ITEM 1.
BUSINESS
INTRODUCTION
Wisconsin Energy Corporation was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.
We conduct our operations primarily in two reportable segments: a utility energy segment and a non-utility energy segment. Our primary subsidiaries are Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and W.E. Power, LLC (We Power).
Utility Energy Segment: Our utility energy segment consists of Wisconsin Electric and Wisconsin Gas, operating together under the trade name of "We Energies." We Energies serves approximately 1,133,600 electric customers in Wisconsin and the Upper Peninsula of Michigan. We Energies serves approximately 1,089,000 gas customers in Wisconsin and approximately 440 steam customers in metropolitan Milwaukee, Wisconsin.
Non-Utility Energy Segment: Our non-utility energy segment consists primarily of We Power, which owns and leases to Wisconsin Electric generation plants constructed as part of our Power the Future (PTF) strategy. Port Washington Generating Station Unit 1 (PWGS 1) and Port Washington Generating Station Unit 2 (PWGS 2) are being leased to Wisconsin Electric under long-term leases that run for 25 years. Oak Creek expansion Unit 1 (OC 1) and Oak Creek expansion Unit 2 (OC 2) are being leased to Wisconsin Electric under long-term leases that run for 30 years.
For further financial information about our business segments, see Results of Operations in Item 7 and Note O -- Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.
Proposed Acquisition: On June 22, 2014, we entered into an agreement to acquire Integrys. The proposed acquisition is scheduled to close in the second half of 2015, and is subject to the receipt of various approvals. The combined company will serve approximately 1.5 million electric customers, 2.8 million gas customers, and own approximately 60% of ATC. For additional information on this acquisition, see Corporate Strategy in Item 7 and Note D -- Proposed Acquisition in the Notes to Consolidated Financial Statements in Item 8.
Our annual and periodical filings with the SEC are available, free of charge, through our Internet website www.wisconsinenergy.com. These documents are available as soon as reasonably practicable after such materials are filed (or furnished) with the SEC.
UTILITY ENERGY SEGMENT
ELECTRIC UTILITY OPERATIONS
Our electric utility operations consist of the electric operations of Wisconsin Electric. Wisconsin Electric, which is the largest electric utility in the state of Wisconsin, generates and distributes electric energy in a territory that includes southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and the Upper Peninsula of Michigan.
Wisconsin Electric participates in the Midcontinent Independent System Operator (MISO) Energy Markets. The competitiveness of our generation offered in the MISO Energy Markets affects how our generating units are dispatched and how we buy and sell power. For further information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.
Electric Sales
Our electric energy deliveries, which include supply and distribution sales to our retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier, totaled approximately 35.1 million MWh during 2014 and approximately 33.0 million MWh during 2013. We had approximately 1,133,600 electric customers as of December 31, 2014 and 1,128,300 electric customers as of December 31, 2013.
Wisconsin Electric is authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits, Certificates of Public Convenience and Necessity (CPCNs) or boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities. Wisconsin Electric also sells wholesale electric power within the MISO Energy Markets.
Electric Sales Growth: Our service territory experienced steady retail sales in 2014 after accounting for changes associated with customers switching to alternative electric suppliers. Assuming continuing improvement in the economy over the five-year forecast horizon, we presently anticipate that total retail electric kWh sales and the associated peak electric demand will grow at a compound annual rate of about 0.5% over the next five years. These estimates assume normal weather.
Sales to 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, as well as to large retail chains.
Prior to September 2013, our largest retail electric customers were two iron ore mines located in the Upper Peninsula of Michigan. The mines were served on an interruptible tariff rate and switched to an alternative electric supplier effective September 1, 2013. The combined electric energy sales to the two mines accounted for 3.7% and 6.6% of our total electric utility energy sales during 2013 and 2012, respectively. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition in Item 7.
Effective February 1, 2015, the two mines returned as retail customers. We expect to defer the net revenue from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in future rate proceedings. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice.
Sales to Wholesale Customers: During 2014, we sold wholesale electric power to two rural cooperatives, and two municipal joint action agencies located in the states of Wisconsin and Michigan. Our wholesale electric energy sales were also made to one other public utility in the region under rates approved by the Federal Energy Regulatory Commission (FERC). Wholesale sales accounted for approximately 5.7% of our total electric energy sales and 3.9% of total electric operating revenues during 2014, compared with 6.1% of total electric energy sales and 4.3% of total electric operating revenues during 2013.
Sales for Resale: During 2014, the majority of our sales for resale were sold to one Regional Transmission Organization (RTO), at market rates based on availability of our generation and RTO demand. Sales for resale accounted for approximately 19.9% of our total electric energy sales and 7.8% of total electric operating revenues during 2014, compared with 13.6% of total electric energy sales and 4.3% of total electric operating revenues during 2013.
Electric System Reliability Matters: 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. The Public Service Commission of Wisconsin (PSCW) has planning reserve requirements consistent with the MISO calculated planning reserve margin. The Michigan Public Service Commission (MPSC) has not yet established guidelines in this area. In accordance with the MISO calculated planning reserve margin requirements, we had adequate capacity to meet MISO calculated planning reserve margin during 2014 and expect to have adequate capacity to meet the planning reserve margin requirements during 2015. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.
Competition
Retail electric customers in Wisconsin currently do not have the ability to choose their electric supplier. It is uncertain when, if ever, retail access might be implemented in Wisconsin. However, Wisconsin Electric attempts to attract new customers into our service territory to increase sales in order to allocate the recovery of our costs
among a larger customer base. The regulated energy industry continues to experience significant structural changes, which could eventually lead to increased competition in Wisconsin.
Michigan has adopted retail choice 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. See Factors Affecting Results, Liquidity and Capital Resources - Industry Restructuring and Competition - Restructuring in Michigan, for a discussion of the impact of customers switching to an alternative electric supplier in Michigan on our electric sales.
We compete with other utilities for sales to municipalities and cooperatives. We also compete with other utilities and marketers in the wholesale electric business. Our wholesale sales are impacted by availability, wholesale electric prices, market conditions and fuel costs.
Electric Supply
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, including the Point Beach Nuclear Power Plant (Point Beach) power purchase agreement discussed later in this report and through spot purchases in the MISO Energy Markets.
Our dependable capability by fuel type as of December 31 is shown below:
(a)
Dependable capability 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. The values were established by tests and may change slightly from year to year.
(b)
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 gas distribution company that delivers gas to the plants.
(c)
Includes hydroelectric, biomass and wind generation.
(d)
The Natural Gas - Steam Turbine represents the dependable capability associated with the Valley unit converted from coal to natural gas in November 2014. The remaining unit will be converted in 2015.
The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2014, as well as an estimate for 2015:
Our average fuel and purchased power costs per MWh by fuel type for the years ended December 31 are shown below:
Historically, coal has been purchased under long-term contracts, which helped 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.
We have a PSCW-approved hedging program to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. Proceeds related to the natural gas hedging program are reflected in the average costs of natural gas and purchased power shown above.
Coal-Fired Generation
Coal Supply: We diversify the coal supply for our power plants by purchasing coal from mines in Wyoming and Montana, as well as from various other states. During 2015, 87% of our projected coal requirements of 12.5 million tons are under contracts which are not tied to 2015 market pricing fluctuations. At the end of 2014, our coal-fired generation consisted of six operating plants with a dependable capability of approximately 3,707 MW.
The annual tonnage amounts contracted for 2015 through 2017 are as follows:
Coal Deliveries: Approximately 100% of our 2015 coal requirements are expected to be delivered by Wisconsin Electric-owned or leased unit trains. The unit trains will transport coal for the Oak Creek and Pleasant Prairie Power Plants from Wyoming mines, and transport coal for the Oak Creek expansion units from Pennsylvania and Wyoming. Montana and Wyoming coal for the Presque Isle Power Plant (PIPP) is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery. Existing coal inventory will be drawn down to fuel Valley Power Plant (VAPP) until its conversion to natural gas is complete, which is scheduled to
occur in 2015. Milwaukee County Power Plant will be fueled with coal currently stored at a dock in the Port of Milwaukee, and additional small volume purchases will be shipped to that location.
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 have a PSCW-approved hedging program that allows us to hedge up to 75% of our potential risks related to fuel surcharge exposure. The costs of this program are included in our fuel and purchased power costs.
Environmental Matters: For information regarding emission restrictions, especially as they relate to coal-fired generating facilities, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7.
Natural Gas-Fired Generation
Our natural gas-fired generation consists of five operating plants with a dependable capability of approximately 1,982 MW as of December 31, 2014.
We purchase natural gas for these plants on the spot market from 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 the plants' variable usage.
We have a program that allows us to hedge up to 65% of our estimated gas usage for electric generation in order to help manage our natural gas price risk. The costs of this program are included in our fuel and purchased power costs.
Oil-Fired Generation
Fuel oil is used for the combustion turbines at the Germantown Power Plant units 1-4, boiler ignition and flame stabilization at PIPP, and diesel engines at the Pleasant Prairie Power Plant and VAPP. Our oil-fired generation had a dependable capability of approximately 180 MW as of December 31, 2014. Our natural gas-fired peaking units have the ability to burn oil if natural gas is not available due to delivery constraints. Fuel oil requirements are purchased under agreements with suppliers.
Renewable Generation
Hydroelectric: Wisconsin Electric's hydroelectric generating system consists of 13 operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 39 MW as of December 31, 2014. Of these plants, 12 plants (86 MW of installed capacity) have long-term licenses from FERC. The other plant, with an installed generating capacity of approximately 2 MW, is operated under a permit granted by another federal agency.
Wind: We have four wind sites, consisting of 200 turbines with an installed capacity of 338 MW and a dependable capability of 66 MW.
Biomass: We constructed a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. Wood waste and wood shavings are used to produce a dependable capability of approximately 50 MW of electric power as well as steam to support Domtar's papermaking operations.
Power Purchase Commitments
We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. The following table identifies our power purchase commitments as of December 31, 2014 with unaffiliated parties for the next five years:
The above commitments include approximately 1,030 MW per year related to the Point Beach long-term power purchase agreement. The balance of these purchased power commitments is an arrangement where we buy power at a price determined monthly based on a formula tied to the gas price index.
Electric Transmission and Energy Markets
American Transmission Company: ATC is a regional transmission company that owns, maintains, monitors and operates electric transmission systems in Wisconsin, Michigan, Illinois and Minnesota. ATC is expected to provide comparable service to all customers, including Wisconsin Electric, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by FERC for all rate terms and conditions of service and is a transmission-owning member of MISO. MISO maintains operational control of ATC's transmission system, and Wisconsin Electric is a non-transmission owning member and customer of MISO. We owned approximately 26.2% of ATC as of December 31, 2014 and 2013. For additional information, see Note P -- Related Parties in the Notes to Consolidated Financial Statements.
In April 2011, ATC and Duke Energy announced the creation of a joint venture, Duke-American Transmission Company, that will build, own and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity. In April 2013, DATC acquired a 72% interest in California's Path 15 transmission line. DATC continues to evaluate new projects and opportunities, along with participating in the competitive bidding process on projects it considers viable. These projects are located in the service territories of several different regional transmission organizations around the country.
MISO: In connection with its status as a FERC approved RTO, MISO developed and operates the Energy and Operating Reserves Markets, which includes its bid-based energy markets and ancillary services market. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas and Missouri. This new region is referred to as MISO South. We are participants in the West region. These changes have not had a material impact on our allocation of MISO costs, and we do not expect them to have a material impact in the future. For further information on MISO and the MISO Energy Markets, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition - Electric Transmission, Capacity and Energy Markets in Item 7.
Electric Utility Operating Statistics
The following table shows certain electric utility operating statistics for the past five years:
(a)
Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
(b)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.
GAS UTILITY OPERATIONS
Our gas utility operations consist of Wisconsin Gas and the gas operations of Wisconsin Electric, both operating under the trade name of "We Energies." We are authorized to provide retail gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits, CPCNs, or boundary agreements with other utilities. We also transport customer-owned gas. We are the largest natural gas distribution utility in Wisconsin, and we operate throughout the state, including the City of Milwaukee, west and south of the City of Milwaukee, the Appleton area and large areas of both central and western Wisconsin.
Gas Deliveries
Our gas utility business is highly seasonal due to the heating requirements of residential and commercial customers, and annual gas sales are impacted by the variability of winter temperatures.
Total gas therms delivered, including customer-owned transported gas, were approximately 2,570.7 million therms during 2014, a 5.2% increase compared with 2013. As of December 31, 2014, we were transporting gas for approximately 1,800 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 42.3% of the total volumes delivered during 2014, 43.1% during 2013 and 51.3% during 2012. We had approximately 1,089,000 and 1,079,800 gas customers as of December 31, 2014 and 2013, respectively. Our peak daily send-out during 2014 was 1,949,679 Dth on January 6, 2014.
Sales to Large Gas Customers: We provide gas utility service to a diversified base of industrial customers who are largely within our electric service territory. Major industries served include paper, food products, chemicals and fabricated metal products. Fuel used for Wisconsin Electric's electric generation represents our largest transportation customer. Gas therms delivered to Wisconsin Electric for electric generation represents 9.3%, 10.4% and 17.2% of the total volumes delivered during 2014, 2013 and 2012, respectively.
Gas Deliveries Growth: We currently forecast total retail therm deliveries (excluding natural gas deliveries for generation) to grow at a compound annual rate of 0.5% over the five-year period ending December 31, 2019. This forecast reflects a current year weather normalized sales level and normal weather.
Western Gas Lateral: We are projecting the need for additional capacity for our natural gas distribution network in the western part of Wisconsin to address reliability and meet customer demand. We received PSCW approval to construct a new natural gas lateral on July 18, 2014. The anticipated cost of the initial phase of this project is approximately $175 million to $185 million, excluding Allowance for Funds Used During Construction (AFUDC). We are targeting completion of this phase of the project in late 2015.
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 gas sales and transportation services to dual-fuel customers. Under gas transportation agreements, customers purchase gas directly from gas marketers and arrange with interstate pipelines and us to have the gas transported to their facilities. We earn substantially the same margin (difference between revenue and cost of gas) whether we sell and transport gas to customers or only transport their gas.
Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party 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 gas supplies.
Federal and state regulators continue to implement policies to bring more competition to the gas industry. While the 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. It remains uncertain if and when the current economic disincentives for small firm customers to choose an alternative gas commodity supplier may be removed such that we begin to face competition for the sale of gas to those customers.
Gas Supply, Pipeline Capacity and Storage
We have been able to meet our contractual obligations with both our suppliers and our customers.
Pipeline Capacity and Storage: The interstate pipelines serving Wisconsin originate in major gas producing areas of North America: the Oklahoma and Texas basins, the Gulf of Mexico, western Canada and the Rocky Mountains. We have contracted for long-term firm 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 gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 34% of forecasted winter demand; November through March is considered the winter season. Storage capacity, along with our gas purchase contracts, enables us to manage significant changes in daily demand and to optimize our overall gas supply and capacity costs. We generally inject 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 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 Gas Supply: We have contracts for firm supplies with terms in excess of 30 days with suppliers for 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 gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand.
Secondary Market Transactions: Pipeline long-line and storage capacity and gas supplies under contract can be resold in secondary markets. Local distribution companies, like Wisconsin Electric and Wisconsin Gas, 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 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 the Wisconsin Electric and Wisconsin Gas approved Gas Cost Recovery Mechanisms (GCRMs). During 2014, we continued to participate in the secondary markets. See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 for information on the GCRMs.
Spot Market Gas Supply: We expect to continue to make gas purchases in the 30-day spot market as price opportunity and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase spot gas.
Hedging Gas Supply Prices: We have PSCW approval to hedge (i) up to 60% of planned winter and (ii) up to 30% of planned summer flowing gas supply using a mix of New York Mercantile Exchange (NYMEX) based natural gas options and natural gas future contracts. Those approvals allow both Wisconsin Electric and Wisconsin Gas to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through their respective GCRMs. Hedge targets (volumes) are provided annually to the PSCW as part of each company's three-year 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 GCRMs.
Gas Utility Operating Statistics
The following table shows certain gas utility operating statistics for the past five years:
(a)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.
OTHER UTILITY OPERATIONS
Steam Utility Operations: Our steam utility generates, distributes and sells steam supplied by our VAPP and Milwaukee County Power Plant. We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee. Steam is supplied to this system from VAPP. We also operate the steam production and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.
Annual sales of steam fluctuate from year to year based upon system growth and variations in weather conditions. During 2014, the steam utility had $44.1 million of operating revenues from the sale of 2,865 million pounds of steam compared with $39.6 million of operating revenues from the sale of 2,750 million pounds of steam during 2013. As of December 31, 2014 and 2013, steam was used by approximately 440 customers and 445 customers, respectively, for processing, space heating, domestic hot water and humidification.
UTILITY RATE MATTERS
See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7.
NON-UTILITY ENERGY SEGMENT
Our non-utility energy segment consists primarily of generating plants constructed as part of our PTF strategy. As of December 31, 2014, our PTF assets represented virtually all of our non-utility energy segment assets.
We Power
We Power, through wholly owned subsidiaries, has designed and built approximately 2,320 MW of generation in Wisconsin, which is being leased to Wisconsin Electric under long-term leases. This generation consists of approximately 1,230 MW of capacity from OC 1 and OC 2, and 1,090 MW of capacity from PWGS 1 and PWGS 2. PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively. Two unaffiliated entities collectively own approximately 17%, or 200 MW, of OC 1 and OC 2.
Our PTF strategy was designed to address Wisconsin Electric's electric supply needs by increasing the electric generating capacity in Wisconsin while allowing us to maintain a diversified fuel mix, by including both new coal-fired plants and natural-gas fired plants. Because of the significant investment necessary to construct these generating units, we constructed the plants under Wisconsin's Leased Generation Law, which allows a non-utility affiliate to construct an electric generating facility and lease it to the public utility. The law allows a public utility that has entered into a lease approved by the PSCW to recover fully in its retail electric rates that portion of any payments under the lease that the PSCW has allocated to the public utility's Wisconsin retail electric service, and all other costs that are prudently incurred in the public utility's operation and maintenance of the electric generating facility allocated to the utility's Wisconsin retail electric service. In addition, the PSCW may not modify or terminate a lease it has approved under the Leased Generation Law except as specifically provided in the lease or the PSCW's order approving the lease. This law effectively created regulatory certainty in light of the significant investment being made to construct the units. All four PTF units were constructed under leases approved by the PSCW. For additional background information on our PTF strategy, see Management's Discussion and Analysis of Financial Condition and Results of Operations - Corporate Developments - Corporate Strategy - Power the Future Strategy and - Factors Affecting Results, Liquidity and Capital Resources - Power the Future in Item 7 of our Form 10-K for the year ended December 31, 2007.
