ITEM 1. BUSINESS
A. INTRODUCTION
In this report, when we refer to "us," "we," "our," or "ours," we are referring to WPS. The term "utility" refers to our regulated activities, while the term "non-utility" refers to our activities that are not regulated, as well as the activities of our subsidiary, WPS Leasing. 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 an indirect wholly owned subsidiary of WEC Energy Group. We began operations in 1883. We are an electric and natural gas utility company serving an approximate 12,000-square-mile service territory in northeastern Wisconsin and Michigan's Upper Peninsula. Our three reportable segments are electric utility, natural gas utility, and other. In 2015, electric revenues accounted for 80% of our total utility revenues, while natural gas revenues accounted for 20% of our total utility revenues.
For more information about our electric and natural gas utility operations, including financial and geographic information, see Note 22, Segment Information, and Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations.
Merger
On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of our parent company, Integrys, and changed its name to WEC Energy Group, Inc. In this report, when we refer to the "WEC Merger," we are referring to this acquisition. For additional information on this merger, see Note 2, Merger.
Available Information
Our annual and periodic filings with the SEC are available, free of charge, through WEC Energy Group's website www.wecenergygroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC.
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 information filed or furnished electronically with the SEC at the SEC's website at www.sec.gov.
B. UTILITY OPERATIONS
ELECTRIC UTILITY SEGMENT
Our electric utility generates and distributes electric energy to customers located in northeastern Wisconsin and Michigan's Upper Peninsula.
Electric Utility Operating Statistics
The following table shows certain electric utility operating statistics for the past three years:
(1)
Includes amounts (refunded to) collected from customers for certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.
(2)
Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
Electric Sales
Our electric energy deliveries included supply and distribution sales to retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier. In 2015, retail electric revenues accounted for 85.5% of total electric operating revenues, while wholesale (including resale) electric revenues accounted for 16.3% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Electric Utility Segment Contribution to Operating Income for information on MWh sales by customer class.
We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities.
We buy and sell wholesale electric power by participating in the MISO Energy Markets. The cost of our generation offered into the MISO Energy Markets, compared to our competitors, affects how often our generating units are dispatched and how we buy and sell power. For more information, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -Factors Affecting Results, Liquidity, and Capital Resources - Industry Restructuring.
Large Electric Retail Customers
We provide electric utility service to a diversified base of customers in such industries as paper, foundry, food products and machinery production, health services, governmental, and large retail chains.
Wholesale Customers
We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. Wholesale sales accounted for 18.2%, 19.3%, and 17.7% of total electric energy sales during 2015, 2014, and 2013, respectively. Wholesale revenues accounted for 13.1%, 13.4%, and 12.8% of total electric operating revenues during 2015, 2014, and 2013, respectively.
Resale
The majority of our sales for resale are sold to one RTO, MISO, at market rates based on availability of our generation and RTO demand. Resale sales accounted for 6.4%, 4.2%, and 12.8% of total electric energy sales during 2015, 2014, and 2013, respectively. Resale revenues accounted for 3.2%, 3.0%, and 6.9% of total electric operating revenues during 2015, 2014, and 2013, respectively.
Electric Sales Growth
Our service territory experienced slightly declining weather-normalized retail electric sales in 2015 as positive customer growth was more than offset by reduced volumes related to lower use per customer. We currently forecast retail electric sales volumes to grow at a compound annual rate of between flat and 0.5% over the next five years, assuming normal weather. In addition, we forecast associated electric peak demand to grow at a compound annual rate of between flat to 0.5% over the next five years, also assuming normal weather.
Electric Generation and Supply Mix
Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable, and affordable supply of electricity. We supply a significant amount of electricity to our customers from power plants that we own. We supplement our internally generated power supply with long-term power purchase agreements and through spot purchases in the MISO Energy Markets.
Our rated capacity by fuel type as of December 31 is shown below. For more information on our electric generation facilities, see Item 2. Properties.
(1)
Rated capacity is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility, and amounts are based on expected capacity ratings for the following summer. The values were established by tests and may change slightly from year to year.
(2)
The natural gas steam turbine represents the rated capacity associated with Weston Unit 2, which was converted from coal to natural gas in 2015.
(3)
The dual-fueled facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local natural gas distribution company that delivers natural gas to the plants.
(4)
Includes hydroelectric and wind generation.
The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2016:
*
Represents system energy and capacity purchases used to meet customer requirements and certain FERC regulations.
Coal-Fired Generation
Our coal-fired generation consists of four operating plants with a rated capacity of 1,366 MW as of December 31, 2015. For more information about our operating plants, see Item 2. Properties.
Natural Gas-Fired Generation
Our natural gas-fired generation consists of five operating plants, including peaking units, with a rated capacity of 1,069 MW as of December 31, 2015. For more information about our operating plants, see Item 2. Properties.
Oil-Fired Generation
Fuel oil is used for a combustion turbine at one of our natural gas-fired plants, a WRPC jointly-owned unit, which did not have a rated capacity at December 31, 2015. We also have natural gas-fired peaking units with a rated capacity of 435 MW, which have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our operating plants, see Item 2. Properties.
Renewable Generation
Hydroelectric
Our hydroelectric generating system consists of 17 operating plants with a total installed capacity of 82 MW and a rated capacity of 60 MW as of December 31, 2015. All of our hydroelectric facilities follow FERC guidelines and/or regulations.
Wind
We have two wind sites, consisting of 80 turbines, with an installed capacity of 108 MW and a rated capacity of 22 MW as of December 31, 2015.
Electric System Reliability
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. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. 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. MISO has a 14.3% reserve margin requirement from January 1, 2016, through May 31, 2016, and 15.2% for the remainder of 2016. The MPSC does not have minimum guidelines for future supply reserves.
We had adequate capacity through company-owned generation units and power purchase contracts to meet the MISO calculated planning reserve margin during 2015 and expect to have adequate capacity to meet the planning reserve margin requirements during 2016. However, extremely hot weather, unexpected equipment failure or unavailability across the 15-state MISO market footprint could require us to call upon load management procedures. Load management procedures allow for the reduction of energy use through agreements with customers to directly shut off their equipment or through interruptible service, where customers agree to reduce their load in the case of an emergency interruption.
Fuel and Purchased Power Costs
Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, 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. For more information about the fuel rule, see Item 1. Business - D. Regulation.
Our average fuel and purchased power costs per MWh by fuel type were as follows for the year ended December 31:
We purchase coal under long-term contracts, which helps with price stability. Coal and associated transportation services have continued to see volatility in pricing due to changing domestic and world-wide demand for coal and the impacts of diesel costs, which are incorporated into fuel surcharges on rail transportation. Certain of our coal transportation contracts contain fuel cost adjustments that are tied to changes in diesel fuel and crude oil prices. Currently, diesel fuel contracts are not actively traded. Therefore, we use financial heating oil contracts to mitigate risk related to diesel fuel prices.
We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage.
We have a PSCW-approved hedging program that allows us to hedge up to 75% of our potential risks related to fuel surcharge exposure. We also have a program that allows us to hedge up to 75% of our estimated natural gas use for electric generation in order to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. The results of both of these programs are reflected in the average costs of natural gas and purchased power.
Coal Supply
We diversify the coal supply for our electric generating facilities and jointly-owned plants by purchasing coal from several mines in Wyoming, as well as from various other states. For 2016, approximately 57% of our total projected coal requirements of approximately 4 million tons are contracted under fixed-price contracts. See Note 18, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.
The annual tonnage amounts contracted for 2016 through 2018 are as follows:
Coal Deliveries
All of our 2016 coal requirements are expected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facilities. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.
Midcontinent Independent System Operator Costs
In connection with its status as a FERC approved RTO, MISO developed and operates the MISO Energy Markets, which include its bid-based energy markets and ancillary services market. We are a participant in the MISO Energy Markets. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas, and Missouri, a region referred to as MISO South. These changes have not had a material impact on our allocation of transmission costs, and we do not expect them to have a material impact in the future. For more information on MISO, see Item 1. Business - D. Regulation.
Power Purchase Commitments
We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. As of December 31, 2015, our power purchase commitments with unaffiliated parties for the next five years is 165 MW per year.
Other Matters
Seasonality
Our electric sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. Our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, we did not require any public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs for capacity reasons. However, we did have service curtailments for economic reasons.
Competition
We face competition from various entities and other forms of energy sources available to customers, including self-generation by large industrial customers and alternative energy sources. We compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.
The retail electric utility market in Wisconsin is regulated by the PSCW. Retail electric customers do not have the ability to choose their electric supplier, and it is uncertain when, if ever, retail electric choice might be implemented in Wisconsin. The regulated energy industry continues to experience significant structural changes, which could eventually lead to increased competition in Wisconsin.
The retail electric utility market in Michigan remains open to competition with its retail choice program, which allows customers to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We continue providing distribution and customer service functions regardless of the customer's power supplier.
Environmental Matters
For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 18, Commitments and Contingencies, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity, and Capital Resources - Environmental Matters.
NATURAL GAS UTILITY SEGMENT
We are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. We also transport customer-owned natural gas. Our natural gas utility provides service to customers located in northeastern Wisconsin and Michigan's Upper Peninsula.
Natural Gas Utility Operating Statistics
The following table shows certain natural gas utility operating statistics for the past three years:
Natural Gas Deliveries
Our gas therm deliveries include customer-owned transported natural gas. Transported natural gas accounted for approximately 46.3% of the total volumes delivered during 2015, 43.0% during 2014, and 43.8% during 2013. Our peak daily send-out during 2015 was 5.6 million therms on January 7, 2015.
Large Natural Gas Customers
We provide natural gas utility service to a diversified base of customers in such industries as paper, food products, educational, governmental, and health services.
Natural Gas Supply, Pipeline Capacity and Storage
We have been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas utility supply and transportation contracts, see Note 18, Commitments and Contingencies.
Pipeline Capacity and Storage
The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada, and the Rocky Mountains. We have contracted for long-term capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.
Due to the daily and seasonal variations in natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 35% of forecasted winter demand; November through March is considered the winter season. Storage capacity, along with our natural gas purchase contracts, enables us to manage significant changes in daily demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months when demand is lower and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity during periods of peak usage than would otherwise be necessary and can purchase natural gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.
We hold daily transportation and storage capacity entitlements with interstate pipeline companies as well as other service providers under varied-length long-term contracts.
Term Natural Gas Supply
We have contracts for firm supplies with terms of 3-5 months with suppliers for natural gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices.
Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our natural gas utilities' forecasted design peak-day throughput is 6.9 million therms for the 2015 through 2016 heating season.
The sources of our deliveries to customers (including transportation customers) were as follows:
Secondary Market Transactions
Pipeline long-line and storage capacity and natural gas supplies under contract can be resold in secondary markets. Local distribution companies, like our natural gas operations, must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. The secondary markets facilitate higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and natural gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to rate payers, subject to our approved GCRM. During 2015, we participated in the secondary markets. For information on our GCRM, see Note 1(d), Revenues and Customer Receivables.
Spot Market Natural Gas Supply
We expect to continue to make natural gas purchases in the spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase natural gas in the spot market.
Hedging Natural Gas Supply Prices
We have PSCW approval to hedge up to 67% of planned winter demand using a combination of planned withdrawals from storage and NYMEX financial instruments. This approval allows us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through our GCRM. Hedge targets (volumes) are provided annually to the PSCW as part of our three-year natural gas supply plan and risk management filing.
To the extent that opportunities develop and physical supply operating plans are supportive, we also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward-market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRM.
Seasonality
Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to variations in earnings and working capital throughout the year as a result of changes in weather.
Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be heavily concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through October. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through October. 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.
