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Statements
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Information (Details)
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Revenues and Customer Receivables (Details)
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Materials, Supplies, and Inventories (Details)
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Property, Plant and Equipment (Details)
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(Details)
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Stock-Based Compensation (Details)
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Earnings Per Share (Details)
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Integrys Acquisition (Details)
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Integrys Acquisition (Details)
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Acquisition (Details)
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Integrys Acquisition (Details)
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Michigan (Details)
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Changes to Investment in ATC (Details)
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Transactions with ATC (Details)
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Summarized Financial Data (Details)
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Amounts (Details)
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Facilities (Details)
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Long-term Debt (Details)
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Capital Lease Obligations (Details)
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Liabilities (Details)
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Cash Flow Hedges (Details)
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Parties (Details)
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Securities
registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
Common Stock, $.01 Par Value
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate
by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [X] No [ ]
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ] No [X]
Indicate by check mark whether the
Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and
posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate
by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer,""accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [X]
Accelerated filer [ ]
Non-accelerated
filer [ ]
Smaller reporting company [ ]
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [X]
The aggregate market value of the common stock of WEC Energy Group, Inc. held by non-affiliates was $20.6 billion based upon the reported closing price of such securities as of June 30, 2016.
Indicate
the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2017):
Common Stock, $.01 par value, 315,587,523 shares outstanding
Portions of WEC Energy Group, Inc.'s Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Stockholders, to be held on May 4, 2017, are incorporated
by reference into Part III hereof.
CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING INFORMATION
In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates,""believes,""could,""estimates,""expects,""forecasts,""goals,""guidance,""intends,""may,""objectives,""plans,""possible,""potential,""projects,""seeks,""should,""targets,""will,"
or variations of these terms.
Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, dividend payout ratios, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, liquidity and capital resources, and other matters.
Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and
uncertainties include those described in Item 1A. Risk Factors and those identified below:
•
Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;
•
Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes
in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;
•
The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;
•
The ability to obtain
and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;
•
The timely completion of capital projects within budgets, as well as the recovery of the related costs through rates;
•
The impact of federal, state, and local legislative and regulatory changes, including changes
in rate-setting policies or procedures, tax law changes, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, and energy efficiency mandates;
•
Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of permit conditions by regulatory agencies, and the recovery
of associated remediation and compliance costs;
•
The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;
•
Changes
in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry, us, or any of our subsidiaries;
•
Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;
•
Restrictions
imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances;
The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;
•
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;
•
The
direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber security intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;
•
The financial performance of ATC and its corresponding contribution to our earnings, as well as the ability of ATC and DATC to obtain the required approvals for their transmission projects;
•
The
investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;
•
Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;
•
Advances in technology that result in competitive disadvantages
and create the potential for impairment of existing assets;
•
The timing, costs, and anticipated benefits associated with the remaining integration efforts relating to the Integrys acquisition;
•
The risk associated with the values of goodwill and other intangible assets and their possible impairment;
•
Potential
business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;
•
The timing and outcome of any audits, disputes, and other proceedings related to taxes;
•
The effect of accounting
pronouncements issued periodically by standard-setting bodies; and
•
Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.
We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
In
this report, when we refer to "us,""we,""our," or "ours," we are referring to WEC Energy Group, Inc. The term "utility" refers to the regulated activities of the electric and natural gas utility companies, while the term "non-utility" refers to the activities of the electric and natural gas utility companies that are not regulated, as well as We Power. The term "nonregulated" refers to activities at WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF (prior to the sale of this business in the first quarter of 2016). References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
For more information about our business operations, including financial and geographic information
about each reportable business segment, see Note 24, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.
WEC Energy Group, Inc.
We were 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. Our wholly owned subsidiaries provide regulated natural gas and electricity, as well as nonregulated renewable energy. Another subsidiary, ITF, provided CNG products and services prior to its
sale in the first quarter of 2016. See Note 3, Dispositions, for more information on this sale. We have an approximately 60% equity interest in ATC (an electric transmission company operating in Illinois, Michigan, Minnesota, and Wisconsin). At December 31, 2016, we had six reportable segments which are discussed below. For additional information about our reportable segments, see Note 24, Segment Information.
Acquisition
On June 29, 2015, Wisconsin Energy Corporation acquired 100%
of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. For additional information on this acquisition, see Note 2, Acquisitions.
Available Information
Our annual and periodic filings with the SEC are available, free of charge, on our website, www.wecenergygroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC.
You
may obtain materials we filed with or furnished to the SEC at the SEC Public Reference Room at 100 F Street, NE, Washington, DC 20549. To obtain information on the operation of the Public Reference Room, you may call the SEC at 1-800-SEC-0330. You may also view information filed or furnished electronically with the SEC at the SEC's website at www.sec.gov.
B. UTILITY ENERGY OPERATIONS
Wisconsin Segment
Electric
Utility Operations
For the periods presented in this Annual Report on Form 10-K, our electric utility operations included operations of WE for all periods and operations for WPS beginning July 1, 2015, due to the acquisition of Integrys and its subsidiaries. WE, which is the largest electric utility in the state of Wisconsin, generates and distributes electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin, and serves an iron ore mine owned by Tilden Mining Company (Tilden) in the Upper Peninsula of Michigan. For more information on the mine, see the discussion below under the heading "Large Electric Retail Customers." WPS generates and
distributes electric energy to customers located in northeastern Wisconsin.
Through December
31, 2016, WE and WPS serviced electric customers in the Upper Peninsula of Michigan. Effective January 1, 2017, WE and WPS transferred their electric customers and electric distribution assets located in the Upper Peninsula of Michigan to UMERC, a new stand-alone utility. More information about UMERC is included at the end of the Wisconsin Segment section, under the heading "Upper Michigan Energy Resources Corporation." The operations of UMERC will continue to be reported as a part of the Wisconsin segment.
Operating Revenues
The following table shows electric utility operating revenues, including steam operations, for the past three years:
Year
Ended December 31
(in millions)
2016
2015 (1)
2014
Operating revenues
Residential
$
1,620.7
$
1,398.5
$
1,199.3
Small
commercial and industrial (2)
1,418.1
1,235.7
1,054.3
Large commercial and industrial (2)
949.5
858.8
640.7
Other
29.8
26.9
23.0
Total
retail revenues (2)
4,018.1
3,519.9
2,917.3
Wholesale
231.2
181.4
131.9
Resale
247.1
248.7
264.1
Steam
27.2
41.0
44.1
Other
operating revenues (3)
104.5
77.5
87.8
Total operating revenues (2)
$
4,628.1
$
4,068.5
$
3,445.2
(1)
Includes
the operations of WPS beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.
(2)
Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
(3)
Includes SSR revenue, amounts collected
from (refunded to) customers for certain fuel and purchased power costs that exceed a 2% price variance from costs included in rates, and other revenues, partially offset by revenues from the mines that are being deferred until a future rate proceeding. For more information, see the discussion below under the heading "Large Electric Retail Customers."
Electric Sales
Our electric energy deliveries included supply and distribution sales to retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier. In 2016, retail electric revenues accounted for 86.8% of total electric operating revenues, while wholesale and resale
electric revenues accounted for 10.3% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Wisconsin Segment Contribution to Operating Income for information on MWh sales by customer class.
Our electric utilities are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities.
Our electric utilities buy and sell wholesale electric power by participating in the MISO Energy Markets. The cost of our individual generation offered into the
MISO Energy Markets, compared to our competitors, affects how often our generating units are dispatched and how we buy and sell power. For more information, see Item 1. Business – D. Regulation.
Steam Sales
WE has a steam utility that generates, distributes, and sells steam supplied by VAPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions. In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. See
Note 3, Dispositions, for more information.
Our
service territory experienced increased weather-normalized retail electric sales in 2016 due to both positive customer growth as well as the retirement of some customer generation as a result of EPA regulations. However, we currently forecast retail electric sales volumes, excluding the Tilden mine located in the Upper Peninsula of Michigan, to remain relatively flat over the next five years, assuming normal weather. The associated electric peak demand is expected to grow at a rate of approximately 0.1% over the next five years, also assuming normal weather. The expected decline in retail electric sales volumes is due in part to the closing of a large industrial customer at the end of 2016 and continued energy conservation by our customers.
Customers
Year
Ended December 31
(in thousands)
2016
2015
2014
Electric customers – end of year
Residential
1,421.7
1,414.1
1,015.0
Small
commercial and industrial
171.1
171.1
115.4
Large commercial and industrial
0.9
1.0
0.7
Other
3.0
3.1
2.5
Total
electric customers – end of year
1,596.7
1,589.3
1,133.6
Electric
customers – average
1,593.1
1,584.4
1,130.7
Steam customers – average
0.4
0.4
0.4
Large
Electric Retail Customers
We provide electric utility service to a diversified base of customers in such industries as paper, governmental, food products, foundry, mining, health services, printing, and retail. In February 2015, our largest retail electric customers, two iron ore mines located in the Upper Peninsula of Michigan, returned as customers after choosing an alternative electric supplier in September 2013. For more information on alternative electric suppliers, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring. WE entered into a contract with each of the mines to provide full requirements electric service through December
31, 2019. Since 2015, we have been deferring, and expect to continue to defer, the revenue less costs of sales from the mine sales and will apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding.
In 2016, one of the iron ore mines closed, and the related contract for full requirements electric service was terminated. In August 2016, we entered into a new agreement with the owner of the remaining mine under which it will purchase electric power from UMERC for 20 years. The agreement also calls for UMERC to construct and operate certain natural gas-fired generation located in the Upper Peninsula of Michigan. The remaining iron ore mine will continue to receive full requirements electric service from WE under the existing contract,
as discussed above, until UMERC's proposed generation solution in the Upper Peninsula of Michigan begins commercial operation. See Note 22, Regulatory Environment, for more information, as well as the discussion under the heading "Upper Michigan Energy Resources Corporation" below.
Wholesale Customers
We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. Wholesale sales accounted for 7.4%, 6.0%, and 5.3% of total electric energy sales during 2016, 2015,
and 2014, respectively. Wholesale revenues accounted for 5.0%, 4.5%, and 3.8% of total electric operating revenues during 2016, 2015, and 2014, respectively.
Resale
The majority of our sales for resale are sold to one RTO, MISO, at market rates based on availability of our generation and RTO demand. Resale sales accounted for 17.5%, 20.9%, and 18.5% of total electric energy sales during 2016,
2015, and 2014, respectively. Resale revenues accounted for 5.3%, 6.1%, and 7.7% of total electric operating revenues during 2016, 2015, and 2014, respectively. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales derived from these opportunity sales.
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. Through our participation in the MISO Energy Markets, 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 power purchase agreement discussed under the heading
"Power Purchase Commitments," and through spot purchases in the MISO Energy Markets. We also sell excess capacity into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power.
Our rated capacity by fuel type as of December 31 is shown below. For more information on our electric generation facilities, see Item 2. Properties.
Rated
Capacity in MW (1)
2016
2015
2014
Coal
4,933
4,955
3,707
Natural
gas:
Combined cycle
1,697
1,636
1,082
Steam
turbine (2)
320
305
118
Natural gas/oil peaking units (3)
1,413
1,412
962
Renewables
(4)
273
269
155
Total rated capacity
8,636
8,577
6,024
(1)
Rated
capacity is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility, and amounts are based on expected capacity ratings for the following summer. The values were established by tests and may change slightly from year to year.
(2)
The natural gas steam turbine represents the rated capacity associated with the VAPP Units, which were converted from coal to natural gas in 2014 and 2015, as well as Weston Unit 2, which was converted from coal to natural gas in 2015.
(3)
The
dual-fueled facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local natural gas distribution company that delivers natural gas to the plants.
(4)
Includes hydroelectric, biomass, and wind generation.
The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2017:
Our coal-fired generation consists of eight operating plants with a rated capacity of 4,933 MW as of December 31, 2016. For more information about
our operating plants, see Item 2. Properties.
Natural Gas-Fired Generation
Our natural gas-fired generation consists of nine operating plants, including peaking units, with a rated capacity of 3,250 MW as of December 31, 2016. For more information about our operating plants, see Item 2. Properties.
Oil-Fired Generation
Fuel oil is used for combustion turbines at certain of our natural gas-fired plants as well as for
ignition and flame stabilization at one of our coal-fired plants. Our oil-fired generation had a rated capacity of 180 MW as of December 31, 2016. We also have natural gas-fired peaking units with a rated capacity of 1,221 MW, which have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our operating plants, see Item 2. Properties.
Renewable Generation
In order to comply with renewable energy legislation in Wisconsin and Michigan, our electric utilities meet a portion of their electric generation supply with various renewable energy resources.
Hydroelectric
Our hydroelectric generating system consists of 30 operating plants with a total installed capacity of 171 MW and a rated capacity of 150 MW as of December 31, 2016. All of our hydroelectric facilities follow FERC guidelines and/or regulations.
Wind
We have six wind sites, consisting of 280 turbines, with an installed capacity of 447 MW and a rated capacity
of 73 MW as of December 31, 2016.
Biomass
We have a biomass-fueled power plant at a Rothschild, Wisconsin paper mill site. Wood waste and wood shavings are used to produce a rated capacity of approximately 50 MW of electric power as well as steam to support the paper mill's operations. Fuel for the power plant is supplied by both the paper mill and through contracts with biomass suppliers.
Electric System Reliability
The
PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has a 15.2% reserve margin requirement for the planning year from June 1, 2016, through May 31, 2017. Although MISO's short-term reserve margin changes from year-to-year, fluctuations are typically less than 0.5%. The MPSC does not have minimum guidelines
for future supply reserves.
We had adequate capacity through company-owned generation units and power purchase contracts to meet the MISO calculated planning reserve margin during 2016 and expect to have adequate capacity to meet the planning reserve margin requirements during 2017. However, extremely hot weather, unexpected equipment failure or unavailability across the 15-state MISO footprint could require us to call upon load management procedures. Load management procedures allow for the reduction of energy use through agreements with customers to directly shut off their equipment or through interruptible service, where customers agree to reduce
their load in the case of an emergency interruption.
Our
retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. For more information about the fuel rules, see Item 1. Business – D. Regulation.
Our average fuel and purchased power costs per MWh by fuel type were as follows for the years ended December 31:
2016
2015
2014
Coal
$
23.09
$
25.57
$
27.68
Natural
gas combined cycle
18.79
17.66
40.64
Natural gas/oil peaking units
45.08
56.99
129.83
Purchased
power
40.11
43.50
47.47
We purchase coal under long-term contracts, which helps with price stability. Coal and associated transportation services
have continued to see volatility in pricing due to changing domestic and world-wide demand for coal and the impacts of diesel costs, which are incorporated into fuel surcharges on rail transportation. Certain of our coal transportation contracts contain fuel cost adjustments that are tied to changes in diesel fuel and crude oil prices. Currently, diesel fuel contracts are not actively traded. Therefore, we use financial heating oil contracts to mitigate risk related to diesel fuel prices.
We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange
for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage.
WE and WPS both have a PSCW-approved hedging program that allows them to hedge up to 75% of their potential risks related to fuel surcharge exposure. WE and WPS also have a program that allows them to hedge up to 75% of their estimated natural gas use for electric generation in order to help manage their natural gas price risk. These hedging programs are generally implemented on a 36-month forward-looking basis. The results of all of these programs are reflected in the average costs of natural gas and purchased power.
Coal Supply
We
diversify the coal supply for our electric generating facilities and jointly-owned plants by purchasing coal from several mines in Wyoming, as well as from various other states. For 2017, approximately 76% of our total projected coal requirements of approximately 14 million tons are contracted under fixed-price contracts. See Note 18, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.
The annual tonnage amounts contracted for the next three years are as follows:
(in
thousands)
Annual Tonnage
2017
10,664
2018
7,968
2019
4,032
Coal
Deliveries
All of our 2017 coal requirements are expected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facilities. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.
In connection with its status as a FERC approved RTO, MISO developed and operates the MISO Energy Markets, which include its bid-based energy market and ancillary services market. We are participants in the MISO Energy Markets. For more information on MISO, see Item 1. Business – D. Regulation.
Power Purchase Commitments
We
enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. As of December 31, 2016, our power purchase commitments with unaffiliated parties for the next five years are 1,444 MW per year. This amount includes 1,033 MW per year related to a long-term power purchase agreement for electricity generated by Point Beach.
Other Matters
Seasonality
Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of
the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. Our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, WE did not require public appeals for conservation, and it did not interrupt or curtail service to non-firm customers who participate in load management programs. In addition, WPS did not require any public appeals for conservation, and it did not interrupt or curtail service to non-firm customers who participate in load management programs for capacity reasons. However, WPS did have service curtailments for economic interruptions. Economic interruptions are declared during times in which the price of electricity in the regional market
significantly exceeds the cost of operating the company's peaking generation. During this time, interruptible customers can choose to continue using electricity at a price which exceeds the tariff rate.
Competition
Our electric utilities face competition from various entities and other forms of energy sources available to customers, including self-generation by large industrial customers and alternative energy sources. Our electric utilities compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.
For more information
on competition in our service territories, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring.
Environmental Matters
For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 18, Commitments and Contingencies.
Natural Gas Utility Operations
For the periods presented in this Annual Report on Form
10-K, our Wisconsin natural gas utility operations include WG's and WE's natural gas operations for all periods and WPS's natural gas operations, including in the Upper Peninsula of Michigan, beginning July 1, 2015, due to the acquisition of Integrys and its subsidiaries.
Effective January 1, 2017, WPS natural gas customers and natural gas distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC. More information about UMERC is included at the end of the Wisconsin segment section, under the heading Upper Michigan Resources Corporation.
We are authorized to provide retail
natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. We also transport customer-owned natural gas. Together our natural gas distribution utilities are the largest in Wisconsin, and we operate throughout the state, including the City of Milwaukee and surrounding areas, northeastern Wisconsin, and in large areas of both central and western Wisconsin.
The following table shows certain natural gas utility operating statistics at our Wisconsin segment for the past three years:
Year Ended December 31
2016
2015 (1)
2014
Operating
revenues (in millions)
Residential
$
763.2
$
696.2
$
925.3
Commercial
and industrial
355.3
332.8
506.0
Total retail revenues
1,118.5
1,029.0
1,431.3
Transport
69.7
62.8
54.2
Other
operating revenues (2)
(10.6
)
30.8
10.6
Total
$
1,177.6
$
1,122.6
$
1,496.1
Customers
– end of year (in thousands)
Residential
1,311.0
1,299.7
993.9
Commercial
and industrial
124.3
123.4
93.3
Transport
2.6
2.6
1.8
Total
customers
1,437.9
1,425.7
1,089.0
Customers
– average (in thousands)
1,429.8
1,417.8
1,081.5
(1)
Includes
the operations of WPS beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.
(2)
Includes amounts (refunded to) collected from customers for purchased gas adjustment costs.
Natural Gas Deliveries
Our gas therm deliveries include customer-owned transported natural gas. Transported natural gas accounted for approximately
43.9% of the total volumes delivered during 2016, 41.8% during 2015, and 36.1% during 2014. Our peak daily send-out during 2016 was 23.5 million therms on January 18, 2016.
Large Natural Gas Customers
We provide natural gas utility service to a diversified base of industrial customers who are largely within our electric service territory. Major industries served include governmental,
food products, education, real estate, and metals. Fuel used for WE's electric generation represents our largest transportation customer. Natural gas therms delivered to WE for electric generation represented 15.3% of total volumes delivered during each of 2016 and 2015, and 9.3% during 2014.
Natural Gas Sales Forecast
Our combined service territories in Wisconsin experienced growth in weather-normalized retail natural gas deliveries (excluding natural gas deliveries for electric generation) in 2016 due to positive customer growth, an improving economy, and favorable natural gas prices. We currently forecast retail natural gas delivery volumes to grow at a rate between flat and 0.5% over the next five years, assuming normal weather. The forecast
projects positive customer growth being offset by energy efficiency.
Natural Gas Supply, Pipeline Capacity and Storage
We have been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas utility supply and transportation contracts, see Note 18, Commitments and Contingencies.
The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada, and the Rocky Mountains. We have contracted for long-term 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 natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 35% of forecasted winter demand; November through March is considered the winter season. Storage capacity, along with our natural gas purchase contracts, enables us to manage significant changes in daily demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months when demand is lower and withdraw it in the winter months. As a result, we can contract
for less long-line pipeline capacity during periods of peak usage than would otherwise be necessary and can purchase natural gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.
We hold daily transportation and storage capacity entitlements with interstate pipeline companies as well as other service providers under varied-length long-term contracts.
In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide approximately one-third of the storage needs for our Wisconsin natural gas utilities. See Note 2, Acquisitions, for more information
on this transaction.
Term Natural Gas Supply
We have contracts for firm supplies with terms of 3–5 months with suppliers for natural gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices.
Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet
our forecasted firm peak-day and seasonal demand. Our Wisconsin natural gas utilities' forecasted design peak-day throughput is 31.2 million therms for the 2016 through 2017 heating season.
Secondary Market Transactions
Pipeline and storage capacity and natural gas supplies under contract can be resold in secondary markets. As local distribution companies, our Wisconsin natural gas utilities must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. The secondary markets facilitate higher utilization
of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and natural gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to customers, subject to our approved GCRMs. During 2016, we continued to participate in the secondary markets. For information on the GCRMs, see Note 1(d), Revenues and Customer Receivables.
Spot Market Natural Gas Supply
We expect to continue to make natural gas purchases in the spot market as price and
other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase natural gas in the spot market.
Hedging Natural Gas Supply Prices
WE and WG have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand using a mix of NYMEX-based natural gas options and futures contracts. WPS has PSCW approval to hedge up to 67% of planned winter demand using a combination of planned withdrawals from storage and NYMEX financial instruments. These approvals allow these companies to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to customers through their respective GCRMs. Hedge targets (volumes)
are provided annually to the PSCW as part of each company's three-year natural gas supply plan and risk management filing.
To the
extent that opportunities develop and physical supply operating plans are supportive, WE, WG, and WPS also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward-market price differentials. These approvals provide for 100% of the related proceeds to accrue to these companies' respective GCRMs.
Seasonality
Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to some variations in earnings and working capital throughout the year as a result of changes in weather.
Our working capital needs are met by cash generated from operations
and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.
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 alternative fuels. We are allowed to offer lower-priced natural gas sales and transportation services to dual-fuel customers. Under natural gas transportation agreements, customers purchase natural gas directly from natural gas marketers and arrange with interstate pipelines and us to have the natural gas transported to their facilities. We earn substantially the same operating income whether we sell and transport natural gas to customers or only transport their natural gas.
Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party natural gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating
competitively priced transportation service for those customers that desire to buy their own natural gas supplies.
Federal and state regulators continue to implement policies to bring more competition to the natural gas industry. While the natural gas utility distribution function is expected to remain a highly regulated, monopoly function, the sale of the natural gas commodity and related services are expected to remain subject to competition from third parties for large commercial and industrial customers.
Upper Michigan Energy Resources Corporation
In December 2016, both the MPSC and the PSCW approved the operation of
UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC became operational effective January 1, 2017, and WE and WPS transferred customers and property, plant, and equipment as of that date. WE transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. WPS transferred approximately 9,000 retail electric customers and 5,300 natural gas customers to UMERC, along with approximately 600 miles of electric distribution lines and approximately 100 miles of natural gas distribution mains. WE and WPS also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The estimated net book value of the property, plant, and equipment transferred to UMERC from WE and WPS as of January
1, 2017, was $83 million and $19 million, respectively. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized.
UMERC obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with WE and WPS. The new utility has also proposed a long-term generation solution for electric reliability in the region. See Note 22, Regulatory Environment, for more information. The Tilden Mining Company will remain a customer of WE until this new generation begins commercial operation.
Our Illinois segment includes the natural gas utility operations of PGL and NSG. PGL and NSG, both Illinois corporations, began operations in 1855 and 1900, respectively. We acquired PGL and NSG as a result of the acquisition of Integrys on June
29, 2015. Our customers are located in Chicago and the northern suburbs of Chicago.
Illinois Utilities Operating Statistics
The following table shows certain Illinois utility operating statistics since the acquisition of Integrys.
Year Ended December 31
2016
2015
*
Operating revenues (in millions)
Residential
$
839.2
$
309.8
Commercial
and industrial
136.5
50.4
Total retail revenues
975.7
360.2
Transport
239.4
97.1
Other
operating revenues
27.1
46.1
Total
$
1,242.2
$
503.4
Customers
– end of year (in thousands)
Residential
846.8
838.2
Commercial and industrial
47.1
46.2
Transport
109.5
107.8
Total
customers
1,003.4
992.2
Customers – average (in thousands)
1,005.3
982.3
*
Includes
the operations of PGL and NSG beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.
Natural Gas Supply, Pipeline Capacity and Storage
We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns with safe, reliable natural gas supplies at the best value.
Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases, contracted
and owned storage, peak-shaving facilities, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.
For more information on our natural gas utility supply and transportation contracts, see Note 18, Commitments and Contingencies.
We contract with local distribution
companies and interstate pipelines to purchase firm transportation services. We believe that having multiple pipelines that serve our natural gas service territory benefits our customers by improving reliability, providing access to a diverse supply of natural gas, and fostering competition among these service providers. These benefits can lead to favorable conditions for our Illinois utilities when negotiating new agreements for transportation and storage services. Our Illinois utilities further reduce their supply cost volatility through the use of financial instruments, such as commodity futures, swaps, and options as part of their hedging programs. They hedge between 25% and 50% of natural gas purchases, with a target of 37.5%.
We own a 38.3 Bcf storage field (Manlove Field in central Illinois) and contract
with various other underground storage service providers for additional storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, which provides a hedge against supply cost volatility. We also own a natural gas pipeline system that connects Manlove Field to Chicago and eight major interstate pipelines. These assets are directed primarily to serving rate-regulated retail customers and are included in our regulatory rate base. We also use a portion of these company-owned storage and pipeline assets as a natural gas hub, which consists of providing transportation and storage services in interstate commerce to our wholesale customers. Customers deliver natural gas to us for storage through an injection into the storage reservoir, and we return the natural gas to the customers under an agreed schedule through a withdrawal from the storage
reservoir. Title to the natural gas does not transfer to us. We recognize service fees associated with the natural gas hub services provided to wholesale customers. These service fees reduce the cost of natural gas and services charged to retail customers in rates.
