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EX-32.2 - WISCONSIN ELECTRIC EXHIBIT 32.2 - WISCONSIN ELECTRIC POWER COwepco12312015ex322.htm
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EX-32.1 - WISCONSIN ELECTRIC EXHIBIT 32.1 - WISCONSIN ELECTRIC POWER COwepco12312015ex321.htm
EX-31.1 - WISCONSIN ELECTRIC EXHIBIT 31.1 - WISCONSIN ELECTRIC POWER COwepco12312015ex311.htm
EX-31.2 - WISCONSIN ELECTRIC EXHIBIT 31.2 - WISCONSIN ELECTRIC POWER COwepco12312015ex312.htm
EX-23.1 - WISCONSIN ELECTRIC EXHIBIT 23.1 - WISCONSIN ELECTRIC POWER COwepco12312015ex231.htm

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-K


(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ___________________

Commission
File Number
 
Registrant; State of Incorporation;
Address; and Telephone Number
 
IRS Employer
Identification No.
 
 
 
 
 
001-01245
 
WISCONSIN ELECTRIC POWER COMPANY
 
39-0476280
 
 
(A Wisconsin Corporation)
231 West Michigan Street
P. O. Box 2046
Milwaukee, WI 53201
414-221-2345
 
 

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:
Serial Preferred Stock, 3.60% Series, $100 Par Value
Six Per Cent. Preferred Stock, $100 Par Value

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. [X]

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 [ ]
Accelerated filer [ ]
 
 
Non-accelerated filer [X]
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]

As of June 30, 2015 (and currently), all of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.

 
State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant.
 
None.

 
Number of shares outstanding of each class of common stock, as of
 
 
January 31, 2016
 

Common Stock, $10 par value, 33,289,327 shares outstanding

Documents incorporated by reference:

Portions of Wisconsin Electric Power Company's Definitive information statement on Schedule 14C for its Annual Meeting of Stockholders, to be held on April 28, 2016, are incorporated by reference into Part III hereof.

 




WISCONSIN ELECTRIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2015
TABLE OF CONTENTS
 
 
 
 
 
Page
 
 
 
 
 
 


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2015 Form 10-K
i
Wisconsin Electric Power Company


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




2015 Form 10-K
ii
Wisconsin Electric Power Company


GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Subsidiaries and Affiliates
 
 
ATC
 
American Transmission Company LLC
Bostco
 
Bostco LLC
DATC
 
Duke-American Transmission Company
Integrys
 
Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
WBS
 
WEC Business Services LLC
We Power
 
W.E. Power, LLC
WEC Energy Group
 
WEC Energy Group, Inc. (previously known as Wisconsin Energy Corporation)
Wisconsin Gas
 
Wisconsin Gas LLC
 
 
 
Certain Assets
 
 
OC 1
 
Oak Creek Expansion Unit 1
OC 2
 
Oak Creek Expansion Unit 2
PIPP
 
Presque Isle Power Plant
PSGS
 
Paris Generating Station
PWGS
 
Port Washington Generating Station
PWGS 1
 
Port Washington Generating Station Unit 1
PWGS 2
 
Port Washington Generating Station Unit 2
VAPP
 
Valley Power Plant
 
 
 
Federal and State Regulatory Agencies
EPA
 
United States Environmental Protection Agency
FERC
 
Federal Energy Regulatory Commission
MDEQ
 
Michigan Department of Environmental Quality
MPSC
 
Michigan Public Service Commission
PSCW
 
Public Service Commission of Wisconsin
SEC
 
Securities and Exchange Commission
WDNR
 
Wisconsin Department of Natural Resources
 
 
 
Accounting Terms
AFUDC
 
Allowance for Funds Used During Construction
ARO
 
Asset Retirement Obligation
ASC
 
Accounting Standards Codification
ASU
 
Accounting Standards Update
FASB
 
Financial Accounting Standards Board
GAAP
 
Generally Accepted Accounting Principles
OPEB
 
Other Postretirement Employee Benefits
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2015 Form 10-K
iii
Wisconsin Electric Power Company


Environmental Terms
Act 141
 
2005 Wisconsin Act 141
CAA
 
Clean Air Act
CO2
 
Carbon Dioxide
CSAPR
 
Cross-State Air Pollution Rule
GHG
 
Greenhouse Gas
MATS
 
Mercury and Air Toxics Standards
NAAQS
 
National Ambient Air Quality Standards
NOx
 
Nitrogen Oxide
SO2
 
Sulfur Dioxide
WPDES
 
Wisconsin Pollutant Discharge Elimination System
 
 
 
Measurements
 
 
Btu
 
British Thermal Unit(s)
Dth
 
Dekatherm(s) (One Dth equals one million Btu)
kW
 
Kilowatt(s) (One kW equals one thousand Watts)
kWh
 
Kilowatt-hour(s)
MW
 
Megawatt(s) (One MW equals one million Watts)
MWh
 
Megawatt-hour(s)
 
 
 
Other Terms and Abbreviations
ARRs
 
Auction Revenue Rights
Compensation Committee
 
Compensation Committee of the Board of Directors of WEC Energy Group
CPCN
 
Certificate of Public Convenience and Necessity
Exchange Act
 
Securities Exchange Act of 1934, as amended
FTRs
 
Financial Transmission Rights
GCRM
 
Gas Cost Recovery Mechanism
LMP
 
Locational Marginal Price
Merger Agreement
 
Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation
MISO
 
Midcontinent Independent System Operator, Inc.
MISO Energy Markets
 
MISO Energy and Operating Reserves Market
N/A
 
Not Applicable
NYMEX
 
New York Mercantile Exchange
Point Beach
 
Point Beach Nuclear Power Plant
PTF
 
Power the Future
ROE
 
Return on Equity
RTO
 
Regional Transmission Organization
SSR
 
System Support Resource
Treasury Grant
 
Section 1603 Renewable Energy Treasury Grant


2015 Form 10-K
iv
Wisconsin Electric Power Company


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 Securities Exchange Act of 1934, as amended. 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, 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 businesses;

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, including the extension of bonus depreciation, 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 or us;

Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;

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;


2015 Form 10-K
1
Wisconsin Electric Power Company


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 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 WEC Energy Group's 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 terms and conditions of the governmental and regulatory approvals of WEC Energy Group's acquisition of Integrys that could reduce anticipated benefits and the ability to successfully integrate the operations of the combined company;

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.


2015 Form 10-K
2
Wisconsin Electric Power Company


PART I

ITEM 1. BUSINESS

A. INTRODUCTION

In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and our subsidiary, Bostco. References to "Notes" are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

We are a subsidiary of WEC Energy Group and were incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin and serve customers in Wisconsin and Michigan's Upper Peninsula. Our three reportable segments are electric utility, natural gas utility, and steam utility, which accounted for 89%, 10%, and 1% of total utility revenues, respectively, in 2015. Bostco is our non-utility subsidiary that develops and invests in real estate.

For more information about our utility operations, including financial and geographic information, see Note 21, Segment Information, and Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

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, Acquisition.

Available Information

Our annual and periodic filings with the SEC are available, free of charge, through WEC Energy Group's website www.wecenergygroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC.

You may obtain materials we filed with or furnished to the SEC at the SEC Public Reference Room at 100 F Street, NE, Washington, DC 20549. To obtain information on the operation of the Public Reference Room, you may call the SEC at 1-800-SEC-0330. You may also view information filed or furnished electronically with the SEC at the SEC's website at www.sec.gov.

B. UTILITY OPERATIONS

ELECTRIC UTILITY SEGMENT

We are the largest electric utility in the state of Wisconsin. We generate and distribute electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, northern Wisconsin, and Michigan's Upper Peninsula.


