WEC Energy Group, Inc. (WEC, NYSE)
Industry: Utilities - Regulated Electric
Annual report, fiscal year 2015


## IT'S ONLY THE
BEGINNING



## THE NEW LOOK — WEC ENERGY GROUP

## A LEADER IN THE ENERGY INDUSTRY

WEC Energy Group is one of the nation’s largest electric and natural gas utilities, with deep operational expertise, scale, and the financial resources to meet the region’s future energy needs. We provide vital services to nearly 4.4 million customers in Wisconsin, Illinois, Michigan, and Minnesota.






## TOTAL SHAREHOLDER RETURN

Over the past decade, WEC Energy Group has consistently delivered among the best total returns in the industry. The illustration below demonstrates our stock price appreciation plus the compounded effect of dividend growth over the past decade.



FINANCIAL HIGHLIGHTS







a. Adjusted earnings per share. Excludes acquisition-related costs totaling 6 cents per share in 2014 and 39 cents per share in 2015. 2015 earnings per share reflect Wisconsin Energy's stand-alone earnings which exclude Integrys earnings per share of 47 cents and the impact of additional shares outstanding of 47 cents per share. For a full reconciliation, see Appendix B attached to the proxy statement.

b. Annualized based on 4th quarter 2015 dividend of $0.4575.

c. Included in long-term debt are various issuances of Junior Subordinated Notes. A majority of the rating agencies currently attribute at least 50% common equity to these securities. For further details, see Capital Resources under Liquidity and Capital Resources in the 2015 annual financial statements.




GALE E. KLAPPA
Chairman and
Chief Executive Officer

## TO OUR STOCKHOLDERS,

It’s only the beginning. It’s only just the start.

Those lyrics — from the sound track of a different era — describe the state of our company today as we close the chapter on an historic year.

As we’ve reported to you, we completed the acquisition of Integrys on June 29 — forming WEC Energy Group, the leading electric and natural gas utility system in the Midwest. WEC Energy Group is now the eighth largest natural gas distribution company in the country and one of the 15 largest investor-owned utility systems in the United States. We have a strong platform for growth — a platform focused on the energy infrastructure needs of 4.4 million customers in Wisconsin, Illinois, Michigan, and Minnesota.

And we continue to see tremendous opportunity in the framework of the new company. WEC Energy Group



has the scale, scope, technical depth, geographic reach, and financial resources to thrive in our consolidating industry. We’re leveraging these strengths and incorporating best practices across the organization to streamline our operations and reduce costs.

## WEC Energy Group is now the eighth largest natural gas distribution company in the country and one of the 15 largest investor-owned utility systems in the United States.

Our 2016 budgets and operating plans are in place to achieve our first growth target — an increase of 6 to 8 percent in earnings per share. And for the longer term, beyond 2016, we see earnings per share growth of 5 to 7 percent a year.

## A RECORD OF ACHIEVEMENT

Clearly, the work on our post-acquisition success plan progressed well during the second half of 2015. But we recorded a number of other significant achievements that demonstrate our focus on execution … on delivering world-class results … and on creating enduring value for our customers and stockholders.

For example, We Energies was named the most reliable utility in the Midwest for the fifth consecutive year. And in national studies, We Energies again ranked in the top quartile in the Midwest for customer service and power quality — and in the top quartile nationally for customer service. In addition, Wisconsin Public Service — based in Green Bay and now part of the WEC family — was ranked number two in the Midwest for overall customer satisfaction among mid-sized utilities.

We also reached a milestone for employee safety at We Energies, achieving the safest year in more than 115 years of operation.

We invested nearly $780 million in our core Wisconsin Energy business with all major projects on time and on budget. During the year, we completed the conversion of our Valley Power Plant near downtown Milwaukee from coal to natural gas. And on November 1, we placed into commercial service an 85-mile expansion of our natural gas distribution network in western Wisconsin — the largest expansion of our gas distribution system in our history. In addition, we saw an uptick in customer growth. As we closed 2015, We Energies was serving approximately 6,500 more electric customers and more than 8,500 natural gas customers than we were a year ago.

From a financial standpoint, we continued to deliver solid earnings growth. Through disciplined cost control and effective planning, we delivered record earnings in 2015, despite a very warm fourth quarter. In fact, Milwaukee experienced the warmest December in its history, surpassing the former record set back in 1877.

Through dividends, we returned a total of $580 million of cash to our shareholders. For legacy Wisconsin Energy shareholders, 2015 marked a record year for dividend distributions.

## Through disciplined cost control and effective planning, we delivered record earnings in 2015.

Then, in January, as we opened the new year, our board declared a quarterly cash dividend of 49.50 cents a share — an increase of 8.2 percent over the previous quarterly dividend. This raised the annual dividend rate to $1.98 a share. Going forward, we expect to pay out 65 to 70 percent of our earnings in dividends, and we project our dividends to grow in line with the growth in earnings per share.

## SIGNIFICANT INVESTMENT
OPPORTUNITIES AHEAD

In today’s digital, just-in-time world, our customers rely to a greater degree than ever before on the continuous flow of electricity and natural gas. Our energy networks are literally the lifelines of society. And we’re vigilant about the need to maintain the safety of our operations as our infrastructure ages and as cyber security threats increase.

Looking ahead, assessing the reliability needs of our customers, we expect to invest at least $1.5 billion a year in new, modern infrastructure.

