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Nature of Operations-We are a regulated electric and natural gas utility company, serving customers in northeastern Wisconsin and an adjacent portion of Michigan's Upper Peninsula. We are subject to the jurisdiction of, and regulation by, the PSCW and the MPSC, which have general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin and Michigan, respectively. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates.
As used in these notes, the term “financial statements” refers to the consolidated financial statements. This includes the consolidated statements of income, consolidated balance sheets, consolidated statements of capitalization, consolidated statements of common shareholder's equity, and consolidated statements of cash flows, unless otherwise noted.
The term "utility" refers to our regulated activities, while the term "nonutility" refers to our activities that are not regulated, as well as the activities of our subsidiary.
(b) Consolidated Basis of Presentation-At December 31, 2012, we had one wholly owned subsidiary, WPS Leasing. The financial statements include our accounts and the accounts of our wholly owned subsidiary, after eliminating intercompany transactions and balances. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in businesses not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.
(c) Reclassifications-We adjusted changes in working capital on the statements of cash flows by reclassifying $(6.2) million and $(0.7) million related to materials and supplies at December 31, 2011, and 2010, respectively, from the change in other current assets line item to the change in inventories line item to be consistent with the current year presentation. This reclassification had no impact on total cash flows from operating activities.
(d) Use of Estimates-We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect assets, liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
(e) Cash and Cash Equivalents-Short-term investments with an original maturity of three months or less are reported as cash equivalents.
The following is a supplemental disclosure to our statements of cash flows:
Construction costs funded through accounts payable totaled $24.8 million, $11.3 million, and $5.7 million at December 31, 2012, 2011, and 2010, respectively. These costs were treated as noncash investing activities.
(f) Revenues and Customer Receivables-Revenues related to the sale of energy are recognized when service is provided or energy is delivered to customers. We also accrue estimated amounts of revenues for services provided or energy delivered but not yet billed to customers. Estimated unbilled revenues are calculated using a variety of judgments and assumptions related to customer class, contracted rates, weather, and customer use. At December 31, 2012, and 2011, our unbilled revenues were $70.5 million and $68.2 million, respectively.
At December 31, 2012, there were no customers that accounted for more than 10% of our revenues. However, wholesale sales to other utilities accounted for approximately 13% of our operating revenues.
We present revenues net of pass-through taxes on the income statements.
We have various rate-adjustment mechanisms in place that allow subsequent adjustments to rates for changes in prudently incurred costs. A summary of significant rate-adjustment mechanisms follows:
•
Fuel and purchased power costs are recovered from customers on a one-for-one basis by our wholesale electric operations and Michigan retail electric operations.
•
Our Wisconsin retail electric operations use a "fuel window" mechanism to recover fuel and purchased power costs. Under the fuel window rule, a deferral is required for under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance
from the costs included in the rates charged to customers. Under or over-collections deferred in the current year are recovered or refunded in a future rate proceeding.
•
Our rates include a one-for-one recovery mechanism for natural gas commodity costs.
•
Our rates include a decoupling mechanism, which allows us to adjust our rates going forward to recover or refund differences between actual and authorized margin. See Note 21, "Regulatory Environment" for more information.
Revenues are also impacted by other accounting policies related to our participation in the MISO market. We both sell and purchase power in the MISO market. If we are a net seller in a particular hour, the net amount is reported as revenue. If we are a net purchaser in a particular hour, the net amount is recorded as cost of fuel, natural gas, and purchased power on the income statements.
(g) Inventories-Inventories consist of materials and supplies, natural gas in storage, and other fossil fuels, including coal. Average cost is used to value materials and supplies, fossil fuels, and natural gas in storage.
(h) Risk Management Activities-As part of our regular operations, we enter into contracts, including options, futures, forwards, and other contractual commitments, to manage changes in commodity prices, which are described more fully in Note 2, "Risk Management Activities." Derivative instruments are entered into in accordance with the terms of the risk management plans approved by our Board of Directors and the PSCW or MPSC.
All derivatives are recognized on the balance sheets at their fair value unless they are designated as and qualify for the normal purchases and sales exception. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Most of our energy-related physical and financial derivatives qualify for regulatory deferral. These derivatives are marked to fair value; the resulting risk management assets are offset with regulatory liabilities or decreases to regulatory assets, and risk management liabilities are offset with regulatory assets or decreases to regulatory liabilities. Management believes any gains or losses resulting from the eventual settlement of these derivative instruments will be refunded to or collected from customers in rates.
We classify unrealized gains and losses on derivative instruments that do not qualify for regulatory deferral as a component of natural gas purchased for resale or operating and maintenance expense, depending on the nature of the transaction.
Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On the balance sheets, cash collateral provided to others is reflected in other current assets.
We have risk management contracts with various counterparties. We monitor credit exposure levels and the financial condition of our counterparties on a continuous basis to minimize credit risk. At December 31, 2012, we did not have risk management contracts with any one counterparty or industry that accounted for more than 10% of our total credit risk exposure.
(i) Emission Allowances-We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. Gains on sales of allowances are returned to ratepayers. Losses on emission allowances are included in the costs subject to the fuel window rules.
(j) Property, Plant, and Equipment-Utility plant is stated at cost, including any associated AFUDC and asset retirement costs. The costs of renewals and betterments of units of property (as distinguished from minor items of property) are capitalized as additions to the utility plant accounts. Maintenance, repair, replacement, and renewal costs associated with items not qualifying as units of property are considered operating expenses. We record a regulatory liability for cost of removal accruals, which are included in rates. Actual removal costs are charged against the regulatory liability as incurred. Except for land, no gains or losses are recognized in connection with ordinary retirements of utility property units. We charge the cost of units of property retired, sold, or otherwise disposed of, less salvage value, to accumulated depreciation.
We record straight-line depreciation expense over the estimated useful life of utility property, using depreciation rates as approved by the applicable regulators. Annual utility composite depreciation rates are shown below. We received approval from the PSCW for lower depreciation rates, effective January 1, 2011.
We capitalize certain costs related to software developed or obtained for internal use and amortize those costs to operating expense over the estimated useful life of the related software, which ranges from 3 to 5 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statements.
See Note 4, "Property, Plant, and Equipment," for details regarding our property, plant, and equipment balances.
(k) AFUDC-We capitalize the cost of funds used for construction using a calculation that includes both internal equity and external debt components, as required by regulatory accounting. The internal equity component is accounted for as other income. The external debt component is accounted for as a decrease to interest expense.
Approximately 50% of our retail jurisdictional construction work in progress expenditures are subject to the AFUDC calculation. For 2012, our average AFUDC retail rate was 7.71%, and our average AFUDC wholesale rate was 0.27%.
Our total AFUDC was as follows for the years ended December 31:
(l) Regulatory Assets and Liabilities-Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts collected in rates for future costs. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the year the determination is made. See Note 6, "Regulatory Assets and Liabilities," for more information.
(m) Goodwill-Goodwill is not amortized, but is subject to an annual impairment test. Our natural gas utility reporting unit contains goodwill and performs its annual goodwill impairment test during the second quarter of each year. Interim impairment tests are performed when impairment indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value.
(n) Retirement of Debt-Any call premiums or unamortized expenses associated with refinancing utility debt obligations are amortized consistent with regulatory treatment of those items. Any gains or losses resulting from the retirement of utility debt that is not refinanced are either amortized over the remaining life of the original debt or recorded through current earnings.
(o) Asset Retirement Obligations-We recognize at fair value legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development, and/or normal operation of the assets. A liability is recorded for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The asset retirement obligations are accreted using a credit-adjusted risk-free interest rate commensurate with the expected settlement dates of the asset retirement obligations; this rate is determined at the date the obligation is incurred. The associated retirement costs are capitalized as part of the related long-lived assets and are depreciated over the useful lives of the assets. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease in the carrying amount of the liability and the associated retirement cost. See Note 10, "Asset Retirement Obligations," for more information.
(p) Income Taxes-We and our subsidiary are included in the consolidated United States income tax return filed by Integrys Energy Group. We and our subsidiary are parties to a federal and state tax allocation arrangement with Integrys Energy Group and its subsidiaries under which each entity determines its provision for income taxes on a stand-alone basis. We settle the intercompany liabilities at the time that payments are made to the applicable taxing authority. See Note 23, "Related Party Transactions," for disclosure of intercompany payables or receivables related to income taxes.
Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. We defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.
We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. Prior to 2012, we earned production tax credits (PTCs) on certain qualifying facilities. PTCs generally reduce the provision for income taxes in the year that electricity from the qualifying facility is generated and sold. ITCs and PTCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.
In 2012, we elected to claim and subsequently received a Section 1603 Grant for our Crane Creek Wind Project in lieu of the PTCs. The grant proceeds reduced the depreciable basis of the qualifying facility and will be reflected in income over a 12-year period through a reduction of depreciation and amortization expense. As a result, we no longer claim PTCs on any of our qualifying facilities.
We report interest and penalties accrued related to income taxes as a component of provision for income taxes in the income statements, as well as regulatory assets or regulatory liabilities in the balance sheets.
We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards.
For more information regarding our accounting for income taxes, see Note 11, "Income Taxes."
(q) Guarantees-We follow the guidance of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. For additional information on guarantees, see Note 13, "Guarantees."
(r) Employee Benefits-The costs of pension and other postretirement benefits are expensed over the periods during which employees render service. Our transition obligation related to the other postretirement benefit plans was recognized over a 20-year period that began in 1993, and ended in 2012. In computing the expected return on plan assets, we use a market-related value of plan assets. Changes in realized and unrealized investment gains and losses are recognized over the subsequent five years for plans we sponsor, while differences between actual investment returns and the expected return on plan assets are recognized over a five-year period for the Integrys Energy Group Retirement Plan, sponsored by IBS. The benefit costs associated with employee benefit plans are allocated among Integrys Energy Group's subsidiaries based on employees' time reporting and actuarial calculations, as applicable. Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP.
We recognize the funded status of defined benefit postretirement plans on the balance sheet, and recognize changes in the plans' funded status in the year in which the changes occur. We record changes in the funded status to regulatory asset or liability accounts, pursuant to the Regulated Operations Topic of the FASB ASC.
We account for our participation in benefit plans sponsored by IBS and other postretirement benefit plans we sponsor as multiple employer plans. Under affiliate agreements, we are responsible for our share of plan costs and obligations and are entitled to our share of plan assets; accordingly, we account for our pro rata share of these plans as our own plan.
For more information on our employee benefits, see Note 14, "Employee Benefit Plans."
(s) Fair Value-A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities.
Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methodologies.
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
We determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs where observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.
We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.
We have established a risk oversight committee whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from the trading function. To validate
the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.
See Note 19, "Fair Value," for more information.