Competition
Competition in varying degrees exists between natural gas and other forms of energy available to consumers. A number of our large commercial and industrial customers are dual-fuel customers that are equipped to switch between natural gas and alternate fuels. We are allowed to offer lower-priced natural gas sales and transportation services to dual-fuel customers. Under natural gas transportation agreements, customers purchase natural gas directly from natural gas marketers and arrange with interstate pipelines and us to have the natural gas transported to their facilities. We earn substantially the same margin (difference between revenue and cost of natural gas) whether we sell and transport natural gas to customers or only transport their natural gas.
Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party natural gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively priced transportation service for those customers that desire to buy their own natural gas supplies.
Federal and state regulators continue to implement policies to bring more competition to the natural gas industry. While the natural gas utility distribution function is expected to remain a highly regulated, monopoly function, the sale of the natural gas commodity and related services are expected to remain subject to competition from third parties for large commercial and industrial customers. It remains uncertain if and when the current economic disincentives for small firm customers to choose an alternative natural gas commodity supplier may be removed such that we begin to face competition for the sale of natural gas to those customers.
C. NON-UTILITY OPERATIONS
OTHER SEGMENT
The other segment includes our non-utility activities as well as equity earnings from our investments in WRPC and WPS Investments, LLC. WPS Investments is an indirect wholly owned subsidiary of WEC Energy Group that is owned by Integrys and us. WPS Investments invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015, we had a 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC.
WRPC owns two hydroelectric plants and an oil-fired combustion turbine. We own 50% of the stock of WRPC. Half of the energy output of the hydroelectric plants is sold to us, and half is sold to Wisconsin Power and Light Company, an unaffiliated public utility. The electric power from the combustion turbine is also sold in equal parts to Wisconsin Power and Light Company and us.
D. REGULATION
In addition to the specific regulations noted below, we are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ, the Michigan Department of Natural Resources, and the U.S. Army Corps of Engineers.
Rates
Our retail electric and natural gas rates are regulated by the PSCW and the MPSC. The FERC regulates our wholesale electric rates. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.
Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount.
Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customers and our Wisconsin wholesale electric customers. Our natural gas operations operate under GCRMs as approved by the applicable state regulator. Generally, the GCRMs allow for a dollar-for-dollar recovery of prudently incurred natural gas costs.
For information on how our rates are set, see Note 21, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:
The material and information contained on these websites are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.
The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:
Electric Transmission, Capacity, and Energy Markets
In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which include the bid-based energy markets and an ancillary services market. We previously self-provided both regulation reserves and contingency reserves. In the MISO ancillary services market, we buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market has been able to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.
In MISO, base transmission costs are currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.
As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights (ARRs) and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2015 through May 31, 2016. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.
Beginning June 1, 2013, MISO instituted an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources could be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. Our capacity requirements during 2015 were primarily fulfilled using our own capacity resources.
Other Electric Regulations
We are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize the FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities, and modify certain other aspects of energy regulations and Federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by the FERC, which established mandatory electric reliability standards and which has the authority to levy monetary sanctions for failure to comply with these standards.
We are subject to Act 141 in Wisconsin and Public Act 295 in Michigan, which contain certain minimum requirements for renewable energy generation. See Note 18, Commitments and Contingencies, for more information.
All of our hydroelectric facilities follow FERC guidelines and/or regulations.
Other Natural Gas Regulations
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. In addition, the Pipeline and Hazardous Materials Safety Administration and the state commissions are responsible for monitoring and enforcing requirements governing our natural gas safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 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 natural gas service and grant credit (with applicable deposit requirements) to customers within our service territories. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to our low-income customers.
E. ENVIRONMENTAL COMPLIANCE
Our operations are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation of GHG emissions, coal combustion products, air emissions, or wastewater discharges, could significantly increase these environmental compliance costs.
Anticipated expenditures for environmental compliance and remediation issues for the next three years are included in the estimated capital expenditures described in Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Requirements in Item 7. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites, and air and water quality, see Note 18, Commitments and Contingencies, and Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity, and Capital Resources - Environmental Matters in Item 7.
F. EMPLOYEES
As of December 31, 2015, we had 1,329 employees, of which 1,267 were full-time. Approximately 917 of our total employees were represented by Local 420 of the International Union of Operating Engineers, AFL-CIO. The current Local 420 collective bargaining agreement expires on October 15, 2016.
ITEM 1A.
ITEM 1A. RISK FACTORS
We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.
Risks Related to Legislation and Regulation
Our business is significantly impacted by governmental regulation.
We are subject to significant state, local, and federal governmental regulation, including regulation by the PSCW, MPSC, and FERC. This regulation significantly influences our operating environment and may affect our ability to recover costs from utility customers. Many aspects of our operations are regulated, including, but not limited to: the rates we charge our retail electric and natural gas customers; wholesale power service practices; electric reliability requirements and accounting; participation in the interstate natural gas pipeline capacity market; standards of service; issuance of securities; short-term debt obligations; construction and operation of facilities; transactions with affiliates; and billing practices. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs. Failure to comply with any applicable rules or regulations may lead to customer refunds, penalties, and other payments, which could materially and adversely affect our results of operations and financial condition.
The rates we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation is based on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent on regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable ROE. We defer certain costs and revenues as regulatory assets and liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured, and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.
We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied with all of their associated terms, and that our business is conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies. Changes in regulations, interpretations of regulations, or the imposition of new regulations could influence our operating environment, may result in substantial compliance costs, or may require us to change our business operations.
If we are unable to obtain, renew, or comply with these governmental permits, approvals, authorizations, certificates, or licenses, or if we are unable to recover any increased costs of complying with additional requirements or any other associated costs in customer rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.
We may face significant costs to comply with existing and future environmental laws and regulations.
Our operations are subject to numerous federal and state environmental laws and regulations. These laws and regulations govern, among other things, air emissions (including CO2, methane, mercury, SO2, and NOx), water quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. We incur significant costs to comply with these environmental requirements, including costs associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at our facilities. In addition, if we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines.
The EPA has adopted and has implemented (or is in the process of implementing) regulations governing the emission of NOx, SO2, fine particulate matter, mercury, and other air pollutants under the CAA through the NAAQS, the MATS rule, the Clean Power Plan, the CSAPR, and other air quality regulations. In addition, the EPA has finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA
has also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters; however, this rule has been stayed. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. Several environmental regulations were either finalized or implemented during 2015, and there is still uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with these regulations.
Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that could result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations through emission control technology; operating restrictions on our facilities; and increased compliance costs. In addition, the operation of emission control equipment and compliance with rules regulating our intake and discharge of water could increase our operating costs and reduce the generating capacity of our power plants. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels.
As a result, certain of our coal-fired electric generating facilities may become uneconomical to maintain and operate, which could result in some of these units being retired early or converted to an alternative type of fuel. If generation facility owners in the Midwest, including us, are forced to retire a significant number of older coal-fired generation facilities, a potential reduction in the region's capacity reserve margin below acceptable risk levels may result. This could impair the reliability of the grid in the Midwest, particularly during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.
We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities, and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation, and related legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other third parties. Due to the potential for imposition of stricter standards and greater regulation in the future, as well as the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.
In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could contribute to reduced demand for electricity, which could adversely affect our results of operations, cash flows, and financial condition.
Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, has increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by environmental impacts and alleged exposure to hazardous materials have become more frequent. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.
We may face significant costs to comply with the regulation of greenhouse gas emissions.
Federal, state, regional, and international authorities have undertaken efforts to limit GHG emissions. In 2015, the EPA issued the Clean Power Plan, which is a final rule that regulates GHG emissions from existing generating units, as well as a proposed federal plan as an alternative to state compliance plans. The EPA also issued final performance standards for modified and reconstructed generating units, as well as for new fossil-fueled power plants. Under the Clean Power Plan, states are required to submit compliance plans as early as September 2016 to achieve state-specific GHG emission reductions by 2030. If Wisconsin or Michigan determines not to file a state compliance plan, we may be required to comply with the federal plan, which could result in more significant compliance costs than a state compliance plan. We are continuing to analyze the final rule and to work with other stakeholders to determine how to implement the Clean Power Plan and the potential impacts to our operations. In October 2015, numerous states
(including Wisconsin), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) denied the stay request, but on February 9, 2016, the United States Supreme Court (Supreme Court) stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of the state plans until the litigation is complete. Any state or federal compliance plans that are developed could be subject to change based upon the outcome of this litigation. In addition, on February 15, 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The rule could result in significant additional compliance costs, including capital expenditures, and impact how we operate our existing fossil-fueled power plants, all of which could have a material adverse impact on our operating costs.
There is no guarantee that we will be allowed to fully recover costs incurred to comply with the Clean Power Plan or that cost recovery will not be delayed or otherwise conditioned. The Clean Power Plan and any other related regulations that may be adopted in the future, either at the federal or state level, may cause our environmental compliance spending over the next several years to differ materially from the amounts currently estimated. These regulations could have a material adverse impact on our electric generation and natural gas distribution operations, could make some of our electric generating units uneconomic to maintain or operate, and could affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.
In addition, 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. CO2 is also a byproduct of natural gas consumption. As a result, future legislation to regulate GHG emissions could increase the price of natural gas, restrict the use of natural gas, and adversely affect our ability to operate our natural gas facilities. A significant increase in the price of natural gas may increase rates for our natural gas customers, which could reduce natural gas demand.
We could be subject to higher costs and penalties as a result of mandatory reliability standards.
We are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with the mandatory reliability standards could subject us to higher operating costs. If we were ever found to be in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.
Risks Related to the Operation of Our Business
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.
Our financial performance depends on the successful operation of our electric generation and natural gas and electric distribution facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or processes. Potential breakdown or failure may occur due to severe weather; catastrophic events (i.e., fires, earthquakes, explosions, tornadoes, floods, droughts, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security threats. Any of these events could lead to substantial financial losses.
Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.
Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of these lost revenues or increased expenses, which could adversely affect our results of operations and cash flows.
Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general economic conditions in our service areas, varying weather conditions, and energy conservation efforts.
Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:
•
Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including job losses, decreases in income, and business closings. We are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn or disruption of financial markets could adversely affect the financial condition of our customers and demand for their products. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.
•
Weather conditions. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income.
•
Our customers' continued focus on energy conservation and ability to meet their own energy needs. Customers could voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, and individual conservation efforts through the use of more energy efficient technologies. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. In addition, several states, including Wisconsin and Michigan, have adopted energy efficiency targets to reduce energy consumption by certain dates.
As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.
We are actively involved with several significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.
Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, natural gas storage, and other projects, including projects for environmental compliance.
Achieving the intended benefits of any large construction project is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. These risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of our regulators. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, the applicable commission may deem the additional capital costs as imprudent and disallow recovery of them through rates.
To the extent that delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and financial condition may be adversely affected.
Advances in technology could make our electric generating facilities less competitive.
Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, and energy efficiency. We generate power at central station power plants to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become more cost competitive. It is possible that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be
reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.
Our operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.
We face the risk of terrorist and cyber intrusions, both threatened and actual, against our generation facilities, electric and natural gas distribution infrastructure, our information and technology systems, and network infrastructure, including that of third parties on which we rely, any of which could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows.
We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission, distribution, and storage systems, could disrupt our operations and result in loss of service to customers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions 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.
We face on-going threats to our assets and technology systems. Despite the implementation of strong security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to human error or physical or cyber intrusions. If our assets or systems were to fail, be physically damaged, or be breached and were not recovered in a timely manner, we may be unable to perform critical business functions, and sensitive and other data could be compromised.
Our business requires the collection and retention of personally identifiable information of our customers and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.
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.
Transporting, distributing, and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.
Inherent in natural gas distribution activities are a variety of hazards and operational risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.
We may fail to attract and retain an appropriately qualified workforce.
We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.
Failure of our counterparties to meet their obligations, including obligations under power purchase agreements, could have an adverse impact on our results of operations.
We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, 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 required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.