We estimate that more than half of our capital investments — about $800 million annually — will be dedicated to our natural gas delivery business, providing safer and more reliable infrastructure and extending our distribution



network to customers across the Midwest. We also plan to invest about $400 million a year to upgrade and harden our electric delivery networks.

## Looking ahead, assessing the needs of our customers, we expect to invest at least $1.5 billion a year in new, modern infrastructure.

We expect the remaining investments — approximately $300 million a year — will be focused on our generating fleet and corporate infrastructure. I should point out, however, that these projections do not include any capital that would be needed for compliance with the Clean Power Plan.

As you may know, the Clean Power Plan was introduced last year by the federal Environmental Protection Agency. The ultimate goal of this new regulation is to dramatically reduce carbon dioxide ( \( CO_{2} \) ) emissions across the United States by the year 2030. A specific target has been set for each state. In Wisconsin, for example, the plan calls for a 41 percent reduction in  \( CO_{2} \)  emissions with an interim target set for 2022.

The U.S. Supreme Court has stayed the regulation. However, if the plan survives all legal challenges, additional investments in transmission, renewable energy, and natural gas fueled power plants may well be needed.

I would add that during 2015, more than 50 percent of the electricity we delivered to our customers was already derived from low or no carbon sources such as natural gas, nuclear fuel, wind farms, and hydroelectric facilities.

## PROGRESS CONTINUES ON
MULTI-YEAR PROJECTS

As we help to chart the energy future of the region, we’re also making good progress on three multi-year projects that will clearly benefit our customers: the Twin Falls Hydroelectric rebuild, the fuel flexibility initiative at our Oak Creek expansion units, and the replacement of aging gas mains in Chicago.

After more than 100 years of operation, we’re building a new power house and adding spillway capacity to meet current federal standards at our Twin Falls Hydroelectric Plant on the border of Wisconsin and Michigan’s Upper Peninsula. The project is on time and on budget. We’re targeting commercial operation for this summer. And we continue to forecast a total investment of $60 to $65 million.

We’re also working to add fuel flexibility at our Oak Creek expansion units. These units initially were permitted to burn bituminous coal. But given the current cost differential between bituminous coal and Powder River Basin coal, blending the two types of fuel could save our customers $25 to $50 million a year.

Work is underway to expand our coal storage capability at the Oak Creek site. The larger site should be ready by early next year.

Also, the first capital improvement inside the plant was made on one of the units during a planned outage last fall. We plan to upgrade the second unit this spring. Our share of these investments for the new Oak Creek units is targeted at approximately $80 million.

## We have a strong platform for growth focused on the energy infrastructure needs of 4.4 million customers in Wisconsin, Illinois, Michigan, and Minnesota.

## FOCUS ON IMPROVEMENT IN ILLINOIS

We’re also moving forward on the Accelerated Main Replacement Program at Peoples Gas in Chicago. This is one of the largest natural gas infrastructure projects in the country. The program calls for the replacement of approximately 2,000 miles of Chicago’s aging gas pipelines. I’m pleased to report that over the past six months, we’ve taken significant steps to improve the management and performance of this project.

We engaged a nationally recognized engineering firm to conduct an extensive, independent review of the work plan and cost estimates. As part of our fresh start in Chicago, we filed a plan in November that lays out our top priorities for the next three years. Key components of the plan include: removal and replacement of more than 250 miles of aging cast-iron pipes in the neighborhoods most at risk, and regular updates to the Illinois Commerce Commission and other stakeholders to keep them fully informed of our progress.




President Allen Leverett and Chairman and Chief Executive Gale Klappa at Discovery World in Milwaukee.

I’m confident that the steps we’re taking will provide Chicagoans with the safe, modern, natural gas delivery system they deserve.

So in summary, these are exciting times filled with opportunity — and change — for our company.

## LEADERSHIP TRANSITION

And speaking of change, this will be my last message to you as the chief executive of our company. Effective May 1, I will be retiring as chief executive officer. After that date, I will continue to serve the company as non-executive chairman of the board.

I’m very pleased to tell you that Allen Leverett will succeed me as chief executive. He has also been appointed to our board of directors.

It seems like just a short time ago that Allen and I joined Wisconsin Energy in 2003. Allen has been a key contributor to our success all along the way — first as chief financial officer, then as the leader of our power generation group, and most recently as president of the parent firm and our Wisconsin, Minnesota, and Michigan utilities. It's been my great pleasure to have known and worked with Allen for more than 20 years. The depth of his experience, his management skills, and his focus on execution make him the ideal person to lead our company through a time of continuing change in the energy industry.

As I close this letter, I want to express my sincere gratitude for the encouragement and support you’ve given me over the past 13 years.

I believe we’ve built something special here … with a focus on customer satisfaction and accountability that is second to none in our industry. Our company today is exceptionally well positioned for the future. But what gives me great optimism is my firmly held belief that … it’s only the beginning.

Sincerely,



Gale E. Klappa
Chairman and Chief Executive Officer
March 1, 2016







## EXPANDING NATURAL GAS SERVICE
IN CENTRAL WISCONSIN

A section of large-diameter pipe is lowered into a trench as part of an 85-mile expansion project to address reliability concerns and serve new natural gas customers in west central Wisconsin. Completed in November, this was the largest expansion of our natural gas distribution network in history.