(t) New Accounting Pronouncements-
Recent Accounting Guidance Not Yet Effective
Accounting Standards Update (ASU) 2013-02, "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," was issued in February 2013. This guidance requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. Significant amounts are required to be presented by the respective line items of net income or should be cross-referenced to other disclosures. These disclosures may be presented on the income statement or in the notes to the financial statements. This guidance is effective prospectively for reporting periods beginning after December 15, 2012. Adoption of this guidance will result in new disclosures in a footnote for the reporting period ending March 31, 2013.
ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities," was issued in December 2011. The guidance requires enhanced disclosures about offsetting and related arrangements. ASU 2013-01, "Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities," was issued in January 2013. This guidance clarifies that the scope of ASU 2011-11 applies to certain derivatives included in the Derivatives and Hedging Topic of the FASB ASC. The guidance for both of these updates is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. Adoption of the guidance will result in new disclosures in Note 2, "Risk Management Activities," for the reporting period ending March 31, 2013.
ASU 2012-02, "Testing Indefinite-Lived Intangible Assets for Impairment," was issued in July 2012. This guidance gives companies an option to first perform a qualitative assessment to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. If a company concludes that this is the case, the fair value of the indefinite-lived intangible asset must be determined, and a quantitative impairment test is required. Otherwise, a company can bypass the quantitative impairment test. This guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Adoption of the guidance is not expected to have a significant impact on our financial statements.
NOTE 2-RISK MANAGEMENT ACTIVITIES
We use derivative instruments to manage commodity costs. None of these derivatives are designated as hedges for accounting purposes. The derivatives include physical commodity contracts and NYMEX futures and options used by both the electric and natural gas utility segments to manage the risks associated with the market price volatility of natural gas costs and the costs of gasoline and diesel fuel used by our utility vehicles. The electric utility segment also uses financial transmission rights (FTRs) to manage electric transmission congestion costs and NYMEX oil futures and options to reduce price risk related to coal transportation.
The following tables show our assets and liabilities from risk management activities:
*
We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
*
We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.
The following table shows the unrealized gains (losses) recorded related to our derivatives:
We had the following notional volumes of outstanding derivative contracts:
The following table shows our cash collateral positions:
NOTE 3-AGREEMENT TO PURCHASE FOX ENERGY CENTER
In September 2012, we entered into an agreement to acquire all of the equity interests in Fox Energy Company LLC. The purchase includes the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. We currently supply natural gas for the facility and purchase 500 megawatts of capacity and the associated energy output under a tolling arrangement.
We will pay $390.0 million to purchase Fox Energy Company LLC, subject to post-closing adjustments, primarily related to working capital. In addition, we will pay $50.0 million to terminate the existing tolling arrangement immediately prior to the acquisition of the facility. The purchase will be financed initially with a combination of short-term debt, cash flow from operations, and an infusion of equity from our parent company. The short-term debt will be replaced later in 2013 with long-term financing.
Fox Energy Center is a dual-fuel facility, equipped to use fuel oil but expected to run primarily on natural gas. This plant will give us a more balanced mix of electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources.
We received all of the necessary regulatory approvals for this transaction, which is expected to close by the end of March 2013.
NOTE 4-PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following utility and nonutility assets at December 31:
NOTE 5-JOINTLY OWNED UTILITY FACILITIES
We hold a joint ownership interest in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We also pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities on the balance sheets. The amounts were as follows at December 31, 2012:
Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. We have supplied our own financing for all jointly owned projects.
NOTE 6-REGULATORY ASSETS AND LIABILITIES
We expect to recover our regulatory assets and incur future costs or refund our regulatory liabilities through rates charged to customers. Recovery or refund is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets described below.
The following regulatory assets and liabilities were reflected on our balance sheets as of December 31:
(1)
Represents the unrecognized future pension and postretirement costs resulting from actuarial gains and losses on defined benefit and postretirement plans. We are authorized recovery of this regulatory asset over the average future remaining service life of the plans.
(2)
As of December 31, 2012, we had not yet made cash expenditures for $68.8 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.
(3)
In 2012, we elected to claim and subsequently received a Section 1603 grant for our Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12-year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits, partially offset by a regulatory liability related to a portion of the book depreciation taken in prior years. We are authorized recovery of this net regulatory asset through 2039.
(4)
Prior to us purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with the De Pere Energy Center that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023.
(5)
In 2007, a lightning strike caused significant damage to the Weston 3 generating facility. The PSCW approved the deferral of the incremental fuel and purchased power expenses, as well as the nonfuel operating and maintenance expenditures incurred as a result of the outage that were not covered by insurance. We are authorized recovery of this regulatory asset through 2014.
(6)
Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.
(7)
Represents the over-collection of energy costs that will be refunded to customers in the future.
(8)
Not earning a return.
NOTE 7-LEASES
We lease various property, plant, and equipment. Terms of the operating leases vary, but generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value or (b) exercise a renewal option, as set forth in the lease agreement. Rental expense attributable to operating leases was $2.4 million, $2.7 million, and $4.3 million in 2012, 2011, and 2010, respectively. Future minimum rental obligations under noncancelable operating leases are payable as follows:
NOTE 8-SHORT-TERM DEBT AND LINES OF CREDIT
Our outstanding short-term borrowings were as follows as of December 31:
The commercial paper outstanding at December 31, 2012, had maturity dates ranging from January 2, 2013, through January 4, 2013.
The table below presents our average amount of short-term borrowings based on daily outstanding balances during the years ended December 31:
We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities, as of December 31:
(1)
This credit facility was terminated in June 2012.
(2)
This facility will automatically extend through June 13, 2017, upon PSCW approval, which is expected prior to June 13, 2013.
In connection with the pending purchase of Fox Energy Company LLC, we requested approval from the PSCW to temporarily increase our short-term debt limit. See Note 3, “Agreement to Purchase Fox Energy Center,” for more information regarding this pending purchase.
Our revolving credit agreement contains financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%, excluding nonrecourse debt. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations. At December 31, 2012, we were in compliance with all covenants related to outstanding short-term debt.
NOTE 9-LONG-TERM DEBT
See our statements of capitalization for details on our long-term debt.
In December 2012, our $150.0 million of 4.875% Senior Notes matured, and the outstanding principal balance was repaid. In the same month, we issued $300.0 million of 3.671% Senior Notes. These notes are due in December 2042.
In February 2013, our 3.95% Senior Notes matured, and the outstanding principal balance was repaid. As a result, the $22.0 million balance of these notes was included in the current portion of long-term debt on our December 31, 2012, balance sheet. In December 2013, our 4.80% Senior Notes will mature. As a result, the $125.0 million balance of these notes was included in the current portion of long-term debt on our December 31, 2012, balance sheet.
Our First Mortgage Bonds and Senior Notes are subject to the terms and conditions of our First Mortgage Indenture. Under the terms of the Indenture, substantially all our property is pledged as collateral for these outstanding debt securities. All of these debt securities require semi-annual payments of interest. Our Senior Notes become noncollateralized if we retire all of our outstanding First Mortgage Bonds and no new mortgage indenture is put in place.
Our long-term debt obligations contain covenants related to payment of principal and interest when due and various financial reporting obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations. At December 31, 2012, we were in compliance with all covenants related to outstanding long-term debt.
A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to parent, is as follows:
NOTE 10-ASSET RETIREMENT OBLIGATIONS
We have asset retirement obligations primarily related to asbestos abatement at certain generation facilities, office buildings, and service centers; dismantling wind generation projects; disposal of PCB-contaminated transformers; and closure of fly-ash landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the asset retirement obligation accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. All asset retirement obligations are recorded as other long-term liabilities on our balance sheets.
The following table shows changes to our asset retirement obligations through December 31, 2012:
*
Revisions were made to estimated cash flows related to asset retirement obligations for the PCB transformers primarily due to changes in estimated removal costs, estimated settlement date, and transformer quantities.
NOTE 11-INCOME TAXES
Deferred Income Tax Assets and Liabilities
The principal components of deferred income tax assets and liabilities recognized on the balance sheets as of December 31 are included in the table below. Certain temporary differences are netted in the table when the offsetting amount is recorded as a regulatory asset or liability. This is consistent with regulatory treatment.
Net deferred income tax liabilities increased $60.0 million in 2012. The net increase was driven by an increase in capital expenditures and 50% bonus tax depreciation available in 2012. Deferred income tax liabilities also increased due to our election in 2012 to claim a Section 1603 Grant for our Crane Creek Wind Project in lieu of the production tax credit. See Note 1(p), "Income Taxes," for more information. An increase in tax deductions resulting from incremental contributions to our various employee benefit plans also contributed to the increase in net deferred income tax liabilities.
Deferred tax credit carryforwards at December 31, 2012, included $1.4 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $0.5 million of general business credits, which have a carryback period of 1 year and a carryforward period of 20 years. The majority of the general business credit carryforwards will expire in 2029.
Regulated utilities record certain adjustments related to deferred income taxes to regulatory assets and liabilities. As the related temporary differences reverse, we prospectively refund taxes to or collect taxes from customers related to both deferred taxes recorded in prior years at rates potentially different than current rates and when there are other changes in tax laws. The net regulatory assets for these and other regulatory tax effects totaled $17.4 million and $5.4 million at December 31, 2012, and 2011, respectively. See Note 6, "Regulatory Assets and Liabilities," for more information.
Income Before Taxes
All income before taxes is domestic income for the years ended December 31, 2012, 2011, and 2010.
Provision for Income Tax Expense
The components of the provision for income taxes were as follows:
Statutory Rate Reconciliation
The following table presents a reconciliation of the difference between the effective tax rate and the amount computed by applying the statutory federal tax rate to income before taxes.
Unrecognized Tax Benefits
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
We had accrued interest of $0.1 million and no accrued penalties related to unrecognized tax benefits at December 31, 2012. We had accrued interest of $0.2 million and no accrued penalties related to unrecognized tax benefits at December 31, 2011.
We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2012.
We file income tax returns in the United States federal jurisdiction and in our major state operating jurisdictions on a stand-alone basis or as part of Integrys Energy Group filings.
We are no longer subject to income tax examinations by the IRS for years prior to 2009. We have IRS examinations open for tax years 2009 and 2010, which began in 2011.
We file state tax returns based on income in our major state operating jurisdictions of Wisconsin and Michigan. With a few exceptions, we are no longer subject to state and local tax examinations for years prior to 2008. As of December 31, 2012, we were subject to examination by the Wisconsin and Michigan taxing authorities for the 2008 through 2011 tax years. During 2012, the Michigan taxing authority commenced an examination of tax years 2008 through 2010.