2015 Form 10-K
3
Wisconsin Electric Power Company


Electric Utility Operating Statistics

The following table shows certain electric utility operating statistics for the past three years:
 
 
Year Ended December 31
 
 
2015
 
2014
 
2013
Operating revenues (in millions)
 
 
 
 
 
 
Residential
 
$
1,207.6

 
$
1,199.3

 
$
1,208.6

Small commercial and industrial
 
1,035.4

 
1,052.9

 
1,048.0

Large commercial and industrial
 
726.7

 
637.0

 
711.9

Other
 
22.1

 
23.0

 
23.4

Total retail revenues
 
2,991.8

 
2,912.2

 
2,991.9

Wholesale
 
101.4

 
131.9

 
143.7

Resale
 
228.2

 
264.1

 
143.2

Other operating revenues
 
89.6

 
87.8

 
28.4

Total
 
3,411.0

 
3,396.0

 
3,307.2

Electric customer choice *
 
2.4

 
5.1

 
1.5

Total operating revenues
 
$
3,413.4

 
$
3,401.1

 
$
3,308.7

 
 
 
 
 
 
 
Customers – end of year (in thousands)
 
 
 
 
 
 
Residential
 
1,020.8

 
1,015.0

 
1,010.5

Small commercial and industrial
 
116.0

 
115.4

 
114.6

Large commercial and industrial
 
0.7

 
0.7

 
0.7

Other
 
2.6

 
2.5

 
2.6

Total customers
 
1,140.1

 
1,133.6

 
1,128.4

 
 
 
 
 
 
 
Customers – average (in thousands)
 
1,136.5

 
1,130.7

 
1,126.9


*
Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

Electric Sales

Our electric energy deliveries included supply and distribution sales to retail and wholesale customers and distribution sales to those customers who switched to an alternative electric supplier. In 2015, retail electric revenues accounted for 87.6% of total electric operating revenues, while wholesale (including resale) electric revenues accounted for 9.7% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Electric Utility Segment Contribution to Operating Income for information on MWh sales by customer class.

We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities.

We buy and sell wholesale electric power by participating in the MISO Energy Markets. The cost of our generation offered into the MISO Energy Markets, compared to our competitors, affects how often our generating units are dispatched and how we buy and sell power. For more information, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations –Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring.

Large Electric Retail Customers

We provide electric utility service to a diversified base of customers in such industries as mining, paper, foundry, food products and machinery production, health services, governmental, and large retail chains. In February 2015, our largest retail electric customer, the owner of two iron ore mines located in Michigan's Upper Peninsula, returned as a customer after choosing an alternative electric supplier in September 2013. We entered into a special contract with each of the mines to provide full requirements electric service through December 31, 2019. In 2015, we deferred, and we expect to continue to defer, the margin from those sales and will apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. For more information, see Note 20, Michigan Settlement, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Industry Restructuring.

2015 Form 10-K
4
Wisconsin Electric Power Company



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 3.4%, 5.3%, and 5.9% of total electric energy sales during 2015, 2014, and 2013, respectively. Wholesale revenues accounted for 3.0%, 3.9%, and 4.3% of total electric operating revenues during 2015, 2014, and 2013, respectively.

Resale

The majority of our sales for resale are sold to one RTO, MISO, at market rates based on availability of our generation and RTO demand. Resale sales accounted for 23.8%, 18.5%, and 13.3% of total electric energy sales during 2015, 2014, and 2013, respectively. Resale revenues accounted for 6.7%, 7.8%, and 4.3% of total electric operating revenues during 2015, 2014, and 2013, respectively.

Electric Sales Growth

Our service territory experienced slightly declining weather-normalized retail electric sales in 2015 as positive customer growth was more than offset by reduced volumes related to lower use per customer. We currently forecast retail electric sales volumes, excluding the two iron ore mines, to grow at a compound annual rate of between flat and 0.5% over the next five years, assuming normal weather. In addition, we forecast associated electric peak demand, excluding the two iron ore mines, to grow at a compound annual rate of between 0.5% to 1.0% over the next five years, also assuming normal weather. The owner of the two iron ore mines has announced its intention to shut down one of the mines in 2017. The potential loss of retail electric sales associated with this mine is estimated at approximately 3% of our annual total retail electric sales.

Electric Generation and Supply Mix

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable, and affordable supply of electricity. We supply a significant amount of electricity to our customers from power plants that we own or lease from We Power. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach power purchase agreement discussed in Power Purchase Commitments, below and through spot purchases in the MISO Energy Markets.

Our rated capacity by fuel type, including the units we lease from We Power, as of December 31 is shown below. For more information on our electric generation facilities, see Item 2. Properties.
 
 
Rated Capacity in MW (1)
 
 
2015
 
2014
 
2013
Coal
 
3,589

 
3,707

 
3,822

Natural gas:
 
 
 
 
 
 
Combined cycle
 
1,082

 
1,082

 
1,082

Steam turbine (2)
 
240

 
118

 

Natural gas/oil peaking units (3)
 
962

 
962

 
962

Renewables (4)
 
187

 
155

 
155

Total rated capacity by fuel type
 
6,060

 
6,024

 
6,021


(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.

(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.


2015 Form 10-K
5
Wisconsin Electric Power Company


The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2016:
 
 
Estimate
 
Actual
 
 
2016
 
2015
 
2014
 
2013
Company-owned or leased generation units:
 
 
 
 
 
 
 
 
Coal
 
52.2
%
 
53.5
%
 
55.2
%
 
53.6
%
Natural gas:
 
 
 
 
 
 
 
 
Combined cycle
 
15.5
%
 
13.0
%
 
8.7
%
 
10.1
%
Steam turbine
 
1.1
%
 
1.4
%
 
0.2
%
 
%
Natural gas/oil peaking units
 
0.1
%
 
0.6
%
 
0.2
%
 
0.2
%
Renewables
 
3.1
%
 
3.5
%
 
3.8
%
 
3.3
%
Total company-owned or leased generation units
 
72.0
%
 
72.0
%
 
68.1
%
 
67.2
%
Power purchase contracts:
 
 
 
 
 
 
 
 
Nuclear
 
22.7
%
 
24.5
%
 
25.4
%
 
27.1
%
Natural gas
 
3.3
%
 
1.7
%
 
2.1
%
 
2.1
%
Renewables
 
1.2
%
 
1.1
%
 
2.7
%
 
3.1
%
Other
 
0.7
%
 
0.7
%
 
0.9
%
 
0.5
%
Total power purchase contracts
 
27.9
%
 
28.0
%
 
31.1
%
 
32.8
%
Purchased power from MISO
 
0.1
%
 
%
 
0.8
%
 
%
Total purchased power
 
28.0
%
 
28.0
%
 
31.9
%
 
32.8
%
Total electric utility supply
 
100.0
%
 
100.0
%
 
100.0
%
 
100.0
%

Coal-Fired Generation

Our coal-fired generation, including the units we lease from We Power, consists of five operating plants with a rated capacity of 3,589 MW as of December 31, 2015. For more information about our operating plants, see Item 2. Properties.

Natural Gas-Fired Generation

Our natural gas-fired generation, including the units we lease from We Power, consists of four operating plants, including peaking units, with a rated capacity of 2,104 MW as of December 31, 2015. For more information about our operating plants, see Item 2. Properties.

Oil-Fired Generation

Fuel oil is used for 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, 2015. We also have natural gas-fired peaking units with a rated capacity of 782 MW, which have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our operating plants, see Item 2. Properties.

Renewable Generation

Hydroelectric

Our hydroelectric generating system consists of 13 operating plants with a total installed capacity of 86 MW and a rated capacity of 86 MW as of December 31, 2015. All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Wind

We have four wind sites, consisting of 200 turbines, with an installed capacity of 339 MW and a rated capacity of 51 MW as of December 31, 2015.


2015 Form 10-K
6
Wisconsin Electric Power Company


Biomass

We constructed a biomass-fueled power plant at a Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. 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.