INVESTING IN TECHNOLOGY TO
ENSURE SAFETY AND RELIABILITY
After more than two years of construction, the
We Energies System Operations Center opened in August.
The center is equipped with the most sophisticated
technology available to protect the safety and reliability
of the grid.







UPGRADING CHICAGO'S
AGING INFRASTRUCTURE
Peoples Gas is planning to replace approximately
2,000 miles of Chicago's aging natural gas pipelines —
one of the largest modernization programs in the country.
A construction crew guides a 45-foot section of
12-inch-diameter pipe in front of Navy Pier.







## HONORING OUR HEROES

On Sept. 12, 2015, We Energies sponsored a Stars and Stripes Honor Flight — transporting World War II and Korean War veterans to Washington, D.C., to visit their memorials.

Approximately 180 veterans made the trip on a 747 airliner. Each veteran traveled with a guardian, several of them company employees, who served as companions for the journey.

We Energies employees also expressed their gratitude by writing more than 500 thank you cards and notes for the “mail call” portion of the flight.

The Honor Flight is a powerful and emotional day for the veterans, filled with patriotism, memories, camaraderie, and an outpouring of appreciation. We Energies has supported the program since its inception in 2008.

Photo courtesy of Visual Image Photography.




## 2015 ANNUAL FINANCIAL STATEMENTS
AND REVIEW OF OPERATIONS



## TABLE OF CONTENTS

<table><tr><td></td><td>Page</td></tr><tr><td>Glossary of Terms and Abbreviations</td><td>F-3</td></tr><tr><td>Cautionary Statement Regarding Forward Looking Information</td><td>F-5</td></tr><tr><td>Business of the Company</td><td>F-7</td></tr><tr><td>Management&#x27;s Discussion and Analysis of Financial Condition and Results of Operations</td><td>F-8</td></tr><tr><td>Quantitative and Qualitative Disclosures About Market Risk</td><td>F-30</td></tr><tr><td>Consolidated Financial Statements</td><td>F-31</td></tr><tr><td>Notes to Consolidated Financial Statements</td><td>F-38</td></tr><tr><td>Reports of Independent Registered Public Accounting Firm</td><td>F-89</td></tr><tr><td>Internal Control Over Financial Reporting</td><td>F-91</td></tr><tr><td>Comparative Selected Financial Data and Other Statistics</td><td>F-92</td></tr><tr><td>Performance Graph</td><td>F-93</td></tr><tr><td>Market for Our Common Equity and Related Stockholder Matters</td><td>F-94</td></tr><tr><td>Board of Directors</td><td>F-95</td></tr><tr><td>Officers</td><td>F-96</td></tr></table>



## 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:

<table><tr><td colspan="2">Subsidiaries and Affiliates</td></tr><tr><td>ATC</td><td>American Transmission Company LLC</td></tr><tr><td>Bostco</td><td>Bostco LLC</td></tr><tr><td>DATC</td><td>Duke-American Transmission Company</td></tr><tr><td>ERGSS</td><td>Elm Road Generating Station Supercritical, LLC</td></tr><tr><td>Integrys</td><td>Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)</td></tr><tr><td>ITF</td><td>Integrys Transportation Fuels, LLC</td></tr><tr><td>MERC</td><td>Minnesota Energy Resources Corporation</td></tr><tr><td>MGU</td><td>Michigan Gas Utilities Corporation</td></tr><tr><td>NSG</td><td>North Shore Gas Company</td></tr><tr><td>PDL</td><td>WPS Power Development LLC</td></tr><tr><td>PELLC</td><td>Peoples Energy, LLC</td></tr><tr><td>PGL</td><td>The Peoples Gas Light and Coke Company</td></tr><tr><td>WBS</td><td>WEC Business Services, LLC</td></tr><tr><td>We Power</td><td>W.E. Power, LLC</td></tr><tr><td>WECC</td><td>Wisconsin Energy Capital Corporation</td></tr><tr><td>Wisconsin Electric</td><td>Wisconsin Electric Power Company</td></tr><tr><td>Wisconsin Gas</td><td>Wisconsin Gas LLC</td></tr><tr><td>Wispark</td><td>Wispark LLC</td></tr><tr><td>Wisvest</td><td>Wisvest LLC</td></tr><tr><td>WPS</td><td>Wisconsin Public Service Corporation</td></tr></table>

<table><tr><td colspan="2">Certain Assets</td></tr><tr><td>MCPP</td><td>Milwaukee County Power Plant</td></tr><tr><td>OC 1</td><td>Oak Creek Expansion Unit 1</td></tr><tr><td>OC 2</td><td>Oak Creek Expansion Unit 2</td></tr><tr><td>PIPP</td><td>Presque Isle Power Plant</td></tr><tr><td>PSGS</td><td>Paris Generating Station</td></tr><tr><td>PWGS 1</td><td>Port Washington Generating Station Unit 1</td></tr><tr><td>PWGS 2</td><td>Port Washington Generating Station Unit 2</td></tr><tr><td>VAPP</td><td>Valley Power Plant</td></tr></table>