In the next 12 months, it is reasonably possible that we will settle open examinations in taxing jurisdictions related to tax years prior to 2011, resulting in a decrease in unrecognized tax benefits of as much as $0.3 million.
NOTE 12-COMMITMENTS AND CONTINGENCIES
(a) Unconditional Purchase Obligations and Purchase Order Commitments
We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2012.
We also had commitments of $317.9 million in the form of purchase orders issued to various vendors at December 31, 2012, that relate to normal business operations, including construction projects.
(b) Environmental Matters
Air Permitting Violation Claims
Weston and Pulliam Clean Air Act (CAA) Issues:
In November 2009, the EPA issued us a Notice of Violation (NOV) alleging violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. We reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree, which was filed in the U.S. District Court (Court) on January 4, 2013. The Consent Decree includes:
•
the installation of emission control technology, including ReAct ™ or an approved alternative, on Weston 3,
•
changed operating conditions (including refueling, repowering, and/or retirement of units),
•
limitations on plant emissions,
•
beneficial environmental projects totaling $6.0 million (various options, including capital projects, are available), and
•
a civil penalty of $1.2 million.
The Court must review public comments filed by the Sierra Club and Clean Wisconsin before approving the Consent Decree. The final terms of the Consent Decree may be different than currently anticipated.
As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. As of December 31, 2012, no decision had been made on how to address this requirement. Therefore, retirement of the Weston and Pulliam units mentioned in the Consent Decree was not considered probable.
Any costs prudently incurred as a result of actions taken due to the Consent Decree, with the exception of the civil penalty, are expected to be recoverable from customers.
In May 2010, we received from the Sierra Club a Notice of Intent (NOI) to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but further action by the Sierra Club is unknown at this time.
Columbia and Edgewater CAA Issues:
In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants (including us). The NOV alleges violations of the CAA's New Source Review requirements related to certain projects completed at those plants.
In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Edgewater plant did not comply with the CAA. The case was stayed until July 2012, and a request was made by WP&L to further extend the stay and all deadlines. An update was filed with the Court in August 2012, regarding the settlement negotiations with the Sierra Club, the EPA, and the joint owners of the Edgewater plant.
WP&L, Madison Gas and Electric, and we (Joint Owners), along with the EPA and the Sierra Club (collectively, the Parties), are exploring settlement options. The Joint Owners believe that the Parties have reached an agreement with the EPA and the Sierra Club on general terms to settle these air permitting violation claims and are negotiating a consent decree based upon those general terms, which are subject to change during the negotiations. Based upon the status of the current negotiations and a review of existing EPA consent decrees, we anticipate that the final consent decree could include the installation of emission control technology, changed operating conditions (including fuels other than coal and retirement of units), limitations on emissions, beneficial environmental projects, and a civil penalty. Once the Parties agree to the final terms, the Court must approve the consent decree after a public comment process.
We cannot predict the final outcome of this matter because the Parties may be unable to reach a final agreement on the consent decree, the final terms of the consent decree may be different than currently anticipated, or interveners could convince the Court to disapprove some or all of the terms of the consent decree during the public comment process.
Any costs prudently incurred as a result of actions taken due to the consent decree, with the exception of civil fines, are expected to be recoverable from customers. We are currently unable to estimate the possible loss or range of loss related to this matter.
Weston Title V Air Permit:
In November 2010, the WDNR provided a draft revised permit for the Weston 4 plant. We objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR and met with the WDNR to resolve these issues. In September 2011, the WDNR issued an updated draft revised permit and a request for public comments. Due to the significance of the changes to the draft revised permit, the WDNR re-issued the draft revised permit for additional comments on February 4, 2013. In July 2012, Clean Wisconsin filed suit against the WDNR alleging failure to issue or delay in issuing the Weston 4 Title V permit. We are not a party to this litigation, but we filed a request for intervention to protect our interests. The motions for intervention and dismissal filed by us and the WDNR were granted on February 15, 2013. Clean Wisconsin has the right to appeal this decision. We do not expect this matter to have a material impact on our financial statements.
Pulliam Title V Air Permit:
The WDNR issued a renewal of the permit for the Pulliam plant in April 2009. In June 2010, the EPA issued an order directing the WDNR to respond to comments raised by the Sierra Club in its June 2009 Petition requesting the EPA to object to the permit.
In April 2011, we received notification that the Sierra Club filed a civil lawsuit against the EPA based on what the Sierra Club alleged to be an unreasonable delay in responding to the June 2010 order. We are not a party to this litigation, but intervened to protect our interests. In February 2012, the WDNR sent a proposed permit and response to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has been approved by the Court.
In May 2012, the Sierra Club filed another Petition requesting the EPA to again object to the proposed permit and response, which the EPA denied on January 7, 2013. The Sierra Club also recently filed a request for a contested case proceeding regarding the permit, which was granted in part by the WDNR. A schedule has not yet been set for the contested case proceeding.
We are reviewing all of these matters, but we do not expect them to have a material impact on our financial statements.
Columbia Title V Air Permit:
In February 2011, the Sierra Club filed a lawsuit against the EPA seeking to have the EPA take over the Title V permit process for the Columbia plant. The Sierra Club alleges the EPA must now act on the reconsideration of the Title V permit since the WDNR has exceeded its timeframe in which to respond to an EPA order issued in 2009. In May 2011, the WDNR issued a revised draft Title V permit in response to the EPA's order.
In June 2012, WP&L received notice from the EPA of the EPA's proposal for WP&L to apply for a federally-issued Title V permit since the WDNR has not addressed the EPA's objections to the Title V permit issued for the Columbia plant. WP&L has until March 15, 2013, to comment on the EPA's proposal. If the EPA decides to require the submittal of an operation permit application, it would be due within six months of the EPA's notice to WP&L. WP&L believes the previously issued Title V permit for the Columbia plant is still valid. We do not expect this matter to have a material impact on our financial statements.
WDNR Issued NOVs:
Since 2008, we received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant; and Weston 1, Weston 2, and Weston 4 individually. We also received an NOV for a clerical error involving pages missing from a quarterly report for Weston. Corrective actions have been taken for the events in the five NOVs. In December 2011, the WDNR referred several of the claims in the NOVs to the state Justice Department for enforcement. We and the Justice Department began discussing the pending NOVs and their resolution in late 2012. We do not expect this matter to have a material impact on our financial statements.
Weston 4 Construction Permit
From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant. In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible
emissions limits. In July 2010, we, the WDNR, and the Sierra Club filed Petitions for Review with the Wisconsin Supreme Court. In March 2011, the Wisconsin Supreme Court denied all Petitions for Review. Other than the specific visible emissions limits issue, all other challenges to the construction permit are now resolved. We are working with the WDNR to resolve this issue as part of the current construction permit renewal process. We do not expect this matter to have a material impact on our financial statements.
Mercury and Interstate Air Quality Rules
Mercury:
The State of Wisconsin's mercury rule requires a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90% from the historical baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts, but less than 150 megawatts, must reduce their mercury emissions to a level defined by the Best Available Control Technology rule. As of December 31, 2012, we estimate capital costs of approximately $2 million, which includes estimates for both wholly owned and jointly owned plants, to achieve the required reductions. The capital costs are expected to be recovered in future rates.
In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. The State of Wisconsin is assessing how its current mercury rule will be impacted by the MATS rule. We are currently evaluating options for achieving the emission limits specified in this rule, but we do not anticipate the cost of compliance to be significant. We expect to recover future compliance costs in future rates.
Sulfur Dioxide and Nitrogen Oxide:
In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including us, challenged in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective January 1, 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. In October 2012, the EPA and several other parties filed petitions for a rehearing of the D.C. Circuit's decision, which the D.C. Circuit denied on January 24, 2013.
Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART) and the EPA has not revised it to reflect the reinstatement of CAIR. Although particulate emissions also contribute to visibility impairment, the WDNR's modeling has shown the impairment to be so insignificant that additional capital expenditures on controls are not warranted.
Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether we will have to purchase additional emission allowances, idle or abandon certain units, or change how certain units are operated. We expect to recover any future compliance costs in future rates.
Manufactured Gas Plant Remediation
We operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, we are required to undertake remedial action with respect to some of these materials. We are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a "multi-site" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.
We are responsible for the environmental remediation of ten sites, of which seven have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA's program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. As of December 31, 2012, we estimated and accrued for $68.8 million of future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of December 31, 2012, cash expenditures for environmental remediation not yet recovered in rates were $14.2 million. We recorded a regulatory asset of $83.0 million at December 31, 2012, which is net of insurance recoveries received of $22.3 million, related to the expected recovery through rates of both cash expenditures and estimated future expenditures. Under current PSCW policies, we may not recover carrying costs associated with the cleanup expenditures.
Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the PSCW or the MPSC with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.
NOTE 13-GUARANTEES
The following table shows our outstanding guarantees:
(1)
At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts are not reflected on our balance sheets.
(2)
Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.
(3)
Issued for workers compensation coverage in Wisconsin and Michigan. This amount is not reflected on our balance sheets.
NOTE 14-EMPLOYEE BENEFIT PLANS
Defined Benefit Plans
We participate in the Integrys Energy Group Retirement Plan, a noncontributory, qualified retirement plan sponsored by IBS. We are responsible for our share of the plan assets and obligations, and our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets. The defined benefit pension plans are closed to new hires.
In addition, Integrys Energy Group offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred.
We serve as plan sponsor and administrator for certain other postretirement benefit plans. We fund benefits for retirees through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets for these other postretirement benefit plans.
During 2012, $35.3 million of the pension obligation related to the unfunded nonqualified retirement plans were transferred to related parties. Therefore, our balance sheet at December 31, 2012, only reflects the pension liability associated with our past and current employees.
The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets during 2012 and 2011:
The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:
The accumulated benefit obligation for the defined benefit pension plans was $686.2 million and $643.1 million at December 31, 2012, and 2011, respectively. At December 31, 2012, the pension plan had plan assets in excess of the accumulated benefit obligation.
Information for pension plans with an accumulated benefit obligation in excess of plan assets is presented in the following table:
The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31:
The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2013:
The following table shows the components of our net periodic benefit costs (including amounts capitalized to our balance sheets) for the benefit plans:
*
The PSCW authorized recovery for net increased 2009 pension and other postretirement benefit costs related to plan asset losses that occurred in 2008. Amortization and recovery of these deferred costs occurred in 2010.
Assumptions - Pension and Other Postretirement Benefit Plans
The weighted-average assumptions used at December 31 to determine benefit obligations for the plans were as follows:
The weighted-average assumptions used to determine net periodic benefit cost for the plans were as follows for the years ended December 31:
We establish our expected return on assets assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. Beginning in 2013, the expected return on assets assumption for the plans is 8.00%.
Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2012, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:
Pension and Other Postretirement Benefit Plan Assets
Integrys Energy Group's investment policy includes various guidelines and procedures designed to ensure assets are invested in an appropriate manner to meet expected future benefits to be earned by participants. The investment guidelines consider a broad range of economic conditions. The policy is established and administered in a manner that is compliant at all times with applicable regulations.
Central to the policy are target allocation ranges by major asset categories. The objectives of the target allocations are to maintain investment portfolios that diversify risk through prudent asset allocation parameters and to achieve asset returns that meet or exceed the plans' actuarial assumptions and that are competitive with like instruments employing similar investment strategies. The portfolio diversification provides protection against significant concentrations of risk in the plan assets. The target asset allocations for pension and other postretirement benefit plans that have significant assets are: 70% equity securities and 30% fixed income securities. Equity securities primarily include investments in large-cap and small-cap companies. Fixed income securities primarily include corporate bonds of companies from diversified industries, United States government securities, and mortgage-backed securities.
The Board of Directors of Integrys Energy Group established the Employee Benefits Administrator Committee (composed of members of Integrys Energy Group and its subsidiaries' management) to manage the operations and administration of all its and its subsidiaries' benefit plans and trusts. The committee periodically reviews the asset allocation, and the portfolio is rebalanced when necessary.
Pension and other postretirement benefit plan investments are recorded at fair value. Information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used are discussed in Note 1(s), "Summary of Significant Accounting Policies - Fair Value."
The following table provides the fair values of our investments by asset class:
(1)
Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
(2)
Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.
(1)
Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
(2)
Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.
The following table sets forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 measurements:
Cash Flows Related to Pension and Other Postretirement Benefit Plans
Our funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. We expect to contribute $40.4 million to pension plans and $15.6 million to other postretirement benefit plans in 2013, dependent on various factors affecting us, including our liquidity position and tax law changes.
The following table shows the payments, reflecting expected future service, that we expect to make for pension and other postretirement benefits. In addition, the table shows the expected federal subsidies, provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which will partially offset other postretirement benefits.
Defined Contribution Benefit Plans
Integrys Energy Group maintains a 401(k) Savings Plan for substantially all of our full-time employees. A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution up to certain limits. Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan. Employees who are no longer eligible to participate in the defined benefit pension plan participate in a defined contribution pension plan, in which certain amounts are contributed to an employee's account based on the employee's wages, age, and years of service. Our share of the total costs incurred under these plans was $5.5 million in 2012, $5.0 million in 2011, and $4.7 million in 2010.
Integrys Energy Group maintains deferred compensation plans that enable certain key employees, including some who are our employees, to defer a portion of their compensation on a pre-tax basis. The deferred compensation arrangements for which distributions are made solely in Integrys Energy Group common stock are classified as an equity instrument on the balance sheets. Changes in the fair value of this portion of the deferred compensation obligation are not recognized. The deferred compensation obligation classified as an equity instrument was $8.1 million at December 31, 2012, and $8.2 million at December 31, 2011.
The portion of the deferred compensation obligation that is indexed to various investment options and allows for distributions in cash is classified as a liability on the balance sheets. The liability is adjusted, with a charge or credit to expense, to reflect changes in the fair value of the deferred compensation obligation. The obligation classified within other long-term liabilities was $14.9 million at December 31, 2012, and $15.5 million at December 31, 2011. The costs incurred under this arrangement were $1.1 million in 2012, $0.5 million in 2011, and $3.4 million in 2010.
NOTE 15-PREFERRED STOCK
We have 1,000,000 authorized shares of preferred stock with no mandatory redemption and a $100 par value. Outstanding shares were as follows at December 31:
All shares of preferred stock of all series are of equal rank except as to dividend rates and redemption terms. Payment of dividends from any earned surplus or other available surplus is not restricted by the terms of any indenture or other undertaking by us. Each series of outstanding preferred stock is redeemable in whole or in part at our option at any time on 30 days' notice at the respective redemption prices. We may not redeem less than all, nor purchase any, of our preferred stock during the existence of any dividend default.
In the event of our dissolution or liquidation, the holders of preferred stock are entitled to receive (a) the par value of their preferred stock out of the corporate assets other than profits before any of such assets are paid or distributed to the holders of common stock and (b) the amount of dividends accumulated and unpaid on their preferred stock out of the surplus or net profits before any of such surplus or net profits are paid to the holders of common stock. Thereafter, the remainder of the corporate assets, surplus, and net profits would be paid to the holders of common stock.
The preferred stock has no pre-emptive, subscription, or conversion rights, and has no sinking fund provisions.
NOTE 16-COMMON EQUITY
Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys Energy Group.
The PSCW allows us to pay dividends on our common stock of no more than 103% of the previous year's common stock dividend. We may return capital to Integrys Energy Group if our average financial common equity ratio is at least 51.01% on a calendar year basis. We must obtain PSCW approval if a return of capital would cause our average financial common equity ratio to fall below this level. Integrys Energy Group's right to receive dividends on our common stock is also subject to the prior rights of our preferred shareholders and to provisions in our restated articles of incorporation, which limit the amount of common stock dividends that we may pay if our common stock and common stock surplus accounts constitute less than 25% of our total capitalization.
Our short-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.
As of December 31, 2012, total restricted net assets were $1,134.9 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $27.7 million at December 31, 2012.
Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.
Integrys Energy Group may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW. Wisconsin law prohibits us from making loans to or guaranteeing obligations of Integrys Energy Group or its other subsidiaries. During the twelve months ended December 31, 2012, we paid common stock dividends of $105.5 million to Integrys Energy Group, returned $50.0 million of capital to Integrys Energy Group, and received $40.0 million of equity contributions from Integrys Energy Group.
NOTE 17-STOCK-BASED COMPENSATION
Our employees may be granted awards under Integrys Energy Group's stock-based compensation plans. At December 31, 2012, stock options, performance stock rights, and restricted share units were outstanding under various plans. Compensation cost associated with these awards is allocated to us based on the percentages used for allocation of the award recipients' labor costs.
The following table reflects the stock-based compensation expense and the related deferred tax benefit recognized in income for the years ended December 31:
No stock-based compensation cost was capitalized during 2012, 2011, and 2010.
Stock Options
All stock options granted to our employees are for the option to purchase shares of Integrys Energy Group common stock. Stock options have a term not longer than ten years. The exercise price of each stock option is equal to the fair market value of the stock on the date the stock option is granted. Generally, one-fourth of the stock options granted vest and become exercisable each year on the anniversary of the grant date. Under the provisions of the 2010 Integrys Energy Group Omnibus Incentive Compensation Plan, no single employee who is Integrys Energy Group's chief executive officer or one of the other three highest compensated officers of Integrys Energy Group (including officers of its subsidiaries) can be granted stock options for more than 1,000,000 shares during any calendar year.
The fair values of stock option awards granted were estimated using a binomial lattice model. The expected term of stock option awards is calculated based on historical exercise behavior and represents the period of time that stock options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate of Integrys Energy Group. The expected stock price volatility was estimated using 10-year historical volatility. The following table shows the weighted-average fair values per stock option along with the assumptions incorporated into the valuation models:
A summary of stock option activity for 2012, and information related to outstanding and exercisable stock options at December 31, 2012, is presented below:
As of December 31, 2012, future compensation cost expected to be recognized for unvested and outstanding stock options was not significant.
The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options at December 31, 2012. This is calculated as the difference between Integrys Energy Group's closing stock price on December 31, 2012, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during 2012, 2011, and 2010 was not significant.
Performance Stock Rights
Performance stock rights vest over a three-year performance period. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the distribution of these awards is not accelerated. No single employee who is Integrys Energy Group's chief executive officer or one of the other three highest compensated officers of Integrys Energy Group (including officers of its subsidiaries) can receive a payout in excess of 250,000 performance shares during any calendar year. Performance stock rights are paid out in shares of Integrys Energy Group common stock, or eligible employees can elect to defer the value of their awards into the deferred compensation plan and choose among various investment options, some of which are ultimately paid out in Integrys Energy Group common stock and some of which are ultimately paid out in cash. Beginning in 2011, eligible employees can only elect to defer up to 80% of the value of their awards. The number of shares paid out is calculated by multiplying a performance percentage by the number of outstanding stock rights at the completion of the performance period. The performance percentage is based on the total shareholder return of Integrys Energy Group's common stock relative to the total shareholder return of a peer group of companies. The payout may range from 0% to 200% of target.
Performance stock rights are accounted for as either an equity award or a liability award depending on their settlement features. Awards that can only be settled in shares of Integrys Energy Group common stock are accounted for as equity awards. Awards that an employee has elected to defer or is still able to defer into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.
Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in Integrys Energy Group's common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification. The fair value on the modification date is used to measure these awards for the remaining six months of the performance period. No incremental compensation expense is recorded as a result of this award modification.
The fair values of performance stock rights were estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate of Integrys Energy Group. The expected volatility was estimated using one to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at December 31:
A summary of the 2012 activity related to performance stock rights accounted for as equity awards is presented below:
*
Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.
A summary of the 2012 activity related to performance stock rights accounted for as liability awards is presented below:
The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of December 31, 2012, was $43.73 per performance stock right.
As of December 31, 2012, future compensation cost expected to be recognized for unvested and outstanding performance stock rights (equity and liability awards) was not significant.
The total intrinsic value of performance shares distributed during the years ended December 31, 2012, 2011, and 2010, was not significant.
Restricted Shares and Restricted Share Units
Restricted shares and restricted share units generally have a four-year vesting period, with 25% of each award vesting on each anniversary of the grant date. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the releasing of these shares to these employees is not accelerated. During 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at December 31, 2012. Restricted share unit recipients do not have voting rights, but they receive forfeitable Integrys Energy Group dividend equivalents in the form of additional restricted share units.
Restricted share units are accounted for as either an equity award or a liability award depending on their settlement features. Awards that can only be settled in shares of Integrys Energy Group common stock and cannot be deferred into the deferred compensation plan are accounted for as equity awards. Beginning in 2011, eligible employees can only elect to defer up to 80% of their awards into the deferred compensation plan. Equity awards are measured based on the fair value on the grant date. Awards that an employee has elected to defer into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.
A summary of the activity related to all restricted share unit awards (equity and liability awards) for the year ended December 31, 2012, is presented below:
As of December 31, 2012, $1.1 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.8 years.
The total intrinsic value of restricted share and restricted share unit awards vested and released for the years ended December 31, 2012, and 2011, was $1.5 million and $1.0 million, respectively, and was not significant for the year ended December 31, 2010. The actual tax benefit realized for the tax deductions from the vesting and releasing of restricted shares and restricted share units during the years ended December 31, 2012, 2011, and 2010, was not significant.