Generation from Leased Power The Future Units

We also supply electricity to our customers from power plants that we lease from We Power. These plants include the Oak Creek Expansion units and the PWGS units, otherwise known as the PTF units. Lease payments are billed from We Power to us and then recovered in our rates as authorized by the PSCW, the MPSC, and the FERC. We operate the PTF units and are authorized by the PSCW and state law to fully recover prudently incurred operating and maintenance costs in our Wisconsin electric rates. As the operator of the units, we may request We Power to make capital improvements to, or further investments in, the units. Under the lease terms, these capital improvements or further investments will increase lease payments paid by us and should ultimately be recovered in our rates.

Electric System Reliability

The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. The PSCW has a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has a 14.3% reserve margin requirement from January 1, 2016, through May 31, 2016, and 15.2% for the remainder of 2016. The MPSC does not have minimum guidelines for future supply reserves.

We had adequate capacity through company-owned generation units, leased generating units, and power purchase contracts to meet the MISO calculated planning reserve margin during 2015 and expect to have adequate capacity to meet the planning reserve margin requirements during 2016. However, extremely hot weather, unexpected equipment failure or unavailability across the 15-state MISO market footprint could require us to call upon load management procedures. Load management procedures allow for the reduction of energy use through agreements with customers to directly shut off their equipment or through interruptible service, where customers agree to reduce their load in the case of an emergency interruption.

Fuel and Purchased Power Costs

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. For more information about the fuel rule, see Item 1. Business – C. Regulation.

Our average fuel and purchased power costs per MWh by fuel type were as follows for the year ended December 31:
 
 
2015
 
2014
 
2013
Coal
 
$
25.25

 
$
27.68

 
$
27.97

Natural gas combined cycle
 
23.44

 
40.64

 
32.22

Natural gas/oil peaking units
 
56.33

 
129.83

 
83.95

Purchased power
 
43.87

 
47.47

 
43.74


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.


2015 Form 10-K
7
Wisconsin Electric Power Company


We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage.

We have a PSCW-approved hedging program that allows us to hedge up to 75% of our potential risks related to fuel surcharge exposure. We also have a program that allows us to hedge up to 65% of our estimated natural gas use for electric generation in order to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. The results of both of these programs are reflected in the average costs of natural gas and purchased power.

Coal Supply

We diversify the coal supply for our electric generating facilities by purchasing coal from several mines in Wyoming, as well as from various other states. For 2016, approximately 86% of our total projected coal requirements of approximately 12 million tons are contracted under fixed-price contracts. See Note 15, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.

The annual tonnage amounts contracted for 2016 through 2018 are as follows:
(in thousands)
 
Annual Tonnage
2016
 
9,978

2017
 
6,967

2018
 
3,583


Coal Deliveries

All of our 2016 coal requirements are expected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facilities. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.

Midcontinent Independent System Operator Costs

In connection with its status as a FERC approved RTO, MISO developed and operates the MISO Energy Markets, which include its bid-based energy markets and ancillary services market. We are a participant in the MISO Energy Markets. In 2013, MISO expanded its footprint to include entities in Mississippi, Arkansas, Texas, and Missouri, a region referred to as MISO South. These changes have not had a material impact on our allocation of transmission costs, and we do not expect them to have a material impact in the future. For more information on MISO, see Item 1. Business – C. Regulation.

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. As of December 31, 2015, our power purchase commitments with unaffiliated parties for the next five years is 1,267 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. In addition, 234 MW per year relates to a long-term power purchase agreement under which we purchase power at a price determined monthly based on a formula tied to a natural gas price index.

Other Matters

Seasonality

Our electric sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. Our generating plants performed as expected during the warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, we did not require public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs.

2015 Form 10-K
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Wisconsin Electric Power Company



Competition

We face competition from various entities and other forms of energy sources available to customers, including self-generation by large industrial customers and alternative energy sources. We compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.

The retail electric utility market in Wisconsin is regulated by the PSCW. Retail electric customers do not have the ability to choose their electric supplier, and it is uncertain when, if ever, retail electric choice might be implemented in Wisconsin. The regulated energy industry continues to experience significant structural changes, which could eventually lead to increased competition in Wisconsin.

The retail electric utility market in Michigan remains open to competition with its retail choice program, which allows customers to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We continue providing distribution and customer service functions regardless of the customer's power supplier.

Environmental Matters

For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 15, Commitments and Contingencies, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Environmental Matters.

Electric Transmission and Energy Markets

American Transmission Company 

ATC is a regional transmission company that owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota. ATC is expected to provide comparable service to all customers, including us, 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 are a non-transmission owning member and customer of MISO. As of December 31, 2015, our ownership interest in ATC was approximately 23%. See Note 4, Investment in American Transmission Company, for more information

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. These projects are located in the service territories of several different RTOs around the country. On January 20, 2016, the FERC issued an order authorizing ATC to enter into a proposed restructuring involving the creation of three new entities: ATC Holdco, ATC Development, and ATC Development Manager Inc. ATC’s current member owners will have the option to retain their existing ownership interests limited to ATC in Wisconsin and adjacent states or to exchange their current ATC ownership interests for ownership interests in ATC Holdco, which would allow them to participate in ATC's transmission business in Wisconsin and adjacent states, as well as new transmission development projects throughout the U.S.

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, for more information.

NATURAL GAS UTILITY SEGMENT

We are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. We also transport customer-owned natural gas. We operate in three distinct service areas including west and south of the City of Milwaukee, the Appleton area, and areas within Iron and Vilas Counties, Wisconsin.


2015 Form 10-K
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Wisconsin Electric Power Company


Natural Gas Utility Operating Statistics

The following table shows certain natural gas utility operating statistics for the past three years:
 
 
Year Ended December 31
 
 
2015
 
2014
 
2013
Operating revenues (in millions)
 
 
 
 
 
 
Residential
 
$
256.6

 
$
390.5

 
$
296.0

Commercial and industrial
 
118.9

 
204.5

 
140.8

Total retail revenues
 
375.5

 
595.0

 
436.8

Transport
 
16.0

 
16.8

 
16.0

Other operating revenues
 
8.2

 
2.4

 
(0.9
)
Total
 
$
399.7

 
$
614.2

 
$
451.9

 
 
 
 
 
 
 
Customers – end of year (in thousands)
 
 
 
 
 
 
Residential
 
438.7

 
435.6

 
432.1

Commercial and industrial
 
39.1

 
38.9

 
38.6

Transport
 
0.7

 
0.6

 
0.6

Total customers
 
478.5

 
475.1

 
471.3

 
 
 
 
 
 
 
Customers – average (in thousands)
 
476.4

 
472.6

 
469.7


Natural Gas Deliveries

Our gas therm deliveries include customer-owned transported natural gas. Transported natural gas accounted for approximately 39.0% of the total volumes delivered during 2015, 34.9% during 2014, and 35.4% during 2013. Our peak daily send-out during 2015 was 7.3 million therms on January 7, 2015.

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, educational, food products, real estate, and metal.

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 15, Commitments and Contingencies.

Pipeline Capacity and Storage

The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada and the Rocky Mountains. We have contracted for long-term 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.

2015 Form 10-K
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Wisconsin Electric Power Company



Term Natural Gas Supply

We have contracts for firm supplies with terms of 3–7 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 forecasted design peak-day throughput is 9.5 million therms for the 2015 through 2016 heating season.

Secondary Market Transactions

Pipeline long-line and storage capacity and natural gas supplies under contract can be resold in secondary markets. Local distribution companies, like our natural gas operations, must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. The secondary markets facilitate higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and natural gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to rate payers, subject to our approved GCRM. During 2015, we continued to participate in the secondary markets. For information on our GCRM, see Note 1(d), Revenues and Customer Receivables.

Spot Market Natural Gas Supply

We expect to continue to make natural gas purchases in the spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase natural gas in the spot market.