<table><tr><td colspan="2">Federal and State Regulatory Agencies</td></tr><tr><td>EPA</td><td>United States Environmental Protection Agency</td></tr><tr><td>FERC</td><td>Federal Energy Regulatory Commission</td></tr><tr><td>ICC</td><td>Illinois Commerce Commission</td></tr><tr><td>MDEQ</td><td>Michigan Department of Environmental Quality</td></tr><tr><td>MPSC</td><td>Michigan Public Service Commission</td></tr><tr><td>MPUC</td><td>Minnesota Public Utilities Commission</td></tr><tr><td>PSCW</td><td>Public Service Commission of Wisconsin</td></tr><tr><td>SEC</td><td>Securities and Exchange Commission</td></tr><tr><td>WDNR</td><td>Wisconsin Department of Natural Resources</td></tr></table>

<table><tr><td colspan="2">Accounting Terms</td></tr><tr><td>AFUDC</td><td>Allowance for Funds Used During Construction</td></tr><tr><td>ARO</td><td>Asset Retirement Obligation</td></tr><tr><td>ASC</td><td>Accounting Standards Codification</td></tr><tr><td>ASU</td><td>Accounting Standards Update</td></tr><tr><td>CWIP</td><td>Construction Work in Progress</td></tr><tr><td>FASB</td><td>Financial Accounting Standards Board</td></tr><tr><td>GAAP</td><td>Generally Accepted Accounting Principles</td></tr><tr><td>OPEB</td><td>Other Postretirement Employee Benefits</td></tr></table>



Environmental Terms

<table><tr><td>Act 141</td><td>2005 Wisconsin Act 141</td></tr><tr><td>CAA</td><td>Clean Air Act</td></tr><tr><td>CO2</td><td>Carbon Dioxide</td></tr><tr><td>CSAPR</td><td>Cross-State Air Pollution Rule</td></tr><tr><td>GHG</td><td>Greenhouse Gas</td></tr><tr><td>MATS</td><td>Mercury and Air Toxics Standards</td></tr><tr><td>NAAQS</td><td>National Ambient Air Quality Standards</td></tr><tr><td>NOx</td><td>Nitrogen Oxide</td></tr><tr><td>SO2</td><td>Sulfur Dioxide</td></tr><tr><td>WPDES</td><td>Wisconsin Pollutant Discharge Elimination System</td></tr></table>

Measurements

<table><tr><td>Bcf</td><td>Billion Cubic Feet</td></tr><tr><td>Btu</td><td>British Thermal Unit(s)</td></tr><tr><td>Dth</td><td>Dekatherm(s) (One Dth equals one million Btu)</td></tr><tr><td>kW</td><td>Kilowatt(s) (One kW equals one thousand Watts)</td></tr><tr><td>kWh</td><td>Kilowatt-hour(s)</td></tr><tr><td>MDth</td><td>One thousand Dekatherms</td></tr><tr><td>MW</td><td>Megawatt(s) (One MW equals one million Watts)</td></tr><tr><td>MWh</td><td>Megawatt-hour(s)</td></tr></table>

Other Terms and Abbreviations

<table><tr><td>ALJ</td><td>Administrative Law Judge</td></tr><tr><td>AMRP</td><td>Accelerated Natural Gas Main Replacement Program</td></tr><tr><td>ARRs</td><td>Auction Revenue Rights</td></tr><tr><td>CNG</td><td>Compressed Natural Gas</td></tr><tr><td>Compensation Committee</td><td>Compensation Committee of the Board of Directors</td></tr><tr><td>CPCN</td><td>Certificate of Public Convenience and Necessity</td></tr><tr><td>Exchange Act</td><td>Securities Exchange Act of 1934, as amended</td></tr><tr><td>FTRs</td><td>Financial Transmission Rights</td></tr><tr><td>GCRM</td><td>Gas Cost Recovery Mechanism</td></tr><tr><td>LMP</td><td>Locational Marginal Price</td></tr><tr><td>Merger Agreement</td><td>Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation</td></tr><tr><td>MISO</td><td>Midcontinent Independent System Operator, Inc.</td></tr><tr><td>MISO Energy Markets</td><td>MISO Energy and Operating Reserves Market</td></tr><tr><td>N/A</td><td>Not Applicable</td></tr><tr><td>NYMEX</td><td>New York Mercantile Exchange</td></tr><tr><td>Point Beach</td><td>Point Beach Nuclear Power Plant</td></tr><tr><td>PTF</td><td>Power the Future</td></tr><tr><td>ROE</td><td>Return on Equity</td></tr><tr><td>RTO</td><td>Regional Transmission Organization</td></tr><tr><td>SSR</td><td>System Support Resource</td></tr><tr><td>Treasury Grant</td><td>Section 1603 Renewable Energy Treasury Grant</td></tr></table>



# 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, dividend payout ratios, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those 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, us, or any of our subsidiaries;

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



- Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances;

- The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;

- Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;

- The direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;

- The financial performance of ATC and its corresponding contribution to our earnings, as well as the ability of ATC and DATC to obtain the required approvals for their transmission projects;

- The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;

- Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;

- Advances in technology that result in competitive disadvantages and create the potential for impairment of existing assets;

- The terms and conditions of the governmental and regulatory approvals of the acquisition of Integrys that could reduce anticipated benefits and our ability to successfully integrate the operations of the combined company;

- The risk associated with the values of goodwill and other intangible assets and their possible impairment;

- Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;

- The timing and outcome of any audits, disputes, and other proceedings related to taxes;

- The effect of accounting pronouncements issued periodically by standard-setting bodies; and

- Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.

We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.