The weighted-average grant date fair value of restricted share units awarded during the years ended December 31, 2012, 2011, and 2010, was $53.24, $49.40, and $41.58 per share, respectively.
NOTE 18-VARIABLE INTEREST ENTITIES
We have a variable interest in an entity through a power purchase agreement relating to the cost of fuel. This agreement contains a tolling arrangement in which we supply the scheduled fuel and purchase capacity and energy from the facility. In connection with the pending purchase of Fox Energy Company LLC, we will pay $50.0 million to terminate this tolling arrangement. See Note 3, “Agreement to Purchase Fox Energy Center,” for more information regarding this pending purchase. As of December 31, 2012, and December 31, 2011, we had 500 megawatts of capacity available under this agreement.
We evaluated this variable interest entity for possible consolidation. We considered which interest holder has the power to direct the activities that most significantly impact the economics of the variable interest entity; this interest holder is considered the primary beneficiary of the entity and is required to consolidate the entity. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contract compared with the remaining life of the plant and the fact that we do not have the power to direct the operations and maintenance of the facility, we determined we are not the primary beneficiary of this variable interest entity.
At December 31, 2012, and December 31, 2011, the assets and liabilities on the balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with this contract. There is not a significant potential exposure to loss as a result of our involvement with the variable interest entity.
NOTE 19-FAIR VALUE
Fair Value Measurements
The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
The risk management assets and liabilities listed in the tables above include NYMEX futures and options, as well as financial contracts used to manage transmission congestion costs in the MISO market. NYMEX contracts are valued using the NYMEX end-of-day settlement price, which is a Level 1 input. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input. The valuation for physical coal contracts is categorized in Level 3, as significant assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. For more information on our derivative instruments, see Note 2, "Risk Management Activities." There were no transfers between the levels of the fair value hierarchy during 2012 and 2011.
The significant unobservable inputs used in the valuation that resulted in categorization within Level 3 were as follows at December 31, 2012. The amounts and percentages listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3.
(1)
Represents forward market prices developed using historical cleared pricing data from MISO used in the valuation of FTRs.
(2)
Represents third-party forward market pricing used in the valuation of our coal contracts.
Significant changes in historical settlement prices and forward coal prices would result in a directionally similar significant change in fair value.
The following table sets forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:
Unrealized gains and losses on FTRs and the coal contract are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on FTRs, as well as the related transmission congestion costs, are recorded in cost of fuel, natural gas, and purchased power on the statements of income.
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
The fair values of long-term debt are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices, when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy.
Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, notes payable, and outstanding commercial paper, the carrying amount for each such item approximates fair value.
NOTE 20-MISCELLANEOUS INCOME
Our total miscellaneous income was as follows at December 31:
NOTE 21-REGULATORY ENVIRONMENT
Wisconsin
2013 Rates
On December 6, 2012, the PSCW issued an order approving a settlement agreement, effective January 1, 2013. The settlement agreement includes a $28.5 million imputed retail electric rate increase, which will be partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase will be deferred for recovery in a future rate proceeding. As a result, there will be no change to customers' 2013 retail electric rates. The settlement agreement also includes a $3.4 million retail natural gas rate decrease. The 2013 electric and natural gas rates are subject to downward adjustment based on updated December 31, 2012, pension and benefit cost estimates, which will be filed with the PSCW by March 1, 2013. The settlement agreement reflects a 10.30% return on common equity and a common equity ratio of 51.61% in our regulatory capital structure. In addition, we were authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset at December 31, 2012. The settlement agreement also authorized the recovery of direct Cross State Air Pollution Rule (CSAPR) costs incurred through the end of 2012. As of December 31, 2012, we had deferred $4.7 million of costs related to CSAPR. Lastly, the settlement agreement also authorized us to switch from production tax credits to Section 1603 Grants for the Crane Creek Wind Project.
Decoupling for natural gas and electric residential and small commercial and industrial customers was approved as part of the settlement agreement on a pilot basis for 2013. The mechanism does not adjust for variations in volumes resulting from changes in customer count compared
to rate case levels, nor does it cover all customer classes. It is based on total rate case-approved margins, rather than being calculated on a per-customer basis. It will continue to include an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate order.
2012 Rates
On December 9, 2011, the PSCW issued a final written order, effective January 1, 2012. It authorized an electric rate increase of $8.1 million and required a natural gas rate decrease of $7.2 million. The electric rate increase was driven by projected increases in fuel and purchased power costs. However, to the extent that actual fuel and purchased power costs exceeded a 2% price variance from costs included in rates, they were deferred for recovery or refund in a future rate proceeding. The rate order allowed for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection, and reflected reduced contributions to the Focus on Energy Program. The rate order also allowed for the deferral of direct CSAPR compliance costs, including carrying costs.
2011 Rates
On January 13, 2011, the PSCW issued a final written order authorizing an electric rate increase of $21.0 million, calculated on a per-unit basis. Although the rate order included a lower authorized return on common equity, lower rate base, and other reduced costs, which resulted in lower total revenues and margins, the rate order also projected lower total sales volumes, which led to a rate increase on a per-unit basis. The rate order also included a projected increase in customer counts that did not materialize, which impacted the decoupling calculation as it adjusted for differences between the actual and authorized margin per customer. The $21.0 million electric rate increase included $20.0 million of recovery of prior deferrals, the majority of which related to the recovery of the 2009 electric decoupling deferral. The $21.0 million excluded the impact of a $15.2 million estimated fuel refund (including carrying costs) from 2010. The rate order also required an $8.3 million decrease in natural gas rates, which included $7.1 million of recovery for the 2009 decoupling deferral. The new rates were effective January 14, 2011, and reflected a 10.30% return on common equity and a common equity ratio of 51.65% in our regulatory capital structure.
The order also addressed the new Wisconsin electric fuel rule, which was finalized on March 1, 2011. The new fuel rule was effective retroactive to January 1, 2011. It requires the deferral of under or over-collections of fuel and purchased power costs that exceed a 2% price variance from the cost of fuel and purchased power included in rates. Under or over-collections deferred in the current year will be recovered or refunded in a future rate proceeding.
NOTE 22-SEGMENTS OF BUSINESS
At December 31, 2012, we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are the regulated electric utility operations and the regulated natural gas utility operations. The other segment includes nonutility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC. All of our operations and assets are located within the United States.
The tables below present information for the respective years pertaining to our reportable segments:
NOTE 23-RELATED PARTY TRANSACTIONS
We and our subsidiary, WPS Leasing, routinely enter into transactions with related parties, including Integrys Energy Group, its subsidiaries, and other entities in which we have material interests.
We provide and receive services, property, and other items of value to and from our parent, Integrys Energy Group, and other subsidiaries of Integrys Energy Group. All such transactions are made pursuant to an affiliated interest agreement ("Regulated Agreement") approved by the PSCW. MERC, MGU, NSG, PGL, and UPPCO (together with us, the "regulated subsidiaries") have all been added as parties to the Regulated Agreement and, like us, can also provide and receive services, property, and other items of value to and from their parent, Integrys Energy Group, and other regulated subsidiaries of Integrys Energy Group. We are also a party to an agreement with Integrys Energy Group and Integrys Energy Group's nonregulated subsidiaries. This affiliated interest agreement ("Nonregulated Agreement") was also approved by the PSCW. The other regulated subsidiaries are not parties to the Nonregulated Agreement. The Regulated Agreement requires that all services are provided at cost. The Nonregulated Agreement provides that we must receive payment equal to the higher of our cost or fair value for services, property, and other items of value that we provide to Integrys Energy Group or its other nonregulated subsidiaries, and that we must make payments equal to the lower of the provider's cost or fair value for services, property, and other items of value that Integrys Energy Group or its other nonregulated subsidiaries provide to us. Modification or amendment to these agreements requires the approval of the PSCW.
IBS provides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to an affiliated interest agreement (IBS AIA), which has been approved, or from which we have been granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, IBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the IBS AIA. Other modifications or amendments to the IBS AIA would require PSCW approval. Recovery of allocated costs is addressed in our rate cases.
In 2010, a new affiliated interest agreement (NonIBS AIA) that would govern the provision of intercompany services, other than IBS services, within Integrys Energy Group, was submitted to the appropriate regulators for approval. The NonIBS AIA was written primarily to limit the scope of services now provided by IBS that had been provided under the Regulated Agreement and the Nonregulated Agreement. The NonIBS AIA would replace these current agreements, except the IBS AIA, after proper approvals. The pricing methodologies from the current agreements would carry forward to the NonIBS AIA. On January 23, 2012, the PSCW issued its final decision, and on April 3, 2012, the PSCW issued an amended final decision approving the agreement, but it cannot take effect until it is approved in all jurisdictions and compliance filings are made.
We provide services to ATC for the transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost.
We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC under which either party may be a service provider. Services are billed to WRPC under these agreements at our fully allocated cost.
The table below includes information associated with transactions entered into with related parties as of December 31:
(1)
WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.
(2)
The December 31, 2011 balance reflected the unrecognized pension costs that were allocated to Integrys Energy Group's subsidiaries for the nonqualified retirement plan. At December 31, 2012, only the unrecognized pension costs associated with our past and current employees were reflected on our balance sheet.
In addition to the above transactions, $22.6 million was repaid to related parties during 2012 for amounts previously paid to us for the unfunded nonqualified retirement plan.
The following table shows activity associated with related party transactions for the years ended December 31:
(1)
WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.
(2)
WPS Investments, LLC is a consolidated subsidiary of Integrys Energy Group that is jointly owned by Integrys Energy Group, UPPCO, and us. At December 31, 2012, we had a 11.70% interest in WPS Investments accounted for under the equity method. Our percentage ownership interests have continued to decrease as additional equity contributions are made by Integrys Energy Group to WPS Investments.
NOTE 24-QUARTERLY FINANCIAL INFORMATION (Unaudited)
Because of various factors, the quarterly results of operations are not necessarily comparable.
H. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON FINANCIAL STATEMENTS
To the Board of Directors of Wisconsin Public Service Corporation:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Public Service Corporation and subsidiary (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Public Service Corporation and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Milwaukee, Wisconsin
February 28, 2013
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of WPS's disclosure controls and procedures (as defined by Securities Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based upon that evaluation, management, including our Chief Executive Officer and Chief Financial Officer, has concluded that WPS's disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control
There were no changes in our internal control over financial reporting (as defined by Securities Exchange Act Rules 13a-15(f) and 15d-15(f)) during the quarter ended December 31, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management Report on Internal Control over Financial Reporting
For WPS's Management Report on Internal Control Over Financial Reporting see Section A of Item 8.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
(1)
Officers and their ages are as of January 1, 2013. None of the executives and/or directors listed above are related by blood, marriage, or adoption to any of the other officers listed or to any of our directors. Each officer holds office until his or her successor has been duly elected and qualified, or until his or her death, resignation, disqualification, or removal.