For further information about our PTF strategy, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7.
Wisvest LLC
Wisvest was originally formed to develop, own and operate electric generating facilities and to invest in other energy-related entities. As a result of the change in corporate strategy to focus on our PTF strategy, Wisvest discontinued its development activity. As of December 31, 2014, Wisvest's sole operating asset and investment is Wisvest Thermal Energy Services, which provides chilled water services to the Milwaukee Regional Medical Center.
OTHER NON-UTILITY OPERATIONS
Wispark LLC and Bostco LLC
Wispark and Bostco develop and invest in real estate, and combined had $73.7 million in real estate holdings as of December 31, 2014. Wispark has developed several business parks and other commercial real estate projects, primarily in southeastern Wisconsin.
REGULATION
Wisconsin Energy Corporation
Wisconsin Energy is a holding company, but is exempt from the requirements of the Public Utility Holding Company Act of 2005 (PUHCA 2005).
Non-Utility Asset Cap: Pursuant to the non-utility asset cap provisions of Wisconsin's public utility holding company law, the sum of certain assets of all non-utility affiliates in a holding company system may not exceed 25% of the assets of all public utility affiliates. However, among other items, the law exempts energy-related assets, including the generating plants constructed by We Power as part of our PTF strategy, from being counted against the asset cap provided that they are employed in qualifying businesses. As a result of these exemptions, our non-utility assets are significantly below the non-utility asset cap as of December 31, 2014.
Utility Energy Segment
Wisconsin Electric is a holding company because of its ownership interest in ATC, but is exempt from the requirements of PUHCA 2005.
Wisconsin Electric is 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 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 Wisconsin Electric. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by FERC, which established mandatory electric reliability standards and which has the authority to levy monetary sanctions for failure to comply with these standards.
Wisconsin Electric and Wisconsin Gas are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. Wisconsin Electric is also subject to the regulation of the PSCW as to certain levels of short-term debt obligations. Wisconsin Electric is subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Almost all of Wisconsin Electric's hydroelectric facilities are regulated by FERC. Wisconsin Electric is subject to the regulation of FERC with respect to wholesale power service, electric reliability requirements and accounting and with respect to our participation in the interstate natural gas pipeline capacity market. For information on how rates are set for our regulated entities, see Utility Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7.
The following table compares our utility energy segment operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2014:
For additional information on our business operations in Michigan, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition - Michigan Business in Item 7.
The operations of Wisconsin Electric and Wisconsin Gas are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources (WDNR), the Michigan Department of Environmental Quality (MDEQ) and the Michigan Department of Natural Resources.
Public Benefits and Renewable Portfolio Standard
2005 Wisconsin Act 141 (Act 141) established a goal that 10% of electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we must meet certain minimum requirements for renewable energy generation. For the years 2010 through 2014, we were required to increase our percentage of total retail energy sales provided by renewable sources (renewable energy percentage) by at least two percentage points from our baseline renewable percentage of 2.27%. As of December 31, 2014, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. We expect to be in compliance with this standard. In addition, under this Act, 1.2% of utilities' annual operating revenues were required to be used to fund energy conservation programs in 2014. The funding required by Act 141 for 2015 is also 1.2% of annual operating revenues.
Public Act 295 enacted in Michigan requires 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. We are currently in compliance with this requirement. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.
For additional information on Act 141 and our renewable portfolio, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters - Renewables, Efficiency and Conservation in Item 7.
Non-Utility Energy Segment
We Power owns the interests in the companies that constructed the new generating capacity in our PTF strategy (collectively, the We Power project companies). These facilities are being leased on a long-term basis to Wisconsin Electric. We Power received determinations from FERC that upon the transfer of the facilities by lease to Wisconsin Electric, the We Power project companies are not deemed public utilities under the Federal Power Act and thus are not subject to FERC's jurisdiction.
Environmental permits necessary for operating the facilities are the responsibility of the operating entity, Wisconsin Electric.
ENVIRONMENTAL COMPLIANCE
Our operations are subject to extensive environmental regulations 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 statutes and regulations or revisions to existing laws, including for example, additional regulation of greenhouse gas 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 estimated capital expenditures described in Liquidity and Capital Resources -- Capital Requirements in Item 7. For discussion of additional environmental issues, see Environmental Matters in Item 3. For further information concerning air and water quality standards and rulemaking initiated by the EPA, including estimated costs of compliance, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites and air quality, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.
Compliance with federal, state and local environmental protection requirements resulted in capital expenditures by Wisconsin Electric of approximately $1.0 million in 2014 compared with $24.7 million in 2013. Expenditures incurred during 2014 and 2013 primarily included costs associated with the installation of pollution abatement facilities at Wisconsin Electric's power plants. No future expenditures are currently anticipated. Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $110.3 million and $92.9 million during 2014 and 2013, respectively.
Coal Combustion Product Fills and Landfills
We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Some early designed and constructed coal combustion product landfills, which we used prior to developing this program, may allow the release of low levels of constituents resulting in the need for various levels of remediation. Where we have become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. In addition, fill areas for coal ash were used prior to the introduction of landfill regulations. Sites currently undergoing review include the following:
Oak Creek Site Landfills: Groundwater near the sites, located in the Village of Caledonia and the City of Oak Creek, Wisconsin, was found to contain levels of molybdenum above the allowable limit prompting Wisconsin Electric to begin investigation in 2009 for the source of the molybdenum. Our study indicates that the groundwater impacts are naturally occurring or are from other sources based on groundwater flow direction and increasing concentrations of elements deeper in the ground. The WDNR began sampling work in 2011 to identify the source of the groundwater impacts and issued its report in 2013. The WDNR study found that the data was inconclusive as to the source causing the groundwater impacts. We reviewed the WDNR report and provided technical comments further supporting our position that regional ground water impacts are not a result of coal ash management activities at the Oak Creek site. The Wisconsin Department of Health Services has since increased the allowable limit for molybdenum in groundwater, and the WDNR sent a letter to residents with private wells that exceeded the earlier limit with information about the change. For additional information regarding molybdenum, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters -- Land Quality -- New Coal Combustion Products Regulation in Item 7.
OTHER
Research and Development: We had immaterial research and development expenditures in the last three years, primarily for improvement of service and abatement of air and water pollution by our electric utility operations. Research and development activities include work done by employees, consultants and contractors, plus sponsorship of research by industry associations.
Employees: As of December 31, 2014, we had the following number of employees:
The employees represented under labor agreements were with the following bargaining units as of December 31, 2014:
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. We are subject to regulation by the PSCW of retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, short-term debt obligations, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. In addition, we are subject to regulation by the MPSC of various matters associated with retail electric service in the state of Michigan, except the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Further, Wisconsin Electric's hydroelectric facilities are regulated by FERC, and FERC also regulates our wholesale power service practices, electric reliability requirements and accounting, and participation in the interstate natural gas pipeline capacity market. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs.
We are obligated to comply in good faith with all applicable governmental rules and regulations. If it is determined that we failed to comply with any applicable rules or regulations, whether through new interpretations or applications of the regulations or otherwise, we may be liable for customer refunds, penalties and other amounts, which could materially and adversely affect our results of operations and financial condition.
The rates we are allowed to charge our customers for electric, natural gas and steam services have the most significant impact on our financial condition, results of operations and liquidity. Within our regulated energy segment, approximately 85% of our 2014 electric revenues were regulated by the PSCW, 2% were regulated by the MPSC and the balance of our electric revenues were regulated by the FERC. All of our natural gas and steam revenues are regulated by the PSCW. 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 return on equity. 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 charged to income in the current period and could have a material adverse impact on our financial results.
We believe we have obtained the necessary permits, approvals and certificates for our existing operations and that our respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to us cannot be predicted. Changes in regulation, interpretations of regulations or the imposition of additional regulations could influence our operating environment and may result in substantial compliance costs.
Governmental agencies could modify our permits, authorizations or licenses.
Wisconsin Electric and Wisconsin Gas are required to comply with the terms of various permits, authorizations and licenses. These permits, authorizations 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.
Also, if we are unable to obtain, renew or comply with these governmental permits, authorizations or licenses, or if we are unable to recover any increased costs of complying with additional license requirements or any other
associated costs in our rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.
We may face significant costs of compliance with existing and future environmental regulations.
Our operations are subject to extensive environmental legislation and regulation by state and federal environmental agencies governing, among other things, air emissions such as Carbon Dioxide (CO2), Sulfur Dioxide (SO2), Nitrogen Oxide (NOx), fine particulates and mercury; water discharges; and management of hazardous, toxic and solid wastes and substances. We incur significant expenditures in complying with these environmental requirements, including expenditures for the installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of our facilities.
The EPA has adopted and is in the process of implementing regulations governing the emission of NOx, SO2, fine particulate matter (PM2.5), mercury and other air pollutants under the Clean Air Act (CAA) through the National Ambient Air Quality Standards (NAAQS), the Mercury and Air Toxics Standards (MATS) rule and other air quality regulations. The EPA has also indicated that it intends to propose rules later this year that will expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters. In addition, the EPA has finalized rules governing cooling water intake structures at our power plants and proposed revisions to the effluent guidelines for steam electric generating plants under the Clean Water Act (CWA). The EPA also adopted the Cross-State Air Pollution Rule (CSAPR), which provides for limits on the interstate transport of NOx and SO2 emissions. In April 2014, the United States Supreme Court issued a decision largely upholding CSAPR and remanding it for further proceedings. In October 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision that cleared the way for the EPA to begin implementing CSAPR on January 1, 2015. Although the EPA has finalized some parts of the rule, there are several items that still need to be addressed. Therefore, there is still uncertainty as to what capital expenditures may ultimately be required to comply with these regulations.
We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. For example, we are in the process of converting the fuel source for VAPP from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. These and other compliance costs we expect to incur over the next three years are included in the table under "Capital Expenditures" in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations.
Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level which could result in significant additional expenditures, operating restrictions on our facilities and increased compliance costs. In addition, the operation of emission control equipment and regulations on our intake and discharge of water could increase our operating costs and could reduce the generating capacity of our power plants. Additional environmental legislation and regulation and the related compliance costs could affect future unit retirement and replacement decisions.
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.
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.
Our electric and gas utility businesses are also subject to significant liabilities related to the investigation and remediation of environmental contamination at certain of our current and former facilities, and at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and 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.
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 coal combustion residuals 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 the facilities that we have previously owned and operated, regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. If we fail (or failed) 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 greenhouse gas (GHG) emissions. The regulation of GHG emissions continues to be a top priority for the President's administration.
The EPA is pursuing regulation of GHG emissions under the CAA. The EPA issued new rules with GHG limits for new fossil fueled power plants that became effective in June 2014. The rule does not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines.
With respect to existing generating units, the EPA issued a proposed rule in June 2014, and is expected to issue a final rule by mid-summer 2015. The proposed rule would require states to submit state plans as early as June 30, 2016. Single states requesting a one year extension would be required to submit state plans by June 30, 2017, and states that are part of a multi-state plan that request a two year extension would be required to submit state plans by June 30, 2018. We are in the process of reviewing the proposed rule to determine the potential impacts to our operations. We expect that these regulations as currently proposed would impact how we operate our existing facilities, particularly our fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.
Legislation to regulate GHG emissions and establish renewable and efficiency standards has also been considered on the state level. Both Wisconsin and Michigan have adopted renewable portfolio standards and energy optimization (efficiency) targets.
There is no guarantee that we will be allowed to fully recover costs incurred to comply with the impending regulations that will require a reduction in GHG emissions or that cost recovery will not be delayed or otherwise conditioned. These and any other related regulations may cause our environmental compliance spending over the next several years to differ materially from the amounts currently estimated. Any legislation or regulation that may ultimately be adopted, either at the federal or state level, designed to reduce GHG emissions could have a material adverse impact on our electric generation and natural gas distribution operations. Such regulation 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 possibly financial condition if such costs are not recovered through regulated rates.
Wisconsin Electric could be subject to higher costs and penalties as a result of mandatory reliability standards.
Wisconsin Electric is 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 cybersecurity assets. Compliance with the mandatory reliability standards could subject Wisconsin Electric to higher operating costs. If Wisconsin Electric were ever found to be in noncompliance with the mandatory reliability standards it could be subject to sanctions, including substantial monetary penalties.
Provisions of the Wisconsin Utility Holding Company Act limit our ability to invest in non-utility businesses and could deter takeover attempts by a potential purchaser of our common stock that would be willing to pay a premium for our common stock.
Under the Wisconsin Utility Holding Company Act, we remain subject to certain restrictions that have the potential of limiting our diversification into non-utility businesses. Under the Act, the sum of certain assets of all non-utility affiliates in a holding company system generally may not exceed 25% of the assets of all public utility affiliates in the system, subject to certain exceptions.
In addition, the Act precludes the acquisition of 10% or more of the voting shares of a holding company of a Wisconsin public utility unless the PSCW has first determined that the acquisition is in the best interests of utility customers, investors and the public. This provision and other requirements of the Act may delay or reduce the likelihood of a sale or change of control of Wisconsin Energy. As a result, stockholders may be deprived of opportunities to sell some or all of their shares of our common stock at prices that represent a premium over market prices.
A decrease in the return on equity earned by participants in MISO could have a negative impact on our results of operations.
In June 2014, FERC issued an order revising its methodology for determining the base return on equity for jurisdictional electric utilities, including transmission owners. FERC expects its new methodology will narrow the "zone" of reasonable returns on equity. FERC also indicated that it will continue its policy that an electric utility's total return on equity is limited to the zone of reasonableness. FERC has set a complaint against MISO and the transmission owners participating in MISO challenging the owners' 12.38% base return on equity for hearing. There is a risk that FERC would reduce the allowed return on equity ATC receives as a transmission owning member of MISO, which ultimately could reduce our earnings with respect to our investment in ATC. In fact, during the fourth quarter of 2014, ATC reduced its earnings to reflect the potential for lower allowed returns on equity.
Risks Related to the Operation of Our Business
Our financial performance may be adversely affected if we are unable to successfully operate our facilities.
Our financial performance depends on the successful operation of our electric generating and distribution, as well as our gas distribution, facilities. Operation of these facilities involves many risks, including: operator error and breakdown or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; cyber security threats; or catastrophic events such as fires, earthquakes, explosions, floods, droughts, pandemic health events such as influenzas or other similar occurrences. Unplanned outages can result in additional maintenance expenses as well as incremental replacement power costs. A decrease in revenues from these facilities or an increase in operating costs could adversely affect our results of operations and cash flows.
Customer growth in our service areas affects our results of operations.
Our results of operations are affected by customer growth in our service areas. Customer growth and energy use can be affected by population growth as well as economic factors in Wisconsin and the Upper Peninsula of Michigan, including job and income growth. Customer growth directly influences the demand for electricity and gas, and the need for additional power generation and generating facilities. Population declines and/or business closings in our service territories or slower than anticipated customer growth has a negative impact on our results of operations and cash flow and could expose us to greater risks of accounts receivable write-offs if customers are unable to pay their bills.
Energy sales are impacted by seasonal factors and varying weather conditions from year-to-year.
Our electric and gas utility businesses are generally seasonal businesses. 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 in the future may fluctuate substantially on a seasonal basis. In addition, we have historically had lower revenues and net income when weather conditions are milder. Our rates in Wisconsin are set by the PSCW based on estimated temperatures which approximate 20-year averages. Mild temperatures during the summer cooling season and during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business. In addition, mild temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.
Factors beyond our control 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 and natural gas distribution infrastructure and electric generating facilities. We expect to spend an aggregate of between $3.3 billion and $3.5 billion during the period 2015 to 2019 on capital investments in our utility and non-utility energy business. These types of construction projects are subject to many of the usual construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the ability to obtain or the cost of labor or materials; the ability of the contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable law or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy.
Certain of these projects require the approval of our regulators. In the event we receive approval, total costs of a project may be higher than estimated and/or higher than amounts approved by our regulators, and there is no guarantee that we will be allowed to recover these additional costs in rates.
Severe weather events, such as floods, droughts, tornadoes and blizzards, could result in substantial damage to or limit the operation of our facilities.
Severe weather events could result in substantial damage to our electric generating and distribution facilities, as well as our gas distribution facilities and ATC's transmission lines. Our hydroelectric generation operations could be adversely affected if there is a significant change in water levels in their respective waterways. In addition, a significant reduction in water levels in waterways that supply cooling water to our power plants, whether by drought or otherwise, could restrict or prevent the operation of such facilities.
In the event we experience any of these weather events or other natural disaster, recovery of any costs in excess of any reserves or applicable insurance is subject to the approval of the PSCW and/or MPSC. There is no guarantee that we will be allowed to fully recover any such costs or that cost recovery will not be delayed or otherwise conditioned. Any denial or delay in recovery of any such costs could adversely affect our results of operations and cash flows.
In addition, damages resulting from severe weather events within our service territories may result in the loss of customers and reduced demand for electricity and natural gas for extended periods. Any significant loss of customers or reduction in demand could adversely affect our results of operations and cash flows.
Advances in technology could make our electric generating facilities less competitive.
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 electric production. If these technologies became cost competitive and achieved 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.
We could be the subject of cyber intrusions that disrupt our electric generation and gas distribution operations and/or result in security breaches that expose us to a risk of loss or misuse of confidential and proprietary information, litigation and potential liability.
We face the risk of physical and cyber attacks, both threatened and actual, against our generation facilities and electric and natural gas distribution infrastructure, as well as our information and technology systems and network infrastructure, which could adversely impact our ability to generate, support and deliver electricity and natural gas, or otherwise operate our facilities in the most efficient manner or at all.
We operate in an industry that requires the continued operation of sophisticated information technology systems and network infrastructure, which are part of an interconnected regional transmission grid. In addition, in the ordinary course of business, we collect and retain sensitive information including personal identification information
about our customers and employees and other confidential information. 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 attacks. If our assets or systems were to fail, be physically damaged or be breached and were not recovered in a timely manner, we may unable to perform critical business functions, and sensitive and other data could be compromised.
Cyber intrusions, including those targeting the electronic control systems used at our generating facilities and for the electric and gas distribution systems, could result in a full or partial disruption of our electric generation and/or gas distribution operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Furthermore, we may need to obtain more expensive purchased power to meet customer demand for electricity if our electric generating facilities are unable to operate at full capacity as a result of a cyber intrusion. Any resulting loss of revenue or increase in expense could have a material adverse effect on our results of operations, cash flow and financial condition.