We have entered into several power purchase agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. Revenues are dependent on the continued performance by the purchasers of their obligations under the power purchase agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more purchasers could fail to perform their obligations under the power purchase agreements. If this were to occur, we would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase agreement would be reallocated among our retail customers. To the extent there is any regulatory delay in adjusting rates, a customer default under a power purchase agreement could have a negative impact on our results of operations and cash flows.
Our revenues could be negatively impacted by competitive activity in the wholesale electricity markets.
The FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers, and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter. Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.
Risks Related to Economic and Market Volatility
Our business is dependent on our ability to successfully access capital markets.
We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost commercial paper markets.
Our access to the credit and capital markets could be limited, or our cost of capital significantly increased, due to any of the following risks and uncertainties:
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A rating downgrade;
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An economic downturn or uncertainty;
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Prevailing market conditions;
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Concerns over foreign economic conditions;
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Changes in tax policy;
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War or the threat of war; and
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The overall health and view of the utility and financial institution industries.
If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, it could limit our ability to implement, or increase the costs of implementing our business plan, which, in turn, could materially and adversely affect our results of operations, cash flows, and financial condition.
A downgrade in our credit ratings could negatively affect our ability to access capital at reasonable costs and/or require the posting of collateral.
There are a number of factors that impact our credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in our ratings if the rating agencies determine that the level of business or financial risk of us or the utility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings.
Any downgrade by the rating agencies could:
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Increase borrowing costs under our existing credit facility;
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Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;
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Decrease funding sources by limiting our access to the commercial paper market;
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Limit the availability of adequate credit support for our operations; and
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Trigger collateral requirements in various contracts.
Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.
Our margins and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.
We burn natural gas in several of our electric generation plants, and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas may increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations affecting its accessibility.
For Wisconsin customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Our natural gas operations receive dollar-for-dollar recovery of prudently incurred natural gas costs.
Changes in commodity prices could result in:
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Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;
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Reduced profitability to the extent that reduced margins, increased bad debt, and interest expense are not recovered through rates;
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Higher rates charged to our customers, which could impact our 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.
We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.
We are dependent on coal for much of our electric generating capacity. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. The suppliers under these agreements may experience financial or operational problems that inhibit their ability to
fulfill their obligations to us, or we may experience operational problems or constraints that prevent us from taking delivery. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Furthermore, demand for coal can impact its availability and cost. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coal-fired units and replace this lost generation through additional power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our cash flows.
Our electric generation frequently exceeds our customer load. When this occurs, we generally sell the excess generation into the MISO Energy Markets. If we are unable to run our lower cost units, we may lose the ability to engage in these opportunity sales, which may adversely affect our results of operations.
The use of derivative contracts could result in financial losses.
We use derivative instruments such as swaps, options, futures, and forwards to manage commodity price exposure. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.
Restructuring in the regulated energy industry could have a negative impact on our business.
The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us.
Michigan has adopted retail choice. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer. It is uncertain whether retail choice might be implemented in Wisconsin.
FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. The MISO Energy Markets rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes an LMP that reflects the market price for energy. As a participant in the MISO Energy Markets, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. MISO also implemented an ancillary services market for operating reserves that was simultaneously co-optimized with its existing energy markets.
These market designs continue to have the potential to increase the costs of transmission, the costs associated with inefficient generation dispatching, the costs of participation in the MISO Energy Markets, and the costs associated with estimated payment settlements.
We may experience poor investment performance of benefit plan holdings due to changes in assumptions and market conditions.
We have significant obligations related to pension and OPEB plans. If we are unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted.
Our cost of providing these plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future. Types of assumptions include earnings on 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 our required or voluntary contributions to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline
in the market value of plan assets, changes in interest rates, changes in demographics, including the number of retirements, or changes in life expectancy assumptions.
We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.
Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.
Risks Related to the WEC Merger
The WEC Merger may not achieve its anticipated results, and WEC Energy Group may be unable to integrate operations as expected.
The Merger Agreement was entered into with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of WEC Energy Group can be integrated in an efficient, effective, and timely manner.
It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees; the disruption of ongoing businesses, processes, and systems; or inconsistencies in standards, controls, procedures, practices, policies, and compensation arrangements, any of which could adversely affect WEC Energy Group's ability to achieve the anticipated benefits of the transaction as and when expected. WEC Energy Group may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve the anticipated benefits of the merger could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results, and prospects.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We own our principal properties outright, except that the major portion of our electric utility distribution lines and natural gas utility distribution mains and services are located, for the most part, on or under streets and highways and on land owned by others and are generally subject to granted easements, consents or permits.
Electric Facilities
The following table summarizes information on our electric generation facilities, including owned and jointly owned facilities, as of December 31, 2015:
(1)
Based on expected capacity ratings for summer 2016, which can differ from nameplate capacity, especially on wind projects. The summer period is the most relevant for capacity planning purposes. This is 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. 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 interest in this facility. Dairyland Power Cooperative holds the remaining 30%.
(3)
WRPC owns and operates the Juneau unit. We hold a 50% ownership interest in WRPC and are entitled to 50% of the total capacity from the Juneau unit.
(4)
WRPC owns and operates the Castle Rock and Petenwell units. We hold a 50% ownership interest in WRPC and are entitled to 50% of the total capacity at Castle Rock and Petenwell. Our share of capacity for Castle Rock is 8.1 MWs and our share of capacity for Petenwell is 10.2 MWs.
As of December 31, 2015, we operated approximately 18,700 miles of overhead distribution lines and 6,700 miles of underground distribution cable, located in Michigan and Wisconsin, as well as approximately 124 electric distribution substations and 190,500 line transformers.
Natural Gas Facilities
At December 31, 2015, 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 8,000 miles of natural gas distribution mains,
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Approximately 250 miles of natural gas transmission mains,
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Approximately 305,000 natural gas lateral services, and
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85 natural gas distribution and transmission gate stations.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In addition to those legal proceedings discussed in this Annual Report on Form 10-K, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.
See Note 18, Commitments and Contingencies, for more information on material legal proceedings and matters related to us and our subsidiary.
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
Dividends
Dividends declared on our common stock during the two most recent fiscal years are set forth below. Dividends were paid entirely in cash. Dividends were paid to our sole common stockholder, Integrys. There is no established public trading market for our common stock.
Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the Board of Directors and will depend upon, among other factors, our earnings, financial condition, and other requirements.
Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Integrys in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Integrys. See Note 11, Common Equity, for more information regarding restrictions on our ability to pay dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Omitted pursuant to General Instruction I(2)a.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CORPORATE DEVELOPMENTS
Introduction
We are an electric and natural gas utility and an indirect wholly owned subsidiary of WEC Energy Group. 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 utilities and cooperatives for resale. We conduct our business primarily in three reportable segments, an electric utility segment, a natural gas utility segment, and an other segment. See Note 22, Segment Information, for more information on our reportable business segments.
Corporate Strategy
Our goal is to create long-term value for WEC Energy Group's stockholders and our customers by focusing on the following:
Reliability
We have made significant reliability related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution network. We continue work on our System Modernization Reliability Project, which involves modernizing parts of our electric distribution system by burying or upgrading lines. The project focuses on electric lines that currently have the lowest reliability in our system, primarily in rural areas that are heavily forested.
Operating Efficiency
We continually look for ways to optimize the operating efficiency of our company.
Financial Discipline
A strong adherence to financial discipline is essential to earning our authorized ROE and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.
We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment that are no longer performing as intended, or have an unacceptable risk profile.
Exceptional Customer Care
Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.
RESULTS OF OPERATIONS
Consolidated Earnings
The following table compares our consolidated results:
Electric Utility Segment Contribution to Operating Income
Electric utility margins are defined as electric revenues less fuel and purchased power costs. We believe that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric revenues since the majority of prudently incurred fuel and purchased power costs are passed through to customers in current rates under enacted fuel rules.
The following tables provide information on delivered volumes by customer class and weather statistics:
*
Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
*
Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from the Green Bay Weather Station.
2015 Compared with 2014
Operating Income
Operating income at the electric utility segment decreased $10.8 million, driven by:
•
A $9.8 million decrease from electric margins as a result of the PSCW rate order, effective January 1, 2015. Although the PSCW approved an electric rate increase, the majority of the increase related to the higher cost of fuel for electric generation, which does not impact margins unless costs differ by 2% or less from the amounts included in rates. See Note 21, Regulatory Environment, for more information.
•
A $9.6 million increase in electric transmission expenses from MISO and ATC. This increase was driven by higher costs from MISO related to transmission providers' continued investment in equipment and facilities for improved reliability as well as increased costs to meet ATC's revenue requirements. Transmission expenses in 2015 reflect the PSCW's approval of escrow accounting treatment. We expect to recover the amounts deferred in a future rate case. See Note 21, Regulatory Environment, for more information.
•
A $5.6 million net decrease in electric margins related to retail sales volume variances. Margins from residential customers decreased, primarily due to warmer weather during the 2015 heating season and lower weather-normalized use per customer.
•
Severance expense of $3.6 million was recorded in 2015 related to the WEC Merger. See Note 2, Merger, for more information.
•
A $3.4 million decrease in wholesale margins driven by lower sales volumes in 2015. Certain wholesale customers have provisions in their contracts which allow them to reduce the amount of energy we provide to them.
•
A $3.2 million increase in depreciation and amortization expense, primarily due to the installation of scrubbers at the Columbia plant in April and July of 2014.
These decreases in operating income were partially offset by:
•
A $13.8 million decrease in maintenance expense, primarily due to planned major outages at Pulliam Unit 8 and Weston Unit 3 in 2014. Planned outages at our jointly-owned facilities were also less significant in 2015.
•
A $9.9 million increase in electric margins resulting from positive collections of actual fuel and purchased power costs in 2015, compared with 2014 collections which were less than actual costs incurred. Under the fuel rule, we defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins.
•
A $1.7 million net decrease in employee benefits costs and administrative and general salaries and compensation. The decrease was driven by the year-over-year impact of the 2014 amortization of a prior year deferral of certain employee benefit costs, partially offset by an increase in pension expense driven by lower discount rates in 2015.
2014 Compared with 2013
Operating Income
Operating income at the electric utility segment increased $15.3 million, driven by:
•
An approximate $35.0 million net increase in margins related to our PSCW rate order, effective January 1, 2014. Although the PSCW approved an electric rate decrease, the rate decrease was driven by 2013 positive fuel cost collections and 2012 positive decoupling collections that were being refunded to customers in 2014 and had no impact on margins. See Note 21, Regulatory Environment, for more information.
◦
Margins increased approximately $41.0 million as a result of the PSCW rate order, primarily driven by an increase in electric rate base from owning and operating the Fox Energy Center, which was included in rates beginning in 2014. In 2013, customer rates only included recovery of estimated purchased power costs from the Fox Energy Center.
◦
Margins were positively impacted by approximately $5.0 million mainly due to lower fly ash disposal costs in 2014. These costs are not included in the fuel rule recovery mechanism.
◦
Margins decreased by approximately $11.0 million due to fuel and purchased power cost collections in 2014 being less than actual costs incurred, compared with positive collections in 2013. Under the fuel rule, we can only defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates.
•
An approximate $9.0 million increase in wholesale margins driven by higher prices. Wholesale prices increased due to higher generation costs as well as an increase in electric rate base, resulting from the purchase of the Fox Energy Center in 2013 and the installation of environmental projects at the Columbia plant in 2014. Wholesale customers proportionally shared in these price increases through formula rates.
•
A $6.6 million decrease in operating expenses due to the year-over-year impact of the 2013 deferral of the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center. The 2013 PSCW rate order did not reflect this purchase or the related termination of a power purchase agreement. However, we did receive PSCW approval to defer ownership costs above or below our power purchase agreement expenses in 2013.