# BUSINESS OF THE COMPANY

WEC Energy Group, Inc. was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys Energy Group and changed its name to WEC Energy Group, Inc. We maintain our principal executive offices in Milwaukee, Wisconsin.

In this report, when we refer to "us," "we," "our," or "ours," we are referring to WEC Energy Group. The term "utility" refers to the regulated activities of the electric and natural gas utility companies, while the term "non-utility" refers to the activities of the electric and natural gas utility companies that are not regulated, as well as We Power. The term "nonregulated" refers to activities at WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF.

Our wholly owned subsidiaries are primarily engaged in the business of providing regulated electricity service in Wisconsin and Michigan and regulated natural gas service in Wisconsin, Illinois, Michigan, and Minnesota. In addition, we have an approximately 60% equity interest in ATC, an electric transmission company operating in four states. At December 31, 2015, we conducted our operations in the six reportable segments discussed below.

Wisconsin Segment: The Wisconsin segment primarily consists of the electric and natural gas utility and non-utility operations of Wisconsin Electric, Wisconsin Gas, and WPS, including Wisconsin Electric's electric and WPS's electric and natural gas operations in the Upper Peninsula of Michigan. At December 31, 2015, these companies served approximately 1,589,300 electric customers and 1,425,700 natural gas customers. This segment also includes steam service to approximately 430 Wisconsin Electric steam customers in metropolitan Milwaukee, Wisconsin.

Illinois Segment: The Illinois segment consists of the natural gas utility and non-utility operations of PGL and NSG. The approximately 992,200 natural gas customers served by PGL and NSG at December 31, 2015 were located in Chicago and the northern suburbs of Chicago. PGL also owns and operates a 38.3 Bcf natural gas storage field in central Illinois.

Other States Segment: The other states segment includes the natural gas utility and non-utility operations of MERC and MGU. These companies served approximately 402,600 natural gas customers at December 31, 2015, with MERC serving customers in various cities and communities throughout Minnesota, and MGU serving customers in the southern portion of lower Michigan.

Electric Transmission Segment: The electric transmission segment includes our approximate 60% ownership interest in ATC, a federally regulated electric transmission company. ATC owns, maintains, monitors, and operates electric transmission systems in Wisconsin, Michigan, Illinois, and Minnesota.

We Power Segment: We Power, through wholly owned subsidiaries, owns and leases to Wisconsin Electric, generating facilities constructed as part of our PTF strategy. PWGS 1 and PWGS 2, both natural gas-fired generating units, are being leased to Wisconsin Electric under long-term leases that run for 25 years. OC 1 and OC 2, both coal-fired generating units, are being leased to Wisconsin Electric under long-term leases that run for 30 years.

Corporate and Other Segment: The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, and the PELLC holding company, as well as the operations of Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF. Bostco and Wispark develop and invest in real estate, and combined they had $72.7 million in real estate holdings at December 31, 2015. WBS is a wholly owned centralized service company that provides administrative and general support services to our regulated utilities, as well as certain services to our nonregulated entities. PDL owns distributed renewable projects, primarily solar, and a natural gas-fired cogeneration facility in Wisconsin. ITF, which provides CNG products and services in multiple states, was recorded as held for sale at December 31, 2015. We completed the sale of ITF on February 29, 2016.



# MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

# CORPORATE DEVELOPMENTS

## INTRODUCTION

We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in ATC (a federally regulated electric transmission company), and non-utility electric operations through our We Power business. See Note 24, Segment Information, for more information on our reportable business segments.

## CORPORATE STRATEGY

Our goal is to create long-term value for our 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.

- The West Central Gas Expansion project went into service in early November 2015. This natural gas lateral will allow Wisconsin Gas to improve the reliability of its natural gas distribution network in the western part of Wisconsin and better meet customer demand.

- PGL is continuing to work on its gas system modernization program (AMRP), which primarily involves replacing old cast and ductile iron gas pipes and facilities in the city of Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system.

- WPS continues work on its System Modernization Reliability Project, which involves modernizing parts of its electric distribution system by burying or upgrading lines. The project focuses on electric lines that currently have the lowest reliability in its system, primarily in rural areas that are heavily forested.

Our investment in reliability related projects has been very successful. In October 2015, We Energies, the trade name of Wisconsin Electric and Wisconsin Gas, was named the most reliable utility in the Midwest by PA Consulting Group for the fifth year in a row. We Energies received the ReliabilityOne \( ^{TM} \)  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.

- Wisconsin Electric 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 meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, attractive dividends, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment and entire business units that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile.

• See Note 2, Acquisition, for information about the recent acquisition of Integrys.

• Our primary investment opportunities are in three areas: our regulated utility business; our investment in ATC; and our generation plants within our We Power segment. In addition to the projects discussed above, other on-going projects are discussed in more detail within Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

• See Note 3, Dispositions, for more information on the pending sale of ITF.