Hedging Natural Gas Supply Prices

We have PSCW approval to hedge up to 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. This approval allows us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through our GCRM. Hedge targets (volumes) are provided annually to the PSCW as part of our three-year natural gas supply plan and risk management filing.

To the extent that opportunities develop and physical supply operating plans are supportive, we also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRM.

Seasonality

Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to variations in earnings and working capital throughout the year as a result of changes in weather.

Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of the winter natural gas supply needs is typically purchased and stored from April through October. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through October. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.

Competition

Competition in varying degrees exists between natural gas and other forms of energy available to consumers. A number of our large commercial and industrial customers are dual-fuel customers that are equipped to switch between natural gas and alternate fuels. We are allowed to offer lower-priced natural gas sales and transportation services to dual-fuel customers. Under natural gas

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Wisconsin Electric Power Company


transportation agreements, customers purchase natural gas directly from natural gas marketers and arrange with interstate pipelines and us to have the natural gas transported to their facilities. We earn substantially the same margin (difference between revenue and cost of natural gas) whether we sell and transport natural gas to customers or only transport their natural gas.

Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party natural gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively priced transportation service for those customers that desire to buy their own natural gas supplies.

Federal and state regulators continue to implement policies to bring more competition to the natural gas industry. While the natural gas utility distribution function is expected to remain a highly regulated, monopoly function, the sale of the natural gas commodity and related services are expected to remain subject to competition from third parties for large commercial and industrial customers. It remains uncertain if and when the current economic disincentives for small firm customers to choose an alternative natural gas commodity supplier may be removed such that we begin to face competition for the sale of natural gas to those customers.

STEAM UTILITY SEGMENT

We have a steam utility that generates, distributes, and sells steam supplied by VAPP and MCPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee, and steam is supplied to this system from VAPP. We also operate the steam production and distribution facilities of the MCPP located on the Milwaukee County Grounds in Wauwatosa, Wisconsin. In 2015, we entered into an agreement to sell the MCPP, which is expected to close during the first half of 2016.

Steam Utility Operating Statistics

Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions.

The following table shows certain steam utility operating statistics for the past three years:
 
 
Year Ended December 31
 
 
2015
 
2014
 
2013
Operating revenues (in millions)
 
$
41.0

 
$
44.1

 
$
39.6

 
 
 
 
 
 
 
Pounds of steam sales (in millions)
 
2,515

 
2,865

 
2,750

 
 
 
 
 
 
 
Customers – Average
 
430

 
440

 
445


C. REGULATION

We are subject to the requirements of the Public Utility Holding Company Act of 2005 as we meet the definition of a holding company under this Act due to our ownership interest in ATC.

In addition to the specific regulations noted below, we are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ, the Michigan Department of Natural Resources, and the U.S. Army Corps of Engineers.

Rates
 
Our rates are regulated by the various commissions shown in the table below. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.
Regulated Rates
 
Regulatory Commission
Retail electric, natural gas, and steam
 
PSCW
Retail electric
 
MPSC
Wholesale power
 
FERC


2015 Form 10-K
12
Wisconsin Electric Power Company


Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount.

Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customers and our Wisconsin wholesale electric customers. Our natural gas operations operate under a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar-for-dollar recovery of prudently incurred natural gas costs.

In May 2015, the PSCW approved the acquisition of Integrys on the condition that we will be subject to an earnings sharing mechanism for three years beginning January 1, 2016. See Note 2, Acquisition, for more information on this earnings sharing mechanism.

For information on how our rates are set, see Note 19, Regulatory Environment. Orders from our respective regulators can be viewed at the following websites:
Regulatory Commission
 
Website
PSCW
 
 https://psc.wi.gov/
MPSC
 
http://www.michigan.gov/mpsc/
FERC
 
http://www.ferc.gov/

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:
 
 
2015
 
2014
 
2013
(in millions)
 
Amount
 
Percent
 
Amount
 
Percent
 
Amount
 
Percent
Electric
 
 
 
 
 
 
 
 
 
 
 
 
Wisconsin
 
$
2,829.5

 
82.9
%
 
$
2,889.9

 
85.0
%
 
$
2,874.8

 
86.9
%
Michigan
 
163.0

 
4.8
%
 
58.8

 
1.7
%
 
147.0

 
4.4
%
FERC – Wholesale
 
329.5

 
9.6
%
 
396.0

 
11.6
%
 
286.9

 
8.7
%
FERC – SSR *
 
91.4

 
2.7
%
 
56.4

 
1.7
%
 

 
%
Total
 
3,413.4

 
100.0
%
 
3,401.1


100.0
%
 
3,308.7

 
100.0
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas – Wisconsin
 
399.7

 
100.0
%
 
614.2

 
100.0
%
 
451.9

 
100.0
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Steam – Wisconsin
 
41.0

 
100.0
%
 
44.1

 
100.0
%
 
39.6

 
100.0
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total utility operating revenues
 
$
3,854.1

 


 
$
4,059.4

 


 
$
3,800.2

 



*
See Note 19, Regulatory Environment, for more information regarding SSR revenues.

Electric Transmission, Capacity, and Energy Markets

In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which include the bid-based energy markets and an ancillary services market. We previously self-provided both regulation reserves and contingency reserves. In the MISO ancillary services market, we buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market has been able to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.


2015 Form 10-K
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Wisconsin Electric Power Company


In MISO, base transmission costs are currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2015 through May 31, 2016. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

Beginning June 1, 2013, MISO instituted an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources could be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. Our capacity requirements during 2015 were fulfilled using our own capacity resources.

Other Electric Regulations

We are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize the FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities, and modify certain other aspects of energy regulations and Federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by the FERC, which established mandatory electric reliability standards and which has the authority to levy monetary sanctions for failure to comply with these standards.

We are subject to Act 141 in Wisconsin and Public Act 295 in Michigan, which contain certain minimum requirements for renewable energy generation. See Note 15, Commitments and Contingencies, for more information.

All of our hydroelectric facilities follow FERC guidelines and/or regulations.

Other Natural Gas Regulations

Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the state commissions are responsible for monitoring and enforcing requirements governing our natural gas safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 Code of Federal Regulations (CFR) Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards) and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

We are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service territory. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to our low-income customers.

D. ENVIRONMENTAL COMPLIANCE

Our operations are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation of GHG emissions, coal combustion products, air emissions, or wastewater discharges, could significantly increase these environmental compliance costs.

Anticipated expenditures for environmental compliance and remediation issues for the next three years are included in the estimated capital expenditures described in Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements in Item 7. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites, and air and water quality, see Note 15, Commitments and

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Wisconsin Electric Power Company


Contingencies, and Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Environmental Matters in Item 7.

E. EMPLOYEES

As of December 31, 2015, we had 3,653 employees, of which 3,551 were full-time. Effective January 1, 2016, approximately 485 of our employees were transferred into WBS. See Note 3, Related Parties, for more information on WBS and the services it provides.

As of December 31, 2015, we had employees represented under labor agreements with the following bargaining units:
 
 
Number of Employees
 
Expiration Date of Current Labor Agreement
Local 2150 of International Brotherhood of Electrical Workers, AFL-CIO
 
1,679

 
August 15, 2017
Local 420 of International Union of Operating Engineers, AFL-CIO
 
489

 
September 30, 2017
Local 2006 Unit 1 of United Steel Workers of America, AFL-CIO
 
123

 
April 30, 2017
Local 510 of International Brotherhood of Electrical Workers, AFL-CIO
 
105

 
October 31, 2016
Total
 
2,396

 
 


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Wisconsin Electric Power Company


ITEM 1A. RISK FACTORS

We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.

Risks Related to Legislation and Regulation

Our business is significantly impacted by governmental regulation.