•
A $5.2 million net decrease in employee benefit costs, including the impact of the prior year deferral of some of these costs. Employee benefit costs other than stock-based compensation (discussed below) decreased $24.0 million in 2014. This decrease was driven by the continued funding of our pension plan and higher discount rates assumed in 2014 for both our pension and postretirement plans. The remeasurement of certain other postretirement benefit plans also contributed to the overall decrease in employee benefit costs. See Note 17, Employee Benefits, for more information. This decrease was partially offset by:
◦
Higher stock-based compensation expense of $4.3 million, which was primarily driven by an increase in the fair value of awards accounted for as liabilities. The increase in fair value resulted from an increase in Integrys's stock price.
◦
The year-over-year impact of a deferral of certain increases in employee benefit costs in 2013, recorded in accordance with our PSCW rate order, and the related amortization in 2014. Together, these changes increased employee benefit costs by $14.5 million.
These increases in operating income were partially offset by:
•
A $15.1 million increase in maintenance expense, primarily due to planned major outages in 2014 at the Pulliam plant, Fox Energy Center, and Weston 4, as well as maintenance at certain other generation plants. These increases were partially offset by the year-over-year impact of maintenance expenses associated with the Weston 3 planned major outage in 2013.
•
A $6.8 million increase in depreciation and amortization expense, mainly due to the acquisition of the Fox Energy Center at the end of the first quarter of 2013. In addition, we completed the installation of scrubbers at the Columbia plant in 2014.
•
A $6.0 million increase in costs associated with the acquisition and operation of the Fox Energy Center. The majority of this increase relates to the amortization of a regulatory asset related to the fee paid for the early termination of the Fox Energy Center power purchase agreement. Recovery of the amortization was included in the new rates.
•
A $5.4 million increase in electric transmission expense.
•
A decrease in margins of approximately $3.0 million related to sales volume variances. The decrease in margins was primarily driven by lower sales volumes from both our large commercial and industrial customers as well as our residential customers. The decrease in these sales volumes was driven by lower use per customer in 2014. This decrease was partially offset by the impact of the termination of our decoupling mechanism, effective January 1, 2014. See Note 21, Regulatory Environment, for more information. Our decoupling mechanism did not cover large commercial and industrial customers.
•
A $2.8 million increase in amortization of previously deferred production tax credits related to the Crane Creek wind project.
Natural Gas Utility Segment Contribution to Operating Income
Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold decreased 36.2% in 2015 and increased 44.0% in 2014, which had no impact on margins.
The following tables provide information on delivered sales volumes by customer class and weather statistics:
*
Normal heating degree days are based on a 20-year moving average of monthly temperatures from the Green Bay Weather Station.
2015 Compared with 2014
Operating Income
Operating income at the natural gas utility segment decreased $18.4 million, driven by:
•
A $13.9 million decrease in natural gas margins related to sales volume variances, primarily due to warmer weather in 2015.
•
A $6.5 million decrease in natural gas margins related to the PSCW rate order, effective January 1, 2015. Although the PSCW approved a much larger rate decrease in 2015, the majority of the decrease related to decoupling refunds to customers, which have no impact on margins. See Note 21, Regulatory Environment, for more information.
These decreases in operating income were partially offset by:
•
A $1.8 million net decrease in employee benefits costs and administrative and general salaries and compensation. The decrease was driven by the year-over-year impact of the 2014 amortization of a prior year deferral of certain employee benefit costs.
•
A $1.2 million decrease in operating expenses related to asset usage charges from WBS. See Note 4, Related Parties, for more information on WBS.
2014 Compared with 2013
Operating Income
Operating income at the natural gas utility segment increased $2.4 million, driven by:
•
The combined effect of the change in weather year over year, the impact of higher weather-normalized volumes, and the impact of our decoupling mechanism increased margins approximately $17.0 million. In 2014, our margins were positively impacted by colder than normal weather as we no longer had a decoupling mechanism in place, effective January 1, 2014. Higher use per customer and an increase in customers also contributed to the increase in margins in 2014.
•
A $2.1 million decrease in customer assistance expense, primarily driven by a reduction in costs for energy efficiency programs.
These increases in operating income were partially offset by:
•
Margins were negatively impacted by approximately $5.0 million related to our rate order, effective January 1, 2014. Although the PSCW approved a net rate increase, it was driven by the recovery of the 2012 decoupling under-collections to be recovered from customers in 2014, which has no impact on margins. See Note 21, Regulatory Environment, for more information.
•
A $3.1 million increase in natural gas distribution costs, driven in part by safety inspections performed during 2014. Additional meter maintenance and higher labor costs related to wage increases also contributed to the increase in costs.
•
A $1.4 million increase in bad debt expense, driven by higher natural gas costs in 2014 and an increase in sales volumes.
•
A $1.4 million increase in operating expenses driven by higher information technology costs. New servers and software for natural gas management and work asset management systems were placed in service during the third quarter of 2013, resulting in higher asset usage charges from WBS. Also, in 2014, several information technology projects and upgrades were performed, and additional information technology services were provided by WBS.
•
A $1.3 million increase in operating expenses driven by higher amortization of regulatory assets related to environmental cleanup costs for manufactured gas plant sites.
•
A $0.7 million net increase in employee benefit costs, driven by:
◦
A $4.3 million increase related to the negative year-over-year impact of the deferral of employee benefit costs in 2013 and the related amortization in 2014. In 2013, we deferred certain increases in pension and other employee benefit costs as a result of our 2013 rate order from the PSCW. We began amortizing this regulatory asset in 2014.
◦
A $1.8 million increase in stock-based compensation expense, primarily due to the year-over-year increase in the fair value of awards accounted for as liabilities. The increase in fair value resulted from an increase in Integrys's stock price.
◦
These increases were partially offset by a $5.3 million decrease in other employee benefit costs, driven in part by higher discount rates assumed in 2014. The remeasurement of certain postretirement benefit plans in the first quarter of 2014 also contributed to the decrease. See Note 17, Employee Benefits, for more information on this remeasurement.
•
A $0.6 million increase in depreciation and amortization expense, driven in part by additional investment in natural gas mains.
Other Segment Contribution to Operating Income
There were no significant changes in operating income related to the other segment for the periods presented.
Consolidated Other Income, Net
2015 Compared with 2014
Other income, net increased by $0.4 million when compared to 2014. This increase was primarily due to higher AFUDC as a result of the construction of the ReACTTM emission control technology at the Weston 3 plant, partially offset by environmental compliance projects at the Columbia plant completed in 2014 and a reduction in earnings from ATC related to the ROE complaint. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity, and Capital Resources - Other Matters - ATC Allowed ROE Complaint, for more information.
2014 Compared with 2013
Other income, net increased by $1.7 million when compared to 2013. This increase was primarily due to higher AFUDC as a result of the construction of the ReACTTM emission control technology at the Weston 3 plant, environmental projects at the Columbia plant, and the System Modernization and Reliability Project.
Consolidated Interest Expense
2015 Compared with 2014
Interest expense decreased by $3.9 million when compared to 2014, primarily due to a lower average outstanding intercompany long-term debt balance, and an increase in AFUDC. AFUDC was higher largely due to the construction on the ReACTTM emission
control technology at Weston Unit 3 plant, partially offset by environmental compliance projects at the Columbia plant completed earlier in 2014.
2014 Compared with 2013
Interest expense increased by $13.7 million when compared to 2013, primarily driven by higher average outstanding long-term debt in 2014. An increase in AFUDC partially offset this increase. AFUDC was higher largely due to the construction on the ReACTTM emission control technology at Weston Unit 3 plant and the System Modernization and Reliability Project, partially offset by environmental compliance projects at the Columbia plant completed earlier in 2014.
Consolidated Income Tax Expense
There were no significant changes in the effective tax rate for the periods presented.
For information on our effective tax rate and changes in the deferred income tax balances, see Note 15, Income Taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following summarizes our cash flows during 2015, 2014, and 2013:
Operating Activities
2015 Compared with 2014
Net cash provided by operating activities increased $41.2 million in 2015, driven by:
•
A $47.1 million decrease in contributions to pension and OPEB plans in 2015.
•
A $19.0 million increase in cash related to lower payments for operating and maintenance costs in 2015. The lower payments were partially driven by a decrease in electric utility maintenance.
•
A $14.6 million net increase in cash related to lower payments for natural gas, fuel, and purchased power, partially offset by a decrease in cash driven by lower overall collections from customers in 2015. This net increase was primarily due to the impact of lower commodity prices in 2015.
•
An $8.8 million increase in cash from customer prepayments and credit balances in 2015. In 2015, customer prepayments grew during the warmer winter.
These increases in cash were partially offset by:
•
A $20.7 million increase in cash paid for income taxes in 2015. The increase in cash paid was primarily related to a federal income tax refund received in 2014, partially offset by lower estimated tax payments in 2015.
•
A $13.6 million decrease in cash driven by higher collateral requirements in 2015. Additional collateral was required by MISO as a result of the WEC Merger.
•
A $5.0 million decrease in cash due to an increase in payments for environmental remediation activities in 2015.
2014 Compared with 2013
Net cash provided by operating activities decreased $9.6 million in 2014, driven by:
•
A $79.4 million decrease in cash due to higher costs of natural gas, fuel, and purchased power in 2014. Additional cash was used in 2014 due to higher energy prices and the colder weather.
•
A $21.1 million decrease in cash received from income taxes in 2014. The decrease in cash received was primarily related to quarterly income tax estimated payments, a federal income tax extension payment made in 2014, and an additional payment upon filing the 2013 tax return. A federal income tax refund received in the first quarter of 2014 for an amended return partially offset these income tax payments.
•
A $13.3 million decrease in cash due to increased operating and maintenance costs in 2014. The increase in operating and maintenance costs was driven by higher electric utility maintenance from planned major outages and other higher costs associated with owning and operating the Fox Energy Center beginning in March 2013.
•
A $12.9 million increase in cash paid for interest in 2014, primarily driven by higher average outstanding long-term debt in 2014.
•
A $9.0 million decrease in cash from various deferrals in 2014, primarily for SSR costs, precertification costs for a potential new natural gas combined cycle generating unit, and the net difference between actual and rate case-approved costs resulting from the purchase of the Fox Energy Center.
•
A $6.0 million increase in contributions to pension and other postretirement benefit plans in 2014.
•
A $5.0 million decrease in cash driven by higher collateral requirements in 2014. Collateral requirements are based on forward natural gas and electricity prices and forward positions with counterparties.
•
A $3.9 million decrease in cash from insurance recoveries received related to environmental remediation of manufactured gas plant sites in 2014.
•
A $3.4 million increase in cash used for environmental remediation activities in 2014.
These decreases in cash were partially offset by:
•
A $91.6 million increase in cash collections from customers, mainly due to rate increases, higher commodity prices, an increase in electric wholesale revenues, and the colder weather in 2014. Included in the electric rate increase was the impact of the increase in rate base related to owning and operating the Fox Energy Center.
•
The positive year-over-year impact of a $50.0 million payment in 2013 for the early termination of a tolling agreement in connection with the purchase of Fox Energy Company LLC.
•
A $5.9 million increase in cash from customer prepayments and credit balances in 2014. In 2013, cash received in relation to amounts billed was lower because customer prepayments had grown during an unusually warm 2012.
Investing Activities
2015 Compared with 2014
Net cash used for investing activities increased $52.2 million in 2015, primarily due to a $49.0 million increase in cash used for capital expenditures (discussed below).
2014 Compared with 2013
Net cash used for investing activities decreased $235.5 million in 2014, primarily due to $391.6 million of cash used in 2013 to purchase Fox Energy Company LLC. See Note 3, Acquisition, for more information regarding this purchase. Partially offsetting the decrease in net cash used was the year-over-year negative impact of the receipt of a $69.0 million Section 1603 Grant for the Crane Creek wind project in 2013 and an $85.9 million increase in cash used for other capital expenditures (discussed below).