In addition, any theft, loss and/or fraudulent use of customer, stockholder, employee or proprietary data as a result of cyber intrusion or otherwise could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers, stockholders and regulators, among others.
In addition to lost revenues and increased costs that we could incur as a result of a cyber attack, we may be required to incur significant costs associated with governmental actions in response to such attacks or to strengthen our information and electronic control systems. We could also need to obtain insurance coverage related to the threat of such attacks.
We are a holding company and rely on the earnings of our subsidiaries to meet our financial obligations.
As a holding company with no operations of our own, our ability to meet our financial obligations and pay dividends on our common stock is dependent upon the ability of our subsidiaries to pay amounts to us, whether through dividends or other payments. The ability of our subsidiaries to pay amounts to us will depend on the earnings, cash flows, capital requirements and general financial condition of our subsidiaries and on regulatory limitations. Prior to distributing cash to Wisconsin Energy, our subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. Our subsidiaries also have dividend payment restrictions based on the terms of their outstanding preferred stock and regulatory limitations applicable to them. In addition, each of the bank back-up credit facilities for Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have specified total funded debt to capitalization ratios that must be maintained.
Acts of terrorism could materially and adversely affect our financial condition and results of operations.
Our electric generation and gas distribution facilities, including the facilities of third parties on which we rely, could be targets of terrorist activities. A terrorist attack on our facilities (or those of third parties) could result in a full or partial disruption of our ability to generate, transmit, transport, 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 and financial condition.
Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.
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. 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 a counterparty to one of our power purchase agreements could have an adverse impact on our results of operations.
We have entered into several power purchase agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. Currently, sales through power purchase agreements are responsible for approximately 7.8% of our electric revenues. 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 lag to adjust rates, a customer default under a power purchase agreement could have a negative impact on our results of operations and cash flows.
We are subject to risks associated with changing customer behaviors, including energy conservation and the adoption of new technologies.
Changes in customer behaviors in response to changing conditions and preferences or changes in the adoption of technologies could affect the consumption of electricity. Customers could voluntarily reduce their consumption of electricity, natural gas and steam in response to decreases in their disposable income, increases in energy prices and/or individual conservation efforts. With respect to customer behavior, federal and state programs exist to influence how customers use energy. In addition, Wisconsin and Michigan have adopted energy efficiency targets to reduce energy consumption by certain dates. The adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies use less energy than their older counterparts. On the other hand, new technologies such as electric vehicles can create additional demand for energy. As part of our planning process, we estimate the impacts of changes in customer behavior, government programs, energy efficiency mandates and new technologies, but risks remain.
Any of these matters, as well as any regulatory lag to adjust rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could have a negative impact on our results of operations and cash flows. In addition, any higher costs that are collected through rates could contribute to reduced demand for electricity, natural gas or steam, which could adversely impact our results of operations and financial condition.
Our revenues could be negatively impacted by competitive activity in the wholesale electricity markets.
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 (OTC). 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 short-term and long-term capital markets to support our capital expenditures and other 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, under competitive terms and rates. In addition, we rely on committed bank credit agreements as back-up liquidity which allows us to access the low cost commercial paper markets. If our access to any of these markets were limited, or our cost of capital significantly increased, due
to a rating downgrade, an economic downturn or uncertainty, prevailing market conditions, concerns over foreign economic conditions and/or the ability of foreign governments and central banks to respond to changing economic conditions, changes in tax policy, war or the threat of war, the overall health of the utility and financial institution industries, a negative view of the utility industry, bankruptcy or financial distress at a financial institution or sovereign entity or other factors, our ability to implement our business plan could be limited which could materially and adversely affect our results of operations.
We are exposed to risks related to general economic conditions in our service territories.
Our electric and gas utility businesses are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn or disruption of national or international financial markets could adversely affect the financial condition of our customers and demand for their products. Adverse economic conditions in our service territories and/or decreased demand for products produced in our service area could cause a reduction in demand for electricity and/or natural gas that could result in decreased earnings and cash flow. We would also expect our collections of accounts receivable to be adversely impacted.
A downgrade in the credit ratings of WEC or any of its subsidiaries could negatively affect their ability to access capital at reasonable costs and/or require the posting of collateral.
There are a number of factors that impact Wisconsin Energy's and its subsidiaries' credit ratings, including, without limitation, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. Wisconsin Energy or any of its subsidiaries could experience a downgrade in their ratings if the rating agencies determine that the level of business or financial risk of the industry or Wisconsin Energy and/or its subsidiaries has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings. If Wisconsin Energy or its subsidiaries are downgraded by the rating agencies, their borrowing costs could increase, funding sources could decrease and, for any downgrade to below investment grade, collateral requirements may be triggered in several contracts.
An increase in natural gas costs could negatively impact our electric and gas utility operations.
Wisconsin Electric burns natural gas in several of its peaking power plants and in PWGS 1 and PWGS 2, 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. Disruption in the supply of natural gas due to a curtailment in production or distribution can increase the cost of natural gas, as can international market conditions and demand for natural gas. In addition, the availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas. Higher natural gas costs can have the effect of increasing demand for other sources of fuel thereby increasing the costs of those fuels as well. Additionally, high natural gas costs increase our working capital requirements and could adversely impact our collection of accounts receivable.
For Wisconsin customers, Wisconsin Electric bears the risk for the recovery of fuel and purchased power costs within a symmetrical two percent fuel tolerance band compared to the forecast of fuel and purchased power costs established in its rate structure. Our gas distribution business receives dollar for dollar recovery of the cost of natural gas, subject to tolerance bands and prudency review.
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 mitigate an interruption or decline in supply, there can be no assurance that the inventory will be adequate to fully mitigate all potential reductions in supply. While we have coal supply and transportation contracts in place, there can be no assurance 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 units and replace this lost generation through additional power purchases in the MISO market. 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 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 market. 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 exposures. 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 the hedging programs of Wisconsin Electric and Wisconsin Gas 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. It is uncertain whether retail access might be implemented in Wisconsin.
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. The two iron ore mines located in the Upper Peninsula of Michigan are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.
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 a Locational Marginal Price (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 market and the costs associated with estimated payment settlements.
Poor investment performance of benefit plan holdings and other factors impacting benefit plan costs could unfavorably impact our liquidity and results of operations.
We have significant obligations related to pension and other post-retirement benefit plans. Our cost of providing these plans is dependent upon a number of factors including actual plan experience and assumptions concerning the future, such as 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 and our required or voluntary contributions to be made to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. A decline in the market value of these assets may increase our funding requirements. Changes in interest rates affect plan liabilities - as rates decrease, the liabilities increase, which could increase our funding requirements. Changes in demographics, such as an increase in the number of retirements or changes in life expectancy assumptions, may also increase our funding requirements. Changes made to the plans may also impact
current and future pension costs. In addition, it is possible that medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. 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 ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage 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, as well as by international, national, state or local events, as well as 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 Our Proposed Acquisition of Integrys
We may be unable to satisfy the conditions or obtain the approvals required to complete the acquisition of Integrys or such approvals may contain material restrictions or conditions.
Completion of the acquisition of Integrys remains subject to the approval of various government agencies. We cannot provide assurance that we will obtain all required consents or approvals, or that the regulatory consents or approvals will not impose conditions on the completion, or require changes to the terms, of the acquisition, including restrictions on the business, operations or financial performance of the combined company. These conditions or changes could also delay or materially and adversely affect the business results and financial condition of the combined company.
While the acquisition of Integrys is pending, we are subject to business uncertainties and contractual restrictions that could materially adversely affect our operations and the future of our business.
The Merger Agreement includes restrictions on the conduct of our business prior to the completion of the acquisition of Integrys, generally requiring us to conduct our business in the ordinary course and subjecting us to a variety of specified limitations absent Integrys’ prior written consent. We may find that these and other contractual arrangements in the Merger Agreement may delay or prevent us from or limit our ability to respond effectively to competitive pressures, industry developments and future business opportunities that may arise during such period, even if our management thinks they may be advisable. The pendency of the acquisition may also divert management’s attention and our resources from ongoing business and operations. If any of these effects were to occur, it could materially and adversely affect our operations and the future of our business, regardless of whether the acquisition is completed.
If completed, the acquisition of Integrys may not achieve its intended results.
We entered into the Merger Agreement with the expectation that the acquisition of Integrys would result in various benefits. If the acquisition is completed, achieving the anticipated benefits will be subject to a number of uncertainties, including whether Wisconsin Energy's and Integrys' businesses can be integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.
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, steam utility distribution mains and 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.
As of December 31, 2014, we owned the following generating assets:
(a)
Dependable capability 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. The values are established by tests and may change slightly from year to year. Dependable capability for the wind sites is determined based on a capacity factor of approximately 20%.
As of December 31, 2014, we operated approximately 21,457 pole-miles of overhead distribution lines and 24,303 miles of underground distribution cable, as well as approximately 350 distribution substations and 295,461 line transformers.
As of December 31, 2014, our gas distribution system included approximately 21,382 miles of distribution and transmission mains connected at 184 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, Northern Natural Pipeline Company, Great Lakes Transmission Company, Viking Gas Transmission and Michigan Consolidated Gas Company. We have liquefied natural gas storage plants which convert and store, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plants have a send-out capability of 73,600 Dth per day. We also have propane air systems for peaking purposes. These propane air systems will provide approximately
2,960 Dth per day of supply to the system. Our gas distribution system consists almost entirely of plastic and coated steel pipe.
We also own office buildings, gas regulating and metering stations and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.
As of December 31, 2014, the combined steam systems supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 42 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels and other pressure regulating equipment.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
In addition to those legal proceedings discussed below, 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 other 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.
ENVIRONMENTAL MATTERS
We are subject to federal, state and certain local laws and regulations governing the environmental aspects of our operations. Management believes that our existing facilities are in material compliance with applicable environmental requirements.
Paris Generating Station: See Factors Affecting Results, Liquidity and Capital Resources -- Other Matters for information concerning a contested case on the replacement of certain turbine blades as part of maintenance performed on Units 1 and 4 at our Paris Generating Station (PSGS).
Solvay Coke and Gas Site: Wisconsin Electric and Wisconsin Gas have been identified as potentially responsible parties at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company of Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site. In 2007, Wisconsin Electric, Wisconsin Gas and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. Site investigations led to the submission of a draft remedial investigation report to the EPA in June 2014. The EPA issued subsequent comments which we addressed. Under the Administrative Settlement Agreement, neither Wisconsin Electric nor Wisconsin Gas admits to any liability for the site, waives any liability defenses, or commits to perform future site remedial activities. The companies' share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported in Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
See Environmental Compliance in Item 1 and Environmental Matters, Manufactured Gas Plant Sites, and Coal Combustion Product Landfill Sites in Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements which are incorporated by reference herein, for a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites and air quality.
UTILITY RATE MATTERS
See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 for information concerning rate matters in the jurisdictions where Wisconsin Electric and Wisconsin Gas do business.
OTHER MATTERS
Litigation Relating to the Acquisition of Integrys: Since the announcement of the proposed acquisition, Integrys and its board of directors, along with Wisconsin Energy, have been named as defendants in ten separate purported class action lawsuits filed in Brown County, Wisconsin (three of the cases -- Rubin v. Integrys, et al., Blachor v. Integrys, et al., and Albera v. Integrys, et al.), Milwaukee County, Wisconsin (two of the cases -- Amo v. Integrys, et al. and Inman v. Integrys, et al.), Cook County, Illinois (two of the cases - Taxman v. Integrys, et al. and Curley v. Integrys, et al.), and the federal court for the Northern District of Illinois (three of the cases - Steiner v. Integrys, et al., Tri-State Joint Fund v. Integrys, et al., and Collison v. Integrys, et al.). In the Tri-State Joint Fund case, Wisconsin Energy’s CEO was also named as a defendant. The cases were brought on behalf of proposed classes consisting of shareholders of Integrys. The complaints allege, among other things, that the Integrys board members breached their fiduciary duties by failing to maximize the value to be received by Integrys’ shareholders, that Wisconsin Energy aided and abetted the breaches of fiduciary duty, and that the joint proxy statement/prospectus contains material misstatements and omissions. The complaints seek, among other things, (a) to enjoin defendants from consummating the acquisition; (b) rescission of the Merger Agreement; and (c) to direct the defendants to exercise their fiduciary duties to obtain the highest value possible for the Integrys shareholders. The Brown County and Cook County cases have been dismissed in favor of the Milwaukee County actions. On November 12, 2014, the parties entered into a Memorandum of Understanding which provides the basis for a complete settlement of these actions. Wisconsin Energy anticipates that a Stipulation of Settlement will be presented to the Court for approval during the second quarter of 2015.
For information concerning our PTF strategy, including the Settlement Agreement with Bechtel Power Corporation (Bechtel), see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not Applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages at December 31, 2014 and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until they resign, die or are removed pursuant to the Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.
Gale E. Klappa. Age 64.
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Wisconsin Energy -- Chairman of the Board and Chief Executive Officer since May 2004. President from April 2003 to July 2013.
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Wisconsin Electric -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
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Wisconsin Gas -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
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Director of Joy Global, Inc. and Badger Meter, Inc.
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Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.
Stephen P. Dickson. Age 54.
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Wisconsin Energy -- Vice President since 2005. Controller since 2000.
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Wisconsin Electric -- Vice President since 2005. Controller since 2000.
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Wisconsin Gas -- Vice President since 2005. Controller since 1998.
J. Kevin Fletcher. Age 56.
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Wisconsin Electric -- Senior Vice President since October 2011.
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Wisconsin Gas -- Senior Vice President since October 2011.
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Georgia Power -- Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.
Robert M. Garvin. Age 48.
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Wisconsin Energy -- Senior Vice President since April 2011.
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Wisconsin Electric -- Senior Vice President since April 2011.
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Wisconsin Gas -- Senior Vice President since April 2011.
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American Transmission Co. -- Vice President and General Counsel from 2009 to April 2011.
J. Patrick Keyes. Age 49.
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Wisconsin Energy -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
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Wisconsin Electric -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
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Wisconsin Gas -- Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
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Accenture -- Senior Executive from September 2001 to March 2011.
Allen L. Leverett. Age 48.
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Wisconsin Energy -- President since August 2013. Executive Vice President from May 2004 to July 2013. Chief Financial Officer from July 2003 to February 2011.
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Wisconsin Electric -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 to February 2011.
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Wisconsin Gas -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 to February 2011.
Susan H. Martin. Age 62.
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Wisconsin Energy -- Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.
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Wisconsin Electric -- Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.
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Wisconsin Gas -- Executive Vice President and General Counsel since March 2012. Corporate Secretary since December 2007. Vice President and Associate General Counsel from December 2007 to February 2012.
Certain executive officers also hold offices in our non-utility subsidiaries.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NUMBER OF COMMON STOCKHOLDERS
As of December 31, 2014, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had approximately 38,110 registered stockholders.
COMMON STOCK LISTING AND TRADING
Our common stock is listed on the New York Stock Exchange under the ticker symbol "WEC."
DIVIDENDS AND COMMON STOCK PRICES
Common Stock Dividends of Wisconsin Energy: Cash dividends on our common stock, as declared by the Board of Directors, are normally paid on or about the first day of March, June, September and December of each year. We review our dividend policy on a regular basis. Subject to any regulatory restrictions 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, earnings, financial condition and other requirements. For information regarding restrictions on the ability of our subsidiaries to pay us dividends, see Note H -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.
On January 15, 2015, the Board of Directors increased the quarterly dividend to $0.4225 per share effective with the first quarter of 2015 dividend payment, which would result in annual dividends of $1.69 per share. In addition, the Board affirmed our dividend policy that targets a dividend payout ratio of 65-70% of earnings in 2017.
Range of Wisconsin Energy Common Stock Prices and Dividends:
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
(a)
Quarterly results of operations are not directly comparable because of seasonal and other factors. See Management's Discussion and Analysis of Financial Condition and Results of Operations.
(b)
Quarterly earnings per share may not total to the amounts reported for the year because the computation is based on the weighted average common shares outstanding during each quarter.
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
CORPORATE DEVELOPMENTS
INTRODUCTION
Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in a utility energy segment and a non-utility energy segment. Unless qualified by their context, when used in this document the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.
Our utility energy segment primarily consists of Wisconsin Electric and Wisconsin Gas, both doing business under the trade name of "We Energies." We generate and distribute electricity in Wisconsin and the Upper Peninsula of Michigan and we distribute natural gas in Wisconsin. Our non-utility energy segment primarily consists of We Power, which primarily owns and leases to Wisconsin Electric electric power generating facilities constructed as part of our PTF strategy.
CORPORATE STRATEGY
Business Opportunities
Acquisition: On June 22, 2014, we entered into an agreement to acquire Integrys. The proposed acquisition is scheduled to close in the second half of 2015, and is subject to the receipt of various approvals. This acquisition is in alignment with our corporate strategy to invest in regulated electric and gas businesses. We expect the acquisition to:
•
Add approximately $6.6 billion of regulated fixed assets;
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Add 0.5 million electric customers;
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Add 1.7 million gas customers; and
•
Increase our ownership of ATC to 60% from 26.2%.
For additional information on this acquisition, see Note D -- Proposed Acquisition in the Notes to Consolidated Financial Statements.
Additional Investment Opportunities: Our primary investment opportunities are in three areas: our regulated utility business; our investment in ATC; and our generation plants within our non-utility energy segment.
Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve our electric and gas customers under the trade name of We Energies. We Energies operates under a traditional rate regulated cost of service environment. During 2014, our regulated utility earned $770.2 million of operating income. Over the next five years, we currently expect to invest between $3.2 billion and $3.4 billion in this business.
We have a 26.2% ownership interest in ATC, a MISO member company regulated by FERC. Our investment in ATC totaled $424.1 million as of December 31, 2014, and our 2014 pre-tax earnings from ATC totaled $66.0 million. Over the next five years, in addition to any potential investment through our undistributed earnings in ATC, on a stand-alone basis we expect to make capital contributions of approximately $130 million in ATC as it continues to invest in transmission projects.
Our non-utility energy segment consists primarily of the four generation plants constructed as part of our PTF strategy. All four plants have been placed in service and are being leased to Wisconsin Electric under long-term leases that run for 25 years (PWGS 1 and PWGS 2) and 30 years (OC 1 and OC 2). We recognize revenues on a levelized basis over the life of the leases. Our operating income from our non-utility business totaled $368.2 million during 2014. Over the next five years, we expect to invest approximately $130 million in this segment. These investments should provide additional earnings.