We are subject to significant state, local, and federal governmental regulation, including regulation by the PSCW, MPSC, and FERC. This regulation significantly influences our operating environment and may affect our ability to recover costs from utility customers. Many aspects of our operations are regulated, including, but not limited to: the rates we charge our retail electric, 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 we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation is based on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent on regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable ROE. We defer certain costs and revenues as regulatory assets and liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured, and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.

We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied with all of their associated terms, and that our business is conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies. Changes in regulations, interpretations of regulations, or the imposition of new regulations could influence our operating environment, may result in substantial compliance costs, or may require us to change our business operations.

If we are unable to obtain, renew, or comply with these governmental permits, approvals, authorizations, certificates, or licenses, or if we are unable to recover any increased costs of complying with additional requirements or any other associated costs in customer rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.

We may face significant costs to comply with existing and future environmental laws and regulations.

Our operations are subject to numerous federal and state environmental laws and regulations. These laws and regulations govern, among other things, air emissions (including CO2, methane, mercury, SO2, and NOx), water quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. We incur significant costs to comply with these environmental requirements, including costs associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at our facilities. In addition, if we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines.

The EPA has adopted and has implemented (or is in the process of implementing) regulations governing the emission of NOx, SO2, fine particulate matter, mercury, and other air pollutants under the CAA through the NAAQS, the MATS rule, the Clean Power Plan, the CSAPR, and other air quality regulations. In addition, the EPA has finalized regulations under the Clean Water Act that govern

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Wisconsin Electric Power Company


cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. The EPA has also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters; however, this rule has been stayed. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. Several environmental regulations were either finalized or implemented during 2015, and there is still uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with these regulations.

Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that could result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations through emission control technology; operating restrictions on our facilities; and increased compliance costs. In addition, the operation of emission control equipment and compliance with rules regulating our intake and discharge of water could increase our operating costs and reduce the generating capacity of our power plants. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels.

As a result, certain of our coal-fired electric generating facilities may become uneconomical to maintain and operate, which could result in some of these units being retired early or converted to an alternative type of fuel. If generation facility owners in the Midwest, including us, are forced to retire a significant number of older coal-fired generation facilities, a potential reduction in the region's capacity reserve margin below acceptable risk levels may result. This could impair the reliability of the grid in the Midwest, particularly during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.

We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities, and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation, and related legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other third parties. Due to the potential for imposition of stricter standards and greater regulation in the future, as well as the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.

In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could contribute to reduced demand for electricity, which could adversely affect our results of operations, cash flows, and financial condition.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, has increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by environmental impacts and alleged exposure to hazardous materials have become more frequent. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.

We may face significant costs to comply with the regulation of greenhouse gas emissions.

Federal, state, regional, and international authorities have undertaken efforts to limit GHG emissions. In 2015, the EPA issued the Clean Power Plan, which is a final rule that regulates GHG emissions from existing generating units, as well as a proposed federal plan as an alternative to state compliance plans. The EPA also issued final performance standards for modified and reconstructed generating units, as well as for new fossil-fueled power plants. Under the Clean Power Plan, states are required to submit compliance plans as early as September 2016 to achieve state-specific GHG emission reductions by 2030. If Wisconsin or Michigan determines not to file a state compliance plan, we may be required to comply with the federal plan, which could result in more significant compliance costs than a state compliance plan. We are continuing to analyze the final rule and to work with other stakeholders to

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Wisconsin Electric Power Company


determine how to implement the Clean Power Plan and the potential impacts to our operations. In October 2015, 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 United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) denied the stay request, but on February 9, 2016, the United States Supreme Court (Supreme Court) stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of the state plans until the litigation is complete. Any state or federal compliance plans that are developed could be subject to change based upon the outcome of this litigation. In addition, on February 15, 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The rule could result in significant additional compliance costs, including capital expenditures, and impact how we operate our existing fossil-fueled power plants and biomass facility, all of which could have a material adverse impact on our operating costs.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with the Clean Power Plan or that cost recovery will not be delayed or otherwise conditioned. The Clean Power Plan and any other related regulations that may be adopted in the future, either at the federal or state level, may cause our environmental compliance spending over the next several years to differ materially from the amounts currently estimated. These regulations could have a material adverse impact on our electric generation and natural gas distribution operations, could make some of our electric generating units uneconomic to maintain or operate, and could affect unit retirement and replacement decisions. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.

In addition, our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair of natural gas delivery systems. Fugitive gas typically vents to the atmosphere and consists primarily of methane. CO2 is also a byproduct of natural gas consumption. As a result, future legislation to regulate GHG emissions could increase the price of natural gas, restrict the use of natural gas, and adversely affect our ability to operate our natural gas facilities. A significant increase in the price of natural gas may increase rates for our natural gas customers, which could reduce natural gas demand.

We could be subject to higher costs and penalties as a result of mandatory reliability standards.

We are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with the mandatory reliability standards could subject us to higher operating costs. If we were ever found to be in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.

Risks Related to the Operation of Our Business

Our operations are subject to risks arising from the reliability of our electric generation, transmission, and distribution facilities, natural gas infrastructure facilities, and other facilities, as well as the reliability of third-party transmission providers.

Our financial performance depends on the successful operation of our electric generation and natural gas and electric distribution facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or processes. Potential breakdown or failure may occur due to severe weather; catastrophic events (i.e., fires, earthquakes, explosions, tornadoes, floods, droughts, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security threats. Any of these events could lead to substantial financial losses.

Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.

Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of these lost revenues or increased expenses, which could adversely affect our results of operations and cash flows.

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Wisconsin Electric Power Company



Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general economic conditions in our service areas, varying weather conditions, and energy conservation efforts.

Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:

Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including job losses, decreases in income, and business closings. We are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn or disruption of financial markets could adversely affect the financial condition of our customers and demand for their products. These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.
Weather conditions. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income.
Our customers' continued focus on energy conservation and ability to meet their own energy needs. Customers could voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, and individual conservation efforts through the use of more energy efficient technologies. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. In addition, several states, including Wisconsin and Michigan, have adopted energy efficiency targets to reduce energy consumption by certain dates.

As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.

We are actively involved with several significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.

Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, natural gas storage, and other projects, including projects for environmental compliance.

Achieving the intended benefits of any large construction project is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. These risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of our regulators. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, the applicable commission may deem the additional capital costs as imprudent and disallow recovery of them through rates.

To the extent that delays occur, costs become unrecoverable, or we otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and financial condition may be adversely affected.

Advances in technology could make our electric generating facilities less competitive.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, and energy efficiency. We generate power at central station power plants to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become more cost competitive. It is possible that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be

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Wisconsin Electric Power Company


reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.

Our operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.

We face the risk of terrorist and cyber intrusions, both threatened and actual, against our generation facilities, electric and natural gas distribution infrastructure, our information and technology systems, and network infrastructure, including that of third parties on which we rely, any of which could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows.

We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber intrusions, including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission, distribution, and storage systems, could disrupt our operations and result in loss of service to customers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.

We face on-going threats to our assets and technology systems. Despite the implementation of strong security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to human error or physical or cyber intrusions. If our assets or systems were to fail, be physically damaged, or be breached and were not recovered in a timely manner, we may be unable to perform critical business functions, and sensitive and other data could be compromised.

Our business requires the collection and retention of personally identifiable information of our customers and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.

The costs of repairing damage to our facilities, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.

Transporting, distributing, and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

Inherent in natural gas distribution activities are a variety of hazards and operational risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.


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Wisconsin Electric Power Company


We may fail to attract and retain an appropriately qualified workforce.

We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

Failure of our counterparties to meet their obligations, including obligations under power purchase agreements, could have an adverse impact on our results of operations.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.