Capital Expenditures
Capital expenditures by business segment for the year ended December 31 were as follows:
2015 Compared with 2014
The increase in capital expenditures at the electric utility segment in 2015 was primarily due to the construction of the ReACTTM emission control technology at Weston 3, the System Modernization and Reliability Project, and an expansion of our Legner landfill site. These increases were partially offset by lower capital expenditures related to environmental compliance projects at the Columbia plant in 2015.
2014 Compared with 2013
The decrease in capital expenditures at the electric utility segment was primarily due to our purchase of Fox Energy Company LLC in 2013. Capital expenditures related to environmental compliance projects at the Columbia plant also decreased in 2014. Increased expenditures in 2014 related to the ReACTTM project at Weston 3 and the System Modernization and Reliability Project partially offset the decrease.
The increase in capital expenditures at the natural gas utility segment was primarily related to reinforcements of transmission and distribution systems and the expansion of natural gas services to rural areas.
Financing Activities
2015 Compared with 2014
Net cash provided by financing activities increased $12.0 million in 2015, driven by:
•
A $180.0 million increase in equity contributions from Integrys in 2015.
•
A $124.9 million net increase in cash due to the issuance of $250.0 million of long-term debt in 2015, partially offset by the repayment of $125.1 million of long-term debt in 2015.
These increases in cash were partially offset by:
•
A $150.0 million return of capital to Integrys in 2015.
•
An $81.8 million decrease in cash due to a decrease in net borrowings of commercial paper in 2015.
•
A $52.7 million decrease in cash due to a redemption of preferred stock in 2015. See Note 12, Preferred Stock, for more information.
•
A $3.3 million decrease in cash due to an increase in dividends paid to Integrys in 2015.
2014 Compared with 2013
Net cash provided by financing activities decreased $225.4 million in 2014, driven by:
•
A $303.0 million net decrease in cash due to a $450.0 million decrease in the issuance of long-term debt, which was partially offset by a $147.0 million decrease in the repayment of long-term debt. The issuance of long-term debt in 2013 was partially used to finance the acquisition of Fox Energy Company LLC.
•
A $145.0 million decrease in equity contributions from Integrys, which were used to support the acquisition of Fox Energy Company LLC in 2013.
These decreases in cash were partially offset by:
•
A $189.3 million year-over-year increase in net cash provided by financing activities due to $119.5 million of net borrowings of commercial paper in 2014, compared with $69.8 million of net repayments of commercial paper in 2013.
•
A $35.0 million return of capital to our parent in 2013.
Significant Financing Activities
For information on our short-term debt, see Note 13, Short-Term Debt and Lines of Credit.
For information on our long-term debt, see Note 14, Long-Term Debt.
Capital Resources and Requirements
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 capital markets, and available borrowing capacity under our existing credit facility. 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. Our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control.
Liquidity
Management prioritizes the use of capital and debt capacity, determines cash management policies, uses risk management strategies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage our liquidity and capital resource needs. We plan to meet our capital requirements for the period 2016 through 2018 primarily through internally generated funds (net of forecasted dividend payments to our parent), debt financings, and equity infusions from Integrys. We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.
We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 13, Short-Term Debt and Lines of Credit, for more information about our credit facility and other short-term credit agreements.
At December 31, 2015, 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 13, Short-Term Debt and Lines of Credit, for more information on our credit facility and other short-term credit agreements. See Note 14, Long-Term Debt, for more information on our long-term debt.
Working Capital
As of December 31, 2015, our current liabilities exceeded our current assets by $60.0 million. We do not expect this to have any impact on our liquidity because we believe we have an adequate back-up line of credit in place for ongoing operations. We also have access to the capital markets to finance our construction programs and to refinance current maturities of long-term debt if necessary.
Capital Requirements
Contractual Obligations
The following table shows our contractual obligations as of December 31, 2015, including those of our subsidiary:
(1)
The amounts included in the table are calculated using current market prices, forward curves, and other estimates.
(2)
Principal and interest payments on long-term debt.
(3)
Operating lease obligations for power purchase commitments and rail car leases.
(4)
Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility operations.
(5)
Purchase obligations related to normal business operations, information technology, and other services.
(6)
Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2018.
The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $83.5 million at December 31, 2015, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 18, Commitments and Contingencies, for more information about environmental liabilities.
The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note 15, Income Taxes.
AROs in the amount of $32.7 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled beyond 2020.
Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.
Capital Expenditures and Significant Capital Projects
We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:
The majority of spending consists of upgrading our electric and natural gas distribution systems.
Common Stock Matters
For information related to our common stock matters, see Note 11, Common Equity.
Investments in Outside Trusts
We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $943.5 million as of December 31, 2015. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $2.4 million, $49.5 million, and $43.5 million to our pension and OPEB plans in 2015, 2014, and 2013, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 17, Employee Benefits.
Off-Balance Sheet Arrangements
We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 16, Guarantees.
Factors Affecting Results, Liquidity, and Capital Resources
Market Risks and Other Significant Risks
We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to:
Regulatory Recovery
We account for our regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory authorities. Our primary regulator is the PSCW.
Regulated entities are allowed to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. In general, regulatory assets are recovered in a period between one to six years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2015, our regulatory assets totaled $462.7 million and our regulatory liabilities totaled $293.6 million.
Regarding our ReACT™ project, the PSCW approved deferral of costs above the originally authorized $275.0 million level through 2016. We will be required to obtain a separate approval for collection of these deferred costs. Also, prior to the WEC Merger (for a discussion of the merger see Note 2, Merger), Integrys initiated an IT project with the goal of improving the customer experience at its subsidiaries, including us. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of December 31, 2015, none of the costs have been disallowed in rate proceedings. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.
See Note 21, Regulatory Environment, for additional information regarding recent rate proceedings, orders, and investigations.
Commodity Costs
In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.
Embedded within our rates are amounts to recover fuel, natural gas, and purchased power costs. We have recovery mechanisms in place that allow us to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business - D. Regulation for more information on these mechanisms.
Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.
Weather
Our utility rates are based upon estimated normal temperatures. Our electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas revenues are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2015, 2014, and 2013, as measured by degree days, may be found above in Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations.
Interest Rates
We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our 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. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.
Based on our variable rate debt outstanding at December 31, 2015, and December 31, 2014, a hypothetical increase in market interest rates of one-percentage point would have increased annual interest expense by $1.8 million and $1.5 million, respectively. 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.
Marketable Securities Return
We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.
The fair value of our trust fund assets and expected long-term returns were approximately:
Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.
WEC Energy Group consults with its investment advisors on an annual basis to help it forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.
Economic Conditions
Our service territory is within the state of Wisconsin and the Upper Peninsula of Michigan. As such, we are exposed to market risks in the regional midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.
Inflation
We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.
For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Risk Factors in Item 1A.
Industry Restructuring
Electric Utility Industry
The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which affects the structure of the wholesale market. To this end, MISO implemented the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when retail choice might be implemented, if at all, in Wisconsin. However, Michigan has adopted retail choice.
Restructuring in Wisconsin
Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW has been focused on electric reliability infrastructure issues for the state of Wisconsin in recent years. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.
Restructuring in Michigan
Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. Some of our small retail customers have switched to an alternative electric supplier. The law limits customer choice to 10% of our Michigan retail load. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.
Natural Gas Utility Industry
Restructuring in Wisconsin
The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer classes with workably competitive market choices and has adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas directly from a third party supplier. However, work on deregulation of the natural gas distribution
industry by the PSCW continues to be on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.
Restructuring in Michigan
The option to choose an alternative retail natural gas supplier has been provided to our Michigan customers since the late 1990s. We are not required by the MPSC or state law to make this option available to customers, but since this option is currently provided to customers, we would need MPSC approval to eliminate it.
We offer natural gas transportation service to customers that select an alternative retail natural gas supplier. Transportation customers purchase natural gas directly from an alternative retail natural gas supplier and use our distribution system to transport the natural gas to their facilities. We still earn a distribution charge when we transport natural gas for these customers. As such, the loss of revenue associated with the natural gas that transportation customers purchase from an alternative retail natural gas supplier has little impact on our net income, since it is offset by an equal reduction to natural gas costs.
Environmental Matters
Cross-State Air Pollution Rule
In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule (CAIR). The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allocation plan and allowance trading scheme. The rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court). In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The compliance deadlines were also changed by three years, so that Phase I emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond.
In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and plans to issue a final rule by August 2016. Starting in 2017, this proposed rule would reduce ozone season (May 1 through September 30) NOx emissions from power plants in 23 states in the eastern United States. In this rule, the EPA is proposing to update Phase II CSAPR NOx ozone season budgets for electric generating units in the 23 states. An approximate 60% reduction in NOx emissions is proposed for Wisconsin beginning in May 2017. Additional investments in controls and/or shifts in generation may be required depending upon the final outcome of the rule. We submitted comments to the EPA on the potential impacts of the rule.
See Note 18, Commitments and Contingencies, for a discussion of additional environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, renewable energy requirements, and climate change.
Other Matters
American Transmission Company Allowed Return On Equity Complaint
In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. The FERC conducted hearings in August 2015, and the administrative law judge (ALJ) issued an initial decision in December 2015. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The ALJ's recommendation is not binding to the FERC. A FERC order related to this complaint is expected during the fourth quarter of 2016.
In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to the filing date of the complaint. The FERC conducted hearings in February 2016 with respect to this second complaint, and an initial decision is expected by June 30, 2016.
In October 2014, the FERC issued an order, in regard to a similar complaint, reducing the base ROE for New England transmission owners from their existing rate of 11.14% to 10.57%. In this order, the FERC used a revised method for determining the appropriate ROE for FERC-jurisdictional electric utilities. The FERC expects its new methodology will narrow the "zone" of reasonable returns on equity. The FERC has stated that it expects future decisions on pending complaints related to similar ROE issues to be guided by the New England transmission decision.
Any change to ATC's ROE could result in lower equity earnings and distributions from ATC in the future. We are currently unable to determine how the FERC may rule in these complaints. However, we believe it is probable that refunds will be required upon resolution of these issues. Based on the ALJ's initial decision in December 2015, ATC reduced its earnings, which resulted in us recognizing lower earnings from our investment in ATC.
Presque Isle System Support Resource Costs
In August 2013, Wisconsin Electric notified MISO of its intention to suspend the operation of Units 5 through 9 of its Presque Isle generating facility for 16 months, starting February 1, 2014. MISO notified Wisconsin Electric in October 2013 that the Presque Isle facilities are required for reliability and would be SSR-designated. Under the terms of the SSR Tariff, in exchange for keeping the units in service, MISO initially planned to compensate Wisconsin Electric by allocating the SSR costs associated with the operation of the Presque Isle units to regulated and nonregulated load-serving entities, including us, based on load ratio share within the ATC footprint. In February 2015, Wisconsin Electric notified MISO of its intent to rescind its decision to retire the Presque Isle Facility and requested termination of the SSR agreement, effective February 1, 2015. This intent to rescind was driven by a settlement agreement related to the WEC Merger. In April 2015, the FERC approved the termination of the SSR agreement effective February 1, 2015.
In May 2015, MISO made a compliance filing regarding the allocation of Presque Isle SSR costs incurred while the SSR was in effect, which did not allocate any of these SSR costs to us. In September 2015, the FERC approved MISO's new cost allocation method. Subsequently, several parties sought a rehearing of this FERC order, which is still pending.
A potential reallocation of the Presque Isle SSR costs based on the rehearing requests may result in a change in SSR costs allocated to us. SSR costs for our retail customers will be deferred until December 31, 2016, based on a December 2015 order from the PSCW. See Note 21, Regulatory Environment, for more information. We expect that costs for our Michigan customers would be recovered through the Power Supply Cost Recovery mechanism, and costs for our wholesale customers would be recovered through formula rates.