RESULTS OF OPERATIONS
CONSOLIDATED EARNINGS
The following table compares our operating income by business segment and our net income for 2014, 2013 and 2012:
An analysis of contributions to operating income by segment and a more detailed analysis of results follows.
UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
The following table summarizes our utility energy segment's operating income during 2014, 2013 and 2012:
An analysis of the utility energy segment follows.
Electric Utility Gross Margin
The following table compares our electric utility gross margin during 2014 with similar information for 2013 and 2012, including a summary of electric operating revenues and electric sales by customer class:
(a)
Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
(b)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.
Electric Utility Revenues and Sales
2014 vs. 2013: Our electric utility operating revenues increased by $92.4 million, or 2.8%, when compared to 2013. The most significant factors that caused a change in revenues were:
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A $120.9 million increase in sales for resale because of increased sales into the MISO Energy Markets as a result of Michigan's alternative electric supplier program and increased availability of our generating units. The margin on these sales is used to reduce fuel costs for our retail customers.
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A $78.4 million decrease in large commercial/industrial sales because of the two iron ore mines switching to an alternative electric supplier in September 2013. See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Michigan Business, for a discussion of the impact of industry restructuring in Michigan on our electric sales.
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A $59.4 million increase in other operating revenues, primarily driven by the recognition of $56.4 million related to revenues under the System Support Resource (SSR) agreement with MISO. See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Michigan Business -- SSR Payments for further discussion.
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Wisconsin net retail pricing increases of $38.3 million, which are primarily related to our 2013 Wisconsin Rate Case.
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Unseasonably cool summer weather which decreased electric revenues by an estimated $45.8 million.
As measured by cooling degree days, 2014 was 36.6% cooler than normal, and 32.6% cooler than 2013 due to mild second and third quarters. The unfavorable impact of the cool summer weather was partially offset by the cold winter weather. Residential sales decreased by 2.4%, primarily due to the weather. Sales to our large commercial/industrial customers decreased by 14.8% primarily because of the loss of the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 1.1%. The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. In addition, other smaller retail customers switched to an alternative electric supplier.
Effective February 1, 2015, the two mines returned as retail customers. We expect to defer the net revenue from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in future rate proceedings. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice.
2013 vs. 2012: Our electric utility operating revenues increased by $114.8 million, or 3.6%, when compared to 2012. The most significant factors that caused a change in revenues were:
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Wisconsin net retail pricing increases of $115.6 million ($177.7 million less $62.1 million related to Section 1603 Renewable Energy Treasury Grant (Treasury Grant) bill credits), which are primarily related to our 2013 Wisconsin Rate Case. For information on the Treasury Grant and the rate order in the 2013 rate case, see Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments and -- Utility Rates and Regulatory Matters, respectively.
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An $89.8 million increase in sales for resale due to increased sales into the MISO Energy Markets as a result of increased availability of our generating units.
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A $48.0 million decrease in large commercial/industrial sales due to the two iron ore mines that switched to an alternative electric supplier effective September 1, 2013.
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A $23.1 million decrease in other operating revenues, primarily driven by the amortization of $25.9 million in 2012 related to proceeds we received as part of a settlement with the United States Department of Energy (DOE) regarding the DOE's failure to remove spent nuclear fuel from Point Beach.
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A return to more normal summer weather as compared to 2012 that decreased electric revenues by an estimated $17.7 million.
As measured by cooling degree days, 2013 was 5.8% cooler than normal, and 33.9% cooler than 2012. Residential sales decreased by 2.1%, primarily due to the weather. Sales to our large commercial/industrial customers decreased by 10.7% primarily because of the loss of the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 3.0%. Wholesale - Other sales increased 24.7% primarily due to increased off-peak energy sales which generate lower incremental revenue because the majority of our wholesale revenue is tied to demand.
Electric Fuel and Purchased Power Expenses
2014 vs. 2013: Our electric fuel and purchased power costs increased by $69.5 million, or approximately 6.1%, when compared to 2013. This increase was primarily caused by a 1.5% increase in total MWh sales and higher generating costs driven by an increase in natural gas prices.
2013 vs. 2012: Our electric fuel and purchased power costs increased by $54.2 million, or approximately 5.0%, when compared to 2012. This increase was primarily caused by a 6.3% increase in total MWh sales, partially offset by a decrease in our average cost of fuel because of outage timing and a decrease in coal costs.
Gas Utility Revenues, Gross Margin and Therm Deliveries
The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2014, 2013 and 2012.
We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under GCRMs. Our average cost of gas per therm during 2014, 2013 and 2012 was $0.70, $0.48 and $0.50, respectively. The following table compares our gas utility gross margin and therm deliveries by customer class during 2014, 2013 and 2012:
(a)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.
2014 vs. 2013: Our total retail gas margin increased by $15.8 million, or approximately 4.1%, when compared to 2013, primarily because of colder winter weather in 2014. We estimate that colder winter weather increased gas margins by approximately $11.2 million. As measured by heating degree days, 2014 was 5.3% colder than 2013 and 15.4% colder than normal.
2013 vs. 2012: Our total retail gas margin increased by $24.1 million, or approximately 6.7%, when compared to 2012. We estimate that colder winter weather increased gas margins by approximately $56.9 million. As measured by heating degree days, 2013 was 26.8% colder than 2012 and 9.9% colder than normal. Gas margins were reduced by $42.3 million because of lower gas rates that became effective January 1, 2013.
Other Operation and Maintenance Expense
2014 vs. 2013: Our other operation and maintenance expense decreased by $59.3 million, or approximately 3.9%, when compared to 2013. This decrease was primarily driven by lower benefit costs related to pensions and medical costs.
Our utility operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages and amortization of regulatory assets.
2013 vs. 2012: Our other operation and maintenance expense increased by $45.5 million, or approximately 3.1%, when compared to 2012. This increase was primarily driven by the reinstatement of $148.0 million of regulatory amortizations, offset in part by a $50.1 million reduction in bad debt expense related to our natural gas customers and continued cost control efforts across our utilities. For additional information on the regulatory amortizations, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- 2012 Wisconsin Rate Case.
Depreciation and Amortization Expense
2014 vs. 2013: Depreciation and Amortization expense increased by $20.4 million, or approximately 6.4%, when compared to 2013. This increase was primarily because of an overall increase in utility plant in service as a result of the biomass plant that went into service in November 2013. For additional information on the biomass facility, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- Renewables, Efficiency, and Conservation.
2013 vs. 2012: Depreciation and Amortization expense increased by $23.8 million, or approximately 8.0%, when compared to 2012. This increase was primarily because of an overall increase in utility plant in service. In addition to the biomass facility that went into service in November 2013, the emission control equipment for units 5 and 6 of the Oak Creek Air Quality Control System (AQCS) project went into service in March 2012, and for units 7 and 8 in September 2012.
Treasury Grant
During 2014, we recognized $17.4 million of income related to a Treasury Grant associated with the completion of the biomass plant, compared to $48.0 million in 2013. The lower grant income corresponds to the lower bill credits provided to our retail electric customers in Wisconsin in 2014. For additional information on the Treasury Grant, see Factors Affecting Results, Liquidity and Capital Resources -- Accounting Developments.
NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
Our non-utility energy segment consists primarily of our PTF units (PWGS 1, PWGS 2, OC 1 and OC 2).
This segment reflects the lease revenues on the PTF units as well as the depreciation expense. Operating and maintenance costs and limited management fees associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.
2014 vs. 2013: Non-utility energy segment operating income increased $1.1 million, or approximately 0.3%, when compared to 2013.
2013 vs. 2012: Non-utility energy segment operating income increased $8.3 million, or approximately 2.3%, when compared to 2012. The increase primarily relates to the increase in operating revenues related to the final approved construction costs for the Oak Creek expansion as part of the 2013 Wisconsin Rate Case.
CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME
2014 vs. 2013: Corporate and other affiliates had an operating loss of $26.3 million in 2014 compared with an operating loss of $6.4 million in 2013. The increase in operating loss is primarily attributable to approximately $14.6 million, or $0.06 per share, of external costs related to the proposed acquisition of Integrys.
2013 vs. 2012: Corporate and other affiliates had an operating loss of $6.4 million in 2013 compared with an operating loss of $6.2 million in 2012.
CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET
2014 vs. 2013: Other income and deductions, net decreased by approximately $5.4 million, or 28.7%, when compared to 2013. This decrease primarily relates to lower AFUDC - Equity related to the biomass plant going into service in November 2013, partially offset by an increased gain on property sales.
2013 vs. 2012: Other income and deductions, net decreased by approximately $16.0 million, or 46.0%, when compared to 2012. This decrease primarily relates to lower AFUDC - Equity related to the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8, partially offset by the biomass plant which went into service in November 2013.
CONSOLIDATED INTEREST EXPENSE, NET
2014 vs. 2013: Our net interest expense decreased by $10.6 million, or 4.2%, as compared to 2013 primarily because of lower debt levels and lower average interest rates on long-term debt. Our capitalized interest decreased by $6.4 million primarily because of lower construction work in progress as the biomass plant went into service in November 2013.
2013 vs. 2012: Our net interest expense increased by $3.9 million, or 1.6%, as compared to 2012 primarily because of lower capitalized interest. Our capitalized interest decreased by $6.5 million primarily because of lower construction work in progress.
CONSOLIDATED INCOME TAX EXPENSE
2014 vs. 2013: Our effective tax rate applicable to continuing operations was 38.1% in 2014 compared to 36.9% in 2013. This increase in our effective tax rate was due to reduced tax benefits associated with Treasury Grant income, decreased AFUDC - Equity and non-deductible acquisition related expenses. For further information, see
Note G -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2015 annual effective tax rate to be between 37.0% and 38.0%.
2013 vs. 2012: Our effective tax rate applicable to continuing operations was 36.9% in 2013 compared to 35.9% in 2012. This increase in our effective tax rate was due to reduced domestic production activities deductions and AFUDC - Equity.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The following table summarizes our cash flows during 2014, 2013 and 2012:
Operating Activities
2014 vs. 2013: Cash provided by operating activities was $1,197.7 million during 2014, which was a decrease of $33.3 million when compared to 2013. During 2014, we experienced higher net income, depreciation expense and favorable cash flows from accounts receivable, primarily because of the timing of the Treasury Grant. More than offsetting these favorable items were increases in working capital related to natural gas in storage and increases in regulatory assets.
2013 vs. 2012: Cash provided by operating activities was $1,231.0 million during 2013, which was an increase of $57.1 million over 2012. The increase is primarily because of lower contributions to our qualified benefit plans and higher non-cash charges to earnings. During 2013, we made no contributions to our qualified benefit plans, compared to contributions of $100 million during 2012. In addition, we had higher net income, depreciation expense and amortization expense. Included in the higher amortization expense is a $77.9 million increase in the amortization of regulatory items. Partially offsetting these items is an increase in accounts receivable and accrued revenues of $201.2 million because of colder winter weather and the Treasury Grant.
Investing Activities
2014 vs. 2013: Cash used in investing activities was $756.8 million during 2014, which was $11.0 million higher than 2013. This increase was driven by an increase of $48.7 million in capital expenditures, primarily because of starting the conversion of the fuel source for VAPP from coal to natural gas. This increase in cash used in investing activities was partially offset by an increase in proceeds received from asset sales and a decrease of cost of removal, net of salvage.
The following table identifies capital expenditures by year:
2013 vs. 2012: Cash used in investing activities was $745.8 million during 2013, which was $16.2 million higher than 2012. Our change in restricted cash decreased by $40.1 million, which is related to the 2012 release of restricted cash through bill credits and the reimbursement of costs associated with the proceeds we received from the settlement with the DOE. Our capital expenditures decreased by $19.6 million during 2013 as compared to 2012, primarily because of decreased spending as the Oak Creek AQCS project went into service in 2012.
Financing Activities
The following table summarizes our cash flows from financing activities:
2014 vs. 2013: Cash used in financing activities was $405.0 million during 2014, compared to $494.8 million during 2013. The decrease in cash used in financing activities was primarily driven by a decrease in common stock repurchased as a result of our Board of Directors terminating our share repurchase program in connection with the proposed acquisition of Integrys. During 2014, we repurchased $18.6 million of common stock as compared to $126.0 million in 2013 as part of the share repurchase program. See Note H -- Common Equity for additional information on share repurchases. Our dividends paid on common stock increased by $23.1 million during 2014 as compared to 2013, as a result of increases in the quarterly common stock dividend of 12.5% and 2.0% in the third quarter of 2013 and first quarter of 2014, respectively.
2013 vs. 2012: Cash used in financing activities was $494.8 million during 2013, compared to $422.8 million during 2012. Our dividends paid on common stock increased by $52.6 million during 2013 as compared to 2012, as a result of increases in the quarterly common stock dividend of 13.3% and 12.5% in the first and third quarter, respectively. In 2013, we repurchased approximately 3.0 million shares in the open market at a total cost of $126.0 million, compared to 1.5 million shares at a cost of $51.8 million in 2012 pursuant to a share repurchase program that expired at the end of 2013.
No new shares of Wisconsin Energy's common stock were issued in 2014, 2013 or 2012. During these years, our independent plan agents purchased, in the open market, 2.3 million shares at a cost of $104.6 million, 2.4 million shares at a cost of $97.4 million and 2.8 million shares at a cost of $101.4 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2014, 2013 and 2012, we received proceeds of $50.3 million, $48.5 million and $49.8 million, respectively, related to the exercise of stock options. In addition, we instructed our independent agents to purchase shares of our common stock in the open market to satisfy our obligations under our stock purchase and dividend reinvestment plan and various employee benefit plans.
CAPITAL RESOURCES AND REQUIREMENTS
Working Capital
As of December 31, 2014, our current liabilities exceeded our current assets by approximately $133.3 million. We do not expect this to have any impact on our liquidity because we believe we have adequate back-up lines of credit in place for ongoing operations. We also have access to the capital markets to finance our construction program and to refinance current maturities of long-term debt if necessary.
Liquidity
We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities.
For our existing business, we currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets and internally generated cash.
Wisconsin Energy, Wisconsin Electric and Wisconsin Gas maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.
As of December 31, 2014, we had approximately $1.2 billion of available, undrawn lines under our bank back-up credit facilities. As of December 31, 2014, we had approximately $617.6 million of commercial paper outstanding on a consolidated basis that was supported by the available lines of credit. During 2014, our maximum commercial paper outstanding was $721.4 million with a weighted-average interest rate of 0.18%. For additional information regarding our commercial paper balances during 2014, see Note K -- Short-Term Debt in the Notes to Consolidated Financial Statements.
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. The following table summarizes such facilities as of December 31, 2014:
In December 2014, we amended each of our credit facilities to extend their expirations from December 2017 to December 2019.
Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval.
The following table shows our capitalization structure as of December 31, 2014 and 2013, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the rating agencies currently view Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 (Junior Notes):
For a summary of the interest rate, maturity and amount outstanding of each series of our long-term debt on a consolidated basis, see the Consolidated Statements of Capitalization.
Included in Long-Term Debt on our Consolidated Balance Sheets as of December 31, 2014 and 2013 is $500 million aggregate principal amount of the Junior Notes. The adjusted presentation attributes $250 million of the Junior Notes to Common Equity and $250 million to Long-Term Debt. We believe this presentation is consistent with the 50% or greater equity credit the majority of rating agencies currently attribute to the Junior Notes.
The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages Wisconsin Energy's capitalization structure, including its total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.
As described in Note H -- Common Equity, in the Notes to Consolidated Financial Statements, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.
Wisconsin Electric is the obligor under two series of tax exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric issued commercial paper to fund the purchase of the bonds. As of December 31, 2014, the repurchased bonds were still outstanding, but were not reported as long-term debt or included on our Consolidated Statements of Capitalization because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.
Bonus Depreciation Provisions
The Tax Increase Prevention Act of 2014 was signed into law on December 19, 2014, which extended the 50% bonus depreciation rules to include assets placed in service in 2014. As a result of the increased federal tax depreciation for 2014 and prior years, we did not make federal income tax payments for 2013 and 2014.
Credit Rating Risk
We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity contracts and
employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at Standard & Poor's Ratings Services (S&P) and/or Baa3 at Moody's Investor Service (Moody's). As of December 31, 2014, we estimate that the collateral or the termination payments required under these agreements totaled approximately $198.0 million. Generally, collateral may be provided by a Wisconsin Energy guaranty, letter of credit or cash. We also have other commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.
In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.
In December 2014, Moody's affirmed the ratings of Wisconsin Electric (senior unsecured, A1; commercial paper, P-1) and Wisconsin Gas (senior unsecured, A1; commercial paper, P-1). Moody's affirmed the stable ratings outlook for Wisconsin Electric and Wisconsin Gas. In June 2014, Moody's affirmed the ratings of Wisconsin Energy (senior unsecured, A2; junior subordinated, A3; commercial paper, P-1), Elm Road Generating Station Supercritical, LLC (ERGSS) (senior notes, A1) and Wisconsin Energy Capital Corporation (WECC) (senior unsecured, A2). Moody's also affirmed the stable ratings outlook for ERGSS, and revised the ratings outlook for Wisconsin Energy and WECC from stable to negative.
In August 2014, Fitch Ratings (Fitch) affirmed the ratings of Wisconsin Electric (commercial paper,; senior unsecured, A+), Wisconsin Gas (commercial paper,; senior unsecured, A) and ERGSS (senior notes, A+). Fitch also affirmed the stable ratings outlook for these companies. In June 2014, Fitch placed the ratings of Wisconsin Energy and WECC on Rating Watch Negative.
In June 2014, S&P affirmed the ratings of Wisconsin Energy (commercial paper, A-2; senior unsecured, BBB+; junior subordinated, BBB), Wisconsin Electric (commercial paper, A-2; senior unsecured, A-), Wisconsin Gas (commercial paper, A-1; senior unsecured, A) and WECC (senior unsecured, A-). S&P affirmed the stable ratings outlook for Wisconsin Electric and Wisconsin Gas, and revised the ratings outlook from stable to negative for Wisconsin Energy and WECC.
The change in outlooks for Wisconsin Energy and WECC relates to the proposed acquisition of Integrys.
Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.
Capital Requirements
Acquisition of Integrys: On June 22, 2014, we entered into an agreement to acquire Integrys. We expect the transaction to close in the second half of 2015. Under the terms of the Merger Agreement, for each share of Integrys common stock, Integrys shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash. We expect to finance the acquisition through the issuance of approximately 91 million shares of Wisconsin Energy common stock to Integrys shareholders and through the issuance of $1.5 billion of debt. We will also assume all of Integrys' outstanding debt, which had an estimated fair value of $3.3 billion.