## Exceptional Customer Care

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

## RESULTS OF OPERATIONS

## CONSOLIDATED EARNINGS

The following table compares our consolidated results:

<table><tr><td rowspan="2">(in millions, except per share data)</td><td colspan="4">Year Ended December 31</td></tr><tr><td>2015</td><td>2014</td><td>2013</td><td></td></tr><tr><td>Wisconsin</td><td>$ 884.2</td><td>$ 770.2</td><td>$ 719.4</td><td></td></tr><tr><td>Illinois</td><td>78.1</td><td>—</td><td>—</td><td></td></tr><tr><td>Other states</td><td>6.0</td><td>—</td><td>—</td><td></td></tr><tr><td>We Power</td><td>373.4</td><td>368.0</td><td>366.6</td><td></td></tr><tr><td>Corporate and other</td><td>(91.2)</td><td>(26.1)</td><td>(5.9)</td><td></td></tr><tr><td>Total operating income</td><td>1,250.5</td><td>1,112.1</td><td>1,080.1</td><td></td></tr><tr><td>Electric transmission</td><td>96.1</td><td>66.0</td><td>68.5</td><td></td></tr><tr><td>Other income, net</td><td>58.9</td><td>13.4</td><td>18.8</td><td></td></tr><tr><td>Interest expense</td><td>331.4</td><td>240.3</td><td>250.9</td><td></td></tr><tr><td>Income before income taxes</td><td>1,074.1</td><td>951.2</td><td>916.5</td><td></td></tr><tr><td>Income tax expense</td><td>433.8</td><td>361.7</td><td>337.9</td><td></td></tr><tr><td>Preferred stock dividends of subsidiaries</td><td>1.8</td><td>1.2</td><td>1.2</td><td></td></tr><tr><td>Net income attributed to common shareholders</td><td>$ 638.5</td><td>$ 588.3</td><td>$ 577.4</td><td></td></tr><tr><td>Diluted earnings per share</td><td>$ 2.34</td><td>$ 2.59</td><td>$ 2.51</td><td></td></tr></table>

## 2015 Compared with 2014

Earnings increased $50.2 million in 2015, driven by a $30.1 million net increase in earnings due to the inclusion of Integrys's results, partially offset by acquisition costs recorded by us and our subsidiaries. Integrys was acquired on June 29, 2015. See Note 2, Acquisition, for more information. Also contributing to the increase was a $20.8 million pre-tax gain ($12.5 million after tax) from the sale of Minergy LLC and its remaining financial assets in June 2015.



## 2014 Compared with 2013

Earnings increased $10.9 million in 2014, driven by:

- A $50.8 million pre-tax ($30.5 million after tax) increase in operating income at Wisconsin Electric and Wisconsin Gas driven by lower operation and maintenance expense.

- A $10.6 million pre-tax ($6.4 million after tax) decrease in interest expense driven by lower debt levels and lower average interest rates on long-term debt.

These increases in our earnings were partially offset by:

- A $12.5 million decrease in earnings from acquisition costs that were recorded during 2014. See Note 2, Acquisition, for more information on the acquisition.

- An $8.1 million increase in income tax expense due to reduced tax benefits associated with lower Treasury Grant income and decreased AFUDC – Equity.

## WISCONSIN SEGMENT CONTRIBUTION TO OPERATING INCOME

For the periods presented in this report, our Wisconsin operations included operations for both Wisconsin Electric and Wisconsin Gas for all periods, and operations for WPS beginning July 1, 2015, due to the acquisition of Integrys and its subsidiaries.

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.

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 34.3% in 2015 and increased 45.8% in 2014, neither of which had an impact on margins.

<table><tr><td rowspan="2">(in millions)</td><td colspan="4">Year Ended December 31</td></tr><tr><td>2015</td><td colspan="2">2014</td><td>2013</td></tr><tr><td>Electric revenues</td><td>$ 4,068.5</td><td>$ 3,445.2</td><td>$ 3,348.3</td><td></td></tr><tr><td>Fuel and purchased power</td><td>1,369.3</td><td>1,228.1</td><td>1,158.1</td><td></td></tr><tr><td>Total electric margins</td><td>2,699.2</td><td>2,217.1</td><td>2,190.2</td><td></td></tr><tr><td>Natural gas revenues</td><td>1,122.6</td><td>1,496.1</td><td>1,113.7</td><td></td></tr><tr><td>Cost of natural gas sold</td><td>640.5</td><td>1,036.1</td><td>674.1</td><td></td></tr><tr><td>Total natural gas margins</td><td>482.1</td><td>460.0</td><td>439.6</td><td></td></tr><tr><td>Other operation and maintenance</td><td>1,741.0</td><td>1,462.7</td><td>1,522.0</td><td></td></tr><tr><td>Depreciation and amortization</td><td>408.6</td><td>323.2</td><td>272.2</td><td></td></tr><tr><td>Property and revenue taxes</td><td>147.5</td><td>121.0</td><td>116.2</td><td></td></tr><tr><td>Operating income</td><td>$ 884.2</td><td>$ 770.2</td><td>$ 719.4</td><td></td></tr></table>



The following tables provide information on delivered volumes by customer class and weather statistics:

<table><tr><td rowspan="3">Electric Sales Volumes</td><td colspan="3">Year Ended December 31</td></tr><tr><td colspan="3">MWh (in thousands)</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Customer class</td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>9,218.9</td><td>7,946.3</td><td>8,141.9</td></tr><tr><td>Small commercial and industrial</td><td>10,850.3</td><td>8,805.1</td><td>8,860.4</td></tr><tr><td>Large commercial and industrial</td><td>11,126.8</td><td>7,393.3</td><td>8,673.4</td></tr><tr><td>Other</td><td>162.6</td><td>148.7</td><td>152.3</td></tr><tr><td>Total retail</td><td>31,358.6</td><td>24,293.4</td><td>25,828.0</td></tr><tr><td>Wholesale</td><td>2,588.1</td><td>1,852.8</td><td>1,953.5</td></tr><tr><td>Resale</td><td>9,077.1</td><td>6,497.9</td><td>4,382.7</td></tr><tr><td>Total sales in MWh</td><td>43,023.8</td><td>32,644.1</td><td>32,164.2</td></tr><tr><td>Electric customer choice*</td><td>457.9</td><td>2,440.0</td><td>813.0</td></tr></table>