We had adequate capacity to meet all firm natural gas demand obligations during 2016 and expect
to have adequate capacity to meet all firm demand obligations during 2017. Our Illinois utilities' forecasted design peak-day throughput is 24.4 million therms for the 2016 through 2017 heating season.
Gas System Modernization Program
PGL is continuing work on the SMP, a project that began in 2011 under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved Qualifying Infrastructure Plant rider, which is in effect through 2023. For information on investigations related to the SMP, see Note 22, Regulatory Environment.
Seasonality
Since
the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to variations in earnings and working capital throughout the year as a result of changes in weather.
Our Illinois utilities' working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings
(from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.
Competition
Although our Illinois utilities' rates are regulated by the ICC, we still face varying degrees of competition from other entities and other forms of energy available to consumers. Absent extraordinary circumstances, potential competitors are not allowed to construct competing natural gas distribution systems in our service territory due to a judicial doctrine known as the "first in the field." In addition, we believe it would be impractical to construct competing duplicate distribution facilities due to the high cost of installation.
Since 2002, all
our Illinois utilities' natural gas customers have had the opportunity to choose a natural gas supplier other than us. As a result, we offer natural gas transportation service to enable customers to directly manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution system to transport the natural gas to their facilities. We still earn a distribution charge for transporting the natural gas for these customers. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs.
An interstate pipeline may seek to provide transportation service directly to end users, which would bypass our natural gas transportation service. However,
we have a bypass rate approved by the ICC, which allows us to negotiate rates with customers that are potential bypass candidates to help ensure that such customers use our transportation service.
Other States Segment
Our other states segment includes the natural gas utility operations of MERC and MGU. We acquired the natural gas distribution operations of MERC and MGU, located in Minnesota and Michigan, respectively, on June 29, 2015, with the acquisition of Integrys. MERC serves customers in various cities and communities throughout Minnesota, and MGU serves customers in the southern portion of lower Michigan.
The following table shows certain other states utility operating statistics since the acquisition of Integrys.
Year
Ended December 31
2016
2015*
Operating revenues (in millions)
Residential
$
209.3
$
67.6
Commercial
and industrial
110.7
38.8
Total retail revenues
320.0
106.4
Transport
31.7
11.5
Other
operating revenues
24.8
31.4
Total
$
376.5
$
149.3
Customers
– end of year (in thousands)
Residential
348.1
345.8
Commercial and industrial
34.1
33.8
Transport
24.8
23.0
Total
customers
407.0
402.6
Customers – average (in thousands)
402.8
401.5
*
Includes
the operations of MERC and MGU beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.
Natural Gas Supply, Pipeline Capacity and Storage
We manage portfolios of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns with safe, reliable natural gas supplies at the best value.
Our natural gas supply requirements are met through a combination of fixed-price purchases, index-priced purchases,
contracted and owned storage, peak-shaving facilities, and natural gas supply call options. We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers. To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.
For more information on our natural gas utility supply and transportation contracts, see Note 18, Commitments and Contingencies.
We own a storage field (Partello in Michigan) and contract
with various other underground storage service providers for additional storage services. Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas on a year-round basis, which provides a hedge against supply cost volatility. We contract with local distribution companies and interstate pipelines to purchase firm transportation services. We believe that having multiple pipelines that serve our natural gas service territory benefits our customers by improving reliability, providing access to a diverse supply of natural gas, and fostering competition among these service providers. These benefits can lead to favorable conditions for our other states utilities when negotiating new agreements for transportation and storage services. Our other states utilities further reduce their supply cost volatility through the use of
financial instruments, such as commodity futures, swaps, and options as part of their hedging programs. MERC hedges up to 30% of planned winter demand using NYMEX financial instruments. MGU hedges up to 20% of its planned annual purchases using NYMEX financial instruments.
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. Forecasted design peak-day throughput for our other states utilities segment is 8.7 million therms for the 2016 through 2017 heating season.
Seasonality
Since the majority of
our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to variations in earnings and working capital throughout the year as a result of changes in weather.
Our other states utilities' working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.
Competition
Although
our other states utilities' rates are regulated by the MPUC and MSPC, we still face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternative fuels. Due to the volatility of energy commodity prices, we have seen customers with dual fuel capability switch to alternative fuels for short periods of time, then switch back to natural gas as market rates change.
MERC commercial and industrial customers and all MGU customers have the opportunity to choose a natural gas supplier other than us. We offer natural gas transportation service and also offer interruptible natural gas sales to enable customers to better manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and
use our distribution systems to transport the natural gas to their facilities. We still earn a distribution charge for transporting the natural gas for these customers. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.
Electric Transmission Segment
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 WE and WPS, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by the 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 WE and WPS are non-transmission owning members and customers of MISO. As of December 31, 2016, our ownership interest in ATC was approximately 60%. In addition, we own approximately 68% of ATC Holdco, LLC, a separate entity formed in December 2016 to invest in transmission related projects outside of ATC's traditional footprint. As of December
31, 2016, operations were not significant. In April 2011, ATC and Duke Energy announced the creation of a joint venture, DATC, that will seek opportunities to acquire, 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. However, in January 2017, a subsidiary of ATC Holdco, LLC and Arizona Electric Power Cooperative entered into a joint operating agreement, ATC Southwest, to develop transmission projects in Arizona and the southwestern United States. These projects are located in the service territories of several different RTOs around the country. See Note 4, Investment in American Transmission Company,
for more information.
ATC is currently named in a complaint filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints, for more information.
C. NON-UTILITY OPERATIONS
We Power Segment
We
Power, through wholly owned subsidiaries, designed and built approximately 2,350 MW of generation in Wisconsin. This generation is made up of capacity from the ERGS units, ER 1 and ER 2, which were placed in service in February 2010 and January 2011, respectively, and the PWGS units, PWGS 1 and PWGS 2, which were placed in service in July 2005 and May 2008, respectively. Two unaffiliated entities collectively own approximately 17%, or approximately 211 MW, of ER 1 and ER 2. All four of
these units are being leased to WE under long-term leases (the ERGS units have 30-year leases and the PWGS units have 25-year leases), and are positioned to provide a significant portion of our future generation needs.
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 units were constructed under leases approved by the PSCW.
We are recovering our costs of these units, including subsequent capital additions, through lease payments that are
billed from We Power to WE and then recovered in WE's rates as authorized by the PSCW, the MPSC, and the FERC. Under the lease terms, our return is calculated using a 12.7% ROE and the equity ratio is assumed to be 55% for the ERGS units and 53% for the PWGS units.
Corporate and Other Segment
The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, and the PELLC holding company, as well as the operations of Wispark, Bostco, Wisvest (prior to the sale of these assets in the first quarter of 2016), WECC, WBS, PDL, and ITF (prior to the sale of this business in the first quarter of 2016). See Note 3, Dispositions, for more information on the sale
of Wisvest's assets and ITF.
Bostco and Wispark develop and invest in real estate, and combined they had $69.0 million in real estate holdings at December 31, 2016. Wispark has developed several business parks and other commercial real estate projects, primarily in southeastern Wisconsin.
Wisvest was originally formed to develop, own, and operate electric generating facilities and to invest in other energy-related entities. However, Wisvest discontinued its development activity several years ago. In April 2016, we sold the chilled water generation and distribution assets of Wisvest, which provided chilled water services to the Milwaukee Regional Medical Center. See Note 3, Dispositions, for
more information. Wisvest no longer has significant operations.
WECC was originally formed to invest in non-utility projects, such as low income housing developments. However, due to a focus on our regulated utility business, WECC sold many of its non-utility investments and no longer has significant operations.
WBS is a wholly owned centralized service company that provides administrative and general support services to our regulated utilities. WBS also provides certain administrative and support services to our nonregulated entities.
PDL owns distributed renewable solar projects. During 2016, PDL sold its natural gas-fired cogeneration facility and its landfill gas facility. These facilities were
not significant to our operations. PDL's solar facilities rely on solar irradiance, a renewable energy resource. There is no market price risk associated with the fuel supply of these solar projects. However, production at these facilities can be intermittent due to the variability of solar irradiance.
D. REGULATION
We are a holding company and are subject to the requirements of the Public Utility Holding Company Act of 2005 (PUHCA 2005). We also have various subsidiaries that meet the definition of a holding company under PUHCA 2005 and are also subject to its requirements.
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, from being counted against the asset cap provided that they are employed in qualifying businesses. We report to the PSCW annually our compliance with this law and provide supporting documentation to show that our non-utility assets are below the non-utility asset cap.
In addition to the specific regulations noted above and below, our utilities are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ, the Michigan Department of Natural Resources, the Illinois Environmental Protection Agency, the United States Army Corps of Engineers, the Minnesota Department of Natural Resources, and the Minnesota Pollution Control Agency.
Rates
Our
utilities' rates were regulated by the various commissions shown in the table below as of December 31, 2016. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.
Regulated Rates
Regulatory Commission
WE
Retail electric, natural
gas, and steam
PSCW
Retail electric
MPSC *
Wholesale power
FERC
WPS
Retail electric and natural gas
PSCW
and MPSC *
Wholesale power
FERC
WG
Retail natural gas
PSCW
PGL
Retail natural gas
ICC
NSG
Retail
natural gas
ICC
MERC
Retail natural gas
MPUC
MGU
Retail natural gas
MPSC
*
Effective
January 1, 2017, all of WE's and WPS's electric and natural gas distribution assets and customers located in the Upper Peninsula of Michigan were transferred to UMERC, with the exception of the Tilden Mining Company which will continue to be a customer of WE. See Item 1. Business – B. Utility Energy Operations – Wisconsin Segment – Upper Michigan Energy Resources Corporation and Note 22, Regulatory Environment, for additional information.
Embedded within WE's and WPS’s electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require a utility to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of the utility's symmetrical fuel cost
tolerance, which the PSCW typically sets at plus or minus 2% of the utility's approved fuel and purchased power cost plan. The deferred fuel and purchased power costs are subject to an excess revenues test. If the utility's ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which the utility's return exceeds the authorized amount.
Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customers and our Wisconsin wholesale electric customers. Our natural gas utilities operate under GCRMs as approved by their respective state regulator. Generally, the GCRMs allow for a dollar-for-dollar recovery of prudently incurred natural gas costs.
For
a summary of the significant mechanisms our utility subsidiaries had in place in 2016 that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts, see Note 1(d), Revenues and Customer Receivables.
In May 2015, the PSCW approved the acquisition of Integrys on the condition that WE and WG each be subject to an earnings sharing mechanism for three years beginning January 1, 2016. See Note 2, Acquisitions, for more information on these earnings sharing mechanisms.
For information on how rates are set for our regulated entities, see Note 22, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:
The
material and information contained on these websites are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.
The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:
2016
2015
2014
(in
millions)
Amount
Percent
Amount
Percent
Amount
Percent
Electric *
Wisconsin
$
3,974.8
85.9
%
$
3,466.3
85.2
%
$
2,990.4
86.8
%
Michigan
175.0
3.8
%
173.1
4.3
%
58.8
1.7
%
FERC
– Wholesale
478.3
10.3
%
429.1
10.5
%
396.0
11.5
%
Total
4,628.1
100.0
%
4,068.5
100.0
%
3,445.2
100.0
%
Natural
Gas *
Wisconsin
1,174.2
42.0
%
1,121.3
63.2
%
1,496.1
100.0
%
Illinois
1,242.2
44.4
%
503.4
28.4
%
—
—
%
Minnesota
249.4
8.9
%
98.3
5.5
%
—
—
%
Michigan
130.5
4.7
%
52.3
2.9
%
—
—
%
Total
2,796.3
100.0
%
1,775.3
100.0
%
1,496.1
100.0
%
Total
utility operating revenues
$
7,424.4
$
5,843.8
$
4,941.3
*
Includes
the operations of WPS, PGL, NSG, MERC, and MGU beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.
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 enhanced the energy market by including an ancillary services market. 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,
and has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.
In MISO, base transmission costs are currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.
As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to hedge transmission congestion costs through ARRs and FTRs. ARRs are allocated to market participants
by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2016, through May 31, 2017. 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 2016 were fulfilled using our own capacity resources.
WE
and WPS are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize the FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities, and modify certain other aspects of energy regulations and Federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by the FERC, which established mandatory electric reliability standards and has the authority to levy monetary sanctions for failure to comply with these standards.
As of December 31, 2016, WPS and WE were subject
to Act 141 in Wisconsin and Public Acts 295 and 342 in Michigan, which contain certain minimum requirements for renewable energy generation. See Note 18, Commitments and Contingencies, for more information. Due to the transfer of WPS's electric and natural gas distribution assets and customers located in the Upper Peninsula of Michigan to UMERC on January 1, 2017, WPS is no longer subject to Public Acts 295 and 342 in Michigan. WE will continue to be subject to the Michigan Acts, along with UMERC, as long as the Tilden Mining Company remains a customer of WE. See Item 1. Business – B. Utility Energy Operations – Wisconsin Segment – Upper Michigan Energy Resources Corporation and Note 22, Regulatory Environment, for additional information on the formation of UMERC.
All
of our hydroelectric facilities follow FERC guidelines and/or regulations.
Other Natural Gas Regulations
Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services, including PGL's natural gas hub, are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the state commissions are responsible for monitoring and enforcing requirements governing our natural gas utilities' safety compliance programs for our pipelines under the United States Department of Transportation regulations. These regulations include 49 Code of Federal Regulations (CFR) Part 191 (Transportation of Natural and
Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports), 49 CFR Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards), and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).
We are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service territories. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to low-income customers of the utilities.
Non-Utility Operations
The
generation facilities constructed by wholly owned subsidiaries of We Power are being leased on a long-term basis to WE. Environmental permits necessary for operating the facilities are the responsibility of the operating entity, WE. We Power received determinations from the FERC that upon the transfer of the facilities by lease to WE, We Power's subsidiaries would not be deemed public utilities under the Federal Power Act and thus would not be subject to the FERC's jurisdiction.
E. ENVIRONMENTAL COMPLIANCE
Our operations are subject
to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation of GHG emissions, coal combustion products, air emissions, or wastewater discharges, could significantly increase these environmental compliance costs.
Anticipated expenditures for environmental compliance and remediation issues for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements. For a discussion
of matters related to manufactured gas plant sites and air and water quality, see Note 18, Commitments and Contingencies.
In
September 2016, Local 18007(C) of Utility Workers Union of America, AFL-CIO was formed under Local 18007 of the Utility Workers Union of America, AFL-CIO to add a group of customer service employees to the union.
We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.
Risks Related to Legislation and Regulation
Our business is significantly impacted by governmental regulation.
We are subject to significant
state, local, and federal governmental regulation, including regulation by the various utility commissions in the states where we serve customers. This regulation significantly influences our operating environment and may affect our ability to recover costs from utility customers. Many aspects of our operations are regulated, including, but not limited to: the rates we charge our retail electric, natural gas, and steam customers; wholesale power service practices; electric reliability requirements and accounting; participation in the interstate natural gas pipeline capacity market; standards of service; issuance of securities; short-term debt obligations; construction and operation of facilities; transactions with affiliates; and billing practices. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs. Failure to comply with any applicable rules or regulations may lead to customer refunds, penalties,
and other payments, which could materially and adversely affect our results of operations and financial condition.
The rates, including adjustments determined under riders, we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation is based on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent on regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable ROE. We defer certain costs and revenues as regulatory assets and liabilities
for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured, and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.
We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied with all of their associated terms, and that our businesses are conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when
they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies. Changes in regulations, interpretations of regulations, or the imposition of new regulations could influence our operating environment, may result in substantial compliance costs, or may require us to change our business operations.
If we are unable to obtain, renew, or comply with these governmental
permits, approvals, authorizations, certificates, or licenses, or if we are unable to recover any increased costs of complying with additional requirements or any other associated costs in customer rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.
We may face significant costs to comply with existing and future environmental laws and regulations.
Our operations are subject to numerous federal and state environmental laws and regulations. These laws and regulations govern, among other things, air emissions (including CO2, methane, mercury, SO2, and NOx), water quality, wastewater discharges,
and management of hazardous, toxic, and solid wastes and substances. We incur significant costs to comply with these environmental requirements, including costs associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at our facilities. In addition, if we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines.
The EPA adopted and implemented (or is in the process of implementing) regulations governing the emission of NOx, SO2, fine particulate matter, mercury, and other air pollutants under the CAA through the NAAQS, the MATS rule, the Clean Power Plan, the
CSAPR, and other air quality regulations. In addition, the EPA finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA has also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters; however, this rule has
been stayed. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. In addition, as a result of the new Federal Executive Administration taking office in January 2017 and other factors, there is uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with existing and future environmental laws and regulations.
Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that could result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations; operating restrictions on our facilities; and increased compliance costs. In addition, the operation
of emission control equipment and compliance with rules regulating our intake and discharge of water could increase our operating costs and reduce the generating capacity of our power plants. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels.
As a result, certain of our coal-fired electric generating facilities may become uneconomical to maintain and operate, which could result in some of these units being retired early or converted to an alternative type of fuel. For example, we expect to retire the remaining Pulliam coal-fired units in the next several years. If generation facility owners in the Midwest, including us, retire a significant number of older coal-fired generation facilities, a potential reduction in the region's capacity reserve margin below acceptable
risk levels may result. This could impair the reliability of the grid in the Midwest, particularly during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.
Our electric and natural gas utilities are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation, and related legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other third parties.
Due to the potential for imposition of stricter standards and greater regulation in the future, as well as the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.
In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could contribute to reduced demand for electricity, which could adversely affect our results of operations, cash flows, and financial condition.
Litigation
over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has increased generally throughout the United States. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by environmental impacts and alleged exposure to hazardous materials have become more frequent. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence
of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.
We may face significant costs to comply with the regulation of greenhouse gas emissions.
Federal, state, regional, and international authorities have undertaken efforts to limit GHG emissions. In 2015, the EPA issued the Clean Power Plan, which is a final rule that regulates GHG emissions from existing generating units, as well as a proposed federal plan as an alternative to state compliance plans. The EPA also issued final performance standards for modified and reconstructed generating units, as well as for new fossil-fueled power plants. With the January
2017 change in the Federal Executive Administration, the legal and regulatory future of federal GHG regulations, including the Clean Power Plan, faces increased uncertainty. We are continuing to analyze the GHG emission profile of our electric generation resources and to work with other stakeholders to determine the potential impacts to our operations of the Clean Power Plan, any successor rule, and federal GHG
regulations in general. In October 2015, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the Clean Power Plan, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan rules until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The Clean Power Plan or its successor is not expected to result
in significant additional compliance costs, including capital expenditures, but may impact how we operate our existing fossil-fueled power plants and biomass facility.
There is no guarantee that we will be allowed to fully recover costs incurred to comply with the Clean Power Plan or other federal regulations, or that cost recovery will not be delayed or otherwise conditioned. The Clean Power Plan and any other related regulations that may be adopted in the future, at either the federal or state level, may cause our environmental compliance spending to differ materially from the amounts currently estimated. In December 2016, Michigan enacted Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to 12.5% for years 2019 through
2020, and increases the requirement to 15.0% for 2021. These regulations, as well as changes in the fuel markets and advances in technology, could make some of our electric generating units uneconomic to maintain or operate, and could affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.
In addition, our natural gas delivery systems and natural gas storage fields may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair. Fugitive gas typically vents to the atmosphere and consists primarily of methane. CO2 is also a byproduct of natural gas consumption. As a result, future regulation of GHG emissions could increase the price of natural gas, restrict
the use of natural gas, and adversely affect our ability to operate our natural gas facilities. A significant increase in the price of natural gas may increase rates for our natural gas customers, which could reduce natural gas demand.
We may be negatively impacted by changes in federal income tax policy.
We are impacted by United States federal income tax policy. Both the new Federal Executive Administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to corporate income tax laws. These proposed changes include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital expenditures, and the elimination of the interest expense
deduction. We are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on us. However, it is possible that changes in the United States federal income tax laws could have an adverse effect on our results of operations, financial condition, and liquidity. For example, any changes that eliminate the interest expense deduction, particularly to the extent applicable to existing indebtedness at our holding company and non-utility operations, could have a negative impact on our financial condition. In addition, the immediate deductibility of capital expenditures could have the effect of reducing growth in our regulated rate base, which could negatively impact our results of operations.
Our electric utilities could be subject to higher costs
and penalties as a result of mandatory reliability standards.
Our electric utilities are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with the mandatory reliability standards could subject our electric utilities to higher operating costs. If our electric utilities were ever found to be in noncompliance with the mandatory reliability standards, they 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 WEC Energy Group. 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.
Risks Related to the Operation of Our Business
Our operations are subject to risks arising from the reliability of our electric generation, transmission, and distribution facilities, natural gas infrastructure facilities, and other facilities, as well as the reliability of third-party transmission providers.
Our financial performance depends on the successful operation of our electric generation and natural gas and electric distribution facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or
processes. Potential breakdown or failure may occur due to severe weather; catastrophic events (i.e., fires, earthquakes, explosions, tornadoes, floods, droughts, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security intrusions. Any of these events could lead to substantial financial losses.
Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages
at our power plants may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.
Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of these lost revenues or increased expenses, which could adversely affect our results of operations and cash flows.
Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general economic conditions in our service areas, varying weather conditions, and energy conservation efforts.
Our
results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:
•
Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including job losses, decreases in income, and business closings. Our electric and natural gas utilities are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn or disruption of financial markets could adversely affect the financial condition of our customers and demand
for their products. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.
•
Weather conditions. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income.
•
Our
customers' continued focus on energy conservation and ability to meet their own energy needs. Our customers' use of electricity and natural gas has decreased as a result of individual conservation efforts, including the use of more energy efficient technologies. These conservation efforts could continue. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. In addition, several states, including Wisconsin and Michigan, have adopted energy efficiency targets to reduce energy consumption by certain dates.
As part of our planning process, we estimate the impacts of changes in customer growth and general economic
conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.
We are actively involved with several significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.
Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, natural gas storage, and other projects, including projects for environmental compliance. In addition, WBS has various capital projects that are primarily related to the development of software applications used to support our utilities.
Achieving the intended benefits of any large construction project
is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. These risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of our regulators. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, our regulators may deem the additional
capital costs as imprudent and disallow recovery of them through rates.
To the extent that delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and financial condition may be adversely affected.
Advances in technology could make our electric generating facilities less competitive.
Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, and energy efficiency. We generate power at central station power plants to achieve economies of scale
and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become more cost competitive. It is possible that legislation or regulations could be adopted supporting the use of these technologies. There is also a risk that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.
Our
operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.
We face the risk of terrorist attacks and cyber intrusions, both threatened and actual, against our generation facilities, electric and natural gas distribution infrastructure, our information and technology systems, and network infrastructure, including that of third parties on which we rely, any of which could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect
our results of operations, financial condition, and cash flows.
We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber security intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission, distribution, and storage systems, could disrupt our operations and result in loss of service to customers. These intrusions may cause unplanned outages at our power plants,
which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.
We face on-going threats to our assets and technology systems. Despite the implementation of strong security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to human error or physical or cyber security
intrusions. If our assets or systems were to fail, be physically damaged, or be breached and were not recovered in a timely manner, we may be unable to perform critical business functions, and sensitive and other data could be compromised.
Our business requires the collection and retention of personally identifiable information of our customers, stockholders,
and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers, stockholders and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.
The
costs of repairing damage to our facilities, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.
Transporting, distributing, and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.
Inherent in natural gas distribution activities are a variety of hazards and operational risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury
to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.
We 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. Our subsidiaries are separate legal entities that have no obligation to pay any of our obligations or to make any funds available for that purpose or for the payment of dividends on our common stock. The ability of our subsidiaries to pay amounts to us depends on their earnings, cash flows, capital requirements, and general financial condition, as well as regulatory limitations. Prior
to distributing cash to us, our subsidiaries have financial obligations that must be satisfied, including, among others, debt service and preferred stock dividends. In addition, each subsidiary's ability to pay amounts to us depends on any statutory, regulatory, and/or contractual restrictions and limitations applicable to such subsidiary, which may include requirements to maintain specified levels of debt or equity ratios, working capital, or other assets. Our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met.
We may fail to attract and retain an appropriately
qualified workforce.
We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If
we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.
Failure of our counterparties to meet their obligations, including obligations under power purchase agreements, could have an adverse impact on our results of operations.
We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to
perform, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.
We
have entered into several power purchase agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. Revenues are dependent on the continued performance by the purchasers of their obligations under the power purchase agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more purchasers could fail to perform their obligations under the power purchase agreements. If this were to occur, we would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase agreement would be reallocated among our retail customers. To the extent there is any regulatory delay in adjusting rates, a customer default under a power purchase agreement could have a negative impact on our results of operations and cash flows.
We
may not be able to use tax credits, net operating losses, and/or charitable contribution carryforwards.
We have significantly reduced our consolidated federal and state income tax liability in the past through tax credits, net operating losses, and charitable contribution deductions available under the applicable tax codes. We have not fully used the allowed tax credits, net operating losses, and charitable contribution deductions in our previous tax filings. We may not be able to fully use the tax credits, net operating losses, and charitable contribution deductions available as carryforwards if our future federal and state taxable income and related income tax liability is insufficient to permit their use. In addition, any future disallowance of some or all of those tax credits, net operating losses, or charitable contribution carryforwards as a result of legislation or an adverse
determination by one of the applicable taxing jurisdictions could materially affect our tax obligations and financial results.
The acquisition of Integrys may not achieve its anticipated results, and we may be unable to integrate operations as expected.
The Merger Agreement was entered into with the expectation that the acquisition would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, including whether the businesses of the two companies can continue to be integrated in an efficient, effective, and timely manner.
It is possible that the remaining integration
efforts could take longer and be more costly than anticipated, and could result in the loss of valuable employees; the disruption of ongoing businesses, processes, and systems; or inconsistencies in standards, controls, procedures, practices, policies, and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the transaction as and when expected. Although we expect that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses of the two companies, will offset the incremental transaction-related costs over time, we may not achieve this net benefit in the near term, or at all. Failure to achieve the anticipated benefits of the acquisition could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results, and prospects.