Wisconsin Power and Light's (WP&L) Riverside Energy Center Facility
In April 2015, WP&L filed a CPCN application with the PSCW for approval to construct an approximate 650 MW natural gas-fired combined-cycle generating unit in Beloit, Wisconsin. Recent construction proposals received by WP&L indicate that the unit could generate up to 700 MWs. In the third quarter of 2015, we, along with our affiliated utility, Wisconsin Electric, requested and received intervention in this proceeding. As intervenors, we and Wisconsin Electric proposed purchased power agreement alternatives to the new generating unit. In December 2015, we entered into a settlement agreement with Wisconsin Electric and WP&L that was approved by the PSCW. Based on the settlement agreement, the generating unit cannot become commercially operational before June 1, 2020. We will have the option to purchase an undivided ownership interest of up to 100 MWs of generating capacity from the unit during the first two years of operation and up to an aggregate 200 MWs of generating capacity during the third and fourth years of operation. Other major terms of the settlement included agreement on ownership of future natural gas units, negotiation of a renewable generation joint development plan, and ownership terms of the jointly-owned Columbia plant.
Bonus Depreciation Provisions
The Protecting Americans from Tax Hikes Act of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in service during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and 30% bonus depreciation to assets placed in service during 2019. Bonus depreciation is an additional amount of deductible depreciation that is awarded above and beyond what would normally be available.
Critical Accounting Policies and Estimates
Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgments.
Goodwill Impairment
We completed our annual goodwill impairment test for our natural gas utility reporting unit as of April 1, 2015. 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 the 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 ROE, the long-term growth rate used to determine the terminal value at the end of the discrete forecast period, and the discount rate. 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 value 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. While our annual goodwill impairment test indicated an impairment is unlikely, subsequent changes in these assumptions and estimates could change the results of the test.
Pension and Other Postretirement Employee Benefits
The costs of providing non-contributory defined benefit pension benefits and OPEB, described in Note 17, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
Pension and OPEB 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 OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.
Pension and OPEB 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. We believe that such changes in costs would be recovered or 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 OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
In the fourth quarter of 2014, the Society of Actuaries published a new set of mortality tables, which updated life expectancy assumptions. We have adjusted the tables to better reflect our plan-specific mortality experience and other general assumptions. We have incorporated the revised mortality tables into the projected pension and OPEB obligations at December 31, 2015.
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 $50.0 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 on pension plan assets was 7.75% in 2015 and 8.00% in both 2014 and 2013, respectively. The actual rate of return on pension plan assets, net of fees, was (3.3)%, 6.2%, and 15.2%, in 2015, 2014, and 2013, respectively.
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 our pension and OPEB, see Note 17, Employee Benefits.
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 us. 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 considered 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 our electric and natural gas 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 segments' operations no longer meet the criteria for application. Our regulatory assets and liabilities would be
written off as a charge to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2015, we had $462.7 million in regulatory assets and $293.6 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.
Unbilled Revenues
We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total operating revenues during 2015 of approximately $1.5 billion included accrued revenues of $54.3 million as of December 31, 2015.
Income Tax Expense
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 income tax expense in our 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(m), Income Taxes, and Note 15, Income Taxes, for a discussion of accounting for income taxes.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity, and Capital Resources - Market Risks and Other Significant Risks in Item 7. of this report, as well as Note 1(q), Derivative Instruments, Note 1(p), Fair Value Measurements, and Note 16, Guarantees, for information concerning potential market risks to which we are exposed.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders 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, 2015 and 2014, and the related consolidated statements of income, equity, and cash flows for each of the three years in the period ended December 31, 2015. 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Public Service Corporation and subsidiary as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, 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, present fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
February 26, 2016
B. CONSOLIDATED INCOME STATEMENTS
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
C. CONSOLIDATED BALANCE SHEETS
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
D. CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
E. CONSOLIDATED STATEMENTS OF EQUITY
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
F. CONSOLIDATED STATEMENTS OF CAPITALIZATION
*
In November 2015, we redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2015
NOTE 1-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) General Information-On June 29, 2015, Wisconsin Energy Corporation acquired our parent company, Integrys, and changed its name to WEC Energy Group. See Note 2, Merger, for more information on the acquisition.
We are an electric and natural gas utility company that services customers in northeastern Wisconsin and 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 income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.
At December 31, 2015, we had one wholly owned subsidiary, WPS Leasing. The financial statements include our accounts and the accounts of our wholly owned subsidiary. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information. 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 companies 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.
We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and 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.
(b) Reclassifications-As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below.
Statements of Income
•
Certain amortizations of deferrals were reclassified from other operation and maintenance to cost of sales; depreciation and amortization; and other income, net.
•
Payroll taxes of $8.3 million and $8.9 million for the years ended December 31, 2014 and 2013, respectively, were reclassified from taxes other than income taxes to other operation and maintenance. The taxes other than income taxes line item was also renamed to property and revenue taxes.
•
Certain expenses in cost of sales were reclassified to operating revenues, other operation and maintenance, and depreciation and amortization. The amounts reclassified to other operation and maintenance were $5.9 million and $6.7 million for the years ended December 31, 2014 and 2013, respectively.
•
Certain expenses in other operation and maintenance were reclassified to cost of sales, and depreciation and amortization. The amounts reclassified to other cost of sales were $3.1 million and $5.6 million for the years ended December 31, 2014 and 2013, respectively.
Balance Sheets
•
Current regulatory assets of $1.4 million and $23.6 million were reclassified to accounts receivable and long-term regulatory assets, respectively, at December 31, 2014.
•
Current regulatory liabilities of $6.1 million and $15.1 million were reclassified to other current liabilities and long-term regulatory liabilities, respectively, at December 31, 2014.
•
During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $0.6 million and $8.8 million, previously reported as other current assets and other long-term assets, respectively, were reclassified to offset long-term debt on the December 31, 2014 balance sheet.
•
During the fourth quarter of 2015, we also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $3.8 million, previously reported as a component of other current liabilities, to long-term deferred income tax liabilities on the December 31, 2014 balance sheet.
Statements of Cash Flows
•
Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections.
(c) Cash and Cash Equivalents-Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
(d) Revenues and Customer Receivables-We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers.
We present revenues net of pass-through taxes on the income statements.
Below is a summary of the significant mechanisms we had in place that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts:
•
Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations.
•
Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, 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. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater return on common equity than authorized by the PSCW.
•
Our natural gas utility rates included a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.
Revenues are also impacted by other accounting policies related to our participation in the MISO Energy Markets. We sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If we were a net seller in a particular hour, the net amount was reported as operating revenue. If we were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements.
We provide regulated electric and natural gas service to customers in northeastern Wisconsin and Michigan's Upper Peninsula. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. As a result, we did not have any significant concentrations of credit risk at December 31, 2015. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015.
(e) Materials, Supplies, and Inventories-Our inventory as of December 31 consisted of:
Substantially all fossil fuels, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
(f) Regulatory Assets and Liabilities-The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities 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. 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 reporting period the determination is made. See Note 6, Regulatory Assets and Liabilities, for more information.
(g) Property, Plant, and Equipment-We record property, plant, and equipment at cost. Cost includes material, labor, and overhead. Utility property also includes AFUDC - Equity. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.
We record straight-line depreciation expense over the estimated useful life of utility property, using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:
We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which is three years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.
We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense.
See Note 7, Property, Plant, and Equipment, for more information.
(h) Allowance for Funds Used During Construction-AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - Debt) used during plant construction, and a return on stockholders' capital (AFUDC - Equity) used for construction purposes. AFUDC - Debt is recorded as a reduction of interest expense, and AFUDC - Equity is recorded in other income, net.
Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 7.92%, 8.08%, and 8.61% for 2015, 2014, and 2013, respectively. Our average AFUDC wholesale rates were 5.10%, 6.99%, and 2.64% for 2015, 2014, and 2013, respectively.
We recorded the following AFUDC for the years ended December 31:
(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. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers.
(j) Goodwill-Goodwill is subject to an annual impairment test. Our natural gas utility reporting unit contains goodwill and performed its annual goodwill impairment test as of April 1, 2015. 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.
(k) Asset Retirement Obligations-We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. A liability is recorded, when incurred, 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 associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is incurred. 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 to the carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.
(l) Environmental Remediation Costs - We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 18, Commitments and Contingencies, for more information.
We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of possible losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potential responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.
We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state's Commission's approval.
We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.
(m) Income Taxes - We and our subsidiary are included in the consolidated United States income tax return filed by Integrys for all tax periods up to and including the tax year ended June 29, 2015. For all tax periods after June 29, 2015, we and our subsidiary are included within the WEC Energy Group consolidated return. Similarly, we and our subsidiary are party to a tax allocation arrangement with Integrys and its consolidated subsidiaries for all tax periods up to and including June 29, 2015, and are a party to a tax allocation arrangement with WEC Energy Group and its consolidated subsidiaries for tax periods ending after June 29, 2015.
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. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.
We report interest and penalties accrued, related to income taxes, as a component of income tax expense in our income statements.
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.
See Note 15, Income Taxes, for more information regarding our accounting for income taxes.
(n) Guarantees-We follow the guidance of the Guarantees Topic 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. See Note 21, Regulatory Environment, for more information.
(o) Employee Benefits-The costs of pension and OPEB are expensed over the periods during which employees render service. The benefit costs associated with employee benefit plans are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information.
(p) Fair Value Measurements-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).
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 methods.
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input.
Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available. We recognize transfers at the value as of the end of the reporting period.
Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount for each such item approximates fair value. The fair values of long-term debt, including the current portion of long-term debt, are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity.
We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.
See Note 19, Fair Value Measurements, for more information.
(q) Derivative Instruments-We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by the PSCW and the MPSC.
We record derivative instruments on our balance sheets as an asset or liability measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. 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. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.
We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Gains and losses on derivative instruments are primarily recorded in cost of sales on our income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.
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 our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 20, Derivative Instruments, for more information.
(r) Customer Deposits and Credit Balances-When utility customers apply for new service, they may be required to provide a deposit for the service.
Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within accounts payable on our balance sheets.
NOTE 2-MERGER
On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of Wisconsin Energy Corporation. Wisconsin Energy Corporation then changed its name to WEC Energy Group. The merger was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order requires that any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and Wisconsin Electric filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time. We have been authorized to recover the costs we have recorded at December 31, 2015 related to the proposed construction.
We do not believe that the conditions set forth in the various regulatory orders approving the WEC Merger will have a material impact on our operations or financial results.
In 2015, we recorded $4.6 million of severance expense that resulted from employee reductions related to the post-merger integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $4.3 million were made during 2015, leaving an insignificant severance accrual on our balance sheet at December 31, 2015. Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments:
NOTE 3-ACQUISITION
In March 2013, we acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved immediately after the purchase.
The purchase included the Fox Energy Center, a 593 MW combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives us a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.
The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:
(1)
Relates to the electric utility segment.
(2)
Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information.
Prior to the purchase, we supplied natural gas for the facility and purchased 500 MWs of capacity and the associated energy output under a tolling arrangement. We paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as we are authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.
Our 2015 retail electric rate increase included the recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. See Note 21, Regulatory Environment, for more information. Our rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center.
Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by us. The plant is now part of our regulated fleet, used to serve our customers.
NOTE 4-RELATED PARTIES
We and our subsidiary, WPS Leasing, routinely enter into transactions with related parties, including WEC 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 ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the WEC Merger on June 29, 2015, Integrys Business Support, LLC (IBS) changed its name to WBS, and a new affiliated interest agreement (Non-WBS AIA) went into effect. The new Non-WBS AIA includes the former Wisconsin Energy Corporation and its subsidiaries. It governs the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS will continue to provide services to Integrys and its subsidiaries only under the existing WBS affiliated interest agreements (WBS AIAs). WBS will provide services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries under new interim WBS affiliated interest agreements (interim WBS AIAs). The Non-WBS AIA includes no other significant changes from the prior Non-IBS affiliated interest agreement. The PSCW and all other relevant state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA.
Services under the Non-WBS AIA are subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary are priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary are priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary are
priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS are priced at cost.