We have entered into several power purchase agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. Revenues are dependent on the continued performance by the purchasers of their obligations under the power purchase agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more purchasers could fail to perform their obligations under the power purchase agreements. If this were to occur, we would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase agreement would be reallocated among our retail customers. To the extent there is any regulatory delay in adjusting rates, a customer default under a power purchase agreement could have a negative impact on our results of operations and cash flows.

Our revenues could be negatively impacted by competitive activity in the wholesale electricity markets.

The FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers, and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter. Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.

Risks Related to Economic and Market Volatility

Our business is dependent on our ability to successfully access capital markets.

We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost commercial paper markets.

Our access to the credit and capital markets could be limited, or our cost of capital significantly increased, due to any of the following risks and uncertainties:

A rating downgrade;
An economic downturn or uncertainty;

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Wisconsin Electric Power Company


Prevailing market conditions;
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.

A downgrade in our credit ratings could negatively affect our ability to access capital at reasonable costs and/or require the posting of collateral.

There are a number of factors that impact our credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in our ratings if the rating agencies determine that the level of business or financial risk of us or the utility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings.

Any downgrade by the rating agencies could:

Increase borrowing costs under our existing credit facility;
Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;
Decrease funding sources by limiting our access to the commercial paper market;
Limit the availability of adequate credit support for our operations; and
Trigger collateral requirements in various contracts.

Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.

Our margins and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.

We burn natural gas in several of our electric generation plants, and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas may increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations affecting its accessibility.

For Wisconsin customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Our natural gas operations receive dollar-for-dollar recovery of prudently incurred natural gas costs.

Changes in commodity prices could result in:

Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;
Reduced profitability to the extent that reduced margins, 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 margins 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.

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

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Wisconsin Electric Power Company


fulfill their obligations to us, or we may experience operational problems or constraints that prevent us from taking delivery. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Furthermore, demand for coal can impact its availability and cost. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coal-fired units and replace this lost generation through additional power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our cash flows.

Our electric generation frequently exceeds our customer load. When this occurs, we generally sell the excess generation into the MISO Energy Markets. If we are unable to run our lower cost units, we may lose the ability to engage in these opportunity sales, which may adversely affect our results of operations.

The use of derivative contracts could result in financial losses.

We use derivative instruments such as swaps, options, futures, and forwards to manage commodity price exposure. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.

Restructuring in the regulated energy industry could have a negative impact on our business.

The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us.

Michigan has adopted retail choice. Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The two iron ore mines in the Upper Peninsula of Michigan are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer. It is uncertain whether retail choice might be implemented in Wisconsin.

FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. The MISO Energy Markets rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes an LMP that reflects the market price for energy. As a participant in the MISO Energy Markets, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. MISO also implemented an ancillary services market for operating reserves that was simultaneously co-optimized with its existing energy markets.

These market designs continue to have the potential to increase the costs of transmission, the costs associated with inefficient generation dispatching, the costs of participation in the MISO Energy Markets, and the costs associated with estimated payment settlements.

We may experience poor investment performance of benefit plan holdings due to changes in assumptions and market conditions.

We have significant obligations related to pension and OPEB plans. If WEC Energy Group is unable to successfully manage benefit plan assets and our 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

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Wisconsin Electric Power Company


increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements) or changes in life expectancy assumptions.

We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.

Risks Related to the Integrys Acquisition

The acquisition of Integrys may not achieve its anticipated results, and WEC Energy Group may be unable to integrate operations as expected.
 
The Merger Agreement was entered into with the expectation that the 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 WEC Energy Group can be integrated in an efficient, effective, and timely manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees; the disruption of ongoing businesses, processes, and systems; or inconsistencies in standards, controls, procedures, practices, policies, and compensation arrangements, any of which could adversely affect WEC Energy Group's ability to achieve the anticipated benefits of the transaction as and when expected. WEC Energy Group may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve the anticipated benefits of the 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.


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Wisconsin Electric Power Company


ITEM 2. PROPERTIES

We own our principal properties outright, except that the major portion of our electric utility distribution lines, steam utility distribution mains and 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. In addition, we lease the PTF generating units.

As of December 31, 2015, we owned, or leased from We Power, the following generating assets:
Name
 
Location
 
Fuel
 
Number of Generating Units
 
Rated Capacity In MW (1)
 
Coal-fired plants
 
 
 
 
 
 
 
 
 
Milwaukee County
 
Wauwatosa, WI
 
Coal
 
3

 
7

(2) 
Oak Creek Expansion
 
Oak Creek, WI
 
Coal
 
2

 
1,057

(3) 
Pleasant Prairie
 
Pleasant Prairie, WI
 
Coal
 
2

 
1,188

 
Presque Isle
 
Marquette, MI
 
Coal
 
5

 
344

 
South Oak Creek
 
Oak Creek, WI
 
Coal
 
4

 
993

 
Total coal-fired plants
 
 
 
 
 
16

 
3,589

 
Natural gas-fired plants
 
 
 
 
 
 
 
 
 
Concord Combustion Turbines
 
Watertown, WI
 
Natural Gas/Oil
 
4

 
352

 
Germantown Combustion Turbines
 
Germantown, WI
 
Natural Gas/Oil
 
5

 
258

 
Paris Combustion Turbines
 
Union Grove, WI
 
Natural Gas/Oil
 
4

 
352

 
Port Washington Generating Station
 
Port Washington, WI
 
Natural Gas
 
2

 
1,082

 
Valley Power Plant
 
Milwaukee, WI
 
Natural Gas
 
2

 
240

 
Total natural gas-fired plants
 
 
 
 
 
17

 
2,284

 
Renewables
 
 
 
 
 
 
 
 
 
Hydro Plants (13 in number)
 
WI
 
Hydro
 
33

 
86

 
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

 

 
Glacier Hills
 
Cambria, WI
 
Wind
 
90

 
28

 
Montfort Wind Energy Center
 
Montfort, WI
 
Wind
 
20

 
2

 
Total renewables
 
 
 
 
 
234

 
187

 
Total system
 
 
 
 
 
267

 
6,060

 

(1) 
Based on expected capacity ratings for summer 2016, which can differ from nameplate capacity, especially on wind projects. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(2)  
We expect to complete the sale of the MCPP during the first half of 2016.

(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.

As of December 31, 2015, we operated approximately 21,500 pole-miles of overhead distribution lines and 24,400 miles of underground distribution cable, as well as 366 distribution substations and approximately 298,900 line transformers.

As of December 31, 2015, our natural gas distribution system included approximately 9,700 miles of distribution mains connected at 28 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, Northern Natural Pipeline Company and Great Lakes Transmission Company, and approximately 407,000 natural gas lateral services. We have a liquefied natural gas storage plant that converts and stores, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 Dth per day. Our natural gas distribution system consists almost entirely of plastic and coated steel pipe.

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

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Wisconsin Electric Power Company


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, 2015, the combined steam systems supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 42 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels and other pressure regulating equipment.

ITEM 3. LEGAL PROCEEDINGS

In addition to those legal proceedings discussed in this Annual Report on Form 10-K, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these other legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

See Note 15, Commitments and Contingencies, and Note 19, Regulatory Environment, for more information on material legal proceedings and matters related to us and our subsidiary.
 
ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

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Wisconsin Electric Power Company


EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages, and positions of our executive officers at December 31, 2015 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.

Gale E. Klappa.   Age 65.
WEC Energy Group — Director since 2003. Chairman and Chief Executive Officer since May 2004. President from April 2003 to July 2013.
Wisconsin Electric — Director since 2003. Chairman of the Board since May 2004. Chief Executive Officer since August 2003. President from August 2003 to June 2015.
Director of Joy Global, Inc. since 2006 and Badger Meter, Inc. since 2010.

J. Kevin Fletcher.   Age 57.
Wisconsin Electric — Director and Executive Vice President - Customer Service and Operations since June 2015. Senior Vice President - Customer Operations from October 2011 to June 2015.
Georgia Power — Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.