(2)
The Integrys Gas Group included MGU, MERC, NSG, and PGL.
(3)
Prior to joining Integrys Energy Group, Jodi J. Caro owned and operated her own law practice, Jodi J. Caro, LLC, which provided general counsel and corporate transactional services to clients nationwide.
Our board of directors is comprised solely of inside directors, and we do not have any standing committees of our board of directors. The role of an effective director inherently requires certain personal qualities, such as integrity, as well as the ability to comprehend, discuss, and critically analyze materials and issues that are presented so that the director may exercise judgment and reach conclusions in fulfilling his or her duties and fiduciary obligations. We believe that the specific background of each director, as set forth in the table above, evidences their ability to serve as a director and, accordingly, led to the conclusion that each of the directors should continue to serve as a director.
We are a wholly owned subsidiary of Integrys Energy Group. See Integrys Energy Group's Proxy Statement for its Annual Meeting of Shareholders to be held May 16, 2013 (Proxy Statement), under "Ownership of Voting Securities - Section 16(a) Beneficial Ownership Reporting Compliance" for information related to Section 16 compliance.
Integrys Energy Group has adopted a Code of Conduct, which covers us and serves as our Code of Business Conduct and Ethics. The Code of Conduct applies to all of our directors, officers, and employees, including the Chief Executive Officer, Chief Financial Officer, Corporate Controller, and any other persons performing similar functions.
Integrys Energy Group's Code of Conduct may be accessed on the Integrys Energy Group website at www.integrysgroup.com by selecting "Investors," then selecting "Corporate Governance," then selecting "Governance Documents." Amendments to, or waivers from, the Code of Conduct will be disclosed on Integrys Energy Group's website within the prescribed time period.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
The purpose of this Compensation Discussion and Analysis is to provide material information that is necessary for an understanding of our compensation policies and decisions relating to our named executive officers, including the identification of key components of our executive compensation program, and an explanation of the purpose of each key component. Our named executive officers for 2012 consisted of the following:
•
Lawrence T. Borgard, Chief Executive Officer;
•
Joseph P. O'Leary, Senior Vice President and Chief Financial Officer;
•
Charles A. Schrock, Chairman, President and Chief Executive Officer of Integrys Energy Group;
•
Charles A. Cloninger, President; and
•
Phillip M. Mikulsky, Executive Vice President - Business Performance and Shared Services of Integrys Energy Group
This discussion relates specifically to Mr. Cloninger, as Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky are also named executive officers of Integrys Energy Group, and the compensation paid to them will be reported in the Proxy Statement of Integrys Energy Group and not herein. The compensation reported below reflects total compensation paid to Mr. Cloninger in consideration of his service to Integrys Energy Group and its subsidiaries, including us. For the “Compensation Discussion and Analysis” related to Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement, which addresses, among other things, the short-term incentive compensation, the long-term incentive compensation and the other benefits paid or payable to these named executive officers.
Compensation Philosophy and Objectives
We are a wholly owned subsidiary of Integrys Energy Group. As such, we do not have a standing compensation committee because our executives participate in the compensation programs and plans of Integrys Energy Group, which are administered by the Compensation Committee of Integrys Energy Group's Board of Directors (referred to as the Committee). The Committee presents recommendations regarding appropriate compensation packages for our named executive officers to the Integrys Energy Group Board of Directors for its approval. The recommendations of the Committee are based on the same compensation philosophy and use of market studies as those used in determining compensation for executives of Integrys Energy Group. For information relating to these matters, as well as a discussion of the role of the Committee and the role of advisors to the Committee, see the Proxy Statement under the caption "Executive Compensation - Compensation Discussion and Analysis."
Base Salary
Base salary is used to provide cash income to executives to compensate them for services rendered during the fiscal year. Salary increases for 2012 were determined by the Committee based on recommendations of the Chief Executive Officer of Integrys Energy Group, which may include overall company performance and individual performance of the executive and the Committee's evaluation of current market data as provided by the independent compensation consultant hired by the Committee. In December 2011, the Committee granted a base salary increase for 2012 of 3% for all of the named executive officers, except for Mr. Borgard and Mr. Cloninger. Mr. Borgard received a 10% increase to bring his base pay closer to market median. Mr. Cloninger received a 12% increase in conjunction with his promotion to President and to bring his base pay closer to market median for that position. Base salaries for 2012 for our named executive officers were competitive with the market at the time that the base salaries were approved. Setting base salary at or near market median levels allows the company to be competitive in the marketplace.
Short-Term Incentive Compensation
All of our named executive officers participated in the Integrys Energy Group 2012 Executive Incentive Plan (Incentive Plan). Provided below are the specific performance goals and measurement weightings established for Mr. Cloninger.
(1)
Performance is measured based on Integrys Energy Group diluted earnings per share, which is based on forecasted net income available for common shareholders used to establish investor guidance, and adjusted on an after-tax basis.
(2)
Performance is measured based on the implementation of projects and activities in 2012 that reduced annual emissions of carbon dioxide (CO2) and other greenhouse gases.
(3)
Performance is measured based on customer satisfaction through surveys performed by an outside vendor as compared to survey results of other regional benchmark energy suppliers.
(4)
Performance is measured based on our Occupational Safety and Health Administration recordable incident rates and those at Upper Peninsula Power Company.
Under the Incentive Plan, no payouts for financial measure results are made to any of our named executive officers if the Diluted EPS - Adjusted threshold level is not attained. In addition, Incentive Plan payouts related to nonfinancial measures are reduced by 50% if the Diluted EPS - Adjusted threshold level is not attained.
Threshold, target and superior performance levels for each goal, as well as the weighting of each measure, are approved by the Committee. For each of the short-term incentive measures, the Committee sets specific performance levels early in the plan year and factors in stretch performance objectives in developing the performance measures. Threshold levels represent minimally acceptable performance, target levels represent performance that should typically be achievable in any given year, and superior levels represent stellar performance beyond that typically achievable in any given year.
Provided below are the specific payout levels established for 2012 for Mr. Cloninger.
Provided below are threshold, target and superior levels, as well as information related to actual results achieved for 2012 and related payout percentage for the financial measure:
In making the determination as to the payout related to the financial measure, as provided for in the Incentive Plan approved by the Committee at the beginning of the year, the Committee concluded that certain adjustments to the Diluted EPS - Adjusted measure were appropriate because the events were nonrecurring in nature and the accounting effects of these items were not indicative of the performance of our named executive officers during 2012. The types of these adjustments were specifically allowed for in the Incentive Plan and included adjustments related to Integrys Energy Group's nonregulated operations, including mark-to-market adjustments and discontinued operations, as well as an adjustment for a tax impact resulting from healthcare legislation reform. The total adjustment to the Diluted EPS - Adjusted result was $0.18, with the largest adjustment resulting from a noncash charge related to mark-to-market adjustments at Integrys Energy Services, Inc. All adjustments approved by the Committee were consistent with the types of adjustments allowed under the Incentive Plan.
The 2012 nonfinancial measures and performance range results, in general, are provided in the following table:
The amount of total payouts awarded under the Incentive Plan for Mr. Cloninger, along with the payout percentages as a percent of targets and individual base salary earnings, are summarized in the table below.
The Committee believes it is important to establish performance targets and incentives that align executive compensation with financial and operational performance, promote value-driven decision making by executives and provide total compensation levels that are competitive in the market. Payout is made on any individual measure with results above threshold (provided that no payout for any financial measure is made unless the Diluted EPS - Adjusted threshold is reached, and payouts related to nonfinancial measures are also reduced by 50% if the Diluted EPS - Adjusted threshold is not reached). Company performance and the use of stretch performance objectives have had an effect on payout levels, with payouts for our named executive officers ranging from 28.77% to 91.73% of target and from 16.66% to 91.56% of actual paid base salary during the 2010 through 2012 plan performance periods.
Long-Term Incentive Compensation
The long-term incentive compensation granted by the Committee for 2012 as a percent of annualized base salary for Mr. Cloninger was 70%.
Other Benefits and Plans
We have certain other plans which provide, or may provide, cash compensation and benefits to our named executive officers. These benefits and plans include a nonqualified deferred compensation plan, a qualified pension plan, a nonqualified pension restoration plan and supplemental retirement plan, and perquisites. We also provide life insurance as part of our compensation package. The Committee considers all of these benefits and plans when reviewing total compensation of our named executive officers.
Deferred Compensation Plan
Our named executive officers may participate in the nonqualified Integrys Energy Group Deferred Compensation Plan. This nonqualified benefit allows eligible executives to defer 1% to 80% of base salary, annual short-term incentive, and long-term incentive compensation (other than options for Integrys Energy Group common stock) on a pre-tax (federal and state) basis.
Qualified Pension Plan
Our named executive officers are eligible to participate in the qualified Integrys Energy Group Retirement Plan (referred to as the pension plan) upon completion of one year of service and 1,000 or more hours of work during that year. The pension plan requires three years of employment or the attainment of age 65 to be vested in the plan.
For a more detailed discussion of the pension plan, see the Proxy Statement under the caption "Executive Compensation - Compensation Discussion and Analysis - Other Benefits and Plans - Qualified Pension Plan."
Provided below is the pension service credit for Mr. Cloninger.
The pension plan does not allow for granting of additional service credit not otherwise authorized under the plan terms. Provided in the Pension Benefits Table for 2012 below is a tabulation of the present value of the accumulated pension benefit using full years of credited service only.
Pension Restoration Plan and Supplemental Retirement Plan
Our named executive officers receive a nonqualified pension restoration benefit under the Nonqualified Pension Restoration Plan. Pension restoration provides a benefit based upon the difference between (1) the benefit the executive would have been entitled to under the pension plan if the maximum benefit limitation under IRS Section 415 and the compensation limitation under IRS Section 401(a)(17) did not apply, and if all base compensation and annual incentive amounts had been paid to the executive in cash rather than being deferred into the Integrys Energy Group Deferred Compensation Plan, and (2) the executive's actual benefit under the pension plan. The Nonqualified Deferred Compensation Table for 2012 below provides information on the deferrals into the Pension Restoration Plan and earnings for Mr. Cloninger.
In addition, the Integrys Energy Group Board of Directors, based on the recommendation of the Committee, has authorized certain executive officers to be provided with a nonqualified supplemental retirement benefit under the Supplemental Retirement Plan (SERP). This benefit provides
income replacement when taking into account other retirement benefits provided to the eligible executive and assures that the eligible executive will receive 60% of his/her final average pay (over the last 36 months or the 3 preceding years, whichever is higher). To qualify for the full supplemental retirement benefit, the executive must have completed 15 years of service and retire/terminate after age 62. Reduced benefits are payable if the executive has attained age 55 and completed 10 years of service at retirement or termination.