WBS provides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to the WBS AIAs, which have 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, WBS 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 WBS AIAs. Other modifications or amendments to the WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases.
The PSCW orders approving the Non-WBS AIA and the interim WBS AIAs include an April 1, 2016, sunset date for WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries. These companies may request one extension of the sunset date. Prior to the sunset date, we, along with WEC Energy Group, will file new or modified Non-WBS and WBS AIAs for approval with the PSCW and other state commissions.
We provide services to and receive services from ATC for its 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 and from WRPC under these agreements at a fully allocated cost.
The table below includes information summarizing other transactions entered into with related parties:
*
WPS Leasing, our consolidated subsidiary, has a note payable to Integrys. At December 31, 2015 and 2014, the current portion of the note payable was $2.9 million and $2.5 million, respectively.
The following table shows activity associated with our other related party transactions for the years ended December 31:
(1)
Integrys sold UPPCO in August 2014.
(2)
In February 2016, an agreement was entered into to sell ITF. This sale is scheduled to close in the first quarter of 2016.
(3)
Integrys sold IES's retail energy business in November 2014.
(4)
WPS Leasing has a note payable to Integrys.
(5)
WPS Investments, LLC is an indirect wholly-owned subsidiary of WEC Energy Group that is jointly owned by Integrys and us. WPS Investments, LLC invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015, we had an 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC.
(6)
In November 2015, ITF, an indirect wholly-owned subsidiary of Integrys, sold its ownership interest in AMP Trillium, LLC, a joint venture between ITF and AMP Americas, LLC. This joint venture owned and operated compressed natural gas fueling stations.
NOTE 5-SUPPLEMENTAL CASH FLOW INFORMATION
NOTE 6-REGULATORY ASSETS AND LIABILITIES
The following regulatory assets were reflected on our balance sheets as of December 31:
(1)
Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in the table above.
(2)
As of December 31, 2015, we had $21.0 million of regulatory assets not earning a return.
(3)
Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans.
(4)
As of December 31, 2015, we had not yet made cash expenditures for $83.5 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.
(5)
Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years.
(6)
In 2012, we elected to claim and subsequently received a Section 1603 Grant for the 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 and are authorized recovery of this net regulatory asset through 2039.
(7)
Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them 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.
(8)
Represents energy costs that will be recovered from customers in the future.
(9)
Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets.
The following regulatory liabilities were reflected on our balance sheets as of December 31:
(1)
Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.
(2)
Represents energy costs that will be refunded to customers in the future.
(3)
Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above.
(4)
Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.
NOTE 7-PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following utility and non-utility assets at December 31:
*
In connection with the Consent Decree with the EPA, we retired Weston 1 and Pulliam Units 5 and 6 on June 1, 2015. See Note 18, Commitments and Contingencies, for more information regarding the Consent Decree.
NOTE 8-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 as property, plant, and equipment on the balance sheets. The amounts were as follows at December 31, 2015:
*
Based on expected capacity ratings for summer 2016. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.
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. See Note 18, Commitments and Contingencies, for information related to the requirement to refuel, repower, or retire Edgewater Unit 4.
NOTE 9-ASSET RETIREMENT OBLIGATIONS
We have recorded AROs primarily for asbestos abatement at certain generation facilities, office buildings, and service centers; the dismantling of wind generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the 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 ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities.
The following table shows changes to our AROs:
(1)
An ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates.
(2)
We revised the AROs recorded for the asbestos at our electric generation facilities primarily due to changes in estimated settlement dates.
NOTE 10-GOODWILL AND OTHER INTANGIBLE ASSETS
We had no changes to the carrying amount of goodwill during the years ended December 31, 2015 and 2014. In the second quarter of 2015, we completed our annual goodwill impairment test, and no impairment resulted from this test.
The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets.
*
Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2015, was approximately three years.
NOTE 11-COMMON EQUITY
Stock-Based Compensation
Our employees were granted awards under Integrys’s stock-based compensation plans. Pursuant to the Merger Agreement, immediately prior to completion of the merger, all outstanding stock-based compensation awards became fully vested and were settled in exchange for the right to be paid out in cash to award recipients. See Note 2, Merger, for more information regarding the merger.
The intrinsic values of the awards settled due to the merger were $1.5 million and $5.2 million for performance stock rights and restricted stock units, respectively. The intrinsic value of stock options settled was not significant.
Compensation cost associated with stock-based compensation awards was 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 income tax benefit recognized in income for the years ended December 31:
A summary of the activity for our stock-based compensation awards for the year ended December 31, 2015, is presented below:
*
The intrinsic value of restricted stock unit awards vested and released was $2.2 million. The intrinsic value of stock options exercised and shares distributed for performance stock rights was not significant.
Restrictions
Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys.
In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 51%. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level.
See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.
As of December 31, 2015, restricted retained earnings totaled $528.5 million. Our equity in undistributed earnings of investees accounted for by the equity method was $32.3 million at December 31, 2015.
Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.
Integrys 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 WEC Energy Group, Integrys, or their other subsidiaries.
NOTE 12-PREFERRED STOCK
The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014:
On November 13, 2015, we redeemed all 511,882 outstanding shares of our five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and, (v) 150,000 shares of 6.88% Series. The aggregate redemption price was $52.7 million, plus accumulated and unpaid dividends.
NOTE 13-SHORT-TERM DEBT AND LINES OF CREDIT
Our short-term borrowings and their corresponding weighted-average interest rates as of December 31 were as follows:
*
Based on daily outstanding balances during the year.
We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 65%.
The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31:
*
We plan to request approval from the PSCW to extend the maturity through December 2020.
In December 2015, we terminated our prior credit facilities and entered into a new credit facility maturing in 2016. The lenders under this facility have agreed that its maturity can be extended to December 2020, subject to our receipt of PSCW approval. This $250.0 million facility has a renewal provision for two one-year extensions, subject to lender approval.
Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control.
NOTE 14-LONG-TERM DEBT
See our statements of capitalization for details on our long-term debt.
In November 2015, we redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7.125% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption. Following the redemption, we discharged our mortgage indenture and do not intend to issue additional first mortgage bonds. All of our senior notes outstanding are now senior unsecured obligations and rank equally with all of our other unsecured obligations.
In December 2015, our $125.0 million of 6.375% Senior Notes matured, and the outstanding principal balance was repaid.
In December 2015, we issued $250.0 million of 1.65% Senior Notes due December 4, 2018. The proceeds were used to repay short-term debt that we incurred to repay all of our $125.0 million of 6.375% Senior Notes at maturity, and for working capital and other general corporate purposes.
A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to our parent, is as follows:
We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.
NOTE 15-INCOME TAXES
Income Tax Expense
The following table is a summary of income tax expense for each of the years ended December 31:
Statutory Rate Reconciliation
The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes as a result of the following:
Deferred Income Tax Assets and Liabilities
The components of deferred income taxes as of December 31 are as follows:
Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities.
Deferred tax credit carryforwards at December 31, 2015, included $2.0 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $3.0 million of general business credits, which have a carryback period of one year and a carryforward period of 20 years. The majority of the general business credit carryforwards will expire in 2033.
At December 31, 2015, we had deferred income tax assets of $16.1 million reflecting federal operating loss carryforwards, which have a carryback period of two years and a carryforward period of 20 years and will expire in 2034.
Unrecognized Tax Benefits
We had no unrecognized tax benefits at December 31, 2015, and 2014.
We had no accrued interest and penalties related to unrecognized tax benefits at December 31, 2015, and 2014.
We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2015.
We file income tax returns in the United States federal jurisdiction and in our major state operating jurisdictions as a part of Integrys filings up to June 29, 2015, and as a part of WEC Energy Group filings for periods after June 29, 2015.
With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2012.
We file state tax returns based on income in our major state operating jurisdictions of Wisconsin and Michigan. We are no longer subject to state and local tax examinations for years prior to 2008. As of December 31, 2015, we were subject to examination by the Wisconsin taxing authority for tax years 2011 through 2015 and the Michigan taxing authority for tax years 2008 through 2015. During 2015, the Michigan taxing authority continued its examination of tax years 2008 through 2011.
In the next 12 months, we do not expect to significantly change the amount of unrecognized tax benefits.
NOTE 16-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 obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.
(3)
Consists of (a) $20.0 million not reflected on our balance sheet for an interconnection agreement between us and ATC and (b) $0.3 million reflected on our balance sheet related to workers compensation.
NOTE 17-EMPLOYEE BENEFITS
Pension and Other Postretirement Employee Benefits
We participate in the Integrys retirement plan, a noncontributory, qualified pension plan sponsored by WBS. We are responsible for our share of the plan assets and obligations. We serve as plan sponsor and administrator for certain OPEB plans. The benefits are funded 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 and obligations. Integrys also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred.
The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. In March 2014, we remeasured the obligations of certain OPEB plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 2015.
The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets:
*
Benefit obligations and plan assets were moved along with our employees who were transferred to affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries.
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 $569.6 million and $717.4 million at December 31, 2015, and 2014, respectively.
The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31:
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 components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:
Assumptions - Pension and Other Postretirement Benefit Plans
The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:
The weighted-average assumptions used to determine net periodic benefit cost for the plans were as follows for the years ended December 31:
WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2016, the expected return on assets assumption for the pension and OPEB plans is 7.25%.
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, 2015, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:
Plan Assets
Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.
The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.
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. In 2014, the pension plan target asset allocation was 70% equity securities and 30% fixed income securities. In December 2014, we changed the pension plan target asset allocation to 60% equity securities and 40% fixed income securities for 2015. The target asset allocation for OPEB plans that have significant assets is 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.
Pension and OPEB plan investments are recorded at fair value. See Note 1(p), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.
The following tables provide the fair values of our investments by asset class:
(1)
This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
(2)
Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
(3)
Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.
(1)
This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
(2)
Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
(3)
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 tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2014. There was no level 3 activity in 2015.
Cash Flows
We expect to contribute $1.4 million to the pension plans and $2.1 million to OPEB plans in 2016, 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 OPEB.
Savings Plans
Integrys 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. Certain employees 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 all of these plans was $9.7 million in 2015, $8.6 million in 2014, and $8.2 million in 2013.
NOTE 18-COMMITMENTS AND CONTINGENCIES
We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental remediation, and enforcement and litigation matters.
Energy Related Purchased Power Agreements
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, 2015.
Operating Leases
We lease various property, plant, and equipment with various terms in the operating leases. The operating leases 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 $1.4 million, $1.6 million, and $2.3 million in 2015, 2014, and 2013, respectively.
Future minimum payments under noncancelable operating leases are payable as follows:
Environmental Matters
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:
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the development of additional sources of renewable electric energy supply;
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the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;
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the addition of emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules;
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the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;
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the retirement of old coal plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation;
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the beneficial use of ash and other products from coal-fired generating units; and
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the remediation of former manufactured gas plant sites.
Air Quality
Sulfur Dioxide National Air Ambient Quality Standards
The EPA issued a revised 1-Hour SO2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard.
The final rule affords state agencies latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make attainment designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area would be classified as nonattainment. A plan would need to be developed requiring emission reductions to bring the area back into attainment by 2023. Alternatively, if a state opted out of modeling and instead chose to install air quality monitors, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.
In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO2. The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016.
We believe our fleet overall is well positioned to meet the new regulation.
8-Hour Ozone National Air Ambient Quality Standards
The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule.
Mercury and Other Hazardous Air Pollutants
In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, Wisconsin has a state mercury rule that requires a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect while the EPA completes its cost evaluation.
Our compliance plans currently include capital projects for our jointly owned plants to achieve the required reductions for MATS. Construction of the ReACTTM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date of July 2016. Controls for acid gases and mercury are already in operation at the Pulliam units.
Although we received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is shut down to complete the construction of the ReACTTM system.
Climate Change
In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and requires states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin of 41% below 2012 levels by 2030. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources.
Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO2 equivalent reduction goal by about 10%. The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted comments on the draft Federal Plan and Model Trading Rule.
We are in the process of reviewing the final rule for existing generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants, and could have a material adverse impact on our operating costs. In October 2015, following publication of the final rule, numerous states (including Wisconsin), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but on February 9, 2016, the Supreme Court stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of state plans until the litigation is complete. In addition, on February 15, 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.
We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, we reported aggregated CO2 equivalent emissions of approximately 6.2 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 5.7 million metric tonnes to the EPA for 2015. The level of CO2 and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.
We are also required to report CO2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2014, we reported aggregated CO2 equivalent emissions of approximately 3.9 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 3.5 million metric tonnes to the EPA for 2015.
Water Quality
Clean Water Act Cooling Water Intake Structure Rule
In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures.
Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.
BTA determinations must also be made by the WDNR to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8 and Weston Units 2 through 4.
During 2016-2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Entrainment studies are currently being conducted at Pulliam Units 7 and 8.
Steam Electric Effluent Guidelines
The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin. Unless pending challenges to the final guidelines are successful, the WDNR will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Pulliam Units 7 and 8 and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $10 million to $20 million for these bottom ash transport systems.
Land Quality
Coal Combustion Residuals Rule
In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. We do not expect the compliance costs will be significant because we currently have a program of beneficial utilization for most of our coal combustion products. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources.
Coal Combustion Product Landfill Sites
We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015, 2014, and 2013, landfill remediation expenses were not material. See Note 9, Asset Retirement Obligations, for more information about obligations related to these sites.
Renewables, Efficiency, and Conservation
Wisconsin Act 141
In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we are required to increase our renewable energy percentage to 9.74%. To comply with these requirements, we constructed the Crane Creek wind park. We also rely on renewable energy purchases to meet our renewable portfolio standard commitments.
We are in compliance with Act 141's 2015 standard and have entered into agreements for renewable energy credits, that should allow us to remain in compliance through 2023. If market conditions are favorable, we may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of our annual operating revenues.
Manufactured Gas Plant Remediation
We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.
In addition, some of these sites are coordinating the investigation and cleanup subject to the jurisdiction of the EPA under what is called a "multisite" 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. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.
We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31:
Enforcement and Litigation Matters
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.
Weston Title V Air Permit
In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, we challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The administrative law judge (ALJ) dismissed some of the petition issues relating to the averaging period and monitoring issues.
In May 2014, the WDNR issued a Notice of Violation (NOV) alleging that we failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler.
In June 2015, the WDNR issued a NOV alleging that we failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied our request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV.
The contested case has been stayed for a period of months, and no hearing date has been set. We do not expect these matters to have a material impact on our financial statements.
Consent Decrees
Consent Decree - Weston and Pulliam
In November 2009, the EPA issued a NOV to us, which alleged 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 entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the U.S. District Court for the Eastern District of Wisconsin in March 2013. The final Consent Decree includes:
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the installation of emission control technology, including ReACT™ on Weston 3,
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changed operating conditions (including refueling, repowering, and/or retirement of units),
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limitations on plant emissions,
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beneficial environmental projects totaling $6.0 million, and
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a civil penalty of $1.2 million.
As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023.
We received approval from the PSCW in our rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. The majority of the beneficial environmental projects proposed by us have been approved by the EPA. We are currently working with the EPA on certain changes to the environmental projects, but these changes are not expected to materially impact the overall cost.
Also, in May 2010, we received from the Sierra Club a Notice of Intent 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 no further action has been taken by the Sierra Club as of December 31, 2015. It is unknown whether the Sierra Club will take further action in the future.
Joint Ownership Power Plants Consent Decree - Columbia and Edgewater
In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, Wisconsin Electric (former co-owner of an Edgewater unit), and us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, Wisconsin Power and Light, Madison Gas and Electric, and Wisconsin Electric entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. The final Consent Decree includes:
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the installation of emission control technology, including scrubbers at the Columbia plant,
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changed operating conditions (including refueling, repowering, and/or retirement of units),
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limitations on plant emissions,
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beneficial environmental projects, with our portion totaling $1.3 million, and
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Our portion of a civil penalty and legal fees totaling $0.4 million.
As mentioned above, the Consent Decree contains a requirement to refuel, repower, or retire Edgewater Unit 4, of which we are a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available. All of the beneficial environmental projects that we proposed have been approved by the EPA.
NOTE 19-FAIR VALUE MEASUREMENTS
The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 20, Derivative Instruments, for more information.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:
Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on our income statements.
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
*
On November 13, 2015, we redeemed all of our outstanding shares of preferred stock. See Note 12, Preferred Stock, for more information.
NOTE 20-DERIVATIVE INSTRUMENTS
The following table shows our derivative assets and derivative liabilities:
Our estimated notional volumes and gains (losses) were as follows:
At December 31, 2015, and December 31, 2014, we had posted collateral of $17.6 million and $6.6 million, respectively, in our margin accounts.
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
*
Includes cash collateral posted of $1.1 million and $3.2 million as of December 31, 2015 and December 31, 2014, respectively.
NOTE 21-REGULATORY ENVIRONMENT
2016 Wisconsin Rate Order
In April 2015, we initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0%, authorized a net retail electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). Based on the order, the PSCW will continue to allow escrow treatment for ATC and MISO network transmission expenses, including any future SSR payments. This allows us to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. In addition, the PSCW approved a deferral for ReACT™, which requires us to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.
2015 Wisconsin Rate Order
In April 2014, we initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% ROE. The order also included a common equity component of 50.28%. The PSCW approved a change in rate design, which includes higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014.
The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million. In addition, 2015 rates include approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, we refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, we would have realized an electric rate decrease. In addition, we received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 18, Commitments and Contingencies, for more information. The PSCW is allowing us to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, we defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window.
The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, we refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, we would have realized a retail natural gas rate increase.
2014 Wisconsin Rate Order
In March 2013, we initiated a rate proceeding with the PSCW. In December 2013, the PSCW issued a final written order, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million, reflecting a 10.20% ROE. The order also included a common equity component average of 50.14%. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case, as discussed below. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 18, Commitments and Contingencies, for more information. Additionally, the order required us to terminate our existing decoupling mechanism, beginning January 1, 2014.
2013 Wisconsin Rate Order
In March 2012, we initiated a rate proceeding with the PSCW. In December 2012, the PSCW issued a final written order, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers' 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The order reflected a 10.30% ROE and a common equity component average of 51.61%. The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that were recovered in 2014 rates. 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 in 2012, and recovery from customers began in 2013. The order also authorized the recovery of direct CSAPR costs incurred through the end of 2012. Lastly, the order authorized us to switch from production tax credits to a Section 1603 Grant for the Crane Creek wind project.
A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included 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 were subject to these caps.
2015 Michigan Rate Order
In October 2014, we initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflect a 10.2% ROE and a common equity component average of 50.48%. The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, we will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. We also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. Lastly, we will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.
NOTE 22-SEGMENT INFORMATION
At December 31, 2015, we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are our electric utility operations and the natural gas utility operations. The other segment includes non-utility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC. Operating income is used to measure segment profitability and to allocate resources to our businesses. All of our operations and assets are located within the United States. The table below presents information related to our reportable segments:
NOTE 23-QUARTERLY FINANCIAL INFORMATION (Unaudited)
Due to various factors, the quarterly results of operations are not necessarily comparable.
NOTE 24-NEW ACCOUNTING PRONOUNCEMENTS
Revenue Recognition
In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.
Classification and Measurement of Financial Instruments
In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements.
Leases
In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We are currently assessing the effects this guidance may have on our financial statements.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (a) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (b) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2015.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this annual report.
Changes in Internal Control
There were no changes in our internal control over financial reporting during the fourth quarter of 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
On June 29, 2015, the WEC Merger was completed. WEC Energy Group is currently in the process of integrating and aligning the operations, processes, and internal controls of the combined company. See Note 2, Merger, for more information.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Omitted pursuant to General Instruction I(2)c.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Omitted pursuant to General Instruction I(2)c.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Omitted pursuant to General Instruction I(2)c.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Omitted pursuant to General Instruction I(2)c.
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 2015 and 2014:
(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 LLP 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)
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 a WPS file review in 2015 and to training provided in 2014.
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 (Audit Committee), prior to the WEC Merger, 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's management at the time 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 approved in advance 100% of the audit services described above in accordance with its pre-approval policy at the time.
Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor
The Audit and Oversight Committee (Audit Committee) of the Board of Directors of WEC Energy Group, which is comprised solely of independent directors, is responsible for appointing and overseeing our independent auditor. The Committee has the sole and ultimate authority to appoint, retain, and evaluate the services of the independent auditor. The Audit Committee is committed to ensuring the independence of the auditor, both in appearance as well as in fact. When evaluating the independence of the auditor, the Audit Committee considers whether a relationship with or service provided by the auditor:
•
creates a mutual or conflicting interest with WEC Energy Group or its subsidiaries;
•
places the auditor in the position of auditing their own work;
•
results in the auditor functioning as management or employees of WEC Energy Group or its subsidiaries; or
•
places the auditor in a position of being an advocate for WEC Energy Group or its subsidiaries.
Pre-Approval Process
Before engagement of the independent auditor for the next year's audit, the independent auditor will submit (i) a description of all services anticipated to be rendered during the following year, as well as an estimate of the fees for each of the services, for the Audit Committee to approve, and (ii) written confirmation that the performance of any non-audit services is permissible and will not impact the firm's independence. Annual pre-approval will be deemed effective for a period of twelve months from the date of the pre-approval, unless the Audit Committee specifically provides for a different period. A fee level will be established for all permissible, pre-approved non-audit services. Any additional audit service, audit related service, tax service and other service must also be pre-approved.
The Audit Committee delegates pre-approval authority to the Audit Committee's chair. The Audit Committee chair shall report any pre-approval decisions at the next Audit Committee meeting. Under the pre-approval policy, the Audit Committee may not delegate to management its responsibilities to pre-approve services performed by the independent auditor.
Prohibited Activities are services prohibited by the SEC or by the Public Company Accounting Oversight Board to be performed by our independent auditor. These services include:
•
bookkeeping or other services related to the accounting records or financial statements of the Corporation;
•
financial information systems design and implementation;
•
appraisal or valuation services, fairness opinions or contribution-in-kind reports;
•
actuarial services;
•
internal audit outsourcing services;
•
management functions or human resources;
•
broker-dealer, investment advisor or investment banking services;
•
legal services and expert services unrelated to the audit;
•
services provided for a contingent fee or commission; and
•
services related to planning, marketing or opining in favor of the tax treatment of a confidential transaction or aggressive tax position transaction that was initially recommended, directly or indirectly, by the independent auditor.
In addition, the independent auditor may not provide any services, including personal financial counseling and tax services, to any officer or other employee of WEC Energy Group or its subsidiaries in a financial reporting oversight role or chair of the Audit Committee or to an immediate family member of these individuals, including spouses, spousal equivalents, and dependents.
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:
SCHEDULE II
WISCONSIN PUBLIC SERVICE CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
(1)
Net of recoveries.
(2)
Represents amounts written off to the reserve, net of adjustments to regulatory assets.
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.
WISCONSIN PUBLIC SERVICE CORPORATION
By
/s/ALLEN L. LEVERETT
Date:
February 26, 2016
Allen L. Leverett
Chairman, Chief Executive Officer and President
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 and on the dates indicated.
WISCONSIN PUBLIC SERVICE COMPANY
(Commission File No. 01-3016)
EXHIBIT INDEX
to
Annual Report on Form 10-K
For the year ended December 31, 2015
Set forth below is a listing of all exhibits to this Annual Report on Form 10-K, including those incorporated by reference.
*
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.
#
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.
Exhibit 21 has been omitted pursuant to General Instruction I(2)b.