Capital Expenditures: For our existing business, our estimated capital expenditures for the next three years are as follows:
The majority of spending consists of upgrading our electric and gas distribution systems. Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such as air quality standards, renewable energy standards and electric reliability initiatives that impact our utility energy segment.
Common Stock Matters: In December 2013, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock from January 1, 2014 through the end of 2017. Through December 31, 2014, we acquired approximately 0.4 million shares in the open market at a cost of $18.6 million pursuant to this program. All of these shares were purchased during the first quarter of 2014. On June 22, 2014, in connection with the proposed acquisition of Integrys, the Board of Directors terminated this share repurchase program.
In addition, on January 15, 2015, our Board of Directors increased our quarterly common stock dividend to $0.4225 per share, up approximately 8.3%, from $0.39 per share, effective with the first quarter 2015 dividend payment. This equates to an annual dividend of $1.69 per share. The Board of Directors reaffirmed a policy that targets a dividend payout ratio that trends to 65-70% of earnings in 2017.
Upon consummation of the proposed acquisition of Integrys, we expect to increase the dividend 7-8% for our shareholders to reflect the dividend policy of the combined company. The projected payout target for the combined company in future years after closing the acquisition is 65-70% of earnings.
Investments in Outside Trusts: We use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $1.8 billion as of December 31, 2014. These trusts hold investments that are subject to the volatility of the stock market and interest rates.
During 2014 and 2013, we made no contributions to our qualified pension plans or our qualified Other Post-Retirement Employee Benefit (OPEB) plans. In January 2015, we contributed $100 million to our qualified pension plans. 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 N -- Benefits in the Notes to Consolidated Financial Statements.
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 effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For additional information, see Note F -- Variable Interest Entities in the Notes to Consolidated Financial Statements in this report.
Contractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2014:
(a)
The amounts included in the table are calculated using current market prices, forward curves and other estimates.
(b)
Principal and interest payments on Long-Term Debt (excluding capital lease obligations).
(c)
Capital Lease Obligations of Wisconsin Electric for power purchase commitments. This amount does not include We Power leases to Wisconsin Electric which are eliminated upon consolidation.
(d)
Operating Lease Obligations for power purchase commitments and rail car leases.
(e)
Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation related to utility operations and for construction, information technology and other services for utility and We Power operations. This includes the power purchase agreement for Point Beach.
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 G -- Income Taxes in the Notes to Consolidated Financial Statements in this report.
Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.
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: Our utility energy segment accounts for its regulated operations in accordance with accounting guidance for regulated entities. Our rates are determined by 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 eight years. Regulatory assets associated with pension and OPEB expenses are amortized as a component of pension and OPEB expense. 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, 2014, our regulatory assets totaled $1,271.2 million and our regulatory liabilities totaled $830.6 million.
Commodity Prices: In the normal course of providing energy, we are subject to market fluctuations of the costs of coal, natural gas, purchased power and fuel oil used in the delivery of coal. We manage our fuel and 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 by utilizing gas and electric hedging programs.
Wisconsin's retail electric fuel cost adjustment procedure mitigates some of Wisconsin Electric's risk of electric fuel cost fluctuation. The fuel rules allow for a deferral of prudently incurred fuel costs that fall outside of a symmetrical band (plus or minus 2%). Under the rules, any over or under-collection of fuel costs deferred at the end of the year would be incorporated into fuel cost recovery rates in future years. For information regarding the fuel rules, see Utility Rates and Regulatory Matters -- Wisconsin Fuel Proceedings.
Natural Gas Costs: Higher natural gas costs could increase our working capital requirements and result in higher gross receipts taxes in the state of Wisconsin. Higher natural gas 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. Higher natural gas costs may also lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution.
As part of its December 2014 rate order, the PSCW authorized continued use of the escrow method of accounting for bad debt costs. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceeds or is less than amounts allowed in rates.
As a result of GCRMs, our gas utility operations receive dollar for dollar recovery on the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. For information concerning the natural gas utilities' GCRMs, see Utility Rates and Regulatory Matters.
Weather: Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric's electric revenues and sales 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 gas revenues and sales are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in the utility segment's service territory during 2014, 2013 and 2012, as measured by degree days, may be found above in Results of Operations.
Interest Rate: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding as of December 31, 2014. Borrowing levels under these arrangements vary from period to period depending on capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.
We performed an interest rate sensitivity analysis as of December 31, 2014 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2014, we had $617.6 million of commercial paper outstanding with a weighted average interest rate of 0.22%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $6.2 million.
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.
We consult with our investment advisors on an annual basis to help us 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. 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.
POWER THE FUTURE
All of the PTF units have been placed into service and are positioned to provide a significant portion of our future generation needs. The PTF units include PWGS 1, PWGS 2, OC 1 and OC 2.
As part of our 2013 Wisconsin Rate Case, the PSCW determined that 100% of the construction costs for our Oak Creek expansion units were prudently incurred, and approved the recovery in rates of more than 99.5% of these costs.
We are recovering our costs in these units, including subsequent capital additions, through lease payments associated with PWGS 1, PWGS 2, OC 1 and OC 2 that are billed from We Power to Wisconsin Electric and then recovered in Wisconsin Electric's rates as authorized by the PSCW, the MPSC and FERC. Under the lease terms, our return is calculated using a 12.7% return on equity and the equity ratio is assumed to be 53% for the PWGS Units and 55% for the Oak Creek Units.
Wisconsin Electric operates the PTF units and is authorized by the PSCW to fully recover prudently incurred operating and maintenance costs in its Wisconsin electric rates. As the operator of the units, Wisconsin Electric may request We Power make capital improvements to or further investments in the units. Under the lease terms, we would expect the costs of any capital improvements or further investments to be added to the lease payments, and ultimately to be recovered in Wisconsin Electric's rates.
We Power assigned its warranty rights to Wisconsin Electric upon turnover of each of the Oak Creek expansion units. The warranty claim for costs incurred to repair steam turbine corrosion damage identified on both units was scheduled to go to arbitration in October 2013, but we entered into a settlement agreement with Bechtel in June 2013 resolving the claim, as well as several other warranty claims. This settlement did not have a material impact to our financial statements. All warranty claims between the Company and Bechtel have now been resolved, none of which had a material impact on our financial statements.
UTILITY RATES AND REGULATORY MATTERS
The PSCW regulates our retail electric, natural gas and steam rates in the state of Wisconsin, while FERC regulates our wholesale power, electric transmission and interstate gas transportation service rates. The MPSC regulates our retail electric rates in the state of Michigan. Within our regulated segment, for the year ended December 31, 2014, we estimate that approximately 85% of our electric revenues were regulated by the PSCW, 2% were regulated by the MPSC and the balance of our electric revenues was regulated by FERC. In Wisconsin, a general rate case is typically filed every two years. All of our natural gas and steam revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.
General Rate Proceedings
2015 Wisconsin Rate Case: In May 2014, Wisconsin Electric and Wisconsin Gas applied to the PSCW for a biennial review of costs and rates. On December 23, 2014, the PSCW approved the following rate adjustments:
•
A net bill increase related to non-fuel costs for Wisconsin Electric's Wisconsin retail electric customers of approximately $2.7 million (0.1%) in 2015. This amount reflects Wisconsin Electric's receipt of SSR payments from MISO that are higher than Wisconsin Electric anticipated when it filed its rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from the Treasury Grant Wisconsin Electric received in connection with its biomass facility. This $26.6 million is being returned to customers in the form of bill credits.
•
An electric rate increase for Wisconsin Electric's Wisconsin retail electric customers of $26.6 million (0.9%) for 2016, related to the expiration of the bill credits provided to customers in 2015.
•
A rate decrease of $13.9 million (-0.5%) in 2015 related to a forecasted decrease in fuel costs. Wisconsin Electric will make an annual fuel cost filing, as required, for 2016.
•
A rate decrease of $10.7 million (-2.4%) for Wisconsin Electric's natural gas customers in 2015, with no rate adjustment in 2016.
•
Rate increases of $17.1 million (2.6%) in 2015 and $21.4 million (3.2%) in 2016 for Wisconsin Gas' natural gas customers.
•
An increase of approximately $0.5 million (2.0%) for Wisconsin Electric's Downtown Milwaukee (Valley) steam utility customers for 2015, with no rate adjustment in 2016.
•
An increase of $1.2 million (7.3%) for Wisconsin Electric's Milwaukee County steam utility customers for 2015, with no rate adjustment in 2016.
These rate adjustments were effective January 1, 2015. The electric rates reflect an increased allocation to fixed charges from 7.8% to 13.6% of total electric revenue requirements to more closely reflect our cost structure. In addition, the authorized return on equity for Wisconsin Electric and Wisconsin Gas was set at 10.2% and 10.3%, respectively. The PSCW also authorized an increase in Wisconsin Gas' financial common equity component to an average of 49.5% compared to the current 47.5%, while Wisconsin Electric's equity component will remain the same. The PSCW's order also allowed for escrow accounting treatment for SSR revenue from MISO.
In January 2015, certain parties appealed a portion of the PSCW's final decision adopting the Company's specific rate design changes, including new charges for customer owned generation within its service territory. We believe the appeal is without merit.
2013 Wisconsin Rate Case: In March 2012, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. In December 2012, the PSCW approved the following rate adjustments:
•
A net bill increase related to non-fuel costs for Wisconsin Electric's Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflected an offset of approximately $63 million (2.3%) of bill credits related to the proceeds of the Treasury Grant, including related tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133 million (4.8%) for 2013.
•
An electric rate increase for Wisconsin Electric's Wisconsin retail electric customers of approximately $28 million (1.0%) for 2014, and a $45 million (1.6%) reduction in bill credits.
•
Recovery of a forecasted increase in fuel costs of approximately $44 million (1.6%) for 2013.
•
A rate decrease of approximately $8 million (-1.9%) for Wisconsin Electric's natural gas customers for 2013, with no rate adjustment in 2014. The Wisconsin Electric rates reflected a $6.4 million reduction in bad debt expense.
•
A rate decrease of approximately $34 million (-5.5%) for Wisconsin Gas' natural gas customers for 2013, with no rate adjustment in 2014. The Wisconsin Gas rates reflected a $43.8 million reduction in bad debt expense.
•
An increase of approximately $1.3 million (6.0%) for Wisconsin Electric's Downtown Milwaukee (Valley) steam utility customers for 2013 and another $1.3 million (6.0%) in 2014.
•
An increase of approximately $1 million (7.0%) in 2013 and $1 million (6.0%) in 2014 for Wisconsin Electric's Milwaukee County steam utility customers.
These rate adjustments were effective January 1, 2013. In addition, Wisconsin Electric's and Wisconsin Gas' allowed return on equity remained at 10.4% and 10.5%, respectively. The PSCW also approved escrow accounting treatment for the Treasury Grant.
2012 Wisconsin Rate Case: In May 2011, Wisconsin Electric and Wisconsin Gas filed an application with the PSCW to initiate rate proceedings. In lieu of a traditional rate proceeding, we requested an alternative approach, which resulted in no increase in 2012 base rates for our customers. In order for us to proceed under this alternative approach, Wisconsin Electric and Wisconsin Gas requested that the PSCW issue an order that, among other things:
•
Authorized Wisconsin Electric to suspend the amortization of $148 million of regulatory costs during 2012, with amortization to begin again in 2013.
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Authorized $148 million of carrying costs and depreciation on previously approved air quality and renewable energy projects, effective January 1, 2012.
•
Authorized the refund of $26 million of net proceeds from Wisconsin Electric's settlement of the spent nuclear fuel litigation with the DOE.
We received a final written order from the PSCW in November 2011.
2012 and 2010 Michigan Rate Cases: In July 2011, Wisconsin Electric filed a $17.5 million rate increase request with the MPSC, primarily to recover the costs of environmental upgrades and OC 2. Pursuant to Michigan law, we self-implemented a $5.7 million interim electric base rate increase in January 2012. This increase was partially offset by a refund of $2.7 million of net proceeds from Wisconsin Electric's settlement of the spent nuclear fuel litigation with the DOE, resulting in a net $3.0 million rate increase. In addition, approximately $2.0 million of renewable costs were included in our Michigan fuel recovery rate effective January 1, 2012. The MPSC approved a total increase in electric base rates of $9.2 million annually, effective June 27, 2012, and authorized a 10.1% return on equity.
In July 2009, Wisconsin Electric filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. In July 2010, the MPSC issued its final order, approving a total increase of $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. In October 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $0.3 million annually. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In May 2014, the Court of Appeals issued its decision affirming the MPSC orders in both the 2010 and 2012 rate cases. In August 2014, the mines filed an Application for Leave to Appeal with the Michigan Supreme Court, which Application was denied on February 3, 2015.
Michigan SSR Proceeding: On February 10, 2015, the MPSC issued an Order and Notice of Hearing related to the ongoing operation of PIPP and the need for us to receive SSR payments with the return of the mines as our retail customers on February 1, 2015. We are unable to predict the resolution of this matter at this time.
For additional information relating to the SSR payments we are receiving, see Industry Restructuring and Competition below.
Wisconsin Fuel Proceedings
Embedded within Wisconsin Electric's electric rates is an amount to recover fuel costs. The Wisconsin retail fuel rules require the Company to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the utility's symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the utility's approved fuel cost plan. The deferred fuel costs are subject to an excess revenues test.
Other Utility Rate Matters
Electric Transmission Cost Recovery: Wisconsin Electric divested its transmission assets with the formation of ATC in January 2001. We procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of ATC, our transmission costs escalated due to the allocation of costs over ATC's footprint and increased transmission infrastructure requirements in Wisconsin. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed us to use escrow accounting whereby we deferred transmission costs that exceeded amounts embedded in our rates. We were allowed to earn a return on the unrecovered transmission costs at our weighted-average cost of capital. Our 2008 and 2010 PSCW rate orders discontinued escrow accounting for prospective transmission charges and provided for recovery of those costs as incurred. In our 2013 Wisconsin rate case, the PSCW reauthorized escrow accounting for future transmission costs whereby we defer prospective costs that exceed amounts in rates, and we are allowed to earn a return on the incremental unrecovered transmission costs at the short-term debt rate. As of December 31, 2014, we had $32 million of unrecovered transmission costs related to deferrals subsequent to 2012 that earn a return at the short-term debt rate. In addition, as of December 31, 2014, we had $114 million of unrecovered transmission costs related to deferrals prior to 2008 that earn a return at the weighted-average cost of capital. In our 2015 Wisconsin rate case, the PSCW order reaffirmed our deferral of transmission costs.
Gas Cost Recovery Mechanism: Our natural gas operations operate under GCRMs as approved by the PSCW. Generally, the GCRMs allow for a dollar for dollar recovery of gas costs. The GCRMs use a modified one for one method that measures commodity purchase costs against a monthly benchmark which includes a 2% tolerance. Costs in excess of this monthly benchmark are subject to additional review by the PSCW before they can be passed through to our customers.
Renewables, Efficiency and Conservation: In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Wisconsin Electric's baseline renewable energy percentage is 2.27%. Under Act 141, Wisconsin Electric was required to increase its renewable energy percentage at least two percentage points to a level of 4.27% for the years 2010-2014. As of December 31, 2014, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. To comply with increasing requirements, Wisconsin Electric has constructed and contracted for several hundred megawatts of wind generation and constructed a 50 MW biomass facility at Domtar Corporation's Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. Wood waste and wood shavings are used to produce renewable electricity and the plant also supports Domtar's sustainable papermaking operations. The final cost of completing this project was $268.9 million, excluding AFUDC. We also own four wind sites, consisting of 200 turbines with an installed capacity of 338 MW and a dependable capability of 66 MW.
We expect to be in compliance with Act 141's 2015 standard, and have entered into agreements for renewable energy credits which should allow us to remain in compliance with Act 141 through 2022. If market conditions are favorable, we may purchase more renewable energy credits.
Act 141 allows the PSCW to delay a utility's implementation of the renewable portfolio standard if it finds that achieving the renewable requirement would result in unreasonable rate increases or would lessen reliability, or that new renewable projects could not be permitted on a timely basis or could not be served by adequate transmission facilities. Act 141 provides that if a utility is in compliance with the renewable energy and energy efficiency requirements as determined by the PSCW, then the utility may not be ordered to achieve additional energy conservation or efficiency.
Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the Wisconsin Department of Administration back to the PSCW and/or contracted third parties. In addition, Act 141 required that 1.2% of utilities' annual operating revenues be used to fund these programs in 2014. The funding required by Act 141 for 2015 is also 1.2% of annual operating revenues.
Public Act 295 enacted in Michigan requires 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. We are currently in compliance with this requirement. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.
ELECTRIC SYSTEM RELIABILITY
We continue to upgrade our electric distribution system, including substations, transformers and lines. We had adequate capacity to meet the MISO calculated planning reserve margin during 2014 and 2013. All of 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, public appeals for conservation were not required and we did not interrupt or curtail service to non-firm customers who participate in load management programs. We expect to have adequate capacity to meet the planning reserve margin requirements during 2015. 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.
ENVIRONMENTAL MATTERS
Overview
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 our utility and non-utility energy segments include but are not limited to current and future regulation of: (1) air emissions such as SO2, NOx, fine particulates, mercury and greenhouse gases; (2) water discharges; (3) disposal of coal combustion by-products such as fly ash; and (4) 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: (1) the development of additional sources of renewable electric energy supply; (2) the review of water quality matters such as discharge limits and cooling water requirements and implementing improvements to our cooling water intake systems as needed; (3) the addition of emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules; (4) the conversion of the fuel source for VAPP from coal to natural gas; (5) the beneficial use of ash and other solid products from coal-fired generating units; and (6) the clean-up of former manufactured gas plant sites.
Air Quality
EPA - Consent Decree: In April 2003, Wisconsin Electric reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS that began service in 2012. In September 2014, the Consent Decree was amended a third time to update
some provisions related to the conversion of VAPP from coal to natural gas. In order to achieve the reductions agreed to in the Consent Decree, over the past 11 years we have installed new pollution control equipment, including the Oak Creek AQCS, upgraded existing equipment and retired certain older coal units at a cost of approximately $1.2 billion. We do not expect future costs to have a material impact on our consolidated financial statements.
NAAQS
8-hour Ozone Standards: In 2008, the EPA issued a more stringent 8-hour ozone standard, and made final attainment designations for this revised standard in 2012. Sheboygan County and the eastern portion of Kenosha County were designated as non-attainment areas. As a result, construction permitting for all of our Wisconsin power plants, except the Pleasant Prairie Power Plant, is expected to be subject to less stringent permitting requirements. In addition, modifications to these facilities should not be required to obtain emission offsets. So long as eastern Kenosha County remains an ozone non-attainment area, the Pleasant Prairie Power Plant will continue to be subject to more stringent permitting requirements and offset provisions.