Beginning in 2008, we made the decision to move away from the use of defined benefit plans for all nonunion employees, including executives, because of market trends. A ten-year transition period applies, which means that for new nonunion employees hired after 2008, no qualified or nonqualified defined benefit pension plans will exist for future benefit accruals. These plans are being replaced with defined contribution plans.
Life Insurance
Our named executive officers are eligible for an enhanced life insurance benefit of up to three times their annual base salary, with a maximum benefit level (taking into account both employer-provided coverage and any supplemental coverage that the officer voluntarily purchases) of $1,500,000. Accidental death and dismemberment coverage is also provided for these same named executive officers up to three times their annual base salary, subject to a separate $1,500,000 maximum benefit level. The IRS requires that imputed income be calculated and recorded for company-paid life insurance in excess of $50,000. In compliance with IRS regulations, imputed income is recorded to the extent that an executive's life insurance benefit exceeds this limit. Listed below is the life insurance coverage in place for Mr. Cloninger as of December 31, 2012.
Perquisites
Our named executive officers are provided with a modest level of personal benefits. These may include payments for executive physicals, financial counseling, home office equipment and office parking.
Change in Control Agreements
The Committee has authorized each of our named executive officers other than Mr. Cloninger to receive protection and associated benefits in the event of a covered termination following a change in control of Integrys Energy Group. These agreements between our named executive officers and Integrys Energy Group each contain a "double trigger" arrangement, whereby a payment is made only if there is a change in control of Integrys Energy Group and the executive is actually terminated or terminates employment under certain circumstances after being demoted or after certain other adverse changes in the executive's working conditions or status. The Committee periodically reviews the payment and benefit levels in the change in control agreements and the triggers to ensure that they remain competitive and appropriate. As part of this process, no tax gross-up provisions are being provided to our named executive officers, except for Mr. Mikulsky. Mr. Mikulsky's agreement is a legacy agreement which has contained the gross-up provision since 2000. We do not intend to provide gross-ups to any other executives. The Committee conducted a review of the program again in 2012 and concluded that the program continues to meet our objectives and remains consistent with current market practices.
For a more detailed discussion of the change in control agreements, see the Proxy Statement under the caption "Executive Compensation - Compensation Discussion and Analysis - Other Benefits and Plans - Change in Control Agreements."
Common Stock Ownership Guidelines
We believe that it is important to align executive and shareholder interests by defining stock ownership guidelines for executives. Because we are wholly owned by Integrys Energy Group, the stock ownership guidelines are based on Integrys Energy Group common stock. For 2012, our named executive officers are expected to retain at least 50% of their future vested stock awards until certain levels of common stock are owned, with such levels generally ranging from one to five times base annual salary.
In 2012, the target level for ownership of Integrys Energy Group common stock was five times annualized base salary for Charles A. Schrock, three times annualized base salary for Lawrence T. Borgard and Joseph P. O'Leary, two times annualized base salary for Phillip M. Mikulsky, and one and four tenths times annualized base salary for Charles A. Cloninger. All of our named executive officers are complying with our stock ownership guidelines.
Summary Compensation Table for 2012
The following table sets forth information concerning compensation earned or paid to Mr. Cloninger for the past three fiscal years during which he was a named executive officer: (1) the dollar value of base salary and bonus earned during the applicable fiscal years; (2) the aggregate grant date fair value of stock and option awards, as computed in accordance with the FASB ASC Topic 718 (all stock option awards in this and the other tables relate to Integrys Energy Group common stock); (3) the dollar value of earnings for services pursuant to awards granted during the applicable fiscal years under nonequity incentive plans; (4) the change in pension value and nonqualified compensation earnings during the applicable fiscal years; (5) all other compensation for the applicable fiscal years; and (6) the dollar value of total compensation for the applicable fiscal years. This Summary
Compensation Table for 2012 and the tables that follow reflect the compensation paid to Mr. Cloninger for all services rendered in all capacities to Integrys Energy Group and its subsidiaries, including us, regardless of whether the compensation was paid by Integrys Energy Group or any of its subsidiaries. For Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Summary Compensation Table for 2012."
(1)
Amounts shown include amounts deferred into the Integrys Energy Group Deferred Compensation Plan. See the Nonqualified Deferred Compensation Table for 2012 for more information.
(2)
The amounts shown in columns (e) and (f) reflect the grant date fair value of the awards computed in accordance with FASB ASC Topic 718 - Stock Compensation. For information regarding the assumptions made in valuing the stock and option awards, see Note 17, "Stock-Based Compensation."
(3)
Nonequity incentive compensation is payable annually in the first quarter of the next fiscal year, and a portion may be deferred at the election of Mr. Cloninger. Payment is calculated based on the measurement outcomes and as a percent of adjusted gross base salary earnings from the company for services performed during the payroll year.
(4)
The calculation of above-market earnings on nonqualified deferred compensation is based on the difference between 120% of the applicable federal long-term rate (AFR) and the rate of return received on Reserve Accounts A and B. Provided below are the actual rates of return used in the calculation. Note that Reserve Account A was frozen to new deferrals beginning on January 1, 1996. Reserve Account B was frozen to new deferrals beginning on April 1, 2008.
(5)
The amounts shown include other compensation items consisting of life insurance premiums, imputed income from life insurance benefits, and Employee Stock Ownership Plan (ESOP) matching contributions. For individual items included in column (i) that were in excess of $10,000, see the table below reflecting ESOP matching contributions.
(6)
The amounts shown are only for 2012 as Mr. Cloninger was not a named executive officer during 2011 and 2010.
With regard to equity awards, no re-pricing, extension of exercise periods, change of vesting or forfeiture conditions, change or elimination of performance criteria, change of bases upon which returns are determined, or any other material modification of any outstanding option or other equity-based award occurred during fiscal years reported in the table.
Grants of Plan-Based Awards Table for 2012
The following table sets forth information regarding all incentive plan awards that were made to Mr. Cloninger during 2012, including equity- and nonequity-based awards. For Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Grants of Plan-Based Awards Table for 2012."
(1)
Based on 2012 Executive Incentive Plan payout percentages. For more information, see the Proxy Statement under the caption "Executive Compensation - Compensation Discussion and Analysis - Key Components of the Executive Compensation Program - Short-Term Incentive Compensation."
(2)
Performance shares are valued at $47.63, the target payout value derived from a Monte Carlo simulation. Restricted stock units are valued at $53.24, the closing stock price on the grant date. Stock options are valued at $6.30 on an accounting expense basis based on a proprietary "advance lattice" option pricing model.
For a narrative description of the material factors necessary to understand the information disclosed in the Summary Compensation Table for 2012 and the Grants of Plan-Based Awards Table for 2012, see the Proxy Statement under the caption "Executive Compensation."
Outstanding Equity Awards Table for 2012
The following table sets forth information for Mr. Cloninger regarding outstanding awards under the stock option plan, restricted stock plan, incentive plans, and similar plans, including market-based values of associated rights and/or shares as of December 31, 2012. For Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Outstanding Equity Awards Table for 2012."
(1)
Provided below is the corresponding vesting date relative to each option expiration date:
(2)
Integrys Energy Group stock price on December 31, 2012, was $52.22.
(3)
The following table reflects the amounts of unvested restricted stock units and corresponding grant dates. Restricted stock units vest over four years, with 25% of the original grant amount vesting each year on the anniversary of the respective grant date.
(4)
Included in columns (i) and (j) above are the performance shares pertaining to grants made in 2011 and 2012 for the performance periods of 2011-2013 and 2012-2014 and associated payout values, assuming that both grants will pay out at target following completion of each applicable performance period. Based on total shareholder return (TSR) performance as of December 31, 2012, the grant made in 2011 would pay out at 68% (between threshold and target) and the grant made in 2012 would pay out at 108% (between target and superior). The following two tables show projected payouts of the 2011 and 2012 performance share grants assuming TSR performance as of December 31, 2012, as well as projected payouts that would occur assuming superior performance (200%).
2011 Performance Share Grant:
2012 Performance Share Grant:
(5)
Not included in columns (i) and (j) above are the performance shares pertaining to grants made in 2010 for the performance period of 2010-2012. Subsequent to December 31, 2012, a payout at 130% will occur on performance shares for the performance period of 2010-2012 based on final TSR results. The number of earned performance shares attributable as a result of the threshold level being exceeded, along with the corresponding market value of such shares, is as follows:
Option Exercises and Stock Vested Table for 2012
The following table sets forth amounts received by Mr. Cloninger upon exercise of options (or similar instruments) or the vesting of stock (or similar instruments) during 2012. For Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Option Exercises and Stock Vested Table for 2012."
*
A payout will be made on performance shares in 2013 based on total shareholder return for the performance period ending December 31, 2012, meeting the threshold payout level. These performance shares had a performance period beginning on January 1, 2010, and ending on December 31, 2012.
Pension Benefits Table for 2012
The following table sets forth the actuarial present value of Mr. Cloninger's accumulated benefit under each defined benefit plan, assuming benefits are paid at normal retirement age based on current levels of compensation. For Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Pension Benefits Table for 2012." None of our named executive officers are currently eligible for early retirement other than Mr. O'Leary, Mr. Schrock and Mr. Mikulsky. No pension benefits were paid to any of the currently employed named executive officers during the year. Specific details of these benefits are discussed in more detail in the Proxy Statement under the caption "Executive Compensation - Compensation Discussion and Analysis - Key Components of the Executive Compensation Program - Other Benefits and Plans."
(1)
For a description of the material terms and conditions of the above-named plans, see the Proxy Statement under the caption "Executive Compensation - Compensation Discussion and Analysis - Key Components of the Executive Compensation Program - Other Benefits and Plans."
(2)
Full years of credited service only. Actual plan benefits are calculated taking into account full and fractional years of credited service.
(3)
Change in pension value during 2012 and present value of accumulated benefit at year-end:
Pension Plan
The amount shown is based on the present value of the projected pension plan account balances payable at the plan's normal retirement age (age 65). The projected age 65 pension plan account equals the participant's accrued account balance at year-end rolled forward with interest credits to age 65 using the plan's interest rate (2.45% at December 31, 2012, and 3.25% at December 31, 2011). The present value was determined using an interest rate consistent with assumptions used for financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC (4.10% at December 31, 2012, and 5.10% at December 31, 2011).
Since Mr. Cloninger is covered under the Integrys Energy Group Retirement Plan, the value of the temporary supplemental benefit has been added. The present value was determined assuming current commencement (if currently eligible) or commencement at earliest eligibility (generally age 55) and payment in a single lump sum form, using the plan's interest rate to calculate the lump sum payment (Pension Protection Act segment lump sum rates at December 31, 2012, and December 31, 2011) and using an interest rate consistent with assumptions used in financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC to determine the present value at year-end of the lump sum payable. The benefit was prorated based on current service over service from hire date to date of earliest eligibility.