We
have recorded goodwill that could become impaired and adversely affect financial results.
We assess goodwill for impairment on an annual basis or whenever events or circumstances occur that would indicate a potential for impairment. If goodwill is deemed to be impaired, we may be required to incur material non-cash charges that could materially adversely affect our results of operations.
Risks Related to Economic and Market Volatility
Our business is dependent on our ability to successfully access capital markets.
We rely on access to credit and capital markets to support our capital requirements, including expenditures
for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. In addition, we rely on committed bank credit agreements as back-up liquidity, which allows us to access the low cost commercial paper markets.
Our or our subsidiaries' access to the credit and capital markets could be limited, or our or our subsidiaries' cost of capital significantly increased, due to any of the following risks and uncertainties:
•
A
rating downgrade;
•
An economic downturn or uncertainty;
•
Prevailing market conditions and rules;
•
Concerns over foreign economic conditions;
•
Changes
in tax policy;
•
War or the threat of war; and
•
The overall health and view of the utility and financial institution industries.
If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, it could limit our ability to implement, or increase the costs of implementing, our business plan, which, in turn, could materially and adversely affect
our results of operations, cash flows, and financial condition, and could limit our ability to sustain our current common stock dividend level.
A downgrade in our or any of our subsidiaries' credit ratings could negatively affect our or our subsidiaries' ability to access capital at reasonable costs and/or require the posting of collateral.
There are a number of factors that impact our and our subsidiaries' credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity
requirements, and other requirements for capital. We or any of our subsidiaries could experience a downgrade in ratings if the rating agencies determine that the level of business or financial risk of us, our utilities, or the utility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings.
Any downgrade by the rating agencies could:
•
Increase borrowing costs under certain existing credit facilities;
•
Require
the payment of higher interest rates in future financings and possibly reduce the pool of creditors;
•
Decrease funding sources by limiting our or our subsidiaries' access to the commercial paper market;
•
Limit the availability of adequate credit support for our subsidiaries' operations; and
•
Trigger
collateral requirements in various contracts.
Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.
Our operating and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.
Our electric utilities burn natural gas in several of their electric generation plants and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas may increase
because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations affecting its accessibility.
For Wisconsin retail electric customers, our utilities bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in their respective rate structures. Our natural gas utilities receive dollar-for-dollar recovery of prudently incurred natural gas costs.
Changes in commodity prices could result in:
•
Higher
working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;
•
Reduced profitability to the extent that lower revenues, increased bad debt, and interest expense are not recovered through rates;
•
Higher rates charged to our customers, which could impact our competitive position;
•
Reduced
demand for energy, which could impact revenues and operating expenses; and
•
Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.
We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities and engage in opportunity sales.
We are dependent on coal for much of our electric generating capacity. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. The suppliers
under these agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to us, or we may experience operational problems or constraints that prevent us from taking delivery. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Furthermore, demand for coal can impact its availability and cost. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coal-fired units and replace this lost generation through additional power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise
be delayed, either of which could adversely affect our cash flows.
Our electric generation frequently exceeds our customer load. When this occurs, we generally sell the excess generation into the MISO Energy Markets. If we do not have an adequate supply of coal for our coal-fired units or are unable to run our lower cost units, we may lose the ability to engage in these opportunity sales, which may adversely affect our results of operations.
The use of derivative contracts could result in financial losses.
We use derivative instruments such as swaps, options, futures, and forwards to manage commodity price exposure.
We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although the hedging programs of our utilities must be approved by the various state commissions, 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 reported fair value of these contracts.
Restructuring in the regulated energy industry and competition in the retail and wholesale markets could have a negative impact on our business and revenues.
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.
Certain jurisdictions in which we operate, including Michigan and Illinois, have 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 iron ore mine located in the Upper Peninsula of Michigan is 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. Although Illinois has adopted retail choice, there is currently little or no impact on the net income of our Illinois utilities as they still earn a distribution charge for transporting the natural gas for these customers. It is uncertain whether retail choice might be implemented in Wisconsin or Minnesota.
The FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC approved RTO, MISO
implemented bid-based energy markets that are part of the MISO Energy Markets. The MISO Energy Markets rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes an LMP that reflects the market price for energy. As a participant in the MISO Energy Markets, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. MISO also implemented an ancillary services market for operating reserves that schedules energy and ancillary services at the same time as part of the energy market, allowing for more efficient use of generation assets in the MISO market. These market designs continue to have the potential to increase the costs of transmission, the costs associated
with inefficient generation dispatching, the costs of participation in the MISO Energy Markets, and the costs associated with estimated payment settlements.
The
FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers, and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter. Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand,
which are driven by factors beyond our control.
We may experience poor investment performance of benefit plan holdings due to changes in assumptions and market conditions.
We have significant obligations related to pension and OPEB plans. If we are unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted.
Our cost of providing these plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future. Types of assumptions include earnings on plan assets, discount rates, the level of interest rates used to measure the required
minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and our required or voluntary contributions to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements), or changes in life expectancy assumptions.
We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.
Our
ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.
We own our principal properties outright, except the major portion of our electric utility distribution lines, steam utility distribution mains, and natural gas utility distribution mains and services are located, for the most part, on or under streets and highways,
and on land owned by others and are generally subject to granted easements, consents, or permits.
A. REGULATED
Electric Facilities
The following table summarizes information on our electric generation facilities, including owned and jointly owned facilities, as of December 31, 2016:
Name
Location
Fuel
Number
of Generating Units
Rated Capacity In MW (1)
Coal-fired plants
Columbia
Portage,
WI
Coal
2
334
(2)
Edgewater
Sheboygan, WI
Coal
1
98
(2)
ERGS
Oak
Creek, WI
Coal
2
1,057
(3)
Pleasant Prairie
Pleasant Prairie, WI
Coal
2
1,188
(4)
PIPP
Marquette,
MI
Coal
5
344
Pulliam
Green Bay, WI
Coal
2
211
OCPP
Oak
Creek, WI
Coal
4
993
Weston
Rothschild, WI
Coal
2
708
(2)
Total
coal-fired plants
20
4,933
Natural gas-fired plants
Concord
Combustion Turbines
Watertown, WI
Natural Gas/Oil
4
352
De Pere Energy Center
De
Pere, WI
Natural Gas/Oil
1
170
Fox Energy Center
Wrightstown, WI
Natural
Gas
3
557
Germantown Combustion Turbines
Germantown, WI
Natural Gas/Oil
5
258
Paris
Combustion Turbines
Union Grove, WI
Natural Gas/Oil
4
352
PWGS
Port
Washington, WI
Natural Gas
2
1,140
Pulliam
Green Bay, WI
Natural
Gas/Oil
1
81
VAPP
Milwaukee, WI
Natural Gas
2
240
West
Marinette
Marinette, WI
Natural Gas/Oil
3
149
Weston
Rothschild,
WI
Natural Gas/Oil
3
131
Total natural gas-fired plants
28
3,430
Renewables
Hydro
Plants (30 in number)
WI and MI
Hydro
81
150
(5)
Rothschild Biomass Plant
Rothschild,
WI
Biomass
1
50
Blue Sky Green Field
Fond du Lac, WI
Wind
88
21
Byron
Wind Turbines
Fond du Lac, WI
Wind
2
—
Crane Creek
Howard
County, IA
Wind
66
21
Glacier Hills
Cambria, WI
Wind
90
28
Lincoln
Kewaunee
County, WI
Wind
14
1
Montfort Wind Energy Center
Montfort, WI
Wind
20
2
Total
renewables
362
273
Total system
410
8,636
(1)
Based
on expected capacity ratings for summer 2017, which can differ from nameplate capacity, especially on wind projects. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.
These facilities are jointly owned by WPS and various other utilities. The capacity indicated for each of these units is equal to WPS's portion of total plant capacity based on its percent of ownership.
•
Wisconsin Power and Light Company, an unaffiliated utility, operates the Columbia and Edgewater units. WPS holds a 31.8%
ownership interest in these facilities. See Note 8, Jointly Owned Facilities, for more information on an impending decrease in WPS's ownership interest in the Columbia unit.
•
WPS operates the Weston 4 facility and holds a 70.0% ownership interest in this facility. Dairyland Power Cooperative holds the remaining 30.0% interest.
(3)
This facility is jointly owned by We Power and various other utilities.
The capacity indicated for the facility is equal to We Power's portion of total plant capacity based on its 83.34% ownership.
(4)
Starting in 2017, Pleasant Prairie Power Plant will be placed into economic reserve during months of traditionally lower electric demand. From March through May and from September through November, the units will be on economic reserve.
(5)
WRPC
owns and operates the Castle Rock and Petenwell units. WPS holds a 50.0% ownership interest in WRPC and is entitled to 50.0% of the total capacity at Castle Rock and Petenwell. WPS's share of capacity for Castle Rock is 8.6 MWs, and WPS's share of capacity for Petenwell is 10.2 MWs.
As of December 31, 2016, we operated approximately 37,400 pole-miles of overhead distribution lines and 31,200 miles of underground distribution cable, as well as approximately 500 distribution substations and 492,770 line transformers.
Natural
Gas Facilities
At December 31, 2016, our natural gas properties were located in Illinois, Wisconsin, Minnesota, and Michigan, and consisted of the following:
•
Approximately 45,600 miles of natural gas distribution mains,
•
Approximately 1,100
miles of natural gas transmission mains,
•
Approximately 2.3 million natural gas lateral services,
•
Approximately 500 natural gas distribution and transmission gate stations,
•
A 2.9 billion-cubic-foot
underground natural gas storage field located in Michigan,
•
A 38.3 billion-cubic-foot underground natural gas storage field located in central Illinois,
•
A 2.0 billion-cubic-foot liquefied natural gas plant located in central Illinois,
•
A peak-shaving facility that can store the equivalent of
approximately 80 MDth in liquefied petroleum gas located in Illinois,
•
Peak propane air systems providing approximately 2,960 Dth per day, and
•
Liquefied natural gas storage plants with a total send-out capability of 73,600 Dth per day.
Our natural gas distribution system included distribution mains and transmission mains connected 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. Our liquefied natural gas storage plants convert and store, in liquefied form, natural gas received during periods of low consumption.
PGL owns and operates a reservoir in central Illinois (Manlove Field), and a natural gas pipeline system that connects Manlove Field to Chicago with eight major interstate pipelines. The underground storage reservoir also serves NSG under a contractual arrangement. PGL uses its natural gas storage and pipeline assets as a natural gas hub in the Chicago area.
We also own office buildings, natural 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 natural 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, 2016, the steam system supplied by the VAPP consisted of approximately 40 miles of both high pressure and low pressure steam piping, approximately four miles of walkable tunnels, and other pressure regulating equipment.
General
Substantially all of PGL's and NSG's properties are subject to the lien of the respective company's mortgage indenture for the benefit of bondholders.
B.
CORPORATE AND OTHER
As of December 31, 2016, the corporate and other segment facilities consisted of energy asset facilities owned by PDL.
The energy asset facilities owned by PDL include a portfolio of residential solar facilities and a portfolio of commercial and industrial solar facilities. The solar facilities consist of distributed solar projects ranging from small residential roof top systems up to commercial and industrial solar systems of 4.5 MWs in size. The total capacity of these solar projects is 27.6 MWs. The majority of the solar facilities are wholly owned by subsidiaries of PDL while one is
jointly owned by PDL and Duke Energy Generation Services. PDL's portion of the jointly owned solar capacity is 0.4 MWs.
ITEM 3. LEGAL PROCEEDINGS
The following should be read in conjunction with Note 18, Commitments and Contingencies, and Note 22, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us and our subsidiaries.
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 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
Sheboygan River Matter
We were contacted by the United States Department of Justice in March 2016 to commence discussions between WPS and the federal natural resource trustees to resolve WPS's alleged liability for natural resources damages (NRD) in the Sheboygan River related to the former Camp Marina manufactured
gas plant site. WPS was originally notified about this claim in September 2012, but the WDNR chose not to be a party to the NRD claim negotiation in February 2014. However, the National Oceanic and Atmospheric Administration has co-equal trusteeship with the WDNR over the impacted Sheboygan River natural resources and is now pursuing the NRD claim. Substantial remediation of the uplands at the legacy Sheboygan Camp Marina manufactured gas plant site has already occurred. We received a proposed settlement offer in December 2016 from the Department of Justice, and the terms of the settlement offer, if accepted, will not have a material impact on our financial statements.
The names, ages, and positions of our executive officers at December 31, 2016 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 our 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.
WEC Energy Group — Chief Executive Officer since May 2016. Director since January 2016. President since August 2013. Executive Vice
President from May 2004 to July 2013. Chief Financial Officer from July 2003 to February 2011.
•
WE — Chairman of the Board and Chief Executive Officer since May 2016. Director since June 2015. President from June 2015 to May 2016. Executive Vice President from May 2004 to June 2015. Chief Financial Officer from July 2003 to February 2011.
J. Kevin Fletcher. Age 58.
•
WE — President since May 2016. Director
since June 2015. Executive Vice President - Customer Service and Operations from June 2015 to April 2016. Senior Vice President - Customer Operations from October 2011 to June 2015.
Robert M. Garvin. Age 50.
•
WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.
•
WE — Executive Vice President - External Affairs
since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.
WEC Energy Group — Controller since October 2015. Vice President since June 2015.
•
WE — Vice President and Controller since October 2015.
•
Integrys
Energy Group — Vice President and Treasurer from December 2010 to June 2015.
J. Patrick Keyes. Age 51.
•
WEC Energy Group — Executive Vice President - Strategy since April 2016. Executive Vice President and Chief Financial Officer from September 2012 to March 2016 . Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
•
WE — Director from June 2015 to April 2016. Executive
Vice President and Chief Financial Officer from September 2012 to March 2016. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
WEC Energy Group — Executive Vice President and Chief Financial Officer since April 2016. Vice President and Treasurer from February 2013 to March 2016. Assistant Treasurer from March 2011 to January 2013.
•
WE
— Director and Executive Vice President and Chief Financial Officer since April 2016. Vice President and Treasurer from February 2013 to March 2016. Assistant Treasurer from March 2011 to January 2013.
Susan H. Martin. Age 64.
•
WEC Energy Group — 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.
•
WE
— Director since June 2015. 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.
Charles R. Matthews. Age 60.
•
PELLC — President since June 2015.
•
PGL — Director, President, and Chief Executive Officer since June 2015.
•
NSG
— Director, President, and Chief Executive Officer since June 2015.
•
WE — Senior Vice President - Wholesale Energy and Fuels from January 2012 to June 2015. Vice President - Wholesale Energy and Fuels from August 2006 to January 2012.
Tom Metcalfe. Age 49.
•
WE — Executive Vice President — Generation since April 2016. Senior Vice President - Power Generation from January 2014 to March 2016. Vice President
- Oak Creek Campus from February 2011 to December 2013.
WEC
Energy Group — Vice President and Treasurer since April 2016. Assistant Treasurer from June 2000 to January 2013.
•
WE — Vice President and Treasurer since April 2016. Vice President — State Regulatory Affairs from February 2013 to March 2016. Assistant Treasurer from June 2000 to January 2013.
Joan M. Shafer. Age 63.
•
WE — Executive Vice President - Human Resources and Organizational Effectiveness since
June 2015. Senior Vice President - Customer Services from January 2012 to June 2015. Vice President - Customer Services from January 2004 to January 2012.
Mary Beth Straka. Age 52.
•
WEC Energy Group — Senior Vice President - Corporate Communications and Investor Relations since June 2015.
•
WE — Senior Vice President - Corporate Communications and Investor Relations from June 1 to June
28, 2015.
•
Barclays — Vice President of Equity Research Power and Utilities Group from September 2008 to May 2015.
Certain executive officers also hold officer and/or director positions at our other significant subsidiaries.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Number
of Common Stockholders
As of January 31, 2017, based upon the number of WEC Energy Group stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had approximately 55,000 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 WEC Energy Group
Cash dividends on our common stock, as declared by our 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 11, Common Equity.
On January
19, 2017, the Board of Directors increased the quarterly dividend to $0.5200 per share effective with the first quarter of 2017 dividend payment, which equates to an annual dividend of $2.08 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65.0–70.0% of earnings.
Range of WEC Energy Group Common Stock Prices and Dividends
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CORPORATE DEVELOPMENTS
Introduction
We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in ATC (a federally regulated electric transmission company), and non-utility electric operations through our We Power business. See Note 24,
Segment Information, for information on our reportable business segments.
Corporate Strategy
Our goal is to continue to create long-term value for our shareholders and our customers by focusing on the following:
Reliability
We have made significant reliability-related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution networks. Below are a few examples of reliability projects that are currently
underway.
•
UMERC, our newly created Michigan electric and natural gas utility, is proposing a long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation that will be located in the Upper Peninsula of Michigan. The new generation would provide the region with affordable, reliable electricity that generates less emissions than PIPP. Subject to regulatory approval, the new generation is expected to achieve commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. For more information, see Note 22, Regulatory Environment.
•
PGL
is continuing to work on its SMP, which primarily involves replacing old cast and ductile iron gas pipes and facilities in the city of Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.
•
WPS continues work on its SMRP, which involves modernizing parts of its electric distribution system by burying or upgrading lines. The project focuses on electric lines that currently have the lowest reliability in its system, primarily in rural areas that are heavily forested. WPS is planning to expand the scope of this project with SMRP Phase II. If approved, SMRP Phase II will address areas of WPS's service territory where reliability
is sub-standard to a lesser degree than the areas addressed in the initial phase of the SMRP.
Operating Efficiency
We continually look for ways to optimize the operating efficiency of our company. For example, we received approval from the PSCW to make changes at ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.
Post
merger, we continue to focus on integrating and improving business processes and consolidating our IT infrastructure. We expect the emphasis we are placing on these integration efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.
Financial Discipline
A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, attractive dividends, and quality credit ratings.
We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile.
•
See
Note 2, Acquisitions, for information about our acquisition of Integrys and the pending acquisition of a natural gas storage facility in Michigan.
•
See Note 3, Dispositions, for information on the sale of ITF and the MCPP.
Our primary investment opportunities are in three areas: our regulated utility business, our investment in ATC, and our generation plants within our We Power segment. Over the next five years, we expect capital contributions to ATC and ATC Holdco to be approximately $350 million.
Capital investments will be funded utilizing these capital contributions, in addition to cash generated from operations and debt. We currently forecast that our share of ATC's and ATC Holdco's projected capital expenditures over the next five years will be $1.4 billion inside the traditional ATC footprint and $300 million outside of the traditional ATC footprint.
Excluding ATC, we expect total capital expenditures for our retail utilities to be approximately $9.7 billion over the next five years. Ongoing projects are discussed in more detail within Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.
Exceptional Customer Care
Our
approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.
One example of how we obtain feedback from our customers is through our "We Care" calls, where employees of our utility subsidiaries contact customers after a completed service call. This program began many years ago at We Energies (the trade name of WE and WG), and is now being rolled out to the Integrys utilities. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance in order to improve customer satisfaction.
RESULTS
OF OPERATIONS
Consolidated Earnings
The following table compares our consolidated results:
Earnings increased $300.5 million in 2016, driven by a $201.7 million increase in earnings due to the inclusion of a full year of Integrys's results
for 2016, compared to six months of Integrys's results for 2015. Integrys was acquired on June 29, 2015. See Note 2, Acquisitions, for more information.
The most significant factor driving the remaining $98.8 million increase in earnings was a $104.1 million pre-tax ($80.1 million after tax) decrease in acquisition costs in 2016.
2015 Compared with 2014
Earnings increased $50.2 million in 2015, driven by a $30.1 million net increase in earnings due to the inclusion of Integrys's results for the last six months of 2015, partially offset by acquisition costs
recorded by us and our subsidiaries. Also contributing to the increase was a $20.8 million pre-tax gain ($12.5 million after tax) from the sale of Minergy LLC and its remaining financial assets in June 2015.
Non-GAAP Financial Measure
The discussions below address the operating income contribution of each of our segments and include financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude
other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.
We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our segments as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.
Our
electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our segment operating performance. Operating income for each of the last three fiscal years for each of our segments is presented in the “Consolidated Earnings” table above.
Each applicable segment operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to segment operating income.
Wisconsin Segment Contribution to Operating Income
For the periods presented in this Annual Report on Form 10-K, our Wisconsin operations included operations of WE and WG for all periods, and operations of WPS beginning July 1, 2015,
due to the acquisition of Integrys and its subsidiaries on June 29, 2015.
Year Ended December 31
(in millions)
2016
2015
2014
Electric
revenues
$
4,628.1
$
4,068.5
$
3,445.2
Fuel and purchased power
1,473.1
1,369.3
1,228.1
Total
electric margins
3,155.0
2,699.2
2,217.1
Natural
gas revenues
1,177.6
1,122.6
1,496.1
Cost of natural gas sold
621.2
640.5
1,036.1
Total
natural gas margins
556.4
482.1
460.0
Total
electric and natural gas margins
3,711.4
3,181.3
2,677.1
Other
operation and maintenance
2,025.4
1,741.0
1,462.7
Depreciation and amortization
496.6
408.6
323.2
Property
and revenue taxes
162.4
147.5
121.0
Operating income
$
1,027.0
$
884.2
$
770.2
The
following table shows a breakdown of other operation and maintenance:
Year Ended December 31
(in millions)
2016
2015
2014
Operation
and maintenance not included in line items below
$
881.9
$
744.2
$
607.4
We Power (1)
513.2
510.7
462.1
Transmission
(2)
423.2
341.3
278.6
Regulatory amortizations and other pass through expenses (3)
157.4
144.8
114.6
Earnings
sharing mechanisms
24.4
—
—
Other
25.3
—
—
Total
other operation and maintenance
$
2,025.4
$
1,741.0
$
1,462.7
(1)
Represents
costs associated with the We Power generation units, including operating and maintenance, as well as the lease payments that are billed from We Power to WE and then recovered in WE's rates. During 2016, 2015, and 2014, $528.4 million, $483.4 million, and $475.7 million, respectively, of both lease and operating and maintenance costs were billed to WE, with the difference in costs billed and expenses incurred deferred or deducted from the regulatory asset.
(2)
The PSCW has approved escrow accounting for ATC and MISO network transmission
expenses for our Wisconsin electric utilities. As a result, WE and WPS defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2016, 2015, and 2014, $486.0 million, $388.6 million, and $302.4 million, respectively, of costs were billed by transmission providers to our electric utilities.
(3)
Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore
do not have a significant impact on operating income.
The following tables provide information on delivered volumes
by customer class and weather statistics:
Year Ended December 31
MWh (in thousands)
Electric Sales Volumes
2016
2015
2014
Customer
class
Residential
10,998.9
9,218.9
7,946.3
Small
commercial and industrial *
13,113.1
10,889.2
8,843.1
Large commercial and industrial *
13,418.6
11,545.8
9,795.3
Other
172.2
162.6
148.7
Total
retail *
37,702.8
31,816.5
26,733.4
Wholesale
3,704.6
2,588.1
1,852.8
Resale
8,761.6
9,077.1
6,497.9
Total
sales in MWh *
50,169.0
43,481.7
35,084.1
*
Includes distribution sales for customers who have
purchased power from an alternative electric supplier in Michigan.
Year Ended December 31
Therms (in millions)
Natural Gas Sales Volumes
2016
2015
2014
Customer
class
Residential
1,014.9
859.4
911.5
Commercial
and industrial
610.5
527.4
571.7
Total retail
1,625.4
1,386.8
1,483.2
Transport
1,270.6
994.2
838.5
Total
sales in therms
2,896.0
2,381.0
2,321.7
Year
Ended December 31
Degree Days
Weather
2016
2015
2014
WE and WG (1)
Heating
(6,679 normal)
6,068
6,468
7,616
Cooling (694 normal)
991
622
464
WPS
(2)
Heating (7,498 normal)
6,715
2,215
N/A
Cooling
(488 normal)
572
396
N/A
(1)
Normal heating and cooling degree days
are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.
(2)
Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station. Degree days for 2015 have been included for the period from July 1, 2015, through December 31, 2015.
2016 Compared with 2015
Electric Utility Margins
Electric utility margins at the Wisconsin segment increased $455.8 million during 2016, compared with 2015. The increase was primarily driven by a $386.4 million margin contribution from WPS during the first six months of 2016, compared with no margin contribution from WPS for the first six months of 2015.
The significant factors impacting the remaining $69.4 million increase in electric utility margins at the Wisconsin segment were:
•
A $50.4 million increase related to higher retail sales volumes during 2016, primarily driven by warmer summer weather. As measured by cooling degree days, 2016 was 59.3% warmer than 2015 in the Milwaukee
area.
•
The expiration of $12.5 million of bill credits refunded to customers in 2015 related to the Treasury Grant WE received in connection with its biomass facility.
•
An $11.3 million increase in the last six months of 2016 as a result of WPS's PSCW rate order, effective January 1, 2016. See Note 22, Regulatory Environment, for more information.
These
increases were partially offset by a $12.9 million decrease in wholesale margins driven by a reduction in capacity sales year-over-year at WE in addition to a reduction in sales volumes at WPS for the second half of 2016, compared with the same period in 2015. Certain wholesale customers have provisions in their contracts, which allowed them to reduce the amount of energy we provided to them.
Natural Gas Utility Margins
Natural gas utility margins at the Wisconsin segment increased $74.3 million during 2016, compared with 2015. The increase in natural gas utiilty margins was driven by a $63.6 million margin contribution from WPS during the first six months
of 2016, compared with no margin contribution from WPS for the first six months of 2015.
The most significant factor impacting the remaining $10.7 million increase in natural gas utility margins at the Wisconsin segment was an $18.1 million net increase from both WG's rate order effective January 1, 2016, and a partially offsetting negative impact from WPS's rate order during the last six months of 2016. See Note 22, Regulatory Environment, for more information. This net increase was partially offset by a $3.2 million decrease related to lower sales volumes during 2016, primarily driven by warmer winter weather. As measured by heating degree days, 2016 was 6.2% warmer than 2015 in the Milwaukee area.
Operating
Income
Operating income at the Wisconsin segment increased $142.8 million during 2016, compared with 2015. The increase was driven by the $530.1 million increase in margins discussed above, partially offset by $387.3 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes). Higher operating expenses were driven by $321.6 million of operating expenses from WPS during the first six months of 2016, compared with no operating expenses from WPS for the first six months of 2015.