In April 2014, the U.S. District Court for the Northern District of California adopted a petition from environmental groups to require the EPA to propose a new ozone standard by 2014, and to finalize the standard by October 2015. On November 25, 2014, the EPA proposed to lower the 8-hour ozone standard from its current level of 75 parts per billion. As part of its proposal, the EPA requested comment on values from 60-70 parts per billion. The impact, if any, of a revised standard will depend on how much it is lowered, but could result in widespread areas of the country not being able to meet the new standard.
Fine Particulate Standard: In 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the daily standard for PM2.5. In April 2012, the EPA proposed to determine that these three counties meet the PM2.5 standard, and proposed to suspend the requirement that the state submit a State Implementation Plan (SIP) including reasonably available control technology regulations. In February 2014, the EPA re-proposed this determination, and in April 2014, the EPA took action to redesignate the three counties to attainment. Our generating facilities in the counties are now subject to less stringent construction permitting requirements and emission offset provisions are no longer required for modifications to these facilities. In addition, in December 2012, the EPA issued a revised and more stringent annual PM2.5 standard. On December 18, 2014, the EPA determined that all areas of Wisconsin and Michigan's Upper Peninsula meet the revised standard and designated them as attainment areas. Therefore, we do not currently expect the lower standard to impose any additional requirements on our operations.
Sulfur Dioxide Standard: The EPA issued a new 1-Hour SO2 NAAQS that became effective in August 2010. This standard represents a significant change from the previous SO2 standard, and NAAQS in general, since attainment designations were to be based primarily on modeling rather than monitoring. Typically, attainment designations are based on monitored data. In May 2014, the EPA issued the proposed Data Requirements Rule that would establish procedures and timelines for implementation of the standard. The proposed rule describes the EPA's plans for allowing the states to use either monitoring or modeling to make designations.
We filed comments on the proposed rule with the EPA in July 2014, and proposed a special reliability exclusion for PIPP that would recognize our request to retire the facility, and would exclude it from further modeling or monitoring requirements and subsequent emission reductions. As proposed, the rule affords state agencies latitude in rule implementation. States would have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection). If the state chooses modeling and the sources in an area do not make reductions by 2017, and as a consequence the area is classified as non-attainment, then they would have to make emission reductions by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, and subsequently monitored non-attainment, then it would face a 2026 compliance date. A non-attainment designation could have negative impacts for a localized geographic area, including permitting constraints for the subject source and for other new or existing sources in the area.
We believe our fleet (with the exception of PIPP) is well positioned to meet this regulation once it is finalized. If PIPP is still operating in the 2021-2022 timeframe, it will likely need additional SO2 reductions in order to comply with the standard.
Nitrogen Dioxide Standard: In January 2010, the EPA announced a new hourly Nitrogen Dioxide standard, which became effective in April 2010. In February 2012, all areas of Wisconsin and Michigan were designated as unclassifiable. Until these areas are classified as attainment or non-attainment and any potential rules are adopted, we are unable to predict the impact on the operation of our generation facilities.
Mercury and Other Hazardous Air Pollutants: In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. We currently anticipate that only PIPP will require modifications, and are planning for the addition of a dry sorbent injection system for further control of mercury and acid gases at the plant to comply with MATS. In April 2013, we received a one year MATS compliance extension through April 16, 2016 from the MDEQ.
In addition, both Wisconsin and Michigan have mercury rules that require a 90% reduction of mercury, and compliance with those rules will no longer be required after the compliance date for MATS.
In January 2013, the EPA issued the National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Industrial Boiler MACT Rule). The Industrial Boiler MACT rule imposes stringent limitations on numerous hazardous air pollutants from large boilers that do not meet the definition of electric generating units. The compliance date set forth in the rule is January 31, 2016, but a one year extension of that deadline may be available where emission controls cannot be installed and operational by the compliance date. Along with some smaller gas fired boilers in our fleet, the three coal fired boilers at the Milwaukee County Power Plant are subject to this rule. We are currently evaluating compliance options for these boilers.
Cross-State Air Pollution Rule: In August 2011, the EPA issued CSAPR, formerly known as the Clean Air Transport Rule. This rule was proposed to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of NOX and SO2 that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation plan. In February 2012, the EPA issued final technical revisions to the rule and issued a draft final rule which together delay the implementation date for certain penalty provisions that could potentially impact the PIPP and increase the number of allowances issued to the states of Michigan and Wisconsin. We and a number of other parties sought judicial review of the rule. In April 2014, the United States Supreme Court issued a decision largely upholding the rule and remanding it for further proceedings consistent with the Court's order. Briefing on further challenges to the rule allowed by the U.S. Supreme Court decision is ongoing. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision that cleared the way for the EPA to begin implementing CSAPR on January 1, 2015. We expect that there will be sufficient allowances available for PIPP to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. We also expect to have excess allowances available to sell from our Wisconsin power plants. In light of these developments, we withdrew our challenge to CSAPR.
Clean Air Visibility Rule: The EPA issued the Clean Air Visibility Rule in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to the EPA's CAIR. The pollutants from power plants that reduce visibility include PM2.5 or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia.
In June 2012, the EPA promulgated a Federal Implementation Plan that approves reliance on the CSAPR to satisfy electric generating unit BART requirements for NOx and SO2. In December 2012, the EPA approved Michigan's regional haze SIP. In August 2012, the EPA approved Wisconsin's regional haze SIP, which also relies on the CSAPR to satisfy electric generating unit BART requirements for NOx and SO2. We believe we are well positioned to meet the requirements of the Clean Air Visibility rule based on air quality control system additions that are already in place or planned for our generating facilities.
Climate Change: We continue to take measures to reduce our emissions of GHG. We support flexible, market-based strategies to curb GHG emissions, including emissions trading, emission offset projects and credit for early actions. We support an approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters. We have taken, and continue to take, several steps to reduce our emissions of GHG, including:
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Repowered the Port Washington Power Plant from coal to natural gas-fired combined cycle units.
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Added coal-fired units as part of the Oak Creek expansion that are the most thermally efficient coal units in our system.
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Increased our investment in energy efficiency and conservation.
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Added renewable capacity.
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Converting the fuel source at the VAPP from coal to natural gas, scheduled for completion in 2015.
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Retired coal units 1-4 at PIPP.
Federal, state, regional and international authorities have undertaken efforts to limit GHG emissions. The regulation of GHG emissions continues to be a top priority for the President's administration.
In accordance with instructions from the President, the EPA is pursuing regulation of GHG emissions using its existing authority under the CAA. In September 2013, the EPA issued new proposed New Source Performance Standards with GHG limits for new fossil fueled power plants. The rule would not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines. Based upon currently available technology and the emission limits in the proposed rule, we believe that this rule effectively prohibits new conventional coal-fired power plants.
In addition, the EPA issued proposed guidelines relating to GHG emissions from existing generating units in June 2014, and has announced plans to issue final rules by mid-summer 2015. The EPA also published proposed performance standards for modified and reconstructed generating units. The proposed guidelines for existing fossil generating units seek to attain state-specific GHG rate reductions by 2030, and require states to submit plans as early as June 30, 2016. Single states requesting a one year extension would be required to submit plans by June 30, 2017, and states that are part of a multi-state plan that request a two year extension would be required to submit plans by June 30, 2018. The EPA is seeking GHG rate reductions in Wisconsin of 34% and in Michigan of 31% by 2030, with interim reduction goals beginning in 2020 of 30% and 27% respectively, with interim goal compliance determined by averaging reductions over the ten year period of 2020 to 2029. The proposed program consists of building blocks that include a combination of power plant efficiency improvements, increased reliance on combined cycle gas units, adding new renewable energy resources, and increased demand side management. We are in the process of reviewing the proposed guidelines to determine the potential impacts to our operations, but the guidelines as currently proposed could result in significant additional compliance costs, including capital expenditures, impact how we operate our existing fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.
In June 2014, the U.S. Supreme Court struck down a portion of the EPA’s program for permitting GHG emissions under the Prevention of Significant Deterioration (PSD) and Title V programs. The Court held that a facility’s GHG emissions alone cannot trigger a requirement to obtain a permit and that the EPA did not have the authority to “tailor” the statutory permitting thresholds. The Court also upheld those portions of the EPA’s program that provide for implementation of GHG emissions limits based on the application of BART for facilities already subject to PSD or Title V permitting requirements for other pollutants. We do not expect that this decision will have a material impact on our facilities.
We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2013, we reported CO2 equivalent emissions of approximately 21.9 million metric tonnes to the EPA, compared with approximately 18.1 million metric tonnes for 2012. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 23.3 million metric tonnes to the EPA for 2014. The level of CO2 and other greenhouse gas 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 our gas utility distributes and sells. For 2013, we reported approximately 10.4 million metric tonnes of CO2 equivalent to the EPA related to our distribution and sale of natural gas, compared with approximately 8.4 million metric tonnes for 2012. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO2 emissions of approximately 10.8 million metric tonnes to the EPA for 2014.
Valley Power Plant Conversion: In August 2012, we announced plans to convert the fuel source for VAPP from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million, excluding AFUDC. We received PSCW approval for this project in March 2014. Construction related to the conversion of the first two boilers was completed in November 2014, and the remaining two boilers are scheduled for completion in 2015.
For further information, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
Water Quality
Clean Water Act: Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The EPA finalized rules for new facilities (Phase I) in 2001. The EPA issued a final Phase II rule that became effective on October 14, 2014. The new rule applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the Phase I rules.
The new Phase II rule allows facility owners to select from seven options available to meet the impingement mortality (IM) reduction standard. BTA determinations will be made over the next several years by the WDNR and MDEQ, subject to EPA oversight, when facility permits are reissued. Based upon our assessment, we believe that the existing technologies at our generating facilities will allow us to demonstrate that, other than VAPP, all of our facilities satisfy the IM BTA standard. During 2015 and 2016, we plan to install fish protection screens at VAPP that will meet the IM BTA standard.
The BTA determinations for entrainment mortality (EM) reduction will be made by the WDNR and MDEQ on a case-by-case basis. The new rule requires state permitting agencies to determine EM BTA on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. We cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new requirements for our other generating facilities.
The WDNR issued a new Wisconsin Pollutant Discharge Elimination System (WPDES) permit for VAPP that became effective on January 1, 2013 that contains several additional requirements. Effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges all took effect immediately. Longer term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning and a compliance schedule for the installation of the new cooling water intake fish protection screens.
On November 10, 2014, the WDNR reissued the WPDES permit for the PSGS. We believe that the WDNR imposed unreasonable permit conditions with respect to temperature monitoring, the control of water treatment additive and phosphorus discharges.
To address these permit conditions, we filed a petition for a contested case hearing with the WDNR on January 9, 2015. On the same day, we also filed a request to be covered by the statewide phosphorus variance to address one of our concerns with the permit. We are working with the WDNR to determine if a settlement is possible. A decision on the phosphorus variance request is pending.
Steam Electric Effluent Guidelines: These guidelines regulate waste water discharges from our power plant processes. In June 2013, the EPA issued a proposed rule for comment to modify these guidelines. We submitted comments primarily addressing potential effects to our wastewater treatment facilities and coal combustion residuals effluent management activities. The rules are expected to be finalized by September 2015. After promulgation of the final rules, the WDNR and MDEQ will need to modify state rules accordingly and then
incorporate new requirements into our facility permits. The rule compliance deadline is as soon as possible after July 1, 2017 with full compliance expected by July 1, 2022. We already meet many of the proposed requirements defined by the EPA, and as a result believe we will be well positioned to comply with the proposed guidelines. There are several available options outlined in the proposed rule. The amount of additional costs we may need to incur to comply with the new guidelines, if any, will depend on which option(s) the EPA selects to incorporate into the final guidelines. Until the rules are finalized, we are unable to determine the impact on our facilities.
Land Quality
New Coal Combustion Products Regulation: We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. In 2010, the EPA issued draft rules for public comment proposing two alternative rules for regulating coal combustion products, one of which would classify the materials as hazardous waste. The EPA issued the final rule on December 22, 2014, under which coal combustion residuals will be regulated as a non-hazardous waste. The rule is self-implementing which means that affected facilities must comply with the rules regardless of whether a state adopts the rule. We have been meeting the state requirements and have plans in place to implement the additional federal rule requirements.
In the preamble to the final rule, the EPA referenced reports it received with respect to the molybdenum concerns raised in southeastern Wisconsin, and indicated it will continue to evaluate the beneficial use of coal ash in unencapsulated construction.
Manufactured Gas Plant Sites: We continue to voluntarily review and address environmental conditions at a number of former manufactured gas plant sites. For further information, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
Ash Landfill Sites: We seek environmentally acceptable, beneficial uses for our combustion byproducts. For further information, see Note Q -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.
LEGAL MATTERS
Stray Voltage: On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin's investor-owned utilities. The order clarified the definition of stray voltage, affirmed the level at which utility action is required, and placed some of the responsibility for this issue in the hands of the customer. Additionally, the order established a uniform stray voltage tariff which delineates utility responsibility and provides for the recovery of costs associated with unnecessary customer demanded services.
Dairy farmers have made claims against Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage and ground currents resulting from the operation of its electrical system, even though that electrical system has been operated within the parameters of the PSCW's order. The Wisconsin Supreme Court has rejected the arguments that, if a utility company's measurement of stray voltage is below the PSCW "level of concern," that utility could not be found negligent in stray voltage cases. Additionally, the Court has held that the PSCW regulations regarding stray voltage were only minimum standards to be considered by a jury in stray voltage litigation. As a result of these rulings, claims by dairy farmers for livestock damage have been based upon ground currents with levels measuring less than the PSCW "level of concern." We continue to evaluate various options and strategies to mitigate this risk.
On September 9, 2014, a new stray voltage case was filed against Wisconsin Electric in Sheboygan County, Wisconsin. We do not believe this lawsuit has any merit and intend to defend the case vigorously. This lawsuit is not expected to have a material adverse effect on our financial statements.
INDUSTRY RESTRUCTURING AND COMPETITION
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. The MISO Energy Markets commenced operation in April 2005 for energy distribution and in January 2009 for operating reserves. 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 access 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.
Michigan Business
Michigan Settlement: On January 12, 2015, Wisconsin Energy and Wisconsin Electric entered into an agreement with the Governor of the State of Michigan, the Attorney General of the State of Michigan, the Staff of the MPSC, and Tilden Mining Company and Empire Iron Mining Partnership, owners of the two mines in the Upper Peninsula of Michigan, to resolve all objections these parties raised at the FERC and the MPSC related to Wisconsin Energy’s proposed acquisition of Integrys. The agreement forms the basis for a settlement agreement between the parties and includes the following provisions which directly impact Wisconsin Energy and Wisconsin Electric:
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The Governor, the Attorney General and the owners of the mines will each file a letter with FERC stating that they do not have any objection to FERC’s approval of our acquisition of Integrys, and will refrain from taking any action at FERC seeking to oppose, otherwise condition or delay consummation of the transaction. These letters have been filed with FERC.
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The settlement agreement will request that the MPSC order approving our acquisition of Integrys be subject to the following conditions: (i) the closing of the sale of Wisconsin Electric’s Michigan electric distribution assets and PIPP to Upper Peninsula Power Company (UPPCO) contemporaneously with the closing of the acquisition of Integrys; (ii) the closing of the sale of Wisconsin Public Service Corporation’s Michigan electric distribution assets to UPPCO contemporaneously with the closing of the acquisition; and (iii) termination of the PIPP SSR agreement between MISO and Wisconsin Electric no later than the closing date of the acquisition. To this end, Wisconsin Electric has entered into a non-binding term sheet to sell these assets to UPPCO, which is described in more detail below. The Attorney General, the MPSC Staff and the owners of the mines will not seek or support any other conditions on granting of MPSC approval of our acquisition of Integrys. Wisconsin Public Service Corporation is a subsidiary of Integrys.
The settlement agreements entered into by these parties, as well as two other intervenors in the MPSC proceedings, were filed with the MPSC on January 30, 2015.
SSR Payments: 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. The two iron ore mines are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.
In August 2013, the mines, which were served on an interruptible tariff, notified us that they intended to switch to an alternative electric supplier. In September 2013, the switch was made. In addition, other smaller retail customers have switched to an alternative electric supplier. Following that decision, we initiated discussions with MISO to compensate Wisconsin Electric for the continued short-term operation of the plant through 2014.
In August 2013, we filed a request with MISO to suspend the operation of all five units at PIPP. In October 2013, MISO informed us that the operation of all units is necessary to maintain reliability in the Upper Peninsula of Michigan.
In January 2014, we entered into an SSR agreement (Suspension) with MISO to recover costs for operating and maintaining the units. The agreement was effective February 1, 2014, had a one year term, and specified monthly payments to Wisconsin Electric of $4.4 million to cover fixed costs. The agreement also provided for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR agreement with FERC, and on April 1, 2014, FERC conditionally accepted the agreement as filed, subject to further review and FERC order. We began receiving SSR payments from MISO in the second quarter of 2014 retroactive to the agreement's effective date of February 1, 2014.
In addition, we issued a request for proposals regarding the potential purchase of PIPP in January 2014. We did not receive any valid proposals by the March 3, 2014 deadline. Based upon our evaluation and the lack of interest to purchase the plant, in April 2014, we filed a request with MISO to retire PIPP effective October 15, 2014. In May 2014, MISO informed us that they had determined the operation of all five units at PIPP was necessary for reliability purposes; therefore, the units would continue to be designated as SSR units.
We entered into a new SSR agreement (Retirement) with MISO, effective October 15, 2014, that covered the operating costs of PIPP through December 2015. The new SSR agreement also included, among other things, costs to comply with the MATS rule and a return on and of our investment in the plant. The new agreement is based on projected costs and is subject to a true-up mechanism. The estimated monthly payments under this agreement are approximately $8.1 million. On November 10, 2014, FERC accepted the new SSR agreement, but it is subject to further action.
MISO is responsible for allocating the SSR costs to various market participants within the MISO footprint consistent with FERC approved tariffs. Several interested parties, including the PSCW and the MPSC, filed complaints with the FERC regarding the allocation among the different jurisdictions of the SSR costs associated with the continued operation of PIPP. On February 19, 2015, FERC acted on the jurisdictional allocation of the SSR costs, reaffirming that it is unjust and unreasonable to allocate SSR costs pro rata to all market participants and that SSR costs must be allocated to the load-serving entities that require the operation of SSR units for reliability purposes. FERC directed MISO to file a new study method to identify the entities that benefit from the operation of SSR units within 60 days of the decision date and to allocate the costs directly to these entities.