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

<table><tr><td rowspan="3">Natural Gas Sales Volumes</td><td colspan="3">Year Ended December 31</td></tr><tr><td colspan="3">Therms (in millions)</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Customer class</td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>859.4</td><td>911.5</td><td>872.0</td></tr><tr><td>Commercial and industrial</td><td>527.4</td><td>571.7</td><td>518.0</td></tr><tr><td>Total retail</td><td>1,386.8</td><td>1,483.2</td><td>1,390.0</td></tr><tr><td>Transport</td><td>1,428.5</td><td>1,087.5</td><td>1,052.8</td></tr><tr><td>Total sales in therms</td><td>2,815.3</td><td>2,570.7</td><td>2,442.8</td></tr></table>

<table><tr><td rowspan="3">Weather</td><td colspan="3">Year Ended December 31</td></tr><tr><td colspan="3">Degree Days</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Wisconsin Electric and Wisconsin Gas (1)</td><td></td><td></td><td></td></tr><tr><td>Heating (6,659 normal)</td><td>6,468</td><td>7,616</td><td>7,233</td></tr><tr><td>Cooling (712 normal)</td><td>622</td><td>464</td><td>688</td></tr><tr><td>WPS (2)</td><td></td><td></td><td></td></tr><tr><td>Heating (2,863 normal)</td><td>2,215</td><td></td><td></td></tr><tr><td>Cooling (364 normal)</td><td>396</td><td></td><td></td></tr></table>

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

(2) Normal heating and cooling degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin Weather Station. Degree days have been included beginning July 1, 2015.

## 2015 Compared with 2014

## Operating Income

Operating income at the Wisconsin segment increased $114.0 million, driven by a $122.8 million increase due to the inclusion of WPS operating income beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015. Without the inclusion of WPS operating income, operating income at the Wisconsin segment decreased $8.8 million in 2015.

Significant factors impacting the $8.8 million decrease in operating income were:

- An aggregate $35.8 million decrease in natural gas margins at Wisconsin Electric and Wisconsin Gas in 2015. This decrease was primarily driven by a $42.7 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. This decrease in margins was partially offset by a $6.4 million net



increase in margins as a result of the impact of the Wisconsin Electric and Wisconsin Gas PSCW rate orders, effective January 1, 2015. See Note 22, Regulatory Environment, for more information.

• An aggregate $25.5 million increase in other operation and maintenance expense at Wisconsin Electric and Wisconsin Gas in 2015. This increase was driven by:

A $48.6 million increase from higher PTF lease expense and associated operating and maintenance expenses as approved in Wisconsin Electric's 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:

A $16.1 million decrease in employee benefits in 2015 driven by lower performance units share-based compensation, deferred compensation, and medical costs.

A $9.3 million decrease in electric and natural gas distribution costs in 2015, related to amortization of design software, and maintenance costs.

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

• A $24.5 million increase in other depreciation and amortization expense at Wisconsin Electric and Wisconsin Gas, driven by:

An overall increase in utility plant in service in 2015. During 2015, Wisconsin Gas completed the Western Gas lateral project, and Wisconsin Electric completed the conversion of the fuel source for VAPP from coal to natural gas.

New depreciation studies approved by the PSCW for both the utilities, effective January 1, 2015.

A $7.7 million reduction in income received in 2015 from 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.

• A combined $6.0 million increase in property and revenue taxes at Wisconsin Electric and Wisconsin Gas in 2015.

These decreases in operating income were significantly offset by an $83.0 million increase in electric margins at Wisconsin Electric driven by:

• A $38.4 million increase as a result of the PSCW rate order, effective January 1, 2015. See Note 22, Regulatory Environment, for more information.

• A $35.0 million increase driven by the escrow accounting treatment of the SSR revenues in the PSCW rate order, effective January 1, 2015. See Note 22, Regulatory Environment, for more information.

• A $24.2 million increase due to the return of the iron ore mines as customers in February 2015. The two iron ore mines, which we served on an interruptible tariff rate, switched to an alternative electric supplier effective September 1, 2013. Effective February 1, 2015, the owner of the two mines returned them as retail customers. In 2015, we deferred, and expect to continue to defer, the margin from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. Michigan state law allows the mines to switch to an alternative electric supplier after sufficient notice. See Note 23, 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 at Wisconsin Electric.

• A $10.4 million increase in positive collections of fuel and purchased power costs compared with costs approved in rates in 2015, as compared with 2014. Under the fuel rule, Wisconsin Electric defers 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.

## 2014 Compared with 2013

## Operating Income

Operating income at the Wisconsin segment increased $50.8 million in 2014, 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 23, Michigan Settlement, for more information.

- A $59.3 million decrease in other operation and maintenance expense in 2014. This decrease was primarily driven by lower benefit costs related to pensions, 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 Wisconsin Electric's PSCW rate order, effective January 1, 2013.