The significant factors impacting the remaining $65.7 million increase in operating expenses
at the Wisconsin segment were:
•
A $27.0 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, WG completed the Western Gas lateral project, and WE completed the conversion of the fuel source for VAPP from coal to natural gas.
•
A $25.3 million increase in expenses in 2016 related to a focus on projects that were beneficial to customers and the communities within our
service territories.
•
A $24.4 million expense related to the earnings sharing mechanisms in place at WE and WG, effective January 1, 2016. See the PSCW conditions of approval related to the Integrys acquisition in Note 2, Acquisitions, for more information.
These increases in operating expenses were partially offset by a $16.4 million positive impact at WE from the sale of the MCPP in April 2016, including a gain on sale and lower operating costs
in 2016. See Note 3, Dispositions, for more information.
Electric utility margins at the Wisconsin segment increased $482.1 million during 2015, compared with 2014. The increase was primarily driven by a $399.1 million margin contribution from WPS during the last six months of 2015, compared with no margin contribution from WPS during 2014.
The remaining $83.0 million increase in electric margins at WE was driven by:
•
A
$38.4 million increase as a result of the PSCW rate order, effective January 1, 2015. See Note 22, Regulatory Environment, for more information.
•
A $35.0 million increase driven by the escrow accounting treatment of the SSR revenues in the PSCW rate order, effective January 1, 2015. See Note 22, Regulatory Environment, for more information.
•
A
$24.2 million increase due to the return of the iron ore mines as customers in February 2015. The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. Effective February 1, 2015, the owner of the two mines returned them as retail customers. In 2015, we deferred, and expect to continue to defer, the margin from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice. A large portion of this increase in margins was offset by higher transmission expense included in other operation and maintenance expense at WE.
•
A
$10.4 million positive impact from collections of fuel and purchased power costs compared with costs approved in rates in 2015, compared with 2014. Under the Wisconsin fuel rules, the margins of our electric utilities are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.
•
A $6.2 million increase primarily due to lower fly ash removal costs in 2015.
•
A
partially offsetting $22.3 million decrease related to sales volume variances in 2015. This decrease was driven by lower margins from residential customers in 2015, primarily due to lower weather-normalized use per customer and warmer weather during the heating season.
•
A partially offsetting $10.8 million decrease in wholesale margins driven by a reduction in sales volumes in 2015.
Natural Gas Utility Margins
Natural gas utility margins at the Wisconsin segment increased $22.1 million during
2015, compared with 2014. The increase was related to a $57.9 million margin contribution from WPS during the last six months of 2015, compared with no margin contribution from WPS during 2014. This increase was partially offset by a decrease in natural gas margins at WE and WG of $35.8 million in 2015.
The most significant factor impacting the $35.8 million lower natural gas utility margins at WE and WG was a $42.7 million decrease in sales volumes in 2015, largely related to warmer weather during the heating season as well as lower weather-normalized use per customer. As measured by heating degree days, 2015 was 15.1% warmer than 2014. This decrease in margins was partially offset by a $6.4 million net increase in margins as a result of the impact of the WE and WG PSCW rate orders, effective January 1, 2015. See
Note 22, Regulatory Environment, for more information.
Operating Income
Operating income at the Wisconsin segment increased $114.0 million during 2015, compared with 2014. The increase was driven by the $504.2 million increase in margins discussed above, partially offset by $390.2 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes). Higher operating expenses were driven by $334.2 million of operating expenses from WPS during the last six months of 2015, compared with no operating expenses from WPS during 2014.
The significant factors impacting the remaining $56.0 million of higher operating expenses at WE and WG were:
•
A $48.6 million increase from
higher lease expense related to the We Power leases and associated operating and maintenance expenses as approved in WE's PSCW rate order, effective January 1, 2015.
•
A $24.5 million increase in depreciation and amortization expense, driven by:
◦
An overall increase in utility plant in service in 2015. In November 2015, WG completed the Western Gas lateral project,
and WE completed the conversion of the fuel source for VAPP from coal to natural gas.
◦
New depreciation studies approved by the PSCW for both the utilities, effective January 1, 2015.
◦
A $7.7 million reduction in income received in 2015 from the Treasury Grant WE received in connection with the completion of its biomass plant in November 2013. The lower grant
income corresponds to lower bill credits provided to WE's retail electric customers in Wisconsin.
•
A $16.0 million increase in transmission expense from MISO and ATC related to the iron ore mines returning as customers in February 2015.
•
A combined $6.0 million increase in property and revenues taxes in 2015.
These
increases in operating expenses were partially offset by:
•
A $16.1 million decrease in employee benefit costs in 2015 driven by lower performance units share-based compensation, deferred compensation, and medical costs.
•
A $9.3 million decrease in electric and natural gas distribution costs in 2015, related to amortization of design software and maintenance costs.
Illinois
Segment Contribution to Operating Income
Year Ended December 31
(in millions)
2016
2015
Natural
gas revenues
$
1,242.2
$
503.4
Cost of natural gas sold
365.2
133.2
Total
natural gas margins
877.0
370.2
Other operation and maintenance
485.1
219.6
Depreciation
and amortization
134.0
63.3
Property and revenue taxes
18.3
9.2
Operating
income
$
239.6
$
78.1
The following table shows a breakdown of other operation and maintenance:
Year
Ended December 31
(in millions)
2016
2015
Operation and maintenance not included in the line items below
$
385.3
$
196.0
Riders
*
82.3
20.2
Regulatory amortizations *
2.7
1.3
Other
14.8
2.1
Total
other operation and maintenance
$
485.1
$
219.6
*
Riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant
impact on operating income.
The
following tables provide information on delivered volumes by customer class and weather statistics:
Therms (in millions)
Natural Gas Sales Volumes
2016
2015
Customer
Class
Residential
905.6
300.7
Commercial and industrial
187.6
63.2
Total
retail
1,093.2
363.9
Transport
855.3
328.4
Total
sales in therms
1,948.5
692.3
Degree Days
Weather
*
2016
2015
Heating (6,154 normal)
5,713
1,813
*
Normal
heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport.
We did not have any operations in Illinois until our acquisition of Integrys on June 29, 2015. Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
Natural Gas Utility Margins
Natural gas utility margins at the Illinois segment increased $506.8 million during 2016, compared with 2015. The increase was primarily driven by a $467.8 million margin contribution from the Illinois segment during the first six months
of 2016, compared to no margin contribution from this segment for the first six months of 2015.
The significant factors impacting the remaining $39.0 million increase in natural gas utility margins at the Illinois segment were:
•
A $26.3 million increase in margins related to the riders included in the table above during the last six months of 2016, compared with the last six months of 2015. PGL and NSG recover certain operating expenses directly through separate riders, resulting in no impact on operating income as increases in operating expenses are offset by equal increases in margins.
•
A
$10.8 million increase in revenue at PGL due to continued capital investment in projects under its Qualifying Infrastructure Plant rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved Qualifying Infrastructure Plant rider, which is in effect through 2023.
Operating Income
Operating income at the Illinois segment increased $161.5 million during 2016, compared with 2015. The increase was primarily driven by the $506.8 million increase in margin discussed above, partially offset by:
•
Operating
expenses of $308.2 million during the first six months of 2016, compared with no operating expenses during the first six months of 2015.
•
A $26.3 million increase in other operation and maintenance expenses related to the riders included in the table above during the last six months of 2016, compared with the last six months of 2015.
•
A $9.7 million increase in other operation and maintenance expenses during the last six
months of 2016 compared with the last six months of 2015, due to an increase in expenses related to a focus on projects that were beneficial to customers and the communities within our service territory.
Other States Segment Contribution to Operating Income
Year Ended December 31
(in millions)
2016
2015
Natural
gas revenues
$
376.5
$
149.3
Cost of natural gas sold
182.3
76.9
Total
natural gas margins
194.2
72.4
Other operation and maintenance
110.1
50.0
Depreciation
and amortization
21.1
10.0
Property and revenue taxes
13.1
6.4
Operating
income
$
49.9
$
6.0
The following table shows a breakdown of other operation and maintenance:
Year
Ended December 31
(in millions)
2016
2015
Operation and maintenance not included in line items below
$
86.4
$
43.2
Regulatory
amortizations and other pass through expenses *
23.6
6.7
Other
0.1
0.1
Total
other operation and maintenance
$
110.1
$
50.0
*
Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not
have a significant impact on operating income.
The following tables provide information on delivered volumes by customer class and weather statistics:
Therms (in millions)
Natural Gas Sales Volumes
2016
2015
Customer
Class
Residential
278.5
84.7
Commercial and industrial
178.2
60.9
Total
retail
456.7
145.6
Transport
696.2
279.6
Total
sales in therms
1,152.9
425.2
Degree Days
Weather
*
2016
2015
Heating (7,182 normal)
6,450
2,193
*
Normal
heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective territories.
We did not have any operations in this segment until our acquisition of Integrys on June 29, 2015. Since the majority of MERC and MGU customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
Natural Gas Utility Margins
Natural gas utility margins at the other states segment increased $121.8 million during 2016, compared with 2015. The increase was primarily
driven by a $110.4 million margin contribution from the other states segment during the first six months of 2016, compared to no margin contribution from this segment for the first six months of 2015.
The
significant factors impacting the remaining $11.4 million increase in natural gas utility margins at the other states segment were:
•
A $3.9 million increase in the last six months of 2016 as a result of various rate orders. The MERC interim rate order was effective January 1, 2016, and accounted for $2.5 million of the rate increase. The MGU rate order was also effective January 1, 2016, and accounted for $1.4 million to the rate increase. See Note 22, Regulatory Environment, for more information.
•
A
$3.0 million increase related to higher sales volumes during the last six months of 2016, driven by colder weather. As measured by heating degree days, the last six months of 2016 were 8.2% colder than the last six months of 2015 for these respective territories.
•
A $1.6 million increase related to the MERC conservation improvement program financial incentive as a result of exceeding certain energy savings goals.
Operating Income
Operating income at the other states segment increased $43.9 million
during 2016, compared with 2015. The increase was driven by the $121.8 million increase in margins discussed above, partially offset by $77.9 million of higher operating expenses. Higher operating expenses were driven primarily by $76.3 million of operating expenses from the other states segment during the first six months of 2016, compared with no operating expenses during the first six months of 2015.
We Power Segment Contribution to Operating Income
Year
Ended December 31
(in millions)
2016
2015
2014
Operating income
$
375.6
$
373.4
$
368.0
2016
Compared with 2015
Operating income at the We Power segment increased $2.2 million, or 0.6%, when compared to 2015. This increase was primarily related to higher revenues in connection with capital additions to the plants it owns and leases to WE.
2015 Compared with 2014
Operating income at the We Power segment increased $5.4 million, or 1.5%, when compared to 2014. This increase was primarily related
to higher revenues in connection with capital additions to the plants it owns and leases to WE.
Corporate and Other Segment Contribution to Operating Income
Year Ended December 31
(in
millions)
2016
2015
2014
Operating loss
$
(10.0
)
$
(91.2
)
$
(26.1
)
2016
Compared with 2015
The operating loss at the corporate and other segment decreased $81.2 million when compared to 2015, driven by a reduction in costs as a result of the acquisition of Integrys. See Note 2, Acquisitions, for more information regarding costs associated with the acquisition.
2015 Compared with 2014
The operating loss at the corporate and other segment increased $65.1 million when compared to 2014, driven by costs associated with the acquisition of Integrys on June 29, 2015.
Earnings from our ownership interest in ATC increased $50.4 million when compared to 2015, primarily driven by the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys on June 29, 2015. In addition, lower equity earnings in 2015 were driven by an ALJ initial decision in December 2015 related to the ATC ROE reviews, which was later affirmed by a FERC order in 2016. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints below for more information on these decisions.
2015
Compared with 2014
Earnings from our ownership interest in ATC increased $30.1 million when compared to 2014, primarily driven by the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys. This increase was partially offset by lower earnings recognized by ATC, as ATC further reduced earnings in 2015 related to an anticipated refund to customers resulting from a complaint filed with the FERC requesting a lower ROE for certain transmission owners.
Consolidated Other Income, Net
Year
Ended December 31
(in millions)
2016
2015
2014
AFUDC – Equity
$
25.1
$
20.1
$
5.6
Gain
on repurchase of notes
23.6
—
—
Gain on asset sales
19.6
22.9
7.5
Other,
net
12.5
15.9
0.3
Other income, net
$
80.8
$
58.9
$
13.4
2016
Compared with 2015
Other income, net increased by $21.9 million when compared to 2015. This increase was primarily due to the repurchase of a portion of Integrys's 6.11% Junior Notes at a discount in February 2016, as well as higher AFUDC due to the inclusion of AFUDC from the Integrys companies post acquisition. See Note 14, Long-Term Debt and Capital Lease Obligations, for more information on the repurchase. Partially offsetting this increase was a $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, compared with a $20.8 million gain from the sale of Minergy LLC and its remaining financial assets in June 2015, as well as excise tax credits recognized by ITF in 2015.
ITF was sold in the first quarter of 2016. See Note 3, Dispositions, for more information on our asset sales.
2015 Compared with 2014
Other income, net increased by $45.5 million when compared to 2014. This increase was primarily due to the $20.8 million gain from the sale of Minergy LLC and its remaining financial assets in June 2015, as well as higher AFUDC – Equity due to the inclusion of AFUDC from the Integrys companies post acquisition.
Interest expense increased $71.3 million, or 21.5%, when compared to 2015. The increase was primarily driven by $68.5 million
of interest expense from Integrys and its subsidiaries during the first six months of 2016, compared to no interest expense from these companies during the same period in 2015. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys. This was offset, in part, by the repurchase of a portion of the 6.11% Junior Notes in February 2016. These notes were replaced with lower-interest rate short-term debt.
2015 Compared with 2014
Interest expense increased $91.1 million, or 37.9%, when compared
to 2014, primarily due to higher debt levels. We assumed approximately $3.0 billion of debt from Integrys and its subsidiaries upon the closing of the acquisition on June 29, 2015. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys.
Consolidated Income Tax Expense
Year
Ended December 31
2016
2015
2014
Effective tax rate
37.6
%
40.4
%
38.0
%
2016
Compared with 2015
Our effective tax rate was 37.6% in 2016 compared to 40.4% in 2015. This decrease was primarily related to a charge in 2015 to remeasure our state deferred income taxes as a result of the acquisition of Integrys. See Note 15, Income Taxes, for more information. We expect our 2017 annual effective tax rate to be between 37.0% and 38.0%.
2015 Compared with 2014
Our
effective tax rate was 40.4% in 2015 compared to 38.0% in 2014. This increase in our effective tax rate was primarily related to a charge in 2015 to remeasure our state deferred income taxes as a result of the acquisition of Integrys.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following table summarizes our cash flows for the years ended December 31:
(in
millions)
2016
2015
2014
Change in 2016 Over 2015
Change in 2015 Over 2014
Cash provided by (used in):
Operating
activities
$
2,103.5
$
1,293.6
$
1,198.9
$
809.9
$
94.7
Investing
activities
(1,270.1
)
(2,517.5
)
(756.8
)
1,247.4
(1,760.7
)
Financing
activities
(845.7
)
1,211.8
(406.2
)
(2,057.5
)
1,618.0
Operating
Activities
2016 Compared with 2015
Net cash provided by operating activities increased $809.9 million during 2016. This increase was driven by $466.6 million of net cash flows from the operating activities of Integrys during the first six months of 2016, since Integrys was acquired on June 29, 2015. See Note 2, Acquisitions, for more information.
The remaining $343.3 million increase in net cash provided by operating activities was driven by:
•
A $377.9 million increase in cash resulting from lower payments for natural gas and fuel
and purchased power, due to lower commodity prices and warmer weather during the 2016 heating season. The average per-unit cost of natural gas sold decreased 18.5% in 2016.
•
A $94.2 million decrease in contributions and payments to our pension and OPEB plans during 2016.
•
A $44.1 million increase in cash due to lower collateral requirements during 2016, driven by an increase
in the fair value of our derivative instruments. See Note 20, Derivative Instruments, for more information.
•
A $29.2 million increase in cash received for income taxes, primarily due to a Wisconsin state income tax refund received in the fourth quarter of 2016.
These increases in net cash provided by operating activities were partially offset by a $210.8 million decrease in cash related to lower overall collections from customers. Collections from customers decreased primarily because of lower commodity prices and warmer weather during the
2016 heating season.
2015 Compared with 2014
Net cash provided by operating activities increased $94.7 million during 2015, driven by a $141.6 million increase related to net cash flows from the operating activities of Integrys during the last six months of 2015.
The $46.9 million decrease in net cash provided by operating activities from the legacy Wisconsin Energy Corporation companies was driven by:
•
A
$418.0 million decrease in cash related to lower overall collections from customers during 2015. Collections from customers decreased primarily because of lower commodity prices and warmer weather during the 2015 heating season. The average per-unit cost of natural gas sold decreased 33.1% in 2015.
•
A $141.4 million decrease in cash related to higher payments for operating and maintenance costs during 2015, primarily due to costs related to the acquisition of Integrys.
•
A
$96.8 million increase in contributions and payments to our pension and OPEB plans during 2015.
These decreases in net cash provided by operating activities from the legacy Wisconsin Energy Corporation companies were partially offset by a $592.4 million increase in cash resulting from lower payments for natural gas and fuel and purchased power, due to lower commodity prices and warmer weather during the 2015 heating season.
Investing Activities
2016 Compared with 2015
Net cash used in investing activities decreased
$1,247.4 million during 2016, driven by:
•
An investment of $1,329.9 million in June 2015 related to the acquisition of Integrys, which is net of cash acquired of $156.3 million. See Note 2, Acquisitions, for more information.
•
A $137.4 million increase in
the proceeds received from the sale of certain assets and businesses during 2016. See Note 3, Dispositions, for more information.
These decreases in net cash used in investing activities were partially offset by:
•
A $157.5 million increase in cash paid for capital expenditures, which is discussed in more detail below.
A $33.6 million increase in our capital contributions to ATC, driven by both the continued investment in equipment and facilities by ATC to improve reliability and the increase in our ATC ownership interest as a result of the June
2015 Integrys acquisition. See Note 4, Investment in American Transmission Company, for more information.
2015 Compared with 2014
Net cash used in investing activities increased $1,760.7 million during 2015, driven by:
•
An investment of $1,329.9 million in June 2015 related to the acquisition of Integrys, which is net of cash acquired of $156.3 million.
•
A
$505.0 million increase in cash paid for capital expenditures during 2015, which is discussed in more detail below.
These increases in cash used for investing activities were partially offset by:
•
A $17.3 million increase in cash related to the receipt of the cash surrender value of Integrys corporate-owned life insurance policies in 2015.
•
A
$15.0 million increase in proceeds from asset sales, driven by the sale of Minergy LLC and its remaining financial assets in 2015.
Capital Expenditures
Capital expenditures by segment for the years ended December 31 were as follows:
Reportable Segment
(in
millions)
2016
2015
2014
Change in 2016 over 2015
Change in 2015 over 2014
Wisconsin
$
910.9
$
950.3
$
715.0
$
(39.4
)
$
235.3
Illinois
293.2
194.4
—
98.8
194.4
Other
states
59.5
34.7
—
24.8
34.7
We
Power
62.3
53.4
41.0
8.9
12.4
Corporate
and other
97.8
33.4
5.2
64.4
28.2
Total
capital expenditures
$
1,423.7
$
1,266.2
$
761.2
$
157.5
$
505.0
2016
Compared with 2015
The decrease in cash paid for capital expenditures at the Wisconsin segment during 2016 was driven by lower capital expenditures as a result of the November 2015 completion of both WG's Western Gas Lateral project, which improved the reliability of WG's natural gas distribution network in the western part of Wisconsin, and WE's coal to natural gas conversion project at VAPP. Also contributing to the decrease were lower payments at WE for environmental compliance projects and electric distribution upgrades. The inclusion of WPS for all of 2016, as compared with only the last six months of 2015, substantially offset these lower capital expenditures. WPS's capital expenditures of $154.1 million during the first six months of 2016 related to the ReACTTM
emission control technology project at Weston Unit 3, a combustion turbine project at the Fox Energy Center, and the SMRP, a project to underground and upgrade certain electric distribution facilities in northern Wisconsin.
The increase in cash paid for capital expenditures at the Illinois segment during 2016 was due to the inclusion of PGL and NSG for all of 2016, compared with only the last six months of 2015. Capital expenditures at the Illinois segment were driven primarily by the SMP at PGL.
The increase in cash paid for capital expenditures at the other states segment during 2016 was due to the inclusion of MERC and MGU for all of 2016, compared with only the last six months of 2015. MERC's
and MGU's capital expenditures of $22.7 million during the first six months of 2016 primarily related to natural gas distribution systems and mains.
The increase in cash paid for capital expenditures at the corporate and other segment during 2016 was driven by a project to implement a new enterprise resource planning system and an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements – Capital Expenditures and Significant Capital Projects for more information.
2015 Compared with 2014
The
increase in capital expenditures at the Wisconsin segment during 2015 was primarily due to the inclusion of WPS as a result of the Integrys acquisition on June 29, 2015. Significant projects included in WPS's 2015 capital expenditures were the ReACTTM emission control technology project at Weston Unit 3 and the SMRP. The Wisconsin segment also included increased expenditures in 2015 related to WG's Western Gas Lateral project. These increases were partially offset by lower capital expenditures in 2015 for WE's conversion of the fuel source for VAPP from coal to natural gas, as most of the capital expenditures related to this project were incurred in 2014.
The Illinois segment includes capital expenditures from PGL and NSG as a result of the Integrys acquisition
on June 29, 2015. In 2015, PGL incurred significant capital expenditures related to the SMP.
The other states segment includes capital expenditures from MERC and MGU as a result of the Integrys acquisition on June 29, 2015.
Financing Activities
2016 Compared with 2015
Net cash related to financing activities decreased $2,057.5 million during 2016,
driven by:
•
A $1,526.4 million net decrease in cash due to a $1,750.0 million decrease in the issuance of long-term debt during 2016, partially offset by $223.6 million of lower repayments of long-term debt during 2016. We issued $1,200.0 million of long-term debt during 2015 in connection with the acquisition of Integrys.
•
A
$397.8 million net decrease in cash due to $234.8 million of net repayments of commercial paper during 2016 compared with $163.0 million of net borrowings of commercial paper during 2015.
•
A $169.5 million increase in dividends paid on common stock during 2016, due to the issuance of 90.2 million shares of our common stock in June 2015 as a result of the Integrys acquisition and increases to our quarterly dividend rate. See Note 2, Acquisitions, for more information.
•
A
$33.3 million increase in cash used to purchase shares of our common stock during 2016 to satisfy requirements of our stock-based compensation plans.
These decreases in net cash related to financing activities were partially offset by a $52.7 million increase in cash due to the redemption of all of WPS's preferred stock during 2015.
2015 Compared with 2014
Net cash related to financing activities increased $1,618.0 million during 2015, driven by:
•
A
$1,900.0 million increase in the issuance of long-term debt during 2015, of which $1,200.0 million related to the acquisition of Integrys.
•
An $82.8 million increase in net borrowings of commercial paper during 2015.
These increases in net cash related to financing activities were partially offset by:
•
A $205.3 million increase in retirements
of long-term debt during 2015, of which $130.1 million related to legacy Integrys and its subsidiaries.
•
A $103.4 million increase in dividends paid on common stock due to the issuance of 90.2 million shares of our common stock in June 2015 as a result of the Integrys acquisition and an increase in our quarterly dividend rate effective with the closing of the acquisition.
A $52.7 million decrease in cash due to the redemption of all of WPS's preferred stock during 2015.
Significant Financing
Activities
For more information on our financing activities, see Note 13, Short-Term Debt and Lines of Credit, and Note 14, Long-Term Debt and Capital Lease Obligations.
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, depending on market conditions and other factors.
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.
WEC Energy Group, WE, WG, WPS, and PGL 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. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 13, Short-Term Debt and Lines of Credit, for more
information about these credit facilities.
The following table shows our capitalization structure as of December 31, 2016 and 2015, as well as an adjusted capitalization structure that we believe is consistent with how the rating agencies currently view our 2007 6.25% Series A Junior Subordinated Notes due 2067 (6.25% Junior Notes):
2016
2015
(in
millions)
Actual
Adjusted
Actual
Adjusted
Common equity
$
8,929.8
$
9,179.8
$
8,654.8
$
8,904.8
Preferred
stock of subsidiary
30.4
30.4
30.4
30.4
Long-term debt (including current maturities)
9,315.4
9,065.4
9,281.8
9,031.8
Short-term
debt
860.2
860.2
1,095.0
1,095.0
Total capitalization
$
19,135.8
$
19,135.8
$
19,062.0
$
19,062.0
Total
debt
$
10,175.6
$
9,925.6
$
10,376.8
$
10,126.8
Ratio
of debt to total capitalization
53.2
%
51.9
%
54.4
%
53.1
%
Included
in long-term debt on our balance sheets as of December 31, 2016 and 2015, is $500.0 million principal amount of 6.25% Junior Notes. The adjusted presentation attributes $250.0 million of the 6.25% Junior Notes to common equity and $250.0 million to long-term debt. As a result of Integrys’s repurchase and retirement of some of its 6.11% Junior Notes, we were informed by one rating agency that it will no longer attribute equity credit to Integrys’s remaining junior subordinated notes, consisting of $114.9 million aggregate principal amount of the 6.11% Junior Notes, and $400.0 million aggregate principal amount of its 6.00% Junior Subordinated Notes due 2073. Therefore, the Integrys junior subordinated notes are no longer being adjusted in the table above. For additional information
on the repurchase of the 6.11% Junior Notes, see Note 14, Long-Term Debt and Capital Lease Obligations.
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 our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the 6.25% 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.
For a summary of the interest rate, maturity, and amount
outstanding of each series of our long-term debt on a consolidated basis, see our capitalization statements.
As described in Note 11, Common Equity, 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.
At December 31, 2016, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, for more information about our credit facilities and other short-term credit agreements. See Note 14, Long-Term Debt and Capital Lease Obligations, for more information about our long-term debt.