On February 17, 2015, we entered into an agreement with the owners of the two iron ore mines whereby we agreed to request termination of the SSR agreement effective February 1, 2015, and the two mines agreed to remain full requirements customers until the earlier of the sale of PIPP and July 31, 2015. On the same date, we requested MISO to terminate the SSR agreement, and on February 18, 2015, MISO filed a request with FERC to have the SSR terminated effective February 1, 2015. We do not expect the termination of the SSR agreement to have a material impact on our financial condition or results of operations.
Effective February 1, 2015, the mines returned as retail customers. We expect to defer the net revenue from those sales and will apply these amounts for the benefit of Wisconsin retail electric customers in future rate proceedings. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice.
Sale of Michigan Assets: In January 2015, we entered into a non-binding term sheet to sell our Michigan electric distribution assets and PIPP to UPPCO. We currently expect to enter into a definitive agreement by the end of March 2015. The ultimate sale of these assets would have to be approved by several state and federal regulatory bodies, including the MPSC, PSCW and FERC. If the sale is consummated on terms commensurate with the non-binding term sheet, consistent with the treatment that would be applied to a generating unit retirement we will seek recovery of approximately $190 million of net unrecovered plant costs.
We believe that the sale of these assets is in the best interest of our customers because of the costs associated with the next best solution, which includes operating PIPP for at least five more years. These costs would include ongoing operating costs, decommissioning and dismantling costs and any increased costs for additional transmission capacity in the Upper Peninsula.
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 includes 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. 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.
We, along with others, have sought rehearing and/or appeal of the FERC's various Revenue Sufficiency Guarantee orders related to the determination that MISO had applied its energy markets tariff correctly in the assessment of the charges. The net effects of any final determination by FERC or the courts are uncertain at this time.
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 Financial Transmission Rights (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, 2014 through May 31, 2015. 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 2014 were fulfilled using our own capacity resources.
Natural Gas Utility Industry
Restructuring in Wisconsin: The PSCW previously instituted generic proceedings to consider how its regulation of 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 segments with workably competitive market choices and has adopted standards for transactions between a utility and its gas marketing affiliates. However, work on deregulation of the 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.
OTHER MATTERS
Paris Generating Station Units 1 and 4 Temporary Outage: Between 2000 and 2002, we replaced the blades on the four PSGS combustion turbine generators with blades that were approximately 7% more efficient. The work was performed as routine maintenance that we did not believe required a construction permit at the time and the plant has not been operated to use the potential additional capacity; however, in January 2013, the WDNR indicated that it considered this maintenance to be a modification requiring a construction permit. This matter has since been settled. In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to Units 1 and 4, allowing those units to restart. We received an “after the fact” permit from the WDNR, and the Units are now available for service. On October 24, 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit.
In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administration order issued in this matter, which was granted. However, a hearing has not yet been scheduled.
ACCOUNTING DEVELOPMENTS
New Pronouncements: See Note B -- Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements in this report for information on new accounting pronouncements.
Treasury Grant: In December 2013, we filed an application with the United States Treasury for a Treasury Grant related to the construction of our biomass facility, which was placed into service in November 2013. In December 2013, we recognized income related to the Treasury Grant and we deferred as a regulatory liability the grant proceeds that would be returned to customers subsequent to December 31, 2013. In connection with our Wisconsin retail electric rates that became effective January 1, 2013, our Wisconsin retail electric customers began receiving bill credits for the expected grant proceeds plus the related tax benefits.
In June 2014, we received approximately $76.2 million related to the Treasury Grant. The PSCW approved escrow accounting for the Treasury Grant and the proceeds we received that exceeded the amounts originally included in rates are being returned to customers in the form of bill credits.
As noted above, our Wisconsin retail electric customers are currently receiving bill credits related to the Treasury Grant plus related tax benefits. During 2014, we recognized Treasury Grant income to match the bill credits related to the grant that our Wisconsin retail electric customers received.
CRITICAL ACCOUNTING 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:
Regulatory Accounting: Our utility subsidiaries operate under rates established by state and federal regulatory commissions which are designed to recover the cost of service and provide a reasonable return to investors. The actions of our regulators may allow us to defer costs that non-regulated entities would expense and accrue liabilities that non-regulated companies would not. As of December 31, 2014, we had $1,271.2 million in regulatory assets and $830.6 million in regulatory liabilities. In the future, if we move to market based rates, or if the actions of our regulators change, we may conclude that we are unable to follow regulatory accounting. In this situation, we would record the regulatory assets related to unrecognized pension and OPEB costs as a reduction of equity, after tax. The balance of our regulatory assets net of regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings. We continually review the applicability of regulatory accounting and have determined that it is currently appropriate to continue following it. In addition, each quarter we perform a review of our regulatory assets and our regulatory environment and we evaluate whether we believe that it is probable that we will recover the regulatory assets in future rates. See Note C -- Regulatory Assets and Liabilities in the Notes to Consolidated Financial Statements for additional information.
Pension and OPEB: Our reported costs of providing non-contributory defined pension benefits (described in Note N -- Benefits in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and the discount rates used in determining the projected benefit obligation and pension costs.
Changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.
The following table reflects pension plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.
Pension Plan
Impact on
Actuarial Assumption
Annual Cost
(Millions of Dollars)
0.5% decrease in discount rate and lump sum conversion rate
$
5.5
0.5% decrease in expected rate of return on plan assets
$
6.8
In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note N -- Benefits in the Notes to Consolidated Financial Statements). Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee age and other demographics, our contributions to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of the plans may also impact current and future OPEB costs. OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and the discount rates used in determining the OPEB and post-retirement costs. Our OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns, as well as changes in general interest rates, may result in increased or decreased other post-retirement costs in future periods. Similar to accounting for pension plans, the regulators of our utility segment have adopted accounting guidance for compensation related to retirement benefits for rate-making purposes.
The following table reflects OPEB plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.
In October 2014, the Society of Actuaries released a new set of mortality tables (RP-2014) and an accompanying mortality improvement scale (MP-2014), which incorporates increasing life expectancy experience in the United States. Based on our initial review of the proposed tables, we believe our pension and OPEB obligations would increase by approximately 6% if we adopted these tables. We will continue to evaluate the mortality assumptions in the future, as necessary, to conform to our experience.
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 utility operating revenues during 2014 of approximately $4.9 billion included accrued utility revenues of $291.3 million as of December 31, 2014.
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 L -- Derivative Instruments and Note M -- Fair Value Measurements in the Notes to Consolidated Financial Statements, for information concerning potential market risks to which Wisconsin Energy and its subsidiaries are exposed.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Senior notes are secured by a collateral assignment of the leases between PWGS and Wisconsin Electric related to PWGS 1 and 2.
(b) Senior notes are secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1 and 2.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
WISCONSIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following reportable segments:
•
Utility Energy Segment -- Consisting of Wisconsin Electric and Wisconsin Gas, engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and
•
Non-Utility Energy Segment -- Consisting primarily of We Power, engaged principally in the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.
Our Corporate and Other segment includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions from the consolidated financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenues: We recognize energy revenues on the accrual basis and include estimated amounts for services rendered but not billed.
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 in Wisconsin allow us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the approved fuel cost plan. The deferred under-collected amounts are subject to an excess revenues test.
Our retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) 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.
We recognize We Power revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease.
Accounting for MISO Energy Transactions: The MISO Energy Markets 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.
Other Income and Deductions, Net: We recorded the following items in Other Income and Deductions, net for the years ended December 31:
Property and Depreciation: We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. 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 recorded the following property in service by segment as of December 31:
Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.9% in 2014, 2013 and 2012.
We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.
Our regulated utilities collect in their rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $741.1 million as of December 31, 2014 and $724.5 million as of December 31, 2013.
We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:
Allowance For Funds Used During Construction - Regulated: 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 and Deductions, net.
Our regulated utility segment recorded the following AFUDC for the years ended December 31:
Deferred Revenue: As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms.
Earnings per Common Share: We compute basic earnings per common share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. All stock options outstanding during 2014, 2013 and 2012 were included in the computation of diluted earnings per share. Anti-dilutive shares are excluded from the calculation.
Materials, Supplies and Inventories: Our inventory as of December 31 consists of:
Substantially all fossil fuel, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
Regulatory Accounting: The economic effects of regulation can result in regulated companies recording costs 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 would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and expensed in the periods when they are reflected in rates. We defer regulatory assets pursuant to specific or generic orders issued by our regulators. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. In general, regulatory assets are recovered in a period between one to eight years. For further information, see Note C.
Asset Retirement Obligations: We record a liability for a legal ARO in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply regulatory accounting guidance and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs. For further information, see Note E.
Derivative Financial Instruments: We have derivative physical and financial instruments which we report at fair value. For further information, see Note L.
Cash and Cash Equivalents: Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
Margin Accounts: Cash deposited in brokerage accounts for margin requirements is recorded in Other Current Assets on our Consolidated Balance Sheets.
Goodwill: Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2014 and 2013, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.
Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2014 impairment test date.
Impairment or Disposal of Long Lived Assets: We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2014, we had no assets classified as Held for Sale. Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.
Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 26.2% in ATC as of December 31, 2014 and 2013. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note P.
Income Taxes: We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.
Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note G.
We recognize interest and penalties accrued related to unrecognized tax benefits in Income Taxes in our Consolidated Income Statements, as well as Regulatory Assets or Regulatory Liabilities in our Consolidated Balance Sheets.
We collect sales and use taxes from our customers and remit these taxes to governmental authorities. These taxes are recorded in our Consolidated Income Statements on a net basis.
Stock Options: We estimate the fair value of stock options using the binomial pricing model. We report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within Other Paid in Capital in our Consolidated Statements of Common Equity. We report excess tax benefits as a financing cash inflow. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than 10 years from grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note H.
The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted-average assumptions:
Treasury Grant: In December 2013, we filed an application with the United States Treasury for a Section 1603 renewable energy grant related to the construction of our biomass facility in Rothschild, Wisconsin. The PSCW anticipated the recognition of this grant as income when it set rates for the two years beginning January 1, 2013. We provided bill credits to our customers in 2013 and 2014. For the years ended December 31, 2014 and December 31, 2013, $17.4 million and $48.0 million, respectively, was recognized as income, which reflects the amount that was returned to customers in the form of bill credits during the year. The accounting reflects the regulatory treatment of the grant.
In June 2014, we received approximately $76.2 million related to the Treasury Grant. The PSCW approved escrow accounting for the Treasury Grant and the proceeds we received that exceeded the amounts originally included in rates are being returned to customers in the form of bill credits.
B -- RECENT ACCOUNTING PRONOUNCEMENTS
Revenue Recognition: In May 2014, the Financial Accounting Standards Board and the International Accounting Standards Board issued their joint revenue recognition standard, Accounting Standards Update 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2016, 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 consolidated financial statements.
C -- REGULATORY ASSETS AND LIABILITIES
Our primary regulator, the PSCW, considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon orders or correspondence with our regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2014, we had $12.8 million of regulatory assets not earning a return and $115.1 million of regulatory assets earning a return based on short-term interest rates.
In December 2014, the PSCW issued a rate order effective January 1, 2015 that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below.
Our regulatory assets and liabilities as of December 31 consist of:
D -- PROPOSED ACQUISITION
On June 22, 2014, Wisconsin Energy and Integrys entered into an agreement and plan of merger (Merger Agreement) under which Wisconsin Energy will acquire Integrys. Integrys’ shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash per Integrys share of common stock. We expect to finance the acquisition through the issuance of approximately 91 million shares of Wisconsin Energy common stock to Integrys shareholders and through the issuance of approximately $1.5 billion of debt. We will also assume all of Integrys' outstanding debt. The combined company will be named WEC Energy Group, Inc.
The acquisition is subject to several conditions, including, among others, approval of the shareholders of both Wisconsin Energy and Integrys, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), and the receipt of approvals from various government agencies, including FERC, Federal Communications Commission, PSCW, Illinois Commerce Commission, MPSC and Minnesota Public Utilities Commission. The status of these matters as of December 31, 2014 is as follows:
•
On August 6, 2014, we filed applications for approval with the PSCW, Illinois Commerce Commission, MPSC and Minnesota Public Utilities Commission.
•
On August 15, 2014, we filed an application with the FERC. The initial public comment period closed on October 17, 2014. We subsequently submitted additional information to respond to FERC questions on December 18, 2014. That comment period is now closed.
•
On September 24, 2014, we submitted our HSR Act filings, and on October 24, 2014, the United States Department of Justice closed its review of the transaction with no further action required. In addition, on October 24, 2014, the Federal Trade Commission granted early termination of the 30-day waiting period required by the HSR Act.
•
On November 21, 2014, the shareholders of Wisconsin Energy voted to approve the issuance of common stock as contemplated by the Merger Agreement, as well as to amend the restated articles of incorporation to change the name of Wisconsin Energy from Wisconsin Energy Corporation to WEC Energy Group, Inc. The shareholders of Integrys approved the adoption of the Merger Agreement at its shareholder meeting held on November 21, 2014.
We anticipate the transaction closing in the second half of 2015.
E -- ASSET RETIREMENT OBLIGATIONS
AROs have been recorded for asbestos abatement at certain generation and substation facilities, and for obligations associated with the removal and dismantlement of generation facilities. AROs are recorded in other long-term liabilities on the Consolidated Balance Sheets. The following table presents the change in our AROs during 2014 and 2013:
F -- VARIABLE INTEREST ENTITIES
The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Certain disclosures are required by sponsors, significant interest holders in variable interest entities and potential variable interest entities.
We assess our relationships with potential variable interest entities such as our coal suppliers, natural gas suppliers, coal and gas transporters, and other counterparties in power purchase agreements and joint ventures. In making this assessment, we consider the potential that our contracts or other arrangements provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of the entity, the ability to directly or indirectly make decisions about the entities' activities and other factors.
We have identified a purchased power agreement which represents a variable interest. This agreement is for 236 MW of firm capacity from a gas-fired cogeneration facility and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately eight years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.
We have approximately $174.0 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under contracts considered variable interests in 2014, 2013 and 2012 were $53.0 million, $50.3 million and $45.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.
G -- INCOME TAXES
The following table is a summary of income tax expense for each of the years ended December 31:
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:
The components of deferred income taxes classified as net current assets and net long-term liabilities as of December 31 are as follows:
Consistent with rate-making treatment, deferred taxes are offset in the above table for temporary differences which have related regulatory assets or liabilities.
As of December 31, 2014, we had approximately $416.2 million and $76.0 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $145.7 million and $76.0 million, respectively. As of December 31, 2013, we had approximately $810.3 million and $58.6 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $283.6 million and $58.6 million, respectively. The tax credit and net operating loss carryforwards begin to expire in 2029. We anticipate that we will have future taxable income sufficient to utilize these deferred tax assets.
We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
The amount of unrecognized tax benefits as of December 31, 2014 and 2013 excludes deferred tax assets related to uncertainty in income taxes of $7.2 million and $8.4 million, respectively. As of December 31, 2014 and 2013, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations.
We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2014, 2013 and 2012, we recognized approximately $0.3 million, $0.2 million and $0.2 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2014, 2013 and 2012, we recognized no penalties in the Consolidated Income Statements. We had approximately $0.7 million and $0.4 million of interest accrued and no penalties accrued on the Consolidated Balance Sheets as of December 31, 2014 and 2013, respectively.
We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months.
Our primary tax jurisdictions include the United States and the state of Wisconsin. Currently, the tax years of 2011 through 2014 are subject to Federal examination, and the tax years 2010 through 2014 are subject to examination by the state of Wisconsin.
H -- COMMON EQUITY
As of December 31, 2014 and 2013, we had 325,000,000 shares of common stock, one cent par value, authorized under our charter, of which 225,517,339 and 225,962,959 common shares, respectively, were outstanding. All share-based compensation is currently fulfilled by purchases on the open market by our independent agents and do not dilute shareholders' ownership.
Acquisition of Integrys: On June 22, 2014, we entered into an agreement to acquire Integrys. Integrys shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash per share of Integrys common stock. The proposed acquisition is scheduled to close in the second half of 2015. We expect to finance the acquisition through the issuance of approximately $1.5 billion of debt and approximately 91 million shares of Wisconsin Energy common stock.
Share-Based Compensation Plans: We have a plan that was approved by stockholders that enables us to provide a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of the Company. The plan provides for the granting of stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in common stock, cash or a combination thereof. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award, and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding stock options during the period.
The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:
Stock Options: The exercise price of a stock option under the plan is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. Option grants consist of non-qualified stock options that vest on a cliff-basis after a three year period. Options expire no later than 10 years from the date of grant. For further information regarding stock-based compensation and the valuation of our stock options, see Note A.
We expect that substantially all of the outstanding options as of December 31, 2014 will be exercised.
The following is a summary of our stock option activity during 2014:
In January 2015, the Compensation Committee of the Board of Directors (Compensation Committee) awarded 516,475 non-qualified stock options with an exercise price of $52.895 to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.
The intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $50.5 million, $44.5 million and $47.5 million, respectively. Cash received from options exercised during the years ended December 31, 2014, 2013 and 2012 was $50.3 million, $48.5 million and $49.8 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $19.9 million, $17.8 million and zero, respectively.
The following table summarizes information about stock options outstanding as of December 31, 2014:
The following table summarizes information about our non-vested options during 2014:
As of December 31, 2014, total compensation costs related to non-vested stock options not yet recognized was approximately $2.1 million, which is expected to be recognized over the next 19 months on a weighted-average basis.
Restricted Shares: The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2014:
In January 2015, the Compensation Committee awarded 60,164 restricted shares to our directors, officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.
We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. The intrinsic value of restricted stock vesting was $2.7 million, $4.0 million and $3.5 million for the years ended December 31, 2014, 2013, and 2012, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.0 million, $1.3 million and zero, respectively.
As of December 31, 2014, total compensation cost related to restricted stock not yet recognized was approximately $2.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.
Performance Units: In January 2014, 2013 and 2012, the Compensation Committee awarded 233,735, 239,120 and 346,570 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that will be awarded is dependent upon the achievement of certain financial performance of our stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing compensation costs over the three-year performance period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2014, 2013 and 2012 vested and were settled during the first quarter of 2015, 2014 and 2013, and had a total intrinsic value of $13.2 million, $14.8 million and $19.3 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $4.8 million, $5.3 million and $7.0 million, respectively.
In January 2015, the Compensation Committee awarded 195,365 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.