Pension Restoration Plan
The amount shown is based on the present value of the projected pension plan account balance payable at the plan's normal retirement age (age 65). The projected age 65 pension plan account equals the participant's accrued account balance at year-end rolled forward with interest credits to age 65 using the plan's interest rate (2.45% at December 31, 2012, and 3.25% at December 31, 2011). The present value was determined using an interest rate consistent with assumptions used for financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC (3.20% at December 31, 2012, and 5.10% at December 31, 2011).
Nonqualified Deferred Compensation Table for 2012
The following table sets forth information regarding the contributions, earnings, and balances for Mr. Cloninger relative to the nonqualified deferred compensation plan for 2012. For Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Nonqualified Deferred Compensation Table for 2012."
(1)
Deferrals into the Deferred Compensation Plan were made from compensation earned in 2012 and are reported in column (c) of the Summary Compensation Table for 2012, with the exception of annual incentive and performance share amounts earned in 2011 but paid out and deferred in 2012. These amounts are as follows:
(2)
Above-market earnings received on Reserve Accounts A and B are reported in column (h) of the Summary Compensation Table for 2012.
(3)
The aggregate balance includes amounts shown in footnote (1) and the above-market earnings on Reserve Accounts A and B, which are included in column (h) of the Summary Compensation Table for 2012.
The following table sets forth the actual earnings during 2012 of each deferred compensation account held by Mr. Cloninger. For Mr. Borgard, Mr. O'Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Nonqualified Deferred Compensation Table for 2012."
For further details regarding the deferred compensation accounts, including rates of return, see the Proxy Statement under the caption "Executive Compensation - Compensation Discussion and Analysis - Key Components of the Executive Compensation Program - Other Benefits and Plans." Upon retirement or termination of employment, distribution of our named executive officer's account will commence in January of the year that is both (1) following the calendar year of termination of employment and (2) at least six months following termination or later if a later date is selected by our named executive officer. Our named executive officer can elect a distribution period from 1 to 15 years. Payouts, withdrawals or other distributions cannot commence under the plan while our named executive officer is actively employed by us.
Termination of Employment
Mr. Borgard, Mr. O'Leary, Mr. Schrock, and Mr. Mikulsky, have been provided with an agreement such that, in the event of a termination following a change in control, a termination payment may be provided. For further details regarding the nature of these agreements, see the Proxy Statement under the caption "Executive Compensation - Termination of Employment." No change in control triggering event occurred in 2012 that affected our named executive officers.
Mr. Cloninger participates in the Integrys Energy Group Severance Plan. The severance plan was established to provide severance benefits to eligible employees whose employment at Integrys Energy Group, or at a participating subsidiary of Integrys Energy Group, like us, terminates as a result of an eligible termination.
An employee who becomes entitled to severance benefits will receive a cash severance benefit calculated at the rate of two (2) weeks of base pay for each full year of continuous service (partial years of continuous service will be disregarded) completed by such employee. Payment will be reduced for applicable withholding. The minimum severance benefit is six weeks of base pay. The maximum severance benefit is 52 weeks of base pay.
Provided below are estimated aggregate compensation and benefits that may be payable to Mr. Cloninger in the event of termination of employment. These estimates assume that termination occurred on the last business day of the last fiscal year (December 31, 2012). Mr. Cloninger is not a party to a change in control agreement.
(1)
Mr. Cloninger was not eligible for retirement as of December 31, 2012.
(2)
The present value of any unused and accrued paid time off is included in this amount, as is the estimated value of a lump sum payment equal to three (3) months of Mr. Cloninger's COBRA premium.
For estimated aggregate compensation and benefits that may be payable to Mr. Borgard, Mr. O'Leary, Mr. Schrock, and Mr. Mikulsky, see the Proxy Statement under the caption "Executive Compensation - Termination of Employment."
Director Compensation
At December 31, 2012, the eight directors consisted entirely of employees of Integrys Energy Group or its subsidiaries. The directors are Lawrence T. Borgard, Chairman; Charles A. Cloninger; William D. Laakso; Phillip M. Mikulsky; Joseph P. O'Leary; Mark A. Radtke; James F. Schott and Charles A. Schrock. None of these directors receive compensation for serving in the role of a director for us. Each director is compensated in his role as an employee of Integrys Energy Group or a subsidiary of Integrys Energy Group. For the compensation paid to Mr. Borgard, Mr. Mikulsky, Mr. O'Leary, Mr. Radtke and Mr. Schrock see the Proxy Statement under the caption "Executive Compensation - Summary Compensation Table for 2012." For the compensation paid to Mr. Cloninger, see the sections immediately above. The remaining directors as of December 31, 2012, were paid the following total compensation (calculated in a similar fashion to how total compensation in column (j) of the Summary Compensation Table for 2012 is calculated) by Integrys Energy Group for the year ended December 31, 2012: William D. Laakso $576,798 and James F. Schott $582,654.
Compensation Committee Report
For the Committee's report, see the Proxy Statement under the caption "Executive Compensation - Compensation Committee Report."
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Ownership of Voting Securities
All of our common stock is held by our parent, Integrys Energy Group.
The following table indicates the shares of Integrys Energy Group's common stock and stock options beneficially owned by our directors and executive officers as of February 1, 2013. None of the persons listed beneficially owns shares of any other class of our or Integrys Energy Group's equity securities.
(1)
Includes shares and share equivalents of common stock held in the Integrys Energy Group Employee Stock Ownership Plan and the Integrys Energy Group, LLC Deferred Compensation Trust, as well as stock options exercisable within 60 days of February 1, 2013, restricted stock units vested within 60 days of February 1, 2013, and performance shares paid out within 60 days of February 1, 2013. The reported performance shares are based upon the actual payout as approved by the Integrys Energy Group Board of Directors on February 14, 2013. Each director or officer has sole voting and investment power with respect to the shares reported, unless otherwise noted. No voting or investment power exists related to the stock options reported until exercised.
(2)
Less than 1% of Integrys Energy Group's outstanding shares of common stock as of February 1, 2013.
(3)
550 of reported shares are owned in the spouse's name only.
Equity Compensation Plan Information
Information required by this Item regarding equity compensation plans of Integrys Energy Group can be found in Integrys Energy Group's Proxy Statement, under the caption "Ownership of Voting Securities - Equity Compensation Plan Information." Such information is incorporated by reference as if fully set forth herein.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Our directors are also employees of WPS, our parent company, or a sister company.
Our directors and executive officers who are also executive officers of Integrys Energy Group are subject to Integrys Energy Group's policy regarding related person transactions. Information required by this Item regarding such related person transactions can be found in Integrys Energy Group's Proxy Statement under the caption "Election of Directors - Related Person Transaction Policy." Such information is incorporated by reference as if fully set forth herein.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following is a summary of the fees for professional services provided to us by Deloitte & Touche LLP in 2012 and 2011:
(1)
Audit Fees. Consists of aggregate fees for the audits of the annual consolidated financial statements and reviews of the interim condensed consolidated financial statements included in quarterly reports. Audit fees also include services that are normally provided by Deloitte & Touche in connection with statutory and regulatory filings or engagements, including comfort letters, consents and other services related to SEC matters, and consultations arising during the course of the audits and reviews concerning financial accounting and reporting standards.
(2)
Audit-Related Fees. Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the consolidated financial statements or internal control over financial reporting and are not reported under "Audit Fees."
(3)
All Other Fees. Consists of fees for services provided to us by Deloitte & Touche LLP for products and services other than the services reported above. All Other Fees relate to training provided in 2012.
In considering the nature of the services provided by the independent registered public accounting firm, the Audit Committee of the Board of Directors of Integrys Energy Group (Audit Committee) determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with the independent registered public accounting firm and Integrys Energy Group's management and determined that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as those of the American Institute of Certified Public Accountants. The Audit Committee has approved in advance 100% of the audit services described above in accordance with its pre-approval policy.
For information on the Policy on Audit Committee Pre-Approval of Audit and Permissible Nonaudit Services of Independent Registered Public Accounting Firm, see the discussion in the Integrys Energy Group Proxy Statement, under the caption "Principal Fees and Services Paid to Independent Registered Public Accounting Firm."
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Documents filed as part of this report:
(1)
Consolidated Financial Statements included in Part II at Item 8 above:
(2)
Financial Statement Schedule.
The following financial statement schedule is included in Part IV of this report. Schedules not included herein have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
Description
Pages in 10-K
Schedule II - Wisconsin Public Service Corporation Valuation and Qualifying Accounts
(3)
List of all exhibits, including those incorporated by reference.
See Exhibit Index.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 28, 2013.
WISCONSIN PUBLIC SERVICE CORPORATION
(Registrant)
By:
/s/ Lawrence T. Borgard
Lawrence T. Borgard
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 28, 2013.
Signature
Title
Charles A. Cloninger*
Director
William D. Laakso *
Director
Phillip M. Mikulsky *
Director
Joseph P. O'Leary *
Director
Mark A. Radtke *
Director
Charles A. Schrock *
Director
/s/ Lawrence T. Borgard
Chairman, Chief Executive Officer and Director (principal executive officer)
Lawrence T. Borgard
/s/ James F. Schott
Vice President, Chief Financial Officer and Director (principal financial officer)
James F. Schott
/s/ Linda M. Kallas
Vice President and Corporate Controller (principal accounting officer)
Linda M. Kallas
* By:
/s/ Linda M. Kallas
Linda M. Kallas
Attorney-in-Fact
SCHEDULE II
WISCONSIN PUBLIC SERVICE CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
Allowance for Doubtful Accounts
Years Ended December 31, 2012, 2011, and 2010
(In Millions)
(1)
Net of recoveries.
(2)
Represents amounts written off to the reserve, net of adjustments to regulatory assets.
EXHIBIT INDEX
Set forth below is a listing of all exhibits to this Annual Report on Form 10-K, including those incorporated by reference.
Certain other instruments, which would otherwise be required to be listed below, have not been so listed as such instruments do not authorize long-term securities in an amount that exceeds 10% of the total assets of us and our subsidiary on a consolidated basis. We agree to furnish a copy of any such instrument to the SEC upon request. Integrys Energy Group, Inc.'s SEC File No. is 1-11337.
*
Schedules and exhibits to this document are not filed therewith. The registrant agrees to furnish supplementally a copy of any such schedule or exhibit to the SEC upon request.
+
A management contract or compensatory plan or arrangement.
#
Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of SEC pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934, as amended. The redacted material was filed separately with the SEC.
^
In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.