Robert M. Garvin.   Age 49.
WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.
Wisconsin Electric — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.
ATC — Vice President and General Counsel from 2009 to April 2011.

William J. Guc.   Age 46.
WEC Energy Group — Controller since October 2015. Vice President since June 2015.
Wisconsin Electric — Vice President and Controller since October 2015.
Integrys Energy Group — Vice President and Treasurer from December 2010 to June 2015.

J. Patrick Keyes.   Age 50.
WEC Energy Group — Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
Wisconsin Electric — Director since June 2015. Executive Vice President and Chief Financial Officer since September 2012. Treasurer from April 2011 to January 2013. Vice President from April 2011 to August 2012.
Accenture — Senior Executive from September 2001 to March 2011.

Scott J. Lauber.   Age 50.
WEC Energy Group — Vice President and Treasurer since February 2013. Assistant Treasurer from March 2011 to January 2013.
Wisconsin Electric — Vice President and Treasurer since February 2013. Assistant Treasurer from March 2011 to January 2013.

Allen L. Leverett.   Age 49.
WEC Energy Group — President since August 2013. Executive Vice President from May 2004 to July 2013. Chief Financial Officer from July 2003 to February 2011.
Wisconsin Electric — Director and President since June 2015. Executive Vice President from May 2004 to June 2015. Chief Financial Officer from July 2003 to February 2011.

Susan H. Martin.   Age 63.
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.
Wisconsin Electric — 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.


2015 Form 10-K
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Wisconsin Electric Power Company


Joan M. Shafer.   Age 62.
Wisconsin Electric — 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.

On January 27, 2016, Mr. Klappa notified WEC Energy Group's Board of Directors (Board) of his decision to retire as Chief Executive Officer (CEO) of WEC Energy Group effective May 1, 2016, after which time he will serve as Non-Executive Chairman of the Board. On the same day, the Board elected Mr. Leverett to the Board and appointed him as CEO of WEC Energy Group effective upon Mr. Klappa's retirement.

Certain executive officers also hold officer and/or director positions at other significant subsidiaries of WEC Energy Group.


2015 Form 10-K
28
Wisconsin Electric Power Company


PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Dividends

Dividends declared on our common stock during the two most recent fiscal years are set forth below. Dividends were paid entirely in cash. Dividends were paid to our sole common stockholder, WEC Energy Group. There is no established public trading market for our common stock.
Quarter
 
 
 
 
(in millions)
 
2015
 
2014
First
 
$
60.0

 
$
110.0

Second
 
60.0

 
110.0

Third
 
60.0

 
110.0

Fourth
 
60.0

 
60.0

Total
 
$
240.0

 
$
390.0


Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the Board of Directors and will depend upon, among other factors, our earnings, financial condition, and other requirements.

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to WEC Energy Group. See Note 9, Common Equity, for more information regarding restrictions on our ability to pay dividends.


2015 Form 10-K
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Wisconsin Electric Power Company


ITEM 6. SELECTED FINANCIAL DATA

WISCONSIN ELECTRIC POWER COMPANY
COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS
As of or for Year Ended December 31
 
 
 
 
 
 
 
 
 
 
(in millions)
 
2015
 
2014
 
2013
 
2012
 
2011
Operating revenues
 
$
3,854.1

 
$
4,059.4

 
$
3,800.2

 
$
3,613.3

 
$
3,727.6

Net income attributed to common shareholder
 
375.7

 
376.7

 
360.0

 
366.1

 
338.4

Total assets (1) (2)
 
13,139.6

 
12,597.2

 
12,207.2

 
12,016.2

 
11,659.3

Long-term debt and capital lease obligations (excluding current portion) (1)
 
5,351.3

 
4,875.2

 
4,876.7

 
4,917.5

 
4,982.1


(1) 
In the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs previously reported as other long-term assets were reclassified to offset long-term debt for all periods presented. Amounts reclassified were $2.8 million in 2014, $2.6 million in 2013, $2.3 million in 2012, and $2.0 million in 2011.

(2) 
In the fourth quarter of 2015, we early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. As a result, current deferred income taxes previously reported as a separate component of current assets were reclassified to offset long-term deferred income tax liabilities. Amounts reclassified were $46.7 million in 2014, $75.8 million in 2013, and $4.1 million in 2012. No reclassification was needed for 2011.


2015 Form 10-K
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Wisconsin Electric Power Company


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and are primarily engaged in the business of generating and distributing electricity in Wisconsin and the Upper Peninsula of Michigan, and distributing natural gas in Wisconsin. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies." We conduct our business primarily in three reportable segments, an electric utility segment, a natural gas utility segment, and a steam utility segment. See Note 21, Segment Information, for more information on our reportable business segments.

Corporate Strategy

Our goal is to create long-term value for WEC Energy Group's stockholders and our customers by focusing on the following:

Reliability

We have made significant reliability related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution network.

Our investment in reliability related projects has been very successful. In October 2015, We Energies was named the most reliable utility in the Midwest by PA Consulting Group for the fifth year in a row. We Energies received the ReliabilityOneTM Award, an annual award that recognizes utilities that excel in delivering reliable electric service.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. We have provided some examples from our generating fleet.

VAPP is a co-generation plant in Milwaukee that was constructed in 1968. The plant originally utilized coal to produce electricity and steam; however, the plant's fuel source was converted to natural gas with construction completed in November 2015. Changing the fuel source is expected to reduce operating costs and enhance environmental performance without decreasing the plant’s capacity.

We received approval from the PSCW to make changes at the Oak Creek Expansion units to enable them to burn coal from the Powder River Basin (PRB) in the Western United States. The coal plant was originally designed to burn coal mined from the Eastern United States, but the price of that coal increased relative to the PRB coal in recent years. This project is expected to create flexibility and enable 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.

Financial Discipline

A strong adherence to financial discipline is essential to earning our authorized ROE and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment that are no longer performing as intended, or have an unacceptable risk profile.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

2015 Form 10-K
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Wisconsin Electric Power Company




RESULTS OF OPERATIONS

Consolidated Earnings

The following table compares our consolidated results:
 
 
Year Ended December 31
(in millions)
 
2015
 
2014
 
2013
Electric utility segment
 
$
582.7

 
$
565.6

 
$
533.2

Natural gas utility segment
 
60.6

 
77.2

 
69.8

Steam utility segment
 
5.6

 
7.6

 
2.9

Total operating income
 
648.9

 
650.4

 
605.9

Equity in earnings of transmission affiliate
 
47.8

 
57.9

 
60.2

Other income, net
 
11.2

 
8.7

 
17.4

Interest expense
 
119.0

 
116.5

 
121.4

Income before income taxes
 
588.9

 
600.5

 
562.1

Income tax expense
 
212.0

 
222.6

 
200.9

Preferred stock dividend requirements
 
1.2

 
1.2

 
1.2

Net income attributed to common shareholder
 
$
375.7

 
$
376.7

 
$
360.0


Electric Utility Segment Contribution to Operating Income

Electric utility margins are defined as electric revenues less fuel and purchased power costs. We believe that electric utility margins provide a more meaningful basis for evaluating electric utility operations than electric revenues since the majority of prudently incurred fuel and purchased power costs are passed through to customers in current rates under enacted fuel rules.
 