As of December 31, 2014, total compensation cost related to performance units not yet recognized was approximately $12.6 million, which is expected to be recognized over the next 20 months on a weighted-average basis.
Restrictions: Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its non-utility subsidiary, We Power, and its utility subsidiaries.
Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.
Wisconsin Electric and Wisconsin Gas are required to maintain capital structures that differ from GAAP as they reflect regulatory adjustments. The 2013 PSCW rate case order required Wisconsin Electric to maintain a common equity ratio range of between 48.5% and 53.5%, and Wisconsin Gas to maintain a capital structure which had a common equity range of between 45.0% and 50.0%. The 2015 PSCW rate case requires Wisconsin Electric to
maintain a common equity ratio range of between 48.5% and 53.5%, and Wisconsin Gas to maintain a capital structure which has a common equity range of between 47.0% and 52.0%. Each company is in compliance with its respective common equity range as outlined within the 2013 PSCW rate case. Wisconsin Electric and Wisconsin Gas must obtain PSCW approval if they pay dividends above the test year levels that would cause either company to fall below the authorized levels of common equity.
Wisconsin Electric may not pay common dividends to Wisconsin Energy under Wisconsin Electric's Restated Articles of Incorporation if any dividends on Wisconsin Electric's outstanding preferred stock have not been paid. In addition, pursuant to the terms of Wisconsin Electric's 3.60% Serial Preferred Stock, Wisconsin Electric's ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if Wisconsin Electric's common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.
We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.
As of December 31, 2014, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method total approximately $3.7 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2014.
See Note K for discussion of certain financial covenants related to the bank back-up credit facilities of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
Share Repurchase Program: We do not expect to issue new shares under our various employee benefit plans and our dividend reinvestment and share purchase plan; rather, we instruct independent plan agents to purchase the shares in the open market. In that regard, no new shares of common stock were issued in 2014, 2013 or 2012.
In December 2013, our Board of Directors authorized a share repurchase program for the purchase of up to $300.0 million of our common stock through open market purchases or privately negotiated transactions from January 1, 2014 through the end of 2017. On June 22, 2014, in connection with the proposed acquisition of Integrys, the Board of Directors terminated this share repurchase program. For the twelve months ended December 31, 2014, we repurchased $18.6 million of our common stock pursuant to the terminated program at an average cost of $43.66 per share. All of these shares were purchased during the first quarter of 2014. A previous share repurchase program authorized by our Board of Directors expired at the end of 2013. In addition, we have instructed our independent agents to purchase shares on the open market to fulfill exercised stock options and restricted stock awards. The following table identifies the shares purchased by the Company for the year ending December 31:
I -- PREFERRED STOCK
The following table shows preferred stock authorized and outstanding at December 31, 2014 and 2013:
J -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
Debentures and Notes: As of December 31, 2014, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:
We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.
Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2014 and 2013, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt or included on our Consolidated Statements of Capitalization because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.
In connection with our outstanding Junior Notes, we executed the Replacement Capital Covenant dated May 11, 2007 (RCC) for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.
Effective May 2017, the $500 million of Junior Notes will bear interest at the three-month LIBOR Rate plus 211.25 basis points and will reset quarterly.
Obligations Under Capital Leases: In 1997, Wisconsin Electric entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, Wisconsin Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.
We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $34.9 million and $33.7 million in lease payments during 2014 and 2013, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see Regulatory Assets - Deferred plant related -- capital lease in Note C). Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $84.5 million as of December 31, 2014, and will decrease to zero over the remaining life of the contract.
The following is a summary of our capitalized leased facilities as of December 31:
Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2014 are as follows:
K -- SHORT-TERM DEBT
Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:
The following information relates to commercial paper for the years ended December 31:
Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require the companies to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.
As of December 31, 2014, we had approximately $1.2 billion of available undrawn lines under our bank back-up credit facilities and $617.6 million of commercial paper outstanding that was supported by the available lines of credit. In December 2014, we amended each of our credit facilities to extend their expirations from December 2017 to December 2019.
The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain 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 (ERISA) defaults and change of control. In addition, pursuant to the terms of Wisconsin Energy's credit agreement, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein.
As of December 31, 2014, we were in compliance with all financial covenants.
L -- DERIVATIVE INSTRUMENTS
We utilize derivatives as part of our risk management program to manage the volatility and costs of purchased power, generation and natural gas purchases for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the PSCW.
We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and 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, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of December 31, 2014, we recognized $14.7 million in regulatory assets and $14.2 million in regulatory liabilities related to derivatives in comparison to $0.3 million in regulatory assets and $9.6 million in regulatory liabilities as of December 31, 2013.
We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $0.6 million is recorded in other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.8 million is recorded in other deferred credit and other liabilities. Our Consolidated Balance Sheets as of December 31, 2014 and 2013 include:
Our Consolidated Income Statements include gains (losses) on derivative instruments used in our risk management strategies under fuel and purchased power for those commodities supporting our electric operations and under cost of gas sold for the natural gas sold to our customers. Our estimated notional volumes and gains (losses) for the years ended December 31 were as follows:
As of December 31, 2014 and 2013, we posted collateral of $11.2 million and zero, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.
The fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. The table below shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet as of December 31, 2014 and 2013.
(a)
Gross Amount Not Offset on Balance Sheet includes cash collateral posted of $10.3 million and zero as of December 31, 2014 and 2013, respectively.
M -- FAIR VALUE MEASUREMENTS
Fair value measurements require enhanced disclosures about assets and liabilities that are measured and reported at fair value and establish a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.
Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. Accordingly, we also utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories:
Level 1 -- Pricing inputs are unadjusted quoted prices 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. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.
Level 2 -- Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as OTC forwards and options.
Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.
The following tables summarize our financial assets and liabilities by level within the fair value hierarchy:
Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
Derivative instruments reflected in Level 3 of the hierarchy include MISO FTRs that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note L -- Derivative Instruments, for further information on the offset to regulatory assets and liabilities.
The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:
The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.
N -- BENEFITS
Pensions and Other Post-retirement Benefits: We have defined benefit pension plans that cover substantially all of our employees. Generally, employees who started with the Company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Approximately half of our projected benefit obligation relates to benefits based upon years of service and final average salary. New management employees hired after December 31, 2014 will receive a 6% annual Company contribution to their 401(k) plan instead of being enrolled in the defined benefit plans.
We also have OPEB plans covering substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees.
We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.
The following table presents details about our pension and OPEB plans:
Amounts recognized in our Consolidated Balance Sheets as of December 31 related to the funded status of the benefit plans consisted of:
The accumulated benefit obligation for all defined pension plans was $1,504.6 million and $1,409.5 million as of December 31, 2014, and 2013, respectively.
The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:
We estimate that 2015 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs referred to above of $48.3 million and $0.9 million, respectively.
The components of net periodic pension and OPEB costs for the years ended December 31 are as follows:
The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2014, 2013 and 2012. We consult with our investment advisors on an annual basis to help us 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.
A one-percentage-point change in assumed health care cost trend rates would have the following effects:
We use various Employees' Benefit Trusts to fund a major portion of OPEB. The majority of the trusts' assets are mutual funds.
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.
Previously, our pension plan target allocation was 45% equity investments and 55% fixed income investments. In late 2014, we began transitioning to a target asset allocation of 35% equity investments, 55% fixed income investments and 10% private equity and real estate investments. The current OPEB target asset allocation is 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and U.S. Treasuries.
The following table summarizes the fair value of our pension plan assets by asset category within the fair value hierarchy (for further level information, see Note M):
(a)
This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
The following table summarizes the fair value of our OPEB plan assets by asset category within the fair value hierarchy:
(a)
This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.
In December 2014, our pension and OPEB plans began investing in private equity funds which are a Level 3 investment.
Cash Flows:
Historical employer contributions:
In January 2015, we contributed $100.0 million to the qualified pension plan. Future contributions to the plans will be dependent upon many factors, including the performance of plan assets, long-term discount rates and mortality rates.
Estimated benefit payments:
Savings Plans: We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $14.2 million, $14.2 million and $13.8 million during 2014, 2013 and 2012, respectively.
Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $3.3 million and $4.2 million as of December 31, 2014 and 2013, respectively.
O -- SEGMENT REPORTING
Our reportable segments as of December 31, 2014 include a utility energy segment and a non-utility energy segment. We have organized our reportable segments based upon the regulatory environment in which our utility subsidiaries operate and on how management makes decisions and measures performance. The segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.
Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.
Summarized financial information concerning our reportable segments for each of the three years ended December 31, 2014 is shown in the following table.
(a)
Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.
(b)
An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.
(c)
An elimination of $2,172.9 million, $2,231.2 million and $2,286.7 million is included in Total Assets as of December 31, 2014, 2013 and 2012, respectively, for all PTF-related activity between We Power and Wisconsin Electric.
P -- RELATED PARTIES
We receive and/or provide certain services to other associated companies in which we have an equity investment.
American Transmission Company LLC: As of December 31, 2014, we have a 26.2% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction. ATC reimburses us for these costs when new generation is placed in service.
The following table summarizes material related party transactions with ATC during 2014, 2013 and 2012:
As of December 31, 2014 and 2013, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:
Q -- COMMITMENTS AND CONTINGENCIES
Operating Leases: We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2018. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases including leases for coal cars.
Future minimum payments for the next five years and thereafter for our operating lease contracts are as follows:
Divested Assets: We provided customary indemnifications to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp. in connection with the sale of our interest in Edgewater Generating Unit 5.
Environmental Matters: We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.
We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites used by Wisconsin Electric and Wisconsin Gas, and coal combustion product disposal/landfill sites used by Wisconsin Electric, as discussed below. We are working with the WDNR in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
Manufactured Gas Plant Sites: We have identified several sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. These sites have been substantially remediated or are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $15 million to $47 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2014 and 2013, we established reserves of $32.6 million and $36.9 million, respectively, related to future remediation costs.
Historically, the PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.
Coal Combustion Product Landfill Sites: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its 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 various levels of monitoring or remediation. Where Wisconsin Electric has become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. During 2014, 2013 and 2012, Wisconsin Electric incurred $0.1 million, $0.1 million and $0.3 million respectively, in landfill remediation expenses. As of December 31, 2014, we have no reserves established related to coal combustion product landfill sites.
Valley Power Plant Title V Air Permit: The WDNR renewed VAPP's Title V operating permit in February 2011. The term of the permit is five years. In March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of this proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.
R -- SUPPLEMENTAL CASH FLOW INFORMATION
During the year ended December 31, 2014, we paid $241.1 million in interest, net of amounts capitalized, and paid $22.0 million in income taxes, net of refunds. During the year ended December 31, 2013, we paid $250.4 million in interest, net of amounts capitalized, and received $39.6 million in net refunds from income taxes. During the year ended December 31, 2012, we paid $241.2 million in interest, net of amounts capitalized, and received $107.0 million in net refunds from income taxes.
As of December 31, 2014, 2013 and 2012, the amount of accounts payable related to capital expenditures was $1.8 million, $4.7 million and $15.7 million, respectively.
During the years ended December 31, 2014, 2013 and 2012, total amortization of deferred revenue was $55.7 million, $56.5 million and $54.9 million, respectively.
S -- SUBSEQUENT EVENT
On January 12, 2015, we entered into an agreement with the Governor of the State of Michigan, the Attorney General of the State of Michigan, the Staff of the MPSC and the owners of two large mines in the Upper Peninsula of Michigan, to resolve all objections these parties raised at the FERC and MPSC related to Wisconsin Energy’s proposed acquisition of Integrys. We believe that this agreement is in the best interest of our customers. In connection with the agreement, we entered into a non-binding term sheet to sell our Michigan electric distribution assets and the Presque Isle Power Plant to a third party. The carrying value of these assets is approximately $292 million as of December 31, 2014.
We are working to achieve a definitive agreement for the sale of these assets by the end of March 2015. This agreement would be subject to approval by several regulatory agencies including FERC, the PSCW and the MPSC. If we are able to reach a definitive agreement consistent with the financial terms of the non-binding term sheet, we would seek the recovery of approximately $190 million of net unrecovered plant costs from our remaining customers.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Energy Corporation:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2014 and 2013, and the related consolidated income statements, statements of common equity, and statements of cash flows for each of the three years in the period ended December 31, 2014. Our audits also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Energy Corporation and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP
Milwaukee, Wisconsin
February 27, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Energy Corporation:
We have audited the internal control over financial reporting of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2014 of the Company and our report dated February 27, 2015 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
/s/DELOITTE & TOUCHE LLP
Milwaukee, Wisconsin
February 27, 2015
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 (i) 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 (ii) 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 Wisconsin Energy Corporation's and subsidiaries' 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 Wisconsin Energy Corporation's and subsidiaries' internal control over financial reporting was effective as of December 31, 2014.
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.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our financial statements has issued an attestation report on the effectiveness of Wisconsin Energy Corporation's and its subsidiaries' internal control over financial reporting as of December 31, 2014. Deloitte & Touche LLP's report is included in this report.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT
The information under "Proposal 1: Election of Directors - Terms Expiring in 2016", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance - Stockholder Nominees and Proposals - What is the process used to identify director nominees and how do I recommend a nominee to the Corporate Governance Committee?", "Corporate Governance - Board Committees - Are the Audit and Oversight, Corporate Governance and Compensation Committees comprised solely of independent directors?", "Corporate Governance - Board Committees - Are all the members of the Audit Committee financially literate and does the committee have an 'audit committee financial expert'?" and "Committees of the Board of Directors - Audit and Oversight" in our Definitive Proxy Statement on Schedule 14A to be filed with the SEC for our Annual Meeting of Stockholders to be held May 7, 2015 (the "2015 Annual Meeting Proxy Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.
We have adopted a written code of ethics, referred to as our Code of Business Conduct, that all of our directors, executive officers and employees, including the principal executive officer, principal financial officer and principal accounting officer, must comply with. We have posted our Code of Business Conduct on our website, www.wisconsinenergy.com. We have not provided any waiver to the Code for any director, executive officer or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on our website or in a current report on Form 8-K.
Our website, www.wisconsinenergy.com, also contains our Corporate Governance Guidelines and the charters of our Audit and Oversight, Corporate Governance and Compensation Committees.
Our Code of Business Conduct, Corporate Governance Guidelines and committee charters are also available without charge to any stockholder of record or beneficial owner of our common stock by writing to the corporate secretary, Susan H. Martin, at our principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information under "Compensation Discussion and Analysis", "Executive Compensation Tables", "Director Compensation", "Committees of the Board of Directors - Compensation", "Compensation Committee Report", "Risk Analysis of Compensation Policies and Practices" and "Certain Relationships and Related Transactions - Compensation Committee Interlocks and Insider Participation" in the 2015 Annual Meeting Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The security ownership information called for by Item 12 of Form 10-K is incorporated herein by reference to this information included under "WEC Common Stock Ownership" in the 2015 Annual Meeting Proxy Statement.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information about our equity compensation plans as of December 31, 2014:
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information under "Corporate Governance - Board Independence - Who are the independent directors?", "Corporate Governance - Board Independence - What are the Board's standards of independence?", "Corporate Governance - Board Committees - Are the Audit and Oversight, Corporate Governance and Compensation Committees comprised solely of independent directors?", "Corporate Governance: Does the Company have policies and procedures in place to review and approve related party transactions?" and "Certain Relationships and Related Transactions" in the 2015 Annual Meeting Proxy Statement is incorporated herein by reference. A full description of the guidelines our Board uses to determine director independence is located in Appendix A of our Corporate Governance Guidelines, which can be found on our website, www.wisconsinenergy.com.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2015 Annual Meeting Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) 1.
FINANCIAL STATEMENTS AND REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM INCLUDED IN PART II OF THIS REPORT
2.
FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
3.
EXHIBITS AND EXHIBIT INDEX
See the Exhibit Index included as the last part of this report, which is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.
WISCONSIN ENERGY CORPORATION
INCOME STATEMENTS
(Parent Company Only)
SCHEDULE I -- CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS
WISCONSIN ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
WISCONSIN ENERGY CORPORATION
BALANCE SHEETS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
WISCONSIN ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
1. For Parent Company only presentation, investment in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Wisconsin Energy Corporation appearing in this Annual Report on Form 10-K.
2. Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from the Parent Company's non-utility subsidiary, We Power, and its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2014, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $423.0 million of dividends, and We Power provided $297.0 million of distributions.
Various financing arrangements and regulatory requirements impose certain restrictions on the ability of the Parent Company's subsidiaries to transfer funds to the Parent Company in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to the Parent Company.
Wisconsin Energy does not believe that these restrictions will materially affect the Parent Company's operations or limit any dividend payments in the foreseeable future.
3. As of December 31, 2014, the maturities of the Parent Company long-term debt outstanding were as follows:
Wisconsin Energy amortizes debt premiums, discounts and debt issuance costs over the lives of the debt and includes the costs in interest expense.
Effective May 2017, the $500 million of Junior Notes will bear interest at the three-month LIBOR Rate plus 211.25 basis points and will reset quarterly.
In December 2014, Wisconsin Energy amended its bank back-up credit facility to extend its expiration from December 2017 to December 2019. The facility contains customary covenants, including certain limitations on Wisconsin Energy's 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, ERISA defaults and change of control. In addition, pursuant to the terms of the credit facility, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein. In addition, Wisconsin Energy is required to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%.
As of December 31, 2014, Wisconsin Energy was in compliance with all covenants.
WECC is a subsidiary of Wisconsin Energy and has $50 million of long-term notes outstanding. In a Support Agreement between WECC and Wisconsin Energy, Wisconsin Energy agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.
4. The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:
The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our long-term debt, including the current portion of long-term debt, and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the Parent Company's bond rating and the present value of future cash flows.
5. During the year ended December 31, 2014, Wisconsin Energy paid $44.4 million in interest, net of amounts capitalized, and received $95.1 million in net refunds from income taxes. During the year ended December 31, 2013, Wisconsin Energy paid $44.4 million in interest, net of amounts capitalized, and received $86.1 million in net refunds from income taxes. During the year ended December 31, 2012, Wisconsin Energy paid $45.2 million in interest, net of amounts capitalized, and received $128.2 million in net refunds from income taxes.
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
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.
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 ENERGY CORPORATION
(Commission File No. 001-09057)
EXHIBIT INDEX
to
Annual Report on Form 10-K
For the year ended December 31, 2014
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Energy Corporation. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)
E-1
Wisconsin Energy Corporation
E-2
Wisconsin Energy Corporation
E-3
Wisconsin Energy Corporation
E-4
Wisconsin Energy Corporation
E-5
Wisconsin Energy Corporation
E-6
Wisconsin Energy Corporation