Working
Capital
As of December 31, 2016, our current liabilities exceeded our current assets by approximately $262.9 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for ongoing operations. We also can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.
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. However, we 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 S&P Global Ratings and/or Baa3 at Moody's Investors Service. 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.
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 agency only. An explanation of the significance of these ratings may be obtained from the 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
Contractual Obligations
We
have the following contractual obligations and other commercial commitments as of December 31, 2016:
Payments Due by Period (1)
(in
millions)
Total
Less Than 1 Year
1-3 Years
3-5 Years
More Than 5 Years
Long-term debt obligations (2)
$
17,658.0
$
555.3
$
1,943.2
$
1,700.4
$
13,459.1
Capital
lease obligations (3)
85.3
13.9
30.2
33.6
7.6
Operating
lease obligations (4)
95.5
9.9
14.7
10.8
60.1
Energy
and transportation purchase obligations (5)
11,977.5
1,137.7
1,716.2
1,344.7
7,778.9
Purchase
orders (6)
1,129.5
721.8
226.5
88.4
92.8
Pension
and OPEB funding obligations (7)
170.1
113.3
56.8
—
—
Capital
contributions to equity method investments
24.1
24.1
—
—
—
Total
contractual obligations
$
31,140.0
$
2,576.0
$
3,987.6
$
3,177.9
$
21,398.5
(1)
The
amounts included in the table are calculated using current market prices, forward curves, and other estimates.
(2)
Principal and interest payments on long-term debt (excluding capital lease obligations).
(3)
Capital lease obligations for power purchase commitments. This amount does not include We Power leases to WE which are eliminated upon consolidation.
(4)
Operating
lease obligations for power purchase commitments and rail car leases.
(5)
Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility operations.
Purchase obligations related to normal business operations, information technology, and other services.
(7)
Obligations
for pension and OPEB plans cannot reasonably be estimated beyond 2019.
The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note 15, Income Taxes.
AROs in the amount of $557.7 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years.
Obligations
for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.
Capital Expenditures and Significant Capital Projects
We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next
three years are as follows:
(in millions)
2017
2018
2019
Wisconsin
$
1,376.1
$
1,270.5
$
1,203.8
Illinois
544.8
517.7
523.4
Other
states
91.0
102.7
106.8
We Power
38.4
35.0
36.4
Corporate
and other
131.9
30.9
28.9
Total
$
2,182.2
$
1,956.8
$
1,899.3
WPS
is continuing work on the SMRP. This project includes converting more than 1,000 miles of overhead distribution power lines to underground in northern Wisconsin and adding distribution automation equipment on 400 miles of lines. WPS expects to invest approximately $45 million annually through 2018. Subject to regulatory review, Phase II of the SMRP will expand the scope and cost of the original SMRP and will consist of over 900 miles of underground circuit installation. WPS expects to invest approximately $200 million between 2018 and 2021 related to Phase II. WE, WPS, and WG will also continue to upgrade their electric and natural gas distribution systems to enhance reliability.
In connection with the formation of UMERC, we entered into an agreement with Tilden Mining Company under
which it will purchase electric power from UMERC for 20 years. The agreement calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation located in the Upper Peninsula of Michigan. The estimated cost of this project is approximately $265 million ($275 million including AFUDC). See Note 22, Regulatory Environment, for more information about UMERC and this new generation.
In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan for $225 million that would provide approximately one-third of the storage needs for our Wisconsin natural gas utilities. In addition, we expect to incur approximately $5 million of acquisition related costs. See Note 2, Acquisitions, for more information
on this transaction.
PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved Qualifying Infrastructure Plant rider, which is in effect through 2023. PGL's projected average annual investment through 2019 is between $280 million and $300 million.
We expect to provide capital contributions to ATC (not included in the above table) of approximately $226 million from 2017 through 2019.
For information related to our common stock matters, see Note 11, Common Equity.
On January
19, 2017, our Board of Directors increased our quarterly dividend to $0.52 per share effective with the first quarter of 2017 dividend payment, which equates to an annual dividend of $2.08 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.
Investments in Outside Trusts
We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $3.5 billion as of December 31, 2016. These trusts hold investments that are subject to the volatility of the stock market and interest
rates. We contributed $28.7 million, $121.0 million, and $13.9 million to our pension and OPEB plans in 2016, 2015, and 2014, respectively. In January 2017, we contributed $100.0 million to the 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 17, Employee Benefits.
Off-Balance Sheet Arrangements
We are a party to various financial instruments with off-balance sheet risk as a part
of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 13, Short-Term Debt and Lines of Credit, Note 16, Guarantees, and Note 21, Variable Interest Entities.
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 environments in which those businesses operate. These risks, described in further detail below, include but are not limited to:
Regulatory Recovery
Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated
Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. See Item 1. Business – D. Regulation for more information on these commissions.
Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of these deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. In general, our regulatory assets are recovered over a period of between one
to six years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2016, our regulatory assets were $3,138.3 million, and our regulatory liabilities were $1,597.2 million.
We expect to request or have requested recovery of the costs related to the following projects discussed in recent or pending rate proceedings, orders, and investigations involving our utilities:
•
In
June 2016, the PSCW approved deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. WPS will be required to obtain a separate approval for collection of these deferred costs.
Prior to its acquisition, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of December 31, 2016, we had received no significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project.
•
In
January 2014, the ICC approved PGL's use of the Qualifying Infrastructure Plant rider as a recovery mechanism for costs incurred related to investments in qualifying infrastructure plant. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. No schedule has been set for the 2015 reconciliation. The ALJ has placed the 2014 reconciliation on a stay, pending resolution of the ICC ordered stakeholder workshops and the ICC investigative docket regarding anonymous letters it received, both related to PGL's SMP. Although schedules have not been set for the reconciliations, discovery has continued for both the 2014 and 2015 reconciliations. As of December 31, 2016, there can be no assurance that all costs incurred under the Qualifying Infrastructure Plant rider will be recoverable.
See
Note 22, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.
Commodity Costs
In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility
through natural gas and electric hedging programs.
Embedded within our utilities' rates are amounts to recover fuel, natural gas, and purchased power costs. Our utilities have recovery mechanisms in place that allow them to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – D. Regulation for more information on these mechanisms.
Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable
write-offs as more customers are unable to pay their bills. See Note 1(d), Revenues and Customer Receivables, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.
Weather
Our utilities' rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. PGL, NSG, and MERC have decoupling mechanisms in
place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A summary of actual weather information in our utilities' service territories during 2016, 2015, and 2014, as measured by degree days, may be found in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.
Interest Rates
We are exposed to interest rate risk resulting from our short-term and long-term borrowings and projected near-term
debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.
Based on the variable rate debt outstanding at December 31, 2016, and December 31, 2015, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $9.8 million and $11.0 million in 2016 and
2015, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.
Marketable Securities Return
We
use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.
The fair value of our trust fund assets and expected long-term returns were approximately:
Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual
valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.
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
We have electric and natural gas utility operations that serve customers in Wisconsin, Illinois, Michigan, and Minnesota. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.
Inflation
We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental
compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.
For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.
Industry Restructuring
Electric Utility Industry
The regulated energy industry
continues to experience significant changes. The FERC continues to support large RTOs, which affects the structure of the wholesale market. To this end, MISO implemented the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when retail choice might be implemented, if at all, in Wisconsin. However, Michigan has adopted a limited retail choice program.
Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW has been focused on electric reliability infrastructure issues for the state of Wisconsin in recent years. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.
Restructuring
in Michigan
Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. Some of our small retail customers have switched to an alternative electric supplier. As of December 31, 2016, the law limited customer choice to 10% of our Michigan retail load. Due to the December 2016 passage of Michigan Act 341, this cap could potentially be reduced in future years. The iron ore mine in our service territory and certain load increases by facilities already using an alternative electric supplier are excluded from this cap, if various conditions are met. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.
Natural
Gas Utility Industry
We offer natural gas transportation services to our customers that elect to purchase natural gas from an alternative retail natural gas supplier. Since these transportation customers continue to use our distribution systems to transport the natural gas to their facilities, we earn distribution revenues from them. As such, the loss of revenue associated with the natural gas that transportation customers purchase from an alternative retail natural gas supplier has little impact on our net income, since it is offset by an equal reduction to natural gas costs.
Restructuring in Wisconsin
The PSCW previously instituted generic proceedings to consider how its regulation of natural
gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to provide customer classes with workably competitive market choices the option to choose an alternative retail natural gas supplier. The PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas directly from either an alternative retail natural gas supplier or their local natural gas utility. Currently, we are unable to predict the impact of potential future industry restructuring on our results of operations or financial position.
Restructuring in Illinois
Since 2002,
PGL and NSG have provided their customers with the option to choose an alternative retail natural gas supplier. We are not required by the ICC or state law to make this option available to customers, but since this option is currently provided to our Illinois customers, we would need ICC approval to eliminate it.
Restructuring in Minnesota
MERC has provided its commercial and industrial customers with the option to choose an alternative retail natural gas supplier since 2006. We are not required by the MPUC or state law to make this option available to customers, but since this option is currently provided to our Minnesota commercial and industrial customers, we would need MPUC approval to eliminate it.
Restructuring
in Michigan
The option to choose an alternative retail natural gas supplier has been provided to WPS's Michigan customers since the late 1990s and MGU's customers since 2005. We are not required by the MPSC or state law to make this option available to customers, but since this option is currently provided to our Michigan customers, we would need MPSC approval to eliminate it.
Environmental Matters
See Note 18, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land
quality, and climate change.
American
Transmission Company Allowed Return on Equity Complaints
In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued a final order related to this complaint affirming the use of the ROEs
stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also requires ATC to provide refunds, with interest, for the 15-month refund period from November 13, 2013, through February 11, 2015. As of December 31, 2016, ATC had started to provide refunds to WE and WPS for transmission costs paid during the refund period, and we expect the refund process to be completed by July 2017. As these refunds are received, WE and WPS reduce the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense.
In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with
a refund effective date retroactive to February 12, 2015. In June 2016, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the 0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to revenues collected from February 12, 2015, through May 11, 2016. We are not certain when a FERC order related to this matter will be issued.
MISO transmission owners have filed various appeals related to several of the FERC orders with the D.C. Circuit Court of Appeals as well as requests for rehearing.
The
decrease in ATC's ROE resulting from the FERC's final order will have a negative impact on our equity earnings and distributions from ATC in the future.
Bonus Depreciation Provisions
The Protecting Americans from Tax Hikes Act of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in service during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and 30% bonus depreciation to assets placed in service during 2019. Bonus depreciation is an additional amount of tax deductible depreciation that is awarded above what would normally be available. Due to the resulting increase in federal tax depreciation, we did not make federal income tax payments for 2016,
2015, or 2014.
Critical Accounting Policies and Estimates
Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation
of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgments.
We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2016. No impairments were recorded as a result of these tests. For all of our reporting units, the fair value calculated in step one of the test was greater than carrying value. The fair value of each reporting unit was calculated using a combination of the income approach
and the market approach.
For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the fair value of a reporting unit. Since all of our reporting units are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.
Key assumptions used in the income approach include ROEs, long-term growth rates used to determine terminal values at the end of the discrete forecast period, and discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine
fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.
For the market approach, we used an equal weighting of the guideline public company method and the guideline merged and acquired company method. The guideline public company method uses financial metrics from similar publicly traded companies to determine fair value. The guideline merged and acquired company method calculates fair value by analyzing the actual
prices paid for recent mergers and acquisitions in the industry. We applied multiples derived from these two methods to the appropriate operating metrics for our reporting units to determine fair value.
The underlying assumptions and estimates used in the impairment tests were made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the tests.
The fair values of our reporting units exceeded their carrying values by a substantial amount. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.
Our reporting units had the following goodwill balances at July
1, 2016:
(in millions, except percentages)
Goodwill
Percentage of Total Goodwill
Wisconsin
$
2,104.3
69.1
%
Illinois
758.7
24.9
%
Other
states
183.2
6.0
%
Total goodwill
$
3,046.2
100.0
%
See
Note 10, Goodwill, for more information.
Pension and Other Postretirement Employee Benefits
The costs of providing non-contributory defined pension benefits and OPEB, described in Note 17, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also
be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.
Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded at our utilities through the ratemaking process.
The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
Actuarial
Assumption
(in millions, except percentages)
Percentage-Point Change in Assumption
Impact on Projected Benefit Obligation
Impact on 2016
Pension Cost
Discount rate
(0.5)
$
202.3
$
10.4
Discount
rate
0.5
(176.1
)
(7.4
)
Rate of return on plan assets
(0.5)
N/A
13.9
Rate
of return on plan assets
0.5
N/A
(13.9
)
The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
Actuarial
Assumption
(in millions, except percentages)
Percentage-Point Change in Assumption
Impact on Postretirement
Benefit Obligation
Impact on 2016 Postretirement
Benefit Cost
Discount rate
(0.5)
$
55.2
$
2.8
Discount
rate
0.5
(47.7
)
(2.1
)
Health care cost trend rate
(0.5)
34.9
(4.7
)
Health
care cost trend rate
0.5
40.0
5.4
Rate of return on plan assets
(0.5)
N/A
3.6
Rate
of return on plan assets
0.5
N/A
(3.6
)
The discount rates are selected based on hypothetical bond portfolios consisting of noncallable (or callable with make-whole provisions), noncollateralized, high-quality corporate bonds across the full maturity spectrum. The bonds are generally rated "Aa" with a minimum amount
outstanding of $50.0 million. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.
We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.12% in 2016, 7.37% in 2015, and 7.25% in 2014. The actual rate of return on pension plan assets, net of fees, was 7.75%, (3.85)%, and 6.17%, in 2016, 2015, and 2014,
respectively.
In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 17, Employee Benefits.
Regulatory Accounting
Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC. Our financial statements reflect the effects of the ratemaking principles followed by the various jurisdictions regulating us. Certain items that would otherwise
be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, and the status of any pending or potential deregulation legislation.
The
application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off as a charge to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2016, we had $3,138.3 million in regulatory assets and $1,597.2 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.
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 2016 of approximately $7.4 billion included accrued utility revenues of $509.8 million as of December 31, 2016.
Income
Tax Expense
We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to the provision for income taxes in the income statements.
Uncertainty
associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.
Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are
supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(n), Income Taxes, and Note 15, Income Taxes, for a discussion of accounting for income taxes.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Item 7. 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, as well as Note 1(s), Fair Value Measurements,
Note 1(t), Derivative Instruments, and Note 16, Guarantees, for information concerning potential market risks to which we are exposed.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
WEC Energy Group, Inc.:
Milwaukee, Wisconsin
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of WEC Energy Group, Inc. and subsidiaries
(the “Company”) as of December 31, 2016 and 2015, and the related consolidated income statements, statements of comprehensive income, statements of equity, and statements of cash flows for each of the three years in the period ended December 31, 2016. 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 WEC Energy Group, Inc. and subsidiaries as of December 31,
2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, 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,
2016, 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 28, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.
A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
WEC Energy Group, Inc.:
Milwaukee, Wisconsin
We
have audited the internal control over financial reporting of WEC Energy Group, Inc. and subsidiaries (the “ Company”) as of December 31, 2016, 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, 2016, 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, 2016 of the Company and our report dated February 28, 2017 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
Current
portion of long-term debt and capital lease obligations
(157.2
)
(157.7
)
Total long-term debt
9,158.2
9,124.1
Total
long-term capitalization
$
18,118.4
$
17,809.3
(1)
PGL's
First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.
PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds.
(2)
NSG's
First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.
(3)
We Power senior notes, secured by a collateral assignment of the leases between PWGS and WE related to PWGS 1 and PWGS 2.
(4)
We
Power senior notes, secured by a collateral assignment of the leases between ERGSS and WE related to ER 1 and ER 2.
(5)
Variable interest rate reset quarterly. The rate was 3.05% as of December 31, 2016. Prior to December 1, 2016, fixed rate of 6.11% .
The accompanying Notes to Consolidated Financial Statements are an
integral part of these financial statements.
(a) General Information—On June 29, 2015, Wisconsin Energy Corporation acquired Integrys and changed its name to WEC Energy Group, Inc. WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and it owns approximately 60% of ATC. See Note 2, Acquisitions,
for more information on this acquisition.
As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.
Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments:
•
Wisconsin
segment – Consists of WE, WG, and WPS, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin. WE's electric and WPS's electric and natural gas operations in the state of Michigan are also included in this segment.
•
Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.
•
Other states segment
– Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.
•
Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a federally regulated electric transmission company.
•
We Power segment – Consists of We Power, which is principally engaged in the ownership of electric power
generating facilities for long-term lease to WE.
•
Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, WECC, WBS, PDL, Wisvest and ITF. The sale of ITF was completed in the first quarter of 2016. In the second quarter of 2016, we sold certain assets of Wisvest. See Note 3, Dispositions, for more information on these sales.
Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See
Note 8, Jointly Owned Facilities, for more information. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.
We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
(b)
Balance Sheet Presentation— To be consistent with the current year presentation, we changed our December 31, 2015 balance sheet from a utility format to a traditional format. This change revised the order of certain balance sheet line items, but it did not result in any change to the classification of amounts between line items.
(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.
(d) Revenues and Customer Receivables—We
recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers.
We present revenues net of pass-through taxes on the income statements.
Below is a summary of the significant mechanisms our utility subsidiaries had in place that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts:
•
Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations.
•
Our
retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW.
•
WE received payments from MISO under an SSR agreement for its PIPP units through February
1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 22, Regulatory Environment, for more information.
•
The rates for all of our natural gas utilities included one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.
•
The
rates of PGL and NSG included riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs.
•
MERC's rates included a conservation improvement program rider for cost recovery of energy conservation and management program costs as well as a financial incentive for meeting energy savings goals.
•
The rates of PGL and NSG, and the residential rates of WE and WG, included riders
or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.
•
The rates of PGL, NSG, MERC, and MGU included decoupling mechanisms. These mechanisms differ by state and allow utilities to recover or refund differences between actual and authorized margins. MGU's decoupling mechanism was discontinued after December 31, 2015. See Note 22, Regulatory Environment, for more information.
•
PGL's
rates included a cost recovery mechanism for SMP costs.
Revenues are also impacted by other accounting policies related to PGL's natural gas hub and our electric utilities' participation in the MISO Energy Markets. Amounts collected from PGL's wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers' charges for natural gas and services. Our electric utilities sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If our electric utilities were a net seller in a particular hour, the net amount was reported as operating revenues. If our electric utilities were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income
statements.
We provide regulated electric service to customers in Wisconsin and Michigan and regulated natural gas service to customers in Wisconsin, Illinois, Minnesota, and Michigan. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2016. In addition, there were no customers that
accounted for more than 10% of our revenues for the year ended December 31, 2016.
(e) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:
(in millions)
2016
2015
Natural gas in storage
$
223.1
$
284.1
Materials
and supplies
206.5
219.2
Fossil fuel
158.0
183.7
Total
$
587.6
$
687.0
PGL
and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 18% of total inventories at December 31, 2016 and 2015. The estimated replacement cost of natural gas in inventory at December 31, 2016 and 2015, exceeded the LIFO cost by $92.9 million and $15.2 million, respectively.
In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.63 at December 31, 2016, and $2.48 at December 31, 2015.
Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.
(f) Investments Held in Rabbi Trust— Integrys has a rabbi trust that is used
to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. The trust holds investments that are classified as trading securities for accounting purposes. As we do not intend to sell the investments in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains and losses included in earnings related to the investments held at the end of the period were not significant for the years ended December 31, 2016 and 2015.
(g)
Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to
which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 6, Regulatory Assets and Liabilities, for more information.
(h) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property
less salvage value is charged to accumulated depreciation when property is retired.
We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:
Annual Utility Composite Depreciation Rates
2016
2015
2014
WE
3.00%
3.01%
2.93%
WPS
*
2.58%
1.30%
N/A
WG
2.34%
2.36%
2.69%
PGL *
3.31%
1.67%
N/A
NSG
*
2.44%
1.22%
N/A
MERC *
2.53%
1.26%
N/A
MGU *
2.63%
1.32%
N/A
*
The rates shown for 2015 are for a partial year as a result of the acquisition of Integrys. The full year rate would be approximately double the rate shown.
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 ER 1 and ER 2.
We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss
on the income statement.
(i) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on stockholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net.
The majority of AFUDC is recorded at WE, WPS, and WG. Approximately 50% of WE's, WPS's, and WG's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC
retail rate, while the other utilities AFUDC rates are determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities and WBS did not record significant AFUDC for 2016, 2015, or 2014. Average AFUDC rates are shown below:
2016
Average
AFUDC Retail Rate
Average AFUDC Wholesale Rate
WE
8.45%
2.73%
WPS
7.72%
3.00%
WG
8.33%
N/A
Our
regulated utilities recorded the following AFUDC for the years ended December 31:
(in millions)
2016
2015
2014
AFUDC
– Debt
$
10.9
$
8.6
$
2.3
AFUDC – Equity
$
25.1
$
20.1
$
5.6
(j)
Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Intangible assets with definite lives are reviewed for impairment on a quarterly basis. Other long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable.
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.
Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 10, Goodwill, for more information.
The carrying amounts of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and
it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.
(k) Deferred Revenue—As part of the construction of We Power's 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 these generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheets and we are amortizing the deferred carrying costs to revenue over the individual lease terms.
(l)
Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when
incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted to their present values each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we
recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.
(m) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion product landfill
sites and Note 18, Commitments and Contingencies, for more information regarding manufactured gas plant sites.
We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.
Our
utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state Commission's approval.
We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.
(n) 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. See Note 15, Income Taxes, for more information.
We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements.
(o) Guarantees— We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor
recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 16, Guarantees, for more information.
(p) Employee Benefits—The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are allocated among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information.
(q)
Stock-Based Compensation— In accordance with the shareholder approved Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the
granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. The number of shares of common stock authorized for issuance under the plan is 34.3 million.
We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period based on our estimate of the final expected value of the awards.
Stock Options
We
grant non-qualified stock options that vest on a cliff-basis after a three-year period. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of the grant.
Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following
table shows the estimated fair value per stock option granted along with the weighted-average assumptions used in the valuation models:
2016
2015
2014
Non-qualified
stock options granted
794,764
516,475
899,500
Estimated
fair value per non-qualified stock option
$
5.14
$
5.29
$
4.18
Assumptions
used to value the options:
Risk-free interest rate
0.4% – 2.2%
0.1% – 2.1%
0.1%
– 3.0%
Dividend yield
4.0
%
3.7
%
3.8
%
Expected volatility
18.1
%
18.0
%
18.0
%
Expected
life (years)
6.1
5.8
5.8
The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our current dividend rate
and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience.
Restricted Shares
Restricted shares have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. Our restricted shares are classified as equity awards.
Performance Units
Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on our total shareholder
return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three-year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Under the terms of the award, participants may earn between 0% and 175% of the performance unit award, as adjusted pursuant to the terms of the plan. All grants are settled in cash and are accounted for as liability awards accordingly. Stock-based compensation costs are recorded over the three-year performance period.
See Note 11, Common Equity, for more information on our stock-based compensation plans.
(r)
Earnings Per Share—We compute basic earnings per 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 share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The calculation of diluted earnings per share for the years ended December 31, 2016 and 2015 excluded 181,709 and 516,475 stock options, respectively, that had an anti-dilutive effect. There were no securities
that had an anti-dilutive effect for the year ended December 31, 2014.
(s)
Fair Value Measurements—Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).
Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions
for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
Assets
and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received
from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.
Derivatives were transferred between levels of the fair value hierarchy primarily due to observable pricing becoming available. We recognize transfers at their value as of the end of the reporting period.
Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend
discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
See Note 19, Fair Value Measurements, for more information.
(t) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation,
and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.
We record derivative instruments on our balance sheets as assets or liabilities measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory
treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.
We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on the income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.
Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current
liabilities. See Note 20, Derivative Instruments, for more information.
(u) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service.
Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within
current liabilities on our balance sheets.
NOTE 2—ACQUISITIONS
Acquisition of Integrys
On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy products and services. Integrys also provided CNG products and services prior to the sale of ITF in the first quarter of 2016. Integrys holds a 34%
interest in ATC, a for-profit transmission company regulated by the FERC. The acquisition of Integrys has provided increased scale, operating efficiencies, and the potential for long-term cost savings through a combination of lower capital and operating costs.
Purchase Price
Pursuant to the Merger Agreement, Integrys’s shareholders received 1.128 shares of Wisconsin Energy Corporation common stock and $18.58 in cash per share of Integrys common stock. The total consideration transferred was based on the closing price of Wisconsin Energy Corporation common stock on June 29, 2015, and was calculated as follows:
Wisconsin Energy Corporation shares issued for Integrys shares *
90,187,884
Closing
price of Wisconsin Energy Corporation common shares on June 29, 2015
$45.16
Fair value of common stock issued
$
4,072.9
$
4,072.9
Cash
paid per share of Integrys shares outstanding
$18.58
Fair value of cash paid for Integrys shares *
$
1,486.2
$
1,486.2
Consideration
attributable to settlement of equity awards, net of tax
$
24.0
$
24.0
Total purchase price
$
4,072.9
$
1,510.2
$
5,583.1
*
Fractional
shares of 10,483 totaling $0.5 million were paid in cash.
All Integrys unvested stock-based compensation awards became fully vested upon the close of the acquisition and were either paid to award recipients in cash, or the value of the awards was deferred into a deferred compensation plan. In addition, all vested but unexercised Integrys stock options were paid in cash. In accordance with accounting guidance for business combinations, the acceleration of the vesting was recorded as an acquisition-related expense.
Allocation of Purchase Price
The Integrys assets acquired and liabilities
assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the FASB ASC. Substantially all of Integrys's operations are subject to the rate-setting authority of federal and state regulatory commissions. These operations are accounted for following the accounting guidance under the Regulated Operations Topic of the FASB ASC. The underlying assets and liabilities of ATC are also regulated by the FERC.
Integrys's assets and liabilities that are subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets less liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The goodwill reflects the value paid for the increased scale and efficiencies as a result of the combination. The goodwill recognized is not deductible for income tax purposes, and as such, no
deferred taxes have been recorded related to goodwill. See Note 10, Goodwill, for the allocation of goodwill to our reportable segments.