 
Year Ended December 31
(in millions)
 
2015
 
2014
 
2013
Electric revenues
 
$
3,413.4

 
$
3,401.1

 
$
3,308.7

Fuel and purchased power
 
1,141.4

 
1,214.0

 
1,144.5

Total electric margins
 
2,272.0

 
2,187.1

 
2,164.2

 
 
 
 
 
 
 
Other operation and maintenance
 
1,309.1

 
1,268.9

 
1,323.8

Depreciation and amortization
 
270.4

 
244.1

 
201.5

Property and revenue taxes
 
109.8

 
108.5

 
105.7

Operating income
 
$
582.7

 
$
565.6

 
$
533.2


The following tables provide information on delivered volumes by customer class and weather statistics:
 
 
Year Ended December 31
 
 
MWh (in thousands)
Electric Sales Volumes
 
2015
 
2014
 
2013
Customer class
 
 
 
 
 
 
Residential
 
7,789.3

 
7,946.3

 
8,141.9

Small commercial and industrial
 
8,797.0

 
8,805.1

 
8,860.4

Large commercial and industrial
 
9,085.7

 
7,393.3

 
8,673.4

Other
 
147.7

 
148.7

 
152.3

Total retail
 
25,819.7

 
24,293.4

 
25,828.0

Wholesale
 
1,234.0

 
1,852.8

 
1,953.5

Resale
 
8,577.6

 
6,497.9

 
4,382.7

Total sales in MWh
 
35,631.3

 
32,644.1

 
32,164.2

Electric customer choice*
 
445.2

 
2,440.0

 
813.0


*
Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.

2015 Form 10-K
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Wisconsin Electric Power Company


 
 
Year Ended December 31
 
 
Degree Days
Weather *
 
2015
 
2014
 
2013
Heating (6,659 normal)
 
6,468

 
7,616

 
7,233

Cooling (712 normal)
 
622

 
464

 
688


*
Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

2015 Compared with 2014

Operating Income

Operating income at the electric utility segment increased $17.1 million and was driven by an $84.9 million increase in electric margins. The increase in electric margins resulted from:

A $38.4 million increase as a result of the PSCW rate order, effective January 1, 2015. See Note 19, 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 19, 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. See Note 20, Michigan Settlement, for more information. A large portion of this increase in margins was offset by higher transmission expense included in other operation and maintenance expense.

A $10.4 million increase in positive collections of fuel and purchased power costs as compared with costs approved in rates in 2015, as compared with 2014. Under the fuel rule, we defer under or over-collections of certain fuel and purchased power costs that exceed a 2% price variance from the costs included in rates, and the remaining variance impacts margins.

A $6.2 million increase primarily due to lower fly ash removal costs in 2015. These costs are not included in the fuel rule recovery mechanism.

A partially offsetting $22.3 million decrease in electric margins 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. Certain wholesale customers have provisions in their contracts which allow them to reduce the amount of energy we provide to them.

These increases in operating income were partially offset by:

A $40.2 million increase in other operation and maintenance expense, driven by:

A $48.6 million increase from higher PTF lease expense and associated operating and maintenance expenses as approved in our PSCW rate order, effective January 1, 2015.

A $16.0 million increase in transmission expense from MISO and ATC related to the iron ore mines returning as customers in February 2015.

These increases in other operation and maintenance expenses were partially offset by:


2015 Form 10-K
33
Wisconsin Electric Power Company


A $7.4 million decrease in electric distribution costs and amortization of design software, partially offset by higher electric maintenance costs.

A $5.8 million decrease in employee benefits in 2015 driven by lower performance units share-based compensation, deferred compensation, and medical costs.

Other decreases in other operation and maintenance expenses that were not individually significant.

A $26.3 million increase in other depreciation and amortization expense, driven by:

An overall increase in utility plant in service in 2015. During 2015, we completed the conversion of the fuel source for VAPP from coal to natural gas.

A new depreciation study approved by the PSCW, effective January 1, 2015.

A $7.7 million reduction in income received in 2015 from a Treasury Grant associated with the completion of our biomass plant in 2013. The lower grant income corresponds to lower bill credits provided to our retail electric customers in Wisconsin.

2014 Compared with 2013

Operating Income

Operating income at the electric utility segment increased $32.4 million, driven by:

A $120.9 million increase in sales for resale in 2014 due to higher sales into the MISO Energy Markets as a result of Michigan's alternative electric supplier program and increased availability of our generating units. The margins on these sales are used to reduce fuel costs for our retail customers.

A $59.4 million increase in other operating revenues in 2014, primarily driven by the recognition of $56.4 million related to revenues under the SSR agreement with MISO. See Note 20, Michigan Settlement, for more information.

A $54.9 million decrease in other operation and maintenance expense in 2014. This decrease was primarily driven by lower benefit costs related to pension, postretirement, and medical costs. Our operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages, and amortization of regulatory assets.

A $38.3 million increase in Wisconsin net retail pricing in 2014, primarily related to our PSCW rate order, effective January 1, 2013.

These increases in operating income were partially offset by:

A $78.4 million decrease in large commercial and industrial sales in 2014 due to the two iron ore mines switching to an alternative electric supplier in September 2013.

A $69.5 million increase in electric fuel and purchased power costs in 2014. This increase was primarily driven by a 1.5% increase in total MWh sales and higher generating costs due to an increase in natural gas prices.

A $42.6 million increase in depreciation and amortization expense in 2014. The increase was partially driven by lower income received from a Treasury Grant in 2014. During 2014, we recognized $17.4 million of income related to a Treasury Grant associated with the completion of the biomass plant, compared to $48.0 million in 2013. The lower grant income corresponds to the lower bill credits provided to our retail electric customers in Wisconsin in 2014. In addition, an overall increase in utility plant in service as a result of the biomass plant that went into service in November 2013 contributed to the increase in depreciation and amortization expense.

A $45.8 million decrease in electric revenues related to unseasonably cool summer weather in 2014. As measured by cooling degree days, 2014 was 36.6% cooler than normal and 32.6% cooler than 2013 due to mild second and third quarters. The unfavorable impact of the cool summer weather was partially offset by the cold winter weather.


2015 Form 10-K
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Wisconsin Electric Power Company


Residential sales decreased 2.4%, primarily due to the weather.

Sales to our large commercial and industrial customers decreased 14.8% primarily due to the loss of the two iron ore mines in Michigan. If the mines were excluded, sales to our large commercial and industrial customers would have decreased 1.1%.

Natural Gas Utility Segment Contribution to Operating Income

Natural gas utility margins are defined as natural gas revenues less the cost of natural gas sold. Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues, since prudently incurred natural gas commodity costs are passed through to our customers in current rates. The average per-unit cost of natural gas sold decreased 32.4% in 2015 and increased 44.7% in 2014, neither of which had an impact on margins.
 
 
Year Ended December 31
(in millions)
 
2015
 
2014
 
2013
Natural gas revenues
 
399.7

 
614.2

 
451.9

Cost of natural gas sold
 
244.6

 
432.6

 
278.3

Total natural gas margins
 
155.1

 
181.6

 
173.6

 
 
 
 
 
 
 
Other operation and maintenance
 
59.2

 
70.0

 
75.0

Depreciation and amortization
 
29.1

 
30.5

 
25.5

Property and revenue taxes
 
6.2

 
3.9

 
3.3

Operating income
 
$
60.6

 
$
77.2

 
$
69.8


The following tables provide information on delivered volumes by customer class and weather statistics:
 
 
Year Ended December 31
 
 
Therms (in millions)
Natural Gas Sales Volumes
 
2015
 
2014
 
2013
Customer class
 
 
 
 
 
 
Residential
 
341.2

 
399.3

 
380.8

Commercial and industrial
 
194.5

 
240.4

 
215.7

Other
 
0.6

 
0.7

 
0.6

Total retail
 
536.3

 
640.4

 
597.1

Transport
 
342.8

 
343.1

 
327.6

Total sales in therms
 
879.1

 
983.5

 
924.7


 
 
Year Ended December 31
 
 
Degree Days
Weather *
 
2015
 
2014
 
2013
Heating (6,659 normal)
 
6,468

 
7,616

 
7,233


*
Normal heating degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

2015 Compared with 2014

Operating Income

Operating income at the natural gas utility segment decreased $16.6 million, driven by:

A $26.5 million decrease in natural gas margins in 2015 resulting from:

A $14.9 million decrease from sales volume variances 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.