During the first six months of 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF and reserves recorded for likely settlements of certain legal and regulatory matters. The table below shows the final allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition:
(in millions)
Current
assets
$
1,060.1
Property, plant, and equipment, net
7,107.4
Goodwill
2,604.3
Other
long-term assets *
2,830.5
Current liabilities
(1,320.7
)
Long-term debt
(2,943.6
)
Other long-term liabilities
(3,703.8
)
Preferred
stock of subsidiary
(51.1
)
Total purchase price
$
5,583.1
*
Includes equity method goodwill related to Integrys's investment in ATC. See
Note 4, Investment in American Transmission Company, for more information.
In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments, which requires that an acquirer recognize and disclose adjustments to provisional amounts that are identified during an acquisition measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption was permitted for any interim and annual financial statements that had not yet been issued. We early adopted ASU 2015-16 in the fourth quarter of 2015. Adoption had no impact on our financial statements.
Conditions
of Approval
The acquisition was subject to the approvals of various government agencies, including the FERC, Federal Communications Commission, PSCW, ICC, MPSC, and MPUC. Approvals were obtained from all agencies subject to several conditions.
The PSCW order includes the following conditions:
•
WE and WG are each subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanisms, if either
company earns above its authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers. For WE, the additional utility earnings will be used to reduce the company’s transmission escrow. For WG, additional utility earnings will be used to reduce the costs of the Western Gas Lateral that would otherwise be included in rates. All utility earnings above the first 50 basis points will be used to reduce the transmission escrow for WE and reduce the costs of the Western Gas Lateral that would otherwise be included in rates for WG. For the year ended December 31, 2016, WE and WG recorded a combined $24.4 million
of expense related to these earnings sharing mechanisms.
•
Any future electric generation projects affecting Wisconsin ratepayers submitted by us or our subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, WPS and WE filed a joint integrated resource plan with the PSCW for their combined loads, which indicated that no new generation is currently needed.
The ICC order includes a base rate freeze for PGL and NSG effective for two years after the close of the acquisition. This base rate freeze does not impact PGL's or NSG's ability to adjust rates through various riders or GCRMs.
We do not believe that the conditions set forth in the various regulatory orders approving
the acquisition will have a material impact on our operations or financial results.
Pro Forma Information
The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results.
The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from
the acquisition and does not include certain acquisition-related costs.
Year Ended December 31
(in millions, except per share amounts)
2015
2014
Unaudited
pro forma financial information
Operating revenues
$
7,727.1
$
9,135.4
Net
income attributed to common shareholders
$
873.5
$
869.9
Earnings per share (Basic)
$
2.77
$
2.76
Earnings
per share (Diluted)
$
2.75
$
2.74
Impact of Acquisition
As a result of the acquisition, our ownership of ATC increased to approximately 60%. We have made commitments with respect to our voting rights
of the combined ownership of ATC, which are included as enforceable conditions in the FERC and PSCW orders approving the acquisition. Under GAAP, these commitments do not allow for the consolidation of ATC in our financial statements and the 60% ownership is accounted for as an equity method investment subsequent to the close of the acquisition. See Note 4, Investment in American Transmission Company, for more information.
In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $3.5 million, $107.6 million, and $12.5 million
during 2016, 2015, and 2014, respectively. These costs consisted of employee-related expenses, professional fees, and other miscellaneous costs. They are primarily recorded in the other operation and maintenance line item on the income statements.
Included in the 2015 acquisition costs was $24.9 million of severance expense that resulted from employee reductions related to the post-acquisition integration. Severance expense incurred during 2016 was not significant. The 2015 severance expense was recorded in the following segments:
Severance payments of $7.5 million and $16.9 million were made during 2016 and 2015, respectively. The severance accruals on our our balance sheets were not significant at December 31,
2016 and 2015.
Our revenues for the year ended December 31, 2015 include revenues attributable to Integrys of $1,416.8 million. Included in our net income for the year ended December 31, 2015, is net income attributable to Integrys of $65.9 million.
Acquisition of a Natural Gas Storage Facility in Michigan
In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan for $225 million that would provide approximately one-third of the storage needs for our Wisconsin natural gas utilities. In addition, we expect to incur approximately $5 million of acquisition related costs. A request has been filed with the PSCW for a declaratory ruling related to the recovery
of this investment. PSCW approval and closing of this transaction are expected to occur by the third quarter of 2017.
NOTE 3—DISPOSITIONS
Wisconsin Segment
Sale of Milwaukee County Power Plant
In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of
$10.9 million ($6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
Corporate and Other Segment
Sale of Certain Assets of Wisvest
In April 2016, as part of the MCPP sale transaction, we sold the chilled water generation
and distribution assets of Wisvest, which are used to provide chilled water services to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $19.6 million ($11.8 million after tax), which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
Sale of Integrys Transportation Fuels
Through
a series of transactions in the fourth quarter of 2015 and the first quarter of 2016, we sold ITF, a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation, and maintenance. There was no gain or loss recorded on the sales, as ITF's assets and liabilities were adjusted to fair value through purchase accounting. The sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. The pre-tax profit or loss of this component was not material through the sale date in 2016.
The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31:
(in millions)
2015
Accounts
receivable and unbilled revenues
$
34.9
Materials, supplies, and inventories
18.4
Other current assets
2.6
Property,
plant, and equipment
37.2
Other long-term assets
3.7
Total assets
$
96.8
Accounts
payable
$
12.9
Accrued payroll and benefits
2.4
Other current liabilities
4.5
Pension
and OPEB obligations
1.2
Other long-term liabilities
0.6
Total liabilities *
$
21.6
*
Included
in other current liabilities on our balance sheet.
NOTE 4—INVESTMENT IN AMERICAN TRANSMISSION COMPANY
Due to the acquisition of Integrys, our ownership of ATC increased from 26.2% to approximately 60%. ATC is a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. We have one representative on ATC's ten-member board of directors. Each member of the board has only one vote. Due to voting requirements,
no individual board member has more than 10% of the voting control. The following table shows changes to our investment in ATC during the years ended December 31:
(in millions)
2016
2015
2014
Balance
at beginning of period
$
1,380.9
$
424.1
$
402.7
Add: Earnings from equity method investment
146.5
96.1
66.0
Add:
Capital contributions
42.3
8.7
13.1
Add: Acquisition of Integrys's investment in ATC
(1.0
)
541.5
—
Add:
Equity method goodwill from the acquisition of Integrys (1)
10.4
395.8
—
Less: Distributions
135.1
(2)
85.1
57.5
Less:
Other
0.1
0.2
0.2
Balance at end of period
$
1,443.9
$
1,380.9
$
424.1
(1)
Represents the purchase price allocated to Integrys's investment in ATC in excess of the recorded value.
(2)
Of this amount, $35.2 million was recorded as a receivable at December 31, 2016.
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 are reimbursed by ATC. We are required
to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.
The following table summarizes our significant related party transactions with ATC during the years ended December 31:
(in millions)
2016
2015
2014
Charges
to ATC for services and construction
$
18.5
$
15.4
$
8.1
Charges from ATC for network transmission services
Cash (paid) for interest, net of amount capitalized
$
(411.9
)
$
(329.6
)
$
(241.4
)
Cash
received (paid) for income taxes, net
39.7
(9.3
)
(22.0
)
Significant non-cash transactions:
Accounts
payable related to construction costs
170.1
177.1
1.8
Restricted cash used to purchase investments held in the rabbi trust
59.2
60.2
—
Amortization
of deferred revenue
24.7
39.9
55.7
Note receivable received related to the sale of AMP Trillium*
—
12.0
—
Capital
assets received related to the sale of AMP Trillium *
—
6.3
—
*
ITF
owned a 30% interest in AMP. See Note 3, Dispositions, for more information on the sale of ITF.
At December 31, 2016 and 2015, restricted cash of $33.6 million and $118.4 million, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition. Withdrawals of restricted cash from the rabbi trust
for qualifying payments are shown as an investing activity on the statements of cash flows. Decreases in restricted cash due to the purchase of restricted investments held in the rabbi trust are reflected as non-cash transactions on the statements of cash flows and are included in the table above.
The following regulatory assets were reflected on our balance sheets as of December 31:
(in millions)
2016
2015
See
Note
Regulatory assets (1) (2)
Unrecognized pension and OPEB costs (3)
$
1,252.1
$
1,306.4
17
Environmental
remediation costs (4)
702.7
697.0
18
Income tax related items (5)
285.1
248.3
Electric
transmission costs
234.1
191.5
22
SSR
188.1
86.1
22
AROs
179.2
173.0
9
We
Power generation (6)
54.1
45.4
Energy efficiency programs (7)
36.7
48.7
Derivatives
17.9
70.4
1(t)
Other,
net
188.3
234.9
Total regulatory assets
$
3,138.3
$
3,101.7
Balance
Sheet Presentation
Current assets (8)
$
50.4
$
37.1
Regulatory
assets
3,087.9
3,064.6
Total regulatory assets
$
3,138.3
$
3,101.7
(1)
Based
on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in the table.
(2)
As of December 31, 2016, we had $32.7 million of regulatory assets not earning a return and $204.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of
the actual expenditures.
(3)
Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan.
(4)
As of December 31, 2016,
we had not yet made cash expenditures for $633.6 million of these environmental remediation costs.
(5)
Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse.
(6)
Represents amounts recoverable from customers related to
WE's costs of the generating units leased from We Power, including subsequent capital additions.
(7)
Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards.
(8)
Short-term regulatory assets are recorded in accounts receivable and unbilled revenues on our balance sheets.
The following regulatory liabilities were reflected on our balance sheets as of December 31:
(in
millions)
2016
2015
See Note
Regulatory liabilities
Removal
costs (1)
$
1,262.7
$
1,209.6
Mines deferral (2)
70.2
31.6
Energy
costs refundable through rate adjustments (3)
88.7
76.9
Unrecognized pension and OPEB costs (4)
63.0
26.3
17
Derivatives
41.1
12.6
1(t)
Uncollectible
expense (5)
36.1
31.8
Other, net
35.4
37.2
Total
regulatory liabilities
$
1,597.2
$
1,426.0
Balance
Sheet Presentation
Other current liabilities
$
33.4
$
33.8
Regulatory
liabilities
1,563.8
1,392.2
Total regulatory liabilities
$
1,597.2
$
1,426.0
(1)
Represents
amounts collected from customers to cover the cost of future removal of property, plant, and equipment.
(2)
Represents the deferral of revenues less the associated cost of sales related to sales to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding.
(3)
Represents
energy costs that will be refunded to customers in the future.
(4)
Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.
(5)
Represents amounts refundable to customers
related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates.
NOTE 7—PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31:
(in
millions)
2016
2015
Utility property, plant, and equipment
$
24,185.1
$
22,803.7
Less:
Accumulated depreciation
7,609.7
7,358.2
Net
16,575.4
15,445.5
CWIP
320.0
672.7
Net
utility property, plant, and equipment
16,895.4
16,118.2
Non-utility and other property, plant, and equipment
3,520.3
3,482.2
Less:
Accumulated depreciation
604.9
560.9
Net
2,915.4
2,921.3
CWIP
104.7
150.2
Net
non-utility and other property, plant, and equipment
3,020.1
3,071.5
Total property, plant, and equipment
$
19,915.5
$
19,189.7
NOTE
8—JOINTLY OWNED FACILITIES
We Power and WPS hold joint ownership interests in certain electric generating facilities. They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest. They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects. We Power and WPS record their proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets.
We Power leases its ownership interest in ER 1 and ER 2 to WE, and WE operates these units. WE and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs. WE's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements.
Information
related to jointly owned facilities at December 31, 2016 was as follows:
We Power
WPS
(in
millions, except for percentages and MWs)
Elm Road Generating Station Units 1 and 2
Weston Unit 4
Columbia Energy Center Units 1 and 2 (2)
Edgewater Unit 4
Ownership
83.34
%
70.0
%
31.8
%
31.8
%
Share
of rated capacity (MWs) (1)
1,056.8
373.5
334.4
98.0
In-service
date
2010 and 2011
2008
1975 and 1978
1969
Property, plant, and equipment
$
2,430.8
$
596.3
$
417.9
$
45.8
Accumulated
depreciation
$
(331.5
)
$
(170.3
)
$
(128.3
)
$
(31.7
)
CWIP
$
9.4
$
0.2
$
41.2
$
0.1
(1)
Based
on expected capacity ratings for summer 2017. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.
(2)
Columbia Energy Center (Columbia) is jointly owned by Wisconsin Power and Light (WPL), Madison Gas and Electric (MGE), and WPS. In October 2016, WPL received an order from the PSCW approving amendments to the Columbia joint operating agreement between the parties allowing WPS and MGE to forgo certain capital expenditures at Columbia. As a result, WPL will incur these capital expenditures
in exchange for a proportional increase in its ownership share of Columbia. Based upon the additional capital expenditures WPL expects to incur through June 1, 2020, WPS's ownership interest would decrease to 27.5%.
NOTE 9—ASSET RETIREMENT OBLIGATIONS
Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and polychlorinated biphenyls [PCBs]); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of generation facilities;
the dismantling of wind generation projects; the disposal of PCB-contaminated transformers; the closure of fly-ash landfills at certain generation facilities; and the removal of above ground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. AROs have also been recorded by PDL for the removal of solar equipment components. On our balance sheets, AROs are recorded within other long-term liabilities.
The following table shows changes to our AROs during the years ended December 31:
During
2015, an ARO of $16.1 million was recorded for fly-ash landfills located at generation facilities owned by WE and WPS. An ARO of $9.0 million was also recorded during 2015 for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. In addition, AROs increased $10.4 million in 2015 due to revisions made to estimated cash flows primarily for changes in the weighted average cost to retire natural gas distribution pipe at PGL and NSG.
Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table shows changes to our goodwill balances by segment during the years ended December 31,
2016 and 2015:
Wisconsin
Illinois
Other States
Total
(in millions)
2016
2015
2016
2015
2016
2015
2016
2015
Goodwill
balance as of January 1
$
2,109.5
$
441.9
$
731.2
$
—
$
182.8
$
—
$
3,023.5
$
441.9
Adjustment
to Integrys purchase price allocation
(5.2
)
—
27.5
—
0.4
—
22.7
—
Acquisition
of Integrys
—
1,667.6
—
731.2
—
182.8
—
2,581.6
Goodwill
balance as of December 31 *
$
2,104.3
$
2,109.5
$
758.7
$
731.2
$
183.2
$
182.8
$
3,046.2
$
3,023.5
*
We
had no accumulated impairment losses related to our goodwill as of December 31, 2016.
Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. In the third quarter of 2016, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2016. No impairments resulted from these tests.
NOTE 11—COMMON EQUITY
Stock-Based Compensation Plans
The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit for the years ended December 31:
(in millions)
2016
2015
2014
Stock
options
$
3.5
$
3.3
$
3.7
Restricted stock
5.8
7.0
2.8
Performance
units
8.7
13.0
15.4
Stock-based compensation expense
$
18.0
$
23.3
$
21.9
Related
tax benefit
$
7.2
$
9.3
$
8.8
Stock-based compensation costs capitalized
during 2016, 2015, and 2014 were not significant.
Stock Options
The following is a summary of our stock option activity during 2016:
Stock Options
Number
of Options
Weighted-Average Exercise Price
Weighted-Average Remaining Contractual Life (in years)
The
aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2016. This is calculated as the difference between our closing stock price on December 31, 2016, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2016, 2015, and 2014 was $55.4 million, $36.1
million, and $50.5 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $22.2 million, $14.5 million, and $19.9 million, respectively.
As of December 31, 2016, the total unrecognized compensation cost related to unvested stock options was not significant.
During the first quarter of 2017, the Compensation Committee awarded 552,215 non-qualified stock options with a weighted-average exercise price of $58.31 and a weighted-average grant date fair value of $7.45 per option to certain of our officers and other key employees
under its normal schedule of awarding long-term incentive compensation.
Restricted Shares
The following restricted stock activity occurred during 2016:
The intrinsic value of restricted stock released was $7.7 million, $3.7 million, and $2.7 million for the years ended December 31,
2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $3.1 million, $1.3 million, and $1.0 million, respectively.
As of December 31, 2016, approximately $5.1 million of unrecognized compensation cost related to restricted stock was expected to be recognized over the next 1.9 years on a weighted-average basis.
During
the first quarter of 2017, the Compensation Committee awarded 82,622 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $58.10 per share.
Performance Units
In 2016, 2015, and 2014, the Compensation Committee awarded 297,305; 195,365; and 233,735
performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.
Performance units with an intrinsic value of $19.1 million, $13.2 million, and $14.8 million were settled during 2016, 2015, and 2014, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units for the same years was approximately $6.8 million, $4.8 million, and $5.3 million, respectively.
As
of December 31, 2016, approximately $10.2 million of unrecognized compensation cost related to performance units was expected to be recognized over the next 1.4 years on a weighted-average basis.
During the first quarter of 2017, we settled performance units with an intrinsic value of $6.1 million. The actual tax benefit realized from the distribution of these awards was $1.8 million. In January 2017, the Compensation Committee also awarded 237,650 performance units to certain of our officers and other key employees
under its normal schedule of awarding long-term incentive compensation.
Restrictions
Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception
of MGU, are prohibited from loaning funds to us, either directly or indirectly.
In accordance with their most recent rate orders, WE, WG, and WPS may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized levels of 51%, 49.5%, and 51%, respectively. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized levels.
WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends
would be limited to 75% or 50% of net income during a twelve month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.
NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.
WEC Energy Group and Integrys have the option to defer interest payments on their junior subordinated notes, from time to time, for one or more periods of up to 10 consecutive years per period.
During any period in which they defer interest payments, they may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, their respective common stock.
See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.
As of December 31, 2016, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of investees accounted for by the equity method totaled approximately $6.3 billion.
This amount exceeds 25% of our consolidated net assets as of December 31, 2016.
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 have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued in 2016, 2015, or 2014, other than for the Integrys
acquisition. See Note 2, Acquisitions, for more information.
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 entering into the Merger Agreement, the Board of Directors terminated this share repurchase program. The following table identifies shares purchased during the year ended December 31:
2016
2015
2014
(in
millions)
Shares
Cost
Shares
Cost
Shares
Cost
Under share repurchase programs
—
$
—
—
$
—
0.4
$
18.6
To
fulfill exercised stock options and restricted stock awards
1.8
108.0
1.5
74.7
2.3
104.6
Total
1.8
$
108.0
1.5
$
74.7
$
2.7
$
123.2
Common
Stock Dividends
During the year ended December 31, 2016, our Board of Directors declared common stock dividends which are summarized below:
On January 19, 2017, our Board of Directors increased our quarterly dividend to $0.52 per share effective with the first quarter of 2017 dividend payment, which equates to an annual dividend of $2.08 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.
The following table shows preferred stock authorized and outstanding at December 31, 2016 and 2015:
(in
millions, except share and per share amounts)
Shares Authorized
Shares Outstanding
Redemption Price Per Share
Total
WEC Energy Group
$.01
par value Preferred Stock
15,000,000
—
—
$
—
WE
$100
par value, Six Per Cent. Preferred Stock
45,000
44,498
—
4.4
$100 par value, Serial Preferred
Stock
2,286,500
3.60% Series
260,000
$
101
26.0
$25
par value, Serial Preferred Stock
5,000,000
—
—
—
WPS
$100
par value, Preferred Stock
1,000,000
—
—
—
PGL
$100
par value, Cumulative Preferred Stock
430,000
—
—
—
NSG
$100
par value, Cumulative Preferred Stock
160,000
—
—
—
Total
$
30.4
NOTE
13—SHORT-TERM DEBT AND LINES OF CREDIT
The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:
(in millions, except percentages)
2016
2015
Commercial
paper
Amount outstanding at December 31
$
860.2
$
1,095.0
Average
interest rate on amounts outstanding at December 31
0.96
%
0.68
%
Our average amount of commercial paper borrowings based on daily outstanding balances during 2016, was $882.3 million with a weighted-average interest rate during the period of 0.66%.
WEC
Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70.0%, 65.0%, 65.0%, 65.0%, and 65.0%, respectively. As of December 31, 2016, all companies were in compliance with their respective ratio.
As of December 31, 2016, we had $1,620.7 million of available
capacity under our bank back-up credit facilities and $860.2 million of commercial paper outstanding that was supported by the credit facilities.
The
information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31:
(in millions)
Maturity
2016
WEC Energy Group
December
2020
$
1,050.0
WE
December 2020
500.0
WPS
December 2020
250.0
WG
December
2020
350.0
PGL
December 2020
350.0
Total short-term credit capacity
$
2,500.0
Less:
Letters
of credit issued inside credit facilities
$
19.1
Commercial paper outstanding
860.2
Available
capacity under existing agreements
$
1,620.7
Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval.
The 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 defaults, and change of control. In addition, pursuant to the terms of our credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein.
NOTE 14—LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
See our statements of capitalization for details on our long-term debt.
Wisconsin
Gas LLC
In September 2016, WG issued $200.0 million of 3.71% Debentures due September 30, 2046. The net proceeds were used to repay short-term debt.
The Peoples Gas Light and Coke Company
In December 2016, PGL issued $150.0 million of 3.65% Series DDD Bonds due December 15, 2046. The net proceeds were used for general corporate purposes, including capital expenditures and the refinancing of short-term debt.
In November 2016, PGL issued $50.0 million
of 3.65% Series CCC Bonds due December 15, 2046. The net proceeds were used to repay at maturity PGL's $50.0 million aggregate principal amount outstanding of 2.21% First and Refunding Mortgage Bonds,
Series XX.
In June 2016, PGL issued commercial paper to redeem at par, its $50.0 million of 4.30% Series RR First and Refunding Mortgage Bonds that were due in 2035.
W.E. Power, LLC
During 2017, $5.6 million
of We Power's outstanding $106.7 million of 4.91% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016.
During 2017, $4.6 million of We Power's outstanding $126.1 million of 6.00% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016.
During 2017, $10.8 million
of We Power's outstanding $204.8 million of 5.209% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016.
During 2017, $8.5 million of We Power's outstanding $170.9 million of 4.673% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016.
Integrys Holding, Inc.
In June 2016, Integrys's $50.0 million of 8.00% unsecured senior notes matured and were repaid with contributions from WEC Energy Group, which
were funded by commercial paper issued by WEC Energy Group.
In February 2016, Integrys repurchased and retired $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million, plus accrued and unpaid interest, through a modified “dutch auction” tender offer. The gain associated with this repurchase was included in other income, net on our income statement. In connection with this transaction, Integrys issued approximately $66.4 million of additional common stock to WEC Energy Group in satisfaction of its obligations under a replacement capital covenant relating to the 6.11% Junior Notes. Effective December
1, 2016, the remaining $114.9 million aggregate principal amount of the 6.11% Junior Notes bears interest at the three-month London Interbank Offered Rate (LIBOR) plus 2.12% and will reset quarterly.
Bonds and Notes
The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2016:
(in
millions)
Payments
2017
$
154.5
2018
836.1
2019
357.7
2020
684.4
2021
336.2
Thereafter
6,953.5
Total
$
9,322.4
We
amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.
As of December 31, 2016, WE was the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, WE terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. WE purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2016, the repurchased bonds were still outstanding, but were not reported in our long-term debt since they were held by WE. Depending on market conditions and other factors, WE may change the method
used to determine the interest rate on this bond series and have it remarketed to third parties. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016.
In connection with our outstanding 2007 6.25% Series A Junior Subordinated Notes (6.25% Junior Notes), we executed a Replacement Capital Covenant dated May 11, 2007 (RCC), which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our 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 that our subsidiaries may not purchase, any 6.25% Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities.
Effective May 2017, the $500 million of 6.25% Junior Notes will bear interest at the three-month LIBOR plus 211.25 basis points and will reset quarterly.
In
connection with Integrys’s outstanding 6.11% Junior Notes, Integrys executed a Replacement Capital Covenant dated December 1, 2006, as replaced by a new Replacement Capital Covenant on December 1, 2010 (Integrys RCC) for the benefit of persons that buy, hold, or sell a specified series of its long-term indebtedness (covered debt). Integrys’s 4.17% Senior Notes due November 1, 2020, have been designated as the covered debt under the Integrys RCC. The Integrys RCC provides that Integrys may not redeem, defease,
or purchase, and that its subsidiaries may not purchase, any 6.11% Junior Notes on or before December 1, 2036, unless, subject to certain limitations described in the Integrys RCC, Integrys has received a specified amount of proceeds from the sale of qualifying
securities.
Effective August 2023, Integrys's $400.0 million of 2013 6.00% Junior Subordinated Notes due 2073 will bear interest at the three-month LIBOR plus 322 basis points and will reset quarterly.
Certain long-term debt obligations contain financial and other covenants. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.
Obligations Under Capital Leases
In 1997, WE entered into a 25-year
power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, WE may, at its option and with proper notice, renew for another 10 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 cost of sales on our income statements. We paid a total of $37.6 million and $36.2 million in lease payments during 2016 and 2015,
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 balance sheets. 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 $29.6 million as of December 31, 2016, 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:
(in millions)
2016
2015
Long-term
power purchase commitment
$
140.3
$
140.3
Accumulated amortization
(109.5
)
(103.9
)
Total
leased facilities
$
30.8
$
36.4
Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2016 are as follows:
The following table is a summary of income tax expense for the years ended December 31:
(in
millions)
2016
2015
2014
Current tax expense
$
72.7
$
15.1
$
33.6
Deferred
income taxes, net
498.7
420.4
329.2
Investment tax credit, net
(4.9
)
(1.7
)
(1.1
)
Total
income tax expense
$
566.5
$
433.8
$
361.7
Statutory Rate Reconciliation
The
provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:
2016
2015
2014
Effective
Effective
Effective
(in
millions)
Amount
Tax Rate
Amount
Tax Rate
Amount
Tax Rate
Expected tax at statutory
federal tax rates
$
526.4
35.0
%
$
375.5
35.0
%
$
332.5
35.0
%
State
income taxes net of federal tax benefit
72.8
4.8
%
73.1
6.8
%
50.5
5.3
%
Production
tax credits
(15.7
)
(1.1
)%
(17.4
)
(1.6
)%
(17.4
)
(1.8
)%
AFUDC
– Equity
(8.8
)
(0.6
)%
(7.1
)
(0.7
)%
(1.9
)
(0.2
)%
Investment
tax credit restored
(4.9
)
(0.3
)%
(1.7
)
(0.2
)%
(1.1
)
(0.2
)%
Other,
net
(3.3
)
(0.2
)%
11.4
1.1
%
(0.9
)
(0.1
)%
Total
income tax expense
$
566.5
37.6
%
$
433.8
40.4
%
$
361.7
38.0
%
Deferred
Income Tax Assets and Liabilities
The components of deferred income taxes as of December 31 are as follows:
(in millions)
2016
2015
Deferred tax assets
Future
tax benefits
$
430.4
$
382.8
Employee benefits and compensation
222.0
229.9
Deferred
revenues
207.2
219.9
Property-related
54.5
59.5
Other
230.6
177.1
Total
deferred tax assets
1,144.7
1,069.2
Valuation allowance
(15.0
)
(17.1
)
Net
deferred tax assets
$
1,129.7
$
1,052.1
Deferred
tax liabilities
Property-related
$
4,979.3
$
4,451.5
Investment
in transmission affiliate
476.9
420.4
Employee benefits and compensation
401.6
428.9
Deferred
transmission costs
93.1
76.7
Other
325.4
296.9
Total
deferred tax liabilities
6,276.3
5,674.4
Deferred tax liability, net
$
5,146.6
$
4,622.3
Consistent
with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities.
The
components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2016 and 2015 are summarized in the tables below:
Valuation
allowances of $15.0 million have been established for certain tax benefit carryforwards obtained in the Integrys acquisition based on our projected ability to realize such benefits by offsetting future tax liabilities. This is primarily the result of the extension of bonus depreciation. Realization is dependent on generating sufficient tax liabilities prior to expiration of the tax benefit carryforwards.
Unrecognized Tax Benefits
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:
Additions
based on tax positions related to the current year
1.1
0.2
Reductions for tax positions of prior years
(1.0
)
(1.1
)
Reductions
due to statute of limitations
(1.8
)
—
Settlements during the period
—
(0.7
)
Balance
as of December 31
$
14.5
$
9.5
The amount of unrecognized tax benefits as of December 31, 2016 and 2015, excludes deferred tax assets related to uncertainty in income taxes of $6.6
million and $6.2 million, respectively. As of December 31, 2016 and 2015, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $7.9 million and $2.2 million, respectively.
We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2016, 2015, and 2014, we recognized $0.2 million,
zero, and $0.3 million of accrued interest in our income statements, respectively. For the years ended December 31, 2016, 2015, and 2014, we recognized no penalties in our income statements. For the year ended December 31, 2016, we had $0.8 million of interest accrued and no penalties accrued on our balance sheets. For the year ended December 31, 2015, we had $0.7
million of interest accrued and $0.1 million of penalties accrued on our balance sheets.
We
do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months.
We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. As of December 31, 2016, we were subject to examination by state or local tax authorities for the 2011 through 2016 tax years in our major state operating jurisdictions as follows:
Jurisdiction
Years
Federal
2013–2016
Illinois
2013–2016
Michigan
2012–2016
Minnesota
2014–2016
Wisconsin
2011–2016
NOTE
16—GUARANTEES
The following table shows our outstanding guarantees:
At
our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.
(2)
Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.
(3)
Consists
of $7.6 million related to other indemnifications, for which a liability of $7.1 million related to workers compensation coverage was recorded on our balance sheets.
NOTE 17—EMPLOYEE BENEFITS
Pension and Other Postretirement Employee Benefits
We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded nonqualified retirement
plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.
Generally, former Wisconsin Energy Corporation 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. New Wisconsin Energy Corporation management employees hired after
December 31, 2014 receive a 6% annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.
For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year.
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 tables provide
a reconciliation of the changes in our plans' benefit obligations and fair value of assets:
Pension Costs
OPEB Costs
(in millions)
2016
2015
2016
2015
Change
in benefit obligation
Obligation at January 1
$
3,083.0
$
1,505.5
$
842.0
$
397.7
Obligation
assumed from acquisition
—
1,594.0
—
493.0
Service cost
45.4
30.4
26.1
20.7
Interest
cost
130.8
94.3
37.0
26.7
Participant contributions
—
—
16.4
12.7
Plan
amendments
(3.0
)
—
(18.9
)
—
Actuarial loss (gain)
71.7
14.6
(36.5
)
(74.0
)
Benefit
payments
(269.1
)
(156.0
)
(49.1
)
(36.2
)
Federal subsidy on benefits paid
N/A
N/A
1.4
1.6
Plan
curtailment
—
0.2
—
(0.2
)
Obligation at December 31
$
3,058.8
$
3,083.0
$
818.4
$
842.0
Change
in fair value of plan assets
Fair value at January 1
$
2,755.1
$
1,444.6
$
749.8
$
333.5
Assets
received from acquisition
—
1,420.9
—
442.1
Actual return on plan assets
199.4
(62.1
)
51.5
(15.6
)
Employer
contributions
23.8
107.7
4.9
13.3
Participant contributions
—
—
16.4
12.7
Benefit
payments
(269.1
)
(156.0
)
(49.1
)
(36.2
)
Fair value at December 31
$
2,709.2
$
2,755.1
$
773.5
$
749.8
Funded
status at December 31
$
(349.6
)
$
(327.9
)
$
(44.9
)
$
(92.2
)
The
amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:
Pension Costs
OPEB Costs
(in
millions)
2016
2015
2016
2015
Other long-term assets
$
74.4
$
74.1
$
29.7
$
50.1
Pension
and OPEB obligations *
424.0
402.0
74.6
142.3
Total net liabilities
$
(349.6
)
$
(327.9
)
$
(44.9
)
$
(92.2
)
*
Includes
$0.8 million of pension and $0.4 million of OPEB obligations classified as liabilities held for sale as of December 31, 2015. These amounts are included in other current liabilities on our balance sheets.
The accumulated benefit obligation for all defined benefit pension plans was $2,939.9 million and $2,936.4 million as of December 31, 2016, and 2015, respectively.
The following table shows
information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:
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. For 2017, the expected return on assets assumption
is 7.11% for the pension plans and 7.25% for the OPEB plans.
Assumed health care cost trend rates have a significant effect on the amounts reported by us for health care plans. For the year ended December 31, 2016, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:
(in millions)
1%
Increase
1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost
$
8.5
$
(6.9
)
Effect on health care component
of the accumulated postretirement benefit obligations
49.6
(39.5
)
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.
The Wisconsin Energy Corporation pension trust target asset allocations are 35% equity investments, 55%
fixed income investments, and 10% private equity and real estate investments. The Integrys pension trust target asset allocation is 60% equity investments and 40% fixed income investments. The Wisconsin Energy Corporation OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments. The two largest OPEB trusts for Integrys have target asset allocations of 50% equity investments and 50% fixed income, and 45% equity investments and 55% fixed income, respectively. 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 United States Treasuries.
Pension and OPEB plan investments are recorded at fair value. See Note 1(s), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. Following our adoption of ASU 2015-07 on January 1, 2016, the assets that are not subject to leveling are investments that are valued using the net asset value per share (or its equivalent) practical expedient. We have applied this approach retrospectively to the 2015 table for comparability.
This
category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.
The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:
In January 2017, we contributed $100.0 million to the pension plans. We expect to contribute
an additional $13.2 million to the pension plans and $0.1 million to the OPEB plans in 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.
The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB:
(in millions)
Pension
Costs
OPEB Costs
2017
$
215.7
$
41.8
2018
217.1
49.6
2019
226.5
49.0
2020
233.1
50.9
2021
230.0
53.1
2022-2026
1,031.5
278.5
Savings
Plans
We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. Certain employees participate in a defined contribution pension plan, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $44.3 million in 2016, $48.0 million in 2015, and $14.2 million in 2014.
NOTE
18—COMMITMENTS AND CONTINGENCIES
We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, operating leases, environmental matters, and enforcement and litigation matters.
Unconditional Purchase Obligations
We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity
to their customers. The utilities expect to recover costs related to these obligations in future customer rates.
The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016, including those of our subsidiaries.
We lease property, plant, and equipment under various terms. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair
market value, or (b) exercise a renewal option, as set forth in the lease agreement.
Rental expense attributable to operating leases was $15.1 million, $12.7 million, and $4.8 million in 2016, 2015, and 2014, respectively.
Future minimum payments under noncancelable operating leases are payable as follows:
Year
Ending December 31
Payments
(in millions)
2017
$
9.9
2018
8.8
2019
5.9
2020
5.3
2021
5.5
Later
years
60.1
Total
$
95.5
Environmental Matters
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations.
Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:
•
the development of additional sources of renewable electric energy supply;
•
the
addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;
•
the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;
•
the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;
•
the
retirement of old coal-fired power plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation;
•
the beneficial use of ash and other products from coal-fired and biomass generating units; and
•
the remediation of former manufactured gas plant sites.
Air Quality
Cross-State
Air Pollution Rule
In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets discussed below apply to 2017 and beyond.
In
December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and issued the final rule in September 2016. Starting in 2017, this rule requires reductions in the ozone season (May 1 through September 30) NOxemissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOxozone season
budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.
Sulfur Dioxide National Ambient Air Quality Standards
The EPA issued a revised 1-Hour SO2
NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.
In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO2. The consent decree required the EPA to complete attainment designations for certain areas with large sources by no later
than July 2016. SO2 emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. In July 2016, the EPA finalized its recommendation and published a notice in the Federal Register designating Marquette County, Michigan as unclassified/attainment, effective September 2016.
In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation
and finalize its recommended designation in August 2017, for finalization by the end of 2017.
We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.
8-Hour Ozone National Ambient Air Quality Standards
The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment
areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.
Mercury and Other Hazardous Air Pollutants
In December 2011, the EPA issued the final MATS rule, which imposed stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90%
reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the Supreme Court ruled on a challenge to the MATS rule and remanded the case back to the D.C. Circuit Court of Appeals, ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation.
We believe that the WE and WPS fleets are well positioned to comply with the final MATS rule and do not expect to incur any significant additional costs to comply with this regulation. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, allowing PIPP to be in compliance with MATS. Construction and testing of the ReACTTM
multi-pollutant control system at Weston Unit 3 is complete, and the unit is currently in compliance with both MATS and the WPS Consent Decree emission requirements.
Climate Change
In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for
modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan until disposition of the litigation in the D.C. Circuit Court of
Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The D.C. Circuit Court of Appeals heard the case in September 2016.
The final rule for existing fossil-fueled generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%,
respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We continue to evaluate possible reduction opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions, given the uncertain future of the Clean Power Plan and current fuel and technology markets. Our evaluation to date indicates that the Clean Power Plan, as well as current fuel markets and advances in technology, are not expected to result in significant additional compliance costs, including capital expenditures, but could impact how we operate our
existing fossil-fueled power plants and biomass facility.
However, the timelines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, likely will be changed due to the stay and subsequent legal proceedings. With the new Federal Executive Administration as of January 2017, the Clean Power Plan, or its successor, could be significantly changed from the final rule of October 2015. Notwithstanding the potential changes to the Clean Power Plan, addressing climate change is an integral component of our strategic planning process. We continue to reshape our portfolio of electric generation facilities with investments that will improve our environmental performance, including reduced GHG intensity of our operating fleet. As the regulation of GHG emissions takes shape, our plan is to work with our industry partners, environmental
groups, and the State of Wisconsin, with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO2 reduction goal, such as increased utilization of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.
Draft Federal Plan and Model Trading Rules (Model Rules) were also published in October 2015 for use in developing state plans or for use in states where
a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for reconsideration of the EPA's final standards for existing, as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly asked the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO2 equivalent reduction goal by about 10%. In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. The EPA has not issued decisions
yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2016, the EPA withdrew the draft Model Rules and accompanying draft documents from the review process and made working drafts available to the public. They are not final documents, are not signed by the Administrator, and will not be published in the Federal Register. The EPA’s docket will remain open, with the potential for completing the agency’s work on these materials and finalizing them at a later date.
We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015, we reported aggregated CO2
equivalent emissions of approximately 31.0 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 29.6 million metric tonnes to the EPA for 2016. The level of CO2 and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.
We are also required to report CO2
equivalent amounts related to the natural gas that our natural gas utilities distribute and sell. For 2015, we reported aggregated CO2 equivalent emissions of approximately 27.2 million metric tonnes to the EPA. Based upon our
preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 26.7 million metric tonnes to the EPA for 2016.
Water Quality
Clean Water Act Cooling Water Intake Structure Rule
In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best
Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.
Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units
7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.
BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction 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 intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8, Weston Units 2 through 4, PWGS,
Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8.
During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements) and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Based on discussions with the MDEQ, if we provide
information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and were recently completed at PIPP. See UMERC discussion in Note 22, Regulatory Environment, regarding the potential retirement of PIPP.
We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.
Steam
Electric Effluent Guidelines
The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit and may result in changes to the discharge requirements. The WDNR and MDEQ will continue to modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater
treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at OC 7, OC 8, the Pleasant Prairie units, Pulliam Units 7 and 8, and
Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $80 million to $110 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See UMERC discussion in Note 22,
Regulatory Environment, regarding the potential retirement of PIPP.
Land Quality
Manufactured Gas Plant Remediation
We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation,
monitoring, remediation, and closure.
In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to
recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.
We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31:
(in millions)
2016
2015
Regulatory
assets
$
702.7
$
697.0
Reserves for future remediation
633.4
628.0
Renewables,
Efficiency, and Conservation
Wisconsin Legislation
In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. WE and WPS have achieved renewable energy percentages of 8.27% and 9.74%, respectively, and met their compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their requirements on an ongoing
basis. The PSCW administers the renewable program related to Act 141, and each utility funds the program based on 1.2% of its annual operating revenues.
Michigan Legislation
In 2008, Michigan enacted Act 295, which required 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. In December 2016, Michigan revised this legislation with Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement
to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. WE and WPS were in compliance with these requirements as of December 31, 2016. The revised legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.
We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results
of operations.
Paris Generating Station Units 1 and 4 Construction Permit
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 Paris Generating Station Units 1 and 4. Act 91, along with a new construction permit, allowed those units to restart after a temporary outage. In October 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit. In February 2013, the Sierra Club also filed for a contested case hearing with the WDNR in connection with the administrative order issued in this matter, which was granted. The Sierra Club has withdrawn the contested case hearing request, thereby concluding this matter.
Consent
Decrees
Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam
In November 2009, the EPA issued a NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013.
The final Consent Decree includes:
•
the
installation of emission control technology, including ReACT™ on Weston 3,
•
changed operating conditions (including refueling, repowering, and/or retirement of units),
•
limitations on plant emissions,
•
beneficial environmental projects totaling $6.0 million,
and
•
a civil penalty of $1.2 million.
The Consent Decree also contains requirements to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, WPS retired Weston Unit 1 and Pulliam Units 5 and 6. In March 2016, WPS submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel, and also proposed revisions to the list of beneficial environmental projects required by the Consent Decree. These proposed revisions were approved by the EPA in
May 2016. The revisions to the environmental projects are not expected to materially impact the overall costs noted above.
WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant related to Weston Unit 1 and Pulliam Units 5 and 6 starting June 1, 2015, and concluding by 2023. Therefore, in June 2015, WPS recorded a regulatory asset of $11.5 million for the undepreciated book value. In addition, WPS received approval from the PSCW in its rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty.
Also, in May 2010, WPS received from
the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2016. It is unknown whether the Sierra Club will take further action in the future.
Joint Ownership Power Plants Consent Decree – Columbia and Edgewater
In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the
other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS,
along with Wisconsin Power and Light, Madison Gas and Electric, and WE entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. WE paid an immaterial portion of the assessed penalty but has no further obligations under the Consent Decree.
The final Consent Decree includes:
•
the installation of emission control technology, including scrubbers at the Columbia plant,
•
changed
operating conditions (including refueling, repowering, and/or retirement of units),
•
limitations on plant emissions,
•
beneficial environmental projects, with WPS's portion totaling $1.3 million, and
•
WPS's portion of a civil penalty and legal fees
totaling $0.4 million.
The Consent Decree contains a requirement to, among other things, refuel, repower, or retire Edgewater Unit 4, of which WPS is a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available.
NOTE 19—FAIR
VALUE MEASUREMENTS
The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs
in the MISO Energy Markets. See Note 20, Derivative Instruments, for more information.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:
(in millions)
2016
2015
2014
Balance
at the beginning of the period
$
3.6
$
7.0
$
3.5
Realized and unrealized (losses) gains
(0.2
)
1.3
—
Purchases
15.2
3.9
15.6
Sales
(0.2
)
(0.1
)
—
Settlements
(13.3
)
(11.9
)
(12.1
)
Acquisition
of Integrys
—
(1.3
)
—
Transfers out of level 3
—
4.7
—
Balance
at the end of the period
$
5.1
$
3.6
$
7.0
Unrealized gains and losses
on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the income statements.
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31:
2016
2015
(in
millions)
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Preferred stock
$
30.4
$
28.8
$
30.4
$
27.3
Long-term
debt, including current portion *
$
9,285.8
$
9,818.2
$
9,221.9
$
9,681.0
*
The
carrying amount of long-term debt excludes capital lease obligations of $29.6 million and $59.9 million at December 31, 2016 and
The
following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
Includes
cash collateral received of $4.4 million at December 31, 2016, and cash collateral posted of $19.5 million at December 31, 2015.
At December 31, 2016 and 2015, we had posted cash collateral of $16.4 million and $42.3 million, respectively, in our margin accounts. At December 31, 2016, we had also received cash collateral of $4.4
million in our margin accounts. We had not received any cash collateral at December 31, 2015. Certain of our derivative and non-derivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a net liability position at December 31, 2016 and 2015 was $0.2 million and $23.8 million,
respectively. At December 31, 2016 and 2015, we had not posted any cash collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at December 31, 2016, we would not have been required to post any collateral. At December 31, 2015, we would have been required to post collateral of $18.0 million.
During 2015, we settled several forward interest rate swap agreements entered into to mitigate interest risk associated with
the issuance of $1.2 billion of long-term debt related to the acquisition of Integrys. As these agreements qualified for cash flow hedging accounting treatment, the proceeds of $19.0 million received upon settlement of these agreements were deferred in accumulated other comprehensive income and are being amortized as a decrease to interest expense over the periods in which the interest costs are recognized in earnings.
During 2016, we reclassified $2.2 million of forward interest rate swap agreement settlements deferred in accumulated other comprehensive income as a reduction to interest expense. We estimate that during the next twelve months, $2.2 million
will be reclassified from accumulated other comprehensive income as a reduction to interest expense.
NOTE 21—VARIABLE INTEREST ENTITIES
In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis. This ASU focuses on the consolidation analysis for companies that are required to evaluate whether they should consolidate certain legal entities. It emphasizes the risk of loss when determining a controlling financial interest and amends the guidance for assessing how related party relationships affect the consolidation analysis of variable interest entities. We adopted the standard upon its effective date in the first quarter of 2016, and our adoption resulted in no
changes to our disclosures or financial statement presentation.
The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.
We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements
provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.
American Transmission Company
We
own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment. See Note 4, Investment in American Transmission Company, for more information.
The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At December 31, 2016,
and 2015, our equity investment was $1,443.9 million and $1,380.9 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $28.7 million and $28.3 million of accounts payable due to ATC at December 31, 2016, and 2015, respectively, for network transmission services.
Purchased Power Agreement
We have identified a purchased power agreement that represents
a variable interest. This agreement is for 236 MW of firm capacity from a natural 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 five years. We have examined the risks of the entity, including operations, 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 $85.3 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 this contract for the years ended December 31, 2016, 2015, and 2014, were $54.2 million, $53.6 million, and $53.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.
NOTE
22—REGULATORY ENVIRONMENT
Wisconsin Electric Power Company
2015 Wisconsin Rate Order
In May 2014, WE applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015:
•
A net bill increase related to non-fuel costs for WE's retail electric customers of approximately $2.7
million (0.1%) in 2015. This amount reflected WE's receipt of SSR payments from MISO that were higher than WE 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 a Treasury Grant that WE received in connection with its biomass facility. The majority of this $26.6 million was returned to customers in the form of bill credits in 2015.
•
A rate increase for WE's retail electric customers of $26.6 million (0.9%)
in 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.
•
A rate decrease of $10.7 million (-2.4%) for WE's natural gas customers in 2015, with no rate adjustment
in 2016.
•
A rate increase of approximately $0.5 million (2.0%) for WE's Downtown Milwaukee (Valley) steam utility customers in 2015, with no rate adjustment in 2016.
•
A rate increase of approximately $1.2 million (7.3%) for WE's Milwaukee County steam utility customers in 2015, with no
rate adjustment in 2016. As a result of the sale of the MCPP, WE no longer has any Milwaukee County steam utility customers. See Note 3, Dispositions, for more information about the sale of the MCPP.
The authorized ROE for WE was set at 10.2%, and its common equity component remained at an average of 51%. The PSCW order reaffirmed the deferral of WE's transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored
using a 2% tolerance window. The PSCW approved a change in rate design for WE, which included higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues WE will receive under the PIPP SSR agreements. Under escrow accounting, WE records SSR revenues of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is deferred
and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference is deferred and will be recovered from customers with interest, in a future rate case.
In January 2015, certain parties appealed a portion of the PSCW's final decision adopting WE's specific rate design changes, including new charges for customer-owned generation within its service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in WE's rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate
case were impacted by the Dane County Circuit Court order.
Earnings Sharing Agreement
In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for WE. See Note 2, Acquisitions, for more information on this earnings sharing mechanism.
2013 Wisconsin Rate Order
In March 2012, WE initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved the following rate adjustments, effective January 1, 2013:
•
A
net bill increase related to non-fuel costs for WE's retail electric customers of approximately $70.0 million (2.6%) in 2013. This amount reflected an offset of approximately $63.0 million (2.3%) for bill credits related to the proceeds of the Treasury Grant, including associated tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133.0 million (4.8%) in 2013.
•
An electric rate increase for WE's electric customers
of approximately $28.0 million (1.0%) in 2014, and a $45.0 million (-1.6%) reduction in bill credits.
•
Recovery of a forecasted increase in fuel costs of approximately $44.0 million (1.6%) in 2013.
•
A rate decrease of approximately $8.0
million (-1.9%) for WE's natural gas customers in 2013, with no rate adjustment in 2014. The WE rates reflected a $6.4 million reduction in bad debt expense.
•
An increase of approximately $1.3 million (6.0%) for WE's Downtown Milwaukee (Valley) steam utility customers in 2013 and another $1.3 million (6.0%) in 2014.
•
An
increase of approximately $1.0 million (7.0%) in 2013 and $1.0 million (6.0%) in 2014 for WE's Milwaukee County steam utility customers.
Based on the PSCW order, the authorized ROE for WE remained at 10.4%. In addition, the PSCW approved escrow accounting treatment for the Treasury Grant. The PSCW also determined the construction costs for the ERGS units were prudently incurred, and it approved the recovery of the majority of these costs in rates.
Wisconsin Gas LLC
2015
Wisconsin Rate Order
In May 2014, WG applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved rate increases of $17.1 million (2.6%) in 2015 and $21.4 million (3.2%) in 2016 for WG's natural gas customers. These rate adjustments were effective January 1, 2015. The authorized ROE for WG was set at 10.3%. The PSCW also authorized an increase in WG's common equity component to an average of 49.5%.
Earnings Sharing Agreement
In
May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for WG. See Note 2, Acquisitions, for more information on this earnings sharing mechanism.
In March 2012, WG initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved a rate decrease of approximately $34.0 million (-5.5%) for WG’s natural gas customers in 2013, with no rate adjustment in 2014. The WG rates reflected a $43.8 million reduction in bad debt expense. The rate adjustments were effective January 1, 2013, and the authorized ROE for WG remained at 10.5%.
Wisconsin Public
Service Corporation
2016 Wisconsin Rate Order
In April 2015, WPS initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order for WPS, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0%, authorized a net retail electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). The decrease in retail electric rates was due to
lower monitored fuel costs in 2016 compared to 2015. Absent the adjustment for electric fuel costs, WPS would have realized an electric rate increase. Based on the order, the PSCW allowed WPS to escrow ATC and MISO network transmission expenses through 2016. In addition, future SSR payments will continue to be escrowed until a future rate proceeding. The order directed WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which required WPS to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.
In March 2016, WPS requested extensions from the
PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, WPS also requested to extend through 2017 the previously approved deferral of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of WPS's current large commercial and industrial customers who entered into a service agreement with WPS under Real Time Market Pricing prior to April 15, 2016. These requests were approved by the PSCW in June 2016. The amounts deferred related to these items as of December 31, 2016, were not material.
2015
Wisconsin Rate Order
In April 2014, WPS initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% ROE. The order authorized a common equity component average of 50.28%. The PSCW approved a change in rate design for WPS, which included higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January
1, 2014.
The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million. In addition, 2015 rates included approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, WPS would have realized an electric rate decrease. In addition, WPS received approval from the PSCW to defer and
amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 18, Commitments and Contingencies, for more information. The PSCW allowed WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS deferred as a regulatory asset the difference between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window.
The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative
impact of decoupling refunds to and collections from customers. In 2015 rates, WPS refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, WPS would have realized a retail natural gas rate increase.
In October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition
of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflected a 10.2% ROE and a common equity component average of 50.48%. The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, WPS will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. WPS also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting
with the actual retirement date, June 1, 2015, and concluding by 2023. As a result of the formation of UMERC, WPS transferred the deferrals mentioned above, as well as its customers and property, plant, and equipment located in the Upper Peninsula of Michigan to the new utility, effective January 1, 2017. Therefore, the terms and conditions of this rate order are now applicable to UMERC. UMERC will not seek an increase to legacy WPS retail electric base rates that would become effective prior to January 1, 2018.
The Peoples Gas Light and Coke Company and North Shore Gas Company
Base Rate Freeze
In
June 2015, the ICC approved the acquisition of Integrys subject to the condition that PGL and NSG will not seek increases of their base rates that would become effective earlier than two years after the close of the acquisition.
Illinois Investigations
In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's SMP. This matter is still pending.
In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of
its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops commenced in January 2016 and were completed in March 2016. The ICC staff submitted a report on the workshop process in May 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including what the target end date for the program should be. This proceeding is expected to result in a final order by the ICC in 2017. We are currently unable to determine what, if any, long-term impact there will be on PGL's SMP.
2015 Illinois Rate Order
In February 2014, PGL and NSG initiated a rate proceeding with the ICC. In January 2015, the
ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC issued an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflected a 9.05% ROE and a common equity component average of 50.33%. The rates for NSG reflected a 9.05% ROE and a common equity component
average of 50.48%. The rate order allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL recovers a return on certain investments and depreciation expense through the Qualifying Infrastructure Plant rider, and accordingly, such costs are not subject to PGL's rate order.
PGL's Qualifying Infrastructure Plant rider allows for the recovery of costs incurred related to investments in qualifying infrastructure plant. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudence. No schedule has been set for the 2015 reconciliation. The ALJ has placed the 2014 reconciliation on stay, pending resolution of several open matters related to PGL's SMP. Although schedules have not been set for the reconciliations, discovery has
continued for both the 2014 and 2015 reconciliations. As of December 31, 2016, there can be no assurance that all costs incurred under the Qualifying Infrastructure Plant rider will be recoverable.
In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, which is expected to be effective in the first quarter of 2017. The order authorized a retail natural gas rate increase of $6.8 million (3.0%). The rates reflect a 9.11% ROE and a common equity component average of 50.32%. The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another
three years. The final approved rate increase was lower than the interim rates collected from customers during 2016. Therefore, as of December 31, 2016, we estimate that $3.0 million will be refunded to MERC's customers during 2017.
2015 Minnesota Rate Case
In September 2013, MERC initiated a rate proceeding with the MPUC. In October 2014, the MPUC issued a final written order for MERC, effective April 1, 2015. The order authorized a retail natural gas rate increase of $7.6 million. The rates reflected a 9.35%
ROE and a common equity component average of 50.31%. The order approved a deferral of customer billing system costs, for which recovery was requested in MERC's 2016 rate case. A decoupling mechanism with a 10% cap remains in effect for MERC's residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, MERC refunded $4.7 million to customers in 2015.
Michigan Gas Utilities Corporation
2016 Michigan Rate Order
In June 2015, MGU initiated a rate proceeding
with the MPSC. In December 2015, the MPSC issued a final written order, approving a settlement agreement for MGU. The order, which reflects a 9.9% ROE and a common equity component average of 52.0%, authorized a retail natural gas rate increase of $3.4 million (2.4%), effective January 1, 2016. Based on the settlement agreement, MGU discontinued the use of its decoupling mechanism after December 31, 2015. In addition, since bonus depreciation was in effect in 2016, MGU established a regulatory liability for the resulting cost savings and must refund the liability in its next general rate case.
Upper
Michigan Energy Resources Corporation
In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan and it became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets previously held by WE and WPS located in the Upper Peninsula of Michigan.
In August 2016, we entered into an agreement with the Tilden Mining Company (Tilden) under which it will purchase electric power from UMERC for its iron ore mine for 20 years The agreement also calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation
located in the Upper Peninsula of Michigan. On January 30, 2017, UMERC filed an application with the MPSC for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is approximately $265 million ($275 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain a customer of WE until this new generation
begins commercial operation.
NOTE 23—OTHER INCOME, NET
Total other income, net was as follows for the years ended December 31:
At December 31, 2016, we reported six
segments, which are described below.
•
The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan that were transferred to UMERC effective January 1, 2017.
•
The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG.
•
The
other states segment includes the natural gas utility and non-utility operations of MERC and MGU.
•
The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions.
•
The We Power segment includes our nonregulated entity that owns and leases generating
facilities to WE.
•
The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF. The sale of ITF was completed in the first quarter of 2016. In the second quarter of 2016, we sold certain assets of Wisvest. See Note 3, Dispositions, for more information on these sales.
All of our operations and assets are located within the United States. The following tables show summarized financial
information related to our reportable segments for the years ended December 31, 2016, 2015, and 2014.
Regulated Operations
2016
(in millions)
Wisconsin
Illinois
Other States
Electric Transmission
Total Regulated
Operations
We
Power
Corporate and Other
Reconciling
Eliminations
WEC Energy Group Consolidated
External revenues
$
5,805.4
$
1,242.2
$
376.5
$
—
$
7,424.1
$
24.9
$
23.3
$
—
$
7,472.3
Intersegment
revenues
0.3
—
—
—
0.3
423.3
—
(423.6
)
—
Other
operation and maintenance
2,025.4
485.1
110.1
—
2,620.6
4.3
(15.8
)
(423.6
)
2,185.5
Depreciation
and amortization
496.6
134.0
21.1
—
651.7
68.3
42.6
—
762.6
Operating
income (loss)
1,027.0
239.6
49.9
—
1,316.5
375.6
(10.0
)
—
1,682.1
Equity
in earnings of transmission affiliate
—
—
—
146.5
146.5
—
—
—
146.5
Interest
expense
180.9
38.9
8.5
—
228.3
62.1
120.9
(8.6
)
402.7
Capital
expenditures
910.9
293.2
59.5
—
1,263.6
62.3
97.8
—
1,423.7
Total
assets *
21,730.7
5,714.6
995.1
1,476.9
29,917.3
2,777.1
778.0
(3,349.2
)
30,123.2
*
Total
assets at December 31, 2016 reflect an elimination of $2,029.5 million for all lease activity between We Power and WE.
Total
assets at December 31, 2015 reflect an elimination of $2,105.3 million for all lease activity between We Power and WE.
Regulated Operations
2014 (in
millions)
Wisconsin
Illinois
Other States
Electric Transmission
Total Regulated
Operations
We Power
Corporate and Other
Reconciling
Eliminations
WEC
Energy Group Consolidated
External revenues
$
4,932.1
$
—
$
—
$
—
$
4,932.1
$
55.7
$
9.3
$
—
$
4,997.1
Intersegment
revenues
9.2
—
—
—
9.2
383.4
—
(392.6
)
—
Other
operation and maintenance
1,462.7
—
—
—
1,462.7
4.4
33.0
(387.7
)
1,112.4
Depreciation
and amortization
323.2
—
—
—
323.2
66.7
1.5
—
391.4
Operating
income (loss)
770.2
—
—
—
770.2
368.0
(26.1
)
—
1,112.1
Equity
in earnings of transmission affiliate
—
—
—
66.0
66.0
—
—
—
66.0
Interest
expense
127.6
—
—
—
127.6
64.6
48.8
(0.7
)
240.3
Capital
expenditures
715.0
—
—
—
715.0
41.0
5.2
—
761.2
Total
assets *
14,403.8
—
—
424.1
14,827.9
2,789.9
253.3
(2,966.1
)
14,905.0
*
Total
assets at December 31, 2014 reflect an elimination of $2,172.9 million for all lease activity between We Power and WE.
NOTE 25—QUARTERLY FINANCIAL INFORMATION (Unaudited)
(in
millions, except per share amounts)
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Total
2016
Operating
revenues
$
2,194.8
$
1,602.0
$
1,712.5
$
1,963.0
$
7,472.3
Operating
income
589.3
332.1
399.0
361.7
1,682.1
Net
income attributed to common shareholders
346.2
181.4
217.0
194.4
939.0
Earnings
per share *
Basic
$
1.10
$
0.57
$
0.69
$
0.62
$
2.98
Diluted
1.09
0.57
0.68
0.61
2.96
2015
Operating
revenues
$
1,387.9
$
991.2
$
1,698.7
$
1,848.3
$
5,926.1
Operating
income
358.8
165.8
345.7
380.2
1,250.5
Net
income attributed to common shareholders
195.8
80.9
182.5
179.3
638.5
Earnings
per share *
Basic
$
0.87
$
0.36
$
0.58
$
0.57
$
2.36
Diluted
0.86
0.35
0.58
0.57
2.34
*
Earnings
per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.
Due
to various factors, including the acquisition of Integrys on June 29, 2015, the quarterly results of operations are not necessarily comparable.
NOTE 26—NEW ACCOUNTING PRONOUNCEMENTS
Revenue Recognition
In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core
principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.
We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. This method will result in a cumulative-effect adjustment that will be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. Disclosures in 2018 will include a reconciliation of results under the new revenue guidance
compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.
We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider tariff sales at our regulated utilities, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry, including
the impacts of the new guidance on our ability to recognize revenue for certain contracts where collectability is uncertain and the accounting for contributions in aid of construction (CIAC). We currently account for CIAC funds received from customers and/or developers outside of revenue, as a reduction to property, plant, and equipment. The final resolution of these issues could impact our current accounting policies and revenue recognition.
Classification and Measurement of Financial Instruments
In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December
15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We are currently assessing the effects this guidance may have on our financial statements.
Leases
In
February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements.
Stock-Based Compensation
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning
after December 15, 2016. Under this ASU, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, the tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur, and excess tax benefits are recognized in the current period regardless of whether the benefit reduces taxes payable. On the cash flow statement, excess tax benefits are classified along with other income tax cash flows as an operating activity, and cash paid by an employer when directly
withholding shares for tax purposes is classified as a financing activity. We adopted this guidance effective January 1, 2017, and do not believe it will have a significant impact on our financial statements.
Financial Instruments Credit Losses
In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods
within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.
Classification of Certain Cash Receipts and Cash Payments
In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning
after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We are currently assessing the effects this guidance may have on our financial statements.
Restricted Cash
In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-the period
and end-of-the period total amounts shown on the statements of cash flows. We do not believe the adoption of this guidance will have a significant impact on our financial statements.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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 our and our 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 our and our subsidiaries' internal control over financial reporting was effective
as of December 31, 2016.
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.
Changes in Internal Control Over Financial Reporting
There
were no changes in our internal control over financial reporting during the fourth quarter of 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
For Deloitte & Touche LLP's Report of Independent Registered Public Accounting Firm, attesting to the effectiveness of our internal controls over financial reporting, see Section A of Item 8.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE OF THE REGISTRANT
The
information under "Proposal 1: Election of Directors – Terms Expiring in 2018", "Section 16(a) Beneficial Ownership Reporting Compliance", "Board of Directors – 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?", "Board of Directors – Board Committees – Are the Audit and Oversight, Corporate Governance, and Compensation Committees comprised solely of independent directors?", "Board of Directors – 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 4, 2017
(the "2017 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.wecenergygroup.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.wecenergygroup.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, Wisconsin53201.
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 2017 Annual Meeting Proxy Statement is incorporated herein by reference.
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 Energy Group Common Stock Ownership" in the 2017 Annual Meeting Proxy Statement.
Equity Compensation Plan Information
The following table sets forth information about our equity compensation plans as of December 31, 2016:
Plan
Type
Number of Securities
to be Issued
Upon Exercise of
Outstanding Options,
Warrants, and Rights
(a)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants, and Rights
(b)
Number of Securities
Remaining Available for Future Issuance Under Equity Compensation Plans
(Excluding Shares Reflected in Column (a))
(c)
Equity Compensation Plans Approved by Security Holders
5,122,775
$
38.95
28,250,754
*
Equity
Compensation Plans Not Approved by Security Holders
N/A
N/A
N/A
Total
5,122,775
$
38.95
28,250,754
*
Includes
shares available for future issuance under our 1993 Omnibus Stock Incentive Plan, amended and restated effective May 5, 2011, all of which could be granted as awards of stock options, stock appreciation rights, performance units, restricted stock, or other stock based awards.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information under "Board of Directors – Board Independence – Who are the independent directors?", "Board of Directors – Board Independence – What are the Board's standards of independence?", "Board of Directors – 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 2017 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.wecenergygroup.com.
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 2017 Annual Meeting Proxy Statement is incorporated herein by reference.
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
For Parent Company only presentation, investments 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 WEC Energy Group, Inc. appearing in this Annual Report on Form 10-K.
Dividends received from our subsidiaries during the years ended December 31 were as follows:
(in millions)
2016
2015
2014
WE
$
455.0
$
240.0
$
390.0
WG
75.0
30.0
33.0
We
Power
197.9
262.8
297.0
ATC Holding LLC
6.5
6.0
—
Total
$
734.4
$
538.8
$
720.0
NOTE
3—LONG-TERM DEBT
The following table shows the future maturities of our long-term debt outstanding as of December 31, 2016:
(in millions)
2018
$
300.0
2020
400.0
Thereafter
1,200.0
Total
$
1,900.0
WECC
is our subsidiary and has $50.0 million of long-term notes outstanding. In a Support Agreement between WECC and us, we agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value as of December 31:
2016
2015
(in
millions)
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Long-term debt
$
1,890.0
$
1,906.1
$
1,887.2
$
1,900.7
The
carrying value of cash and cash equivalents, accounts receivable, short-term notes 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 is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for our bond rating and the present value of future cash flows.
NOTE 4—SUPPLEMENTAL CASH FLOW INFORMATION
(in
millions)
2016
2015
2014
Cash (paid) for interest
$
(89.6
)
$
(68.8
)
$
(44.4
)
Cash
(paid) received for income taxes, net
(62.9
)
242.9
95.1
During 2016, we settled a $40.0 million short-term note payable to our subsidiary, Wisvest, through a non-cash capital contribution.
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.
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to WEC Energy Group. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)
Number
Exhibit
2
Plan
of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.1*
Agreement and Plan of Merger, dated as of June 22, 2014, by and between Wisconsin Energy Corporation (n/k/a WEC Energy Group, Inc.) and Integrys Energy Group, Inc. (Exhibit 2.1 to Wisconsin Energy Corporation's 06/22/14 Form
8-K.)
2.2*
Stock Purchase Agreement, dated as of July 29, 2014, between Integrys Energy Group, Inc. and Exelon Generation Company, LLC., as amended on October 31, 2014. (Exhibit 2 under File No. 1-11337, Integrys Energy Group's 09/30/14 Form 10-Q.)
Restated Articles of Incorporation of WEC Energy Group, Inc., as amended effective May 21, 2012. (Exhibit 3.1 to Wisconsin Energy Corporation's 06/30/12 Form 10-Q.)
3.2*
Articles
of Amendment to the Restated Articles of Incorporation of WEC Energy Group, Inc., as amended. (Exhibit 3.1 to WEC Energy Group's 06/29/15 Form 8-K.)
3.3*
Bylaws of WEC Energy Group, Inc., as amended to October 20, 2016.
(Exhibit 3.1 to WEC Energy Group's 10/20/16 Form 8-K.)
4
Instruments defining the rights of security holders, including indentures
4.1*
Reference
is made to Article III of the Restated Articles of Incorporation and the Bylaws of WEC Energy Group, Inc. (Exhibits 3.1 and 3.3 to WEC Energy Group's 12/31/16 Form 10-K.)
4.2*
Replacement Capital Covenant, dated May 11, 2007,
by Wisconsin Energy Corporation for the benefit of certain debtholders named therein. (Exhibit 4.2 to Wisconsin Energy Corporation's 05/08/07 Form 8-K.)
4.3*
Amendment to Replacement Capital Covenant, dated as of June 29, 2015. (Exhibit 4.1 to Wisconsin Energy Corporation's 06/29/15 Form 8-K.)
Indenture for Debt Securities of Wisconsin Electric Power Company (the "Wisconsin Electric Indenture"), dated December 1, 1995. (Exhibit (4)-1 under File No. 1-1245,
WE's 12/31/95 Form 10-K.)
4.5*
Securities Resolution No. 1 of Wisconsin Electric under the Wisconsin Electric Indenture, dated December 5, 1995. (Exhibit (4)-2 under File No. 1-1245, WE's 12/31/95 Form 10-K.)
4.6*
Securities
Resolution No. 3 of Wisconsin Electric under the Wisconsin Electric Indenture, dated May 27, 1998. (Exhibit (4)-1 under File No. 1-1245, WE’s 06/30/98 Form 10-Q.)
4.7*
Securities Resolution No. 5 of Wisconsin Electric
under the Wisconsin Electric Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to Wisconsin Electric's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)
Securities
Resolution No. 7 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 2, 2006. (Exhibit 4.1 under File No. 1-1245, WE's 11/02/06 Form 8-K.)
4.9*
Securities Resolution No. 10 of Wisconsin
Electric under the Wisconsin Electric Indenture, dated as of December 8, 2009. (Exhibit 4.1 under File No. 1-1245, WE's 12/08/09 Form 8-K.)
4.10*
Securities Resolution No. 11 of Wisconsin Electric under the Wisconsin
Electric Indenture, dated as of September 7, 2011. (Exhibit 4.1 under File No. 1-1245, WE's 09/07/11 Form 8-K.)
4.11*
Securities Resolution No. 12 of Wisconsin Electric under the Wisconsin Electric Indenture,
dated as of December 5, 2012. (Exhibit 4.1 under File No. 1-1245, WE's 12/05/12 Form 8-K.)
4.12*
Securities Resolution No. 13 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of June
10, 2013. (Exhibit 4.1 under File No. 1-1245, WE's 06/10/13 Form 8-K.)
4.13*
Securities Resolution No. 14 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 12, 2014. (Exhibit 4.1 under
File No. 1-1245, WE's 05/12/14 Form 8-K.)
4.14*
Securities Resolution No. 15 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 14, 2015. (Exhibit 4.1 to WE's 05/14/15 Form 8-K.)
4.15*
Securities
Resolution No. 16 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 13, 2015. (Exhibit 4.1 under File No. 1-1245, WE's 11/13/15 Form 8-K.)
4.16*
Indenture
for Debt Securities of Wisconsin Energy Corporation (the "Wisconsin Energy Indenture"), dated as of March 15, 1999, between WEC Energy Group and The Bank of New York Mellon Trust Company, N.A. (as successor to First National Bank of Chicago), as Trustee. (Exhibit 4.46 to Wisconsin Energy Corporation's 03/25/99 Form 8-K.)
4.17*
Securities
Resolution No. 4 of Wisconsin Energy Corporation under the Wisconsin Energy Indenture, dated as of March 17, 2003. (Exhibit 4.12 filed with Post-Effective Amendment No. 1 to Wisconsin Energy Corporation's Registration Statement on Form S-3 (File No. 333-69592), filed March 20, 2003.)
4.18*
Securities
Resolution No. 5 of Wisconsin Energy Corporation under the Wisconsin Energy Indenture, dated as of May 8, 2007. (Exhibit 4.1 to Wisconsin Energy Corporation's 05/08/07 Form 8-K.)
4.19*
Securities Resolution No. 6 of WEC Energy Group under the Wisconsin Energy Indenture,
dated as of June 4, 2015. (Exhibit 4.1 to Wisconsin Energy Corporation's 06/04/15 Form 8-K.)
4.20*
Indenture, dated as of December 1, 1998, between Wisconsin Public Service Corporation ("WPS") and U.S. Bank National Association (successor to Firstar
Bank Milwaukee, N.A., National Association) (Exhibit 4A to Form 8-K filed December 18, 1998); First Supplemental Indenture, dated as of December 1, 1998, between WPS and Firstar Bank Milwaukee, N.A., National Association (Exhibit 4C to Form 8-K filed December 18, 1998); Fifth Supplemental Indenture, dated as of December 1, 2006, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 30, 2006); Seventh Supplemental Indenture,
dated as of November 1, 2007, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 16, 2007); Ninth Supplemental Indenture, dated as of December 1, 2012, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed November 29, 2012); Tenth Supplemental Indenture, dated as of November 1, 2013, by and between WPS and U.S. Bank Nation Association (Exhibit 4.1 to Form 8-K filed November 18, 2013); Eleventh Supplemental Indenture,
dated as of December 4, 2015, by and between WPS and U.S. Bank National Association (Exhibit 4.1 to Form 8-K filed December 4, 2015). All references to periodic reports are to those of WPS (File No. 1-3016).
Certain agreements and instruments with respect
to unregistered long-term debt not exceeding 10 percent of the total assets of the Registrant and its subsidiaries on a consolidated basis have been omitted as permitted by related instructions. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments.
WEC Energy Group Supplemental Pension Plan, Amended and Restated Effective as of January 1, 2017.** See Note.
10.2*
Legacy
Wisconsin Energy Corporation Executive Deferred Compensation Plan, Amended and Restated as of January 1, 2016. (Exhibit 10.2 to WEC Energy Group's 12/31/15 Form 10-K.)** See Note.
WEC
Energy Group Executive Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017. ** See Note.
10.4
Legacy Wisconsin Energy Corporation Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017.** See Note.
10.5
WEC
Energy Group Directors' Deferred Compensation Plan, Amended and Restated Effective as of January 1, 2017. ** See Note.
10.6
WEC Energy Group Non-Qualified Retirement Savings Plan, Amended and Restated Effective as of January 1, 2017. ** See Note.
10.7*
WEC
Energy Group Short-Term Performance Plan, as amended and restated effective as of January 1, 2016. (Exhibit 10.2 to WEC Energy Group's 12/3/15 Form 8-K.)** See Note.
10.8*
Wisconsin Energy Corporation 2014 Rabbi Trust by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 23, 2015, regarding the trust established
to provide a source of funds to assist in meeting the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.13 to Wisconsin Energy Corporation's 12/31/14 Form 10K.)** See Note.
10.9*
Amended and Restated Senior Officer Employment and Non-Compete
Agreement between Wisconsin Energy Corporation and Gale E. Klappa, dated as of December 29, 2008. (Exhibit 10.25 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
10.10*
Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen
L. Leverett, dated as of December 30, 2008. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
10.11*
Terms of Employment for J. Patrick Keyes. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/12 Form 10-Q.)** See Note.
10.12*
Letter
Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of December 20, 2010. (Exhibit 10.20 to Wisconsin Energy Corporation's 12/31/12 Form 10-K.)** See Note.
10.13*
Amendment to the Letter Agreement by and between Wisconsin Energy Corporation and J. Patrick Keyes, dated as of August 15, 2011. (Exhibit 10.21 to Wisconsin
Energy Corporation's 12/31/12 Form 10-K.)** See Note.
10.14*
Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/12 Form 10-Q.)** See Note.
10.15*
Letter
Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q.)** See Note.
10.16*
Letter Agreement by and between Wisconsin Energy Corporation and Joseph Kevin Fletcher, dated as of August
17, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/11 Form 10-Q.)** See Note.
10.17*
WEC Energy Group 1993 Omnibus Stock Incentive Plan, Amended and Restated effective as of January 1, 2016 (Exhibit 10.19 to WEC Energy Group's 12/31/15 Form 10-K.)** See Note.
10.18*
2005
Terms and Conditions Governing Non-Qualified Stock Option Award under 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/28/04 Form 8-K.)** See Note.
10.19*
Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit
10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q.)** See Note.
10.20*
Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/01/10 Form 8-K.)** See Note.
Wisconsin
Energy Corporation Terms and Conditions Governing Director Restricted Stock Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 01/19/12 Form 8-K.)** See Note.
10.22*
2016 WEC Energy Group Terms and Conditions Governing Director Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.24 to WEC
Energy Group's 12/31/15 Form 10-K.)** See Note.
10.23*
Director Restricted Stock Award Terms and Conditions under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.2 to WEC Energy Group's 12/01/16 Form 8-K.)** See Note.
10.24*
WEC
Energy Group Performance Unit Plan, amended and restated effective as of January 1, 2017. (Exhibit 10.1 to WEC Energy Group's 12/01/16 Form 8-K.)** See Note.
10.25*
Wisconsin Energy Corporation Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan, approved December
4, 2014. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/04/14 Form 8-K.)** See Note.
10.26*
2016 WEC Energy Group Restricted Stock Award Terms and Conditions governing awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.27 to WEC Energy Group's 12/31/15 Form 10-K.)** See Note.
10.27*
Wisconsin
Energy Corporation Terms and Conditions Governing Non-Qualified Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan, approved December 4, 2014. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/04/14 Form 8-K.)** See Note.
10.28*
2016 WEC Energy Group Terms and Conditions Governing Non-Qualified
Stock Option Award for option awards under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.29 to WEC Energy Group's 12/31/15 Form 10-K.)** See Note.
10.29*
Port Washington I Facility Lease Agreement between Port Washington Generating Station, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to W's 06/30/03 Form 10-Q (File No. 001-01245).)
10.30*
Port
Washington II Facility Lease Agreement between Port Washington Generating Station, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.8 to WE's 06/30/03 Form 10-Q (File No. 001-01245).)
10.31*
Elm Road I Facility Lease Agreement between Elm Road Generating
Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
10.32*
Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November
9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
10.33*
Point Beach Nuclear Plant Power Purchase Agreement between FPL Energy Point Beach, LLC and Wisconsin Electric Power Company, dated as of December 19, 2006 (the "PPA"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08
Form 10-Q.)
10.34*
Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K.)
10.35*
Terms
and Conditions for July 31, 2015 Special Restricted Stock Award. (Exhibit 10.1 to WEC Energy Group's 6/30/15 Form 10-Q.)** See Note.
10.36*
Integrys Energy Group, Inc. Deferred Compensation Plan, as Amended and Restated Effective January 1, 2016. (Exhibit
10.1 to WEC Energy Group's 06/30/16 Form 10-Q.)** See Note.
10.37*
Integrys Energy Group, Inc. Pension Restoration and Supplemental Retirement Plan, as Amended and Restated Effective January 1, 2016. (Exhibit 10.2 to WEC Energy Group's 06/30/16 Form 10-Q.)** See Note.
10.38*
PELLC
Directors Deferred Compensation Plan as amended and restated April 7, 2004. (Exhibit 10(c) under File No. 1-5540, PELLC's 06/30/05 Form 10-Q.)** See Note.
Amended
and Restated Trust under PELLC Directors Deferred Compensation Plan, Directors Stock and Option Plan, Executive Deferred Compensation Plan and Supplemental Retirement Benefit Plan, dated as of August 13, 2003. (Exhibit 10(a) under File No. 1-5540, PELLC's 09/30/03 Form 10-Q.)** See Note.
10.40*
Amendment
Number One to the Amended and Restated Trust under PELLC Directors Deferred Compensation Plan, Directors Stock and Option Plan, Executive Deferred Compensation Plan and Supplemental Retirement Benefit Plan, dated as of July 24, 2006. (Exhibit 10(e) under File No. 1-5540, PELLC's 09/30/06 Form 10-Q.)** See Note.
Note: Two asterisks (**) identify management
contracts and executive compensation plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of Form 10-K.