- A $15.8 million increase in natural gas margins, primarily due to colder winter weather in 2014. We estimate that colder winter weather increased natural gas margins by approximately $11.2 million. As measured by heating degree days, 2014 was 5.3% colder than 2013 and 15.4% colder than normal.

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 $51.0 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 Wisconsin Electric's 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.

☐ 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%.

## ILLINOIS SEGMENT CONTRIBUTION TO OPERATING INCOME

<table><tr><td>(in millions)</td><td>2015</td></tr><tr><td>Natural gas revenues</td><td>$ 503.4</td></tr><tr><td>Cost of natural gas sold</td><td>133.2</td></tr><tr><td>Total natural gas margins</td><td>370.2</td></tr><tr><td>Other operation and maintenance</td><td>219.6</td></tr><tr><td>Depreciation and amortization</td><td>63.3</td></tr><tr><td>Property and revenue taxes</td><td>9.2</td></tr><tr><td>Operating income</td><td>$ 78.1</td></tr></table>

The following tables provide information on delivered volumes by customer class and weather statistics:

<table><tr><td>Natural Gas Sales Volumes</td><td>Therms (in millions)</td></tr><tr><td>Customer Class</td><td>2015</td></tr><tr><td>Residential</td><td>300.7</td></tr><tr><td>Commercial and industrial</td><td>63.2</td></tr><tr><td>Total retail</td><td>363.9</td></tr><tr><td>Transport</td><td>328.4</td></tr><tr><td>Total sales in terms</td><td>692.3</td></tr></table>

<table><tr><td>Weather  \( * \)</td><td>Degree Days</td></tr><tr><td>Heating (2,282 normal)</td><td>1,813</td></tr></table>

* Normal heating degree days are based on a 12-year moving average of monthly total heating degree days at Chicago's O'Hare Airport.

We did not have any operations in Illinois until our acquisition of Integrys on June 29, 2015. Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.

PGL and NSG recover certain operating expenses directly through separate riders, resulting in no impact on operating income as increases in operating expenses are offset by equal increases in margins. The following table shows the impact of these riders on margins and operating expenses.

<table><tr><td>(in millions)</td><td>2015</td></tr><tr><td>Environmental cleanup costs</td><td>$ 9.2</td></tr><tr><td>Energy efficiency program</td><td>7.4</td></tr><tr><td>Bad debt rider</td><td>3.6</td></tr><tr><td>Total increase in margins and operating expenses</td><td>$ 20.2</td></tr></table>



## OTHER STATES SEGMENT CONTRIBUTION TO OPERATING INCOME

<table><tr><td>(in millions)</td><td>2015</td></tr><tr><td>Natural gas revenues</td><td>$ 149.3</td></tr><tr><td>Cost of natural gas sold</td><td>76.9</td></tr><tr><td>Total natural gas margins</td><td>72.4</td></tr><tr><td>Other operation and maintenance</td><td>50.0</td></tr><tr><td>Depreciation and amortization</td><td>10.0</td></tr><tr><td>Property and revenue taxes</td><td>6.4</td></tr><tr><td>Operating income</td><td>$ 6.0</td></tr></table>

The following tables provide information on delivered volumes by customer class and weather statistics:

<table><tr><td rowspan="2">Natural Gas Sales Volumes</td><td>Therms (in millions)</td></tr><tr><td>2015</td></tr><tr><td>Customer Class</td><td></td></tr><tr><td>Residential</td><td>84.7</td></tr><tr><td>Commercial and industrial</td><td>60.9</td></tr><tr><td>Total retail</td><td>145.6</td></tr><tr><td>Transport</td><td>279.6</td></tr><tr><td>Total sales in terms</td><td>425.2</td></tr></table>

<table><tr><td>Weather  \( * \)</td><td>Degree Days</td></tr><tr><td>Heating (2,744 normal)</td><td>2015</td></tr><tr><td></td><td>2,193</td></tr></table>

* Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective territories.

We did not have any operations in this segment until our acquisition of Integrys on June 29, 2015. Since the majority of MERC and MGU customers use natural gas for heating, gross margin is sensitive to weather and is generally higher during the winter months.

## WE POWER SEGMENT CONTRIBUTION TO OPERATING INCOME

<table><tr><td rowspan="2">(in millions)</td><td colspan="4">Year Ended December 31</td></tr><tr><td>2015</td><td>2014</td><td>2013</td><td></td></tr><tr><td>Operating income</td><td>$ 373.4</td><td>$ 368.0</td><td>$ 366.6</td><td></td></tr></table>

## 2015 Compared with 2014

Operating income at the We Power segment increased $5.4 million, or 1.5%, when compared to 2014. This increase was primarily related to higher revenues in connection with capital additions to the plants it owns and leases to Wisconsin Electric.

## 2014 Compared with 2013

Operating income at the We Power segment increased $1.4 million, or 0.4%, when compared to 2013.

## CORPORATE AND OTHER SEGMENT CONTRIBUTION TO OPERATING INCOME

<table><tr><td rowspan="2">(in millions)</td><td colspan="4">Year Ended December 31</td></tr><tr><td>2015</td><td>2014</td><td>2013</td><td></td></tr><tr><td>Operating loss</td><td>$ (91.2)</td><td>$ (26.1)</td><td>$ (5.9)</td><td></td></tr></table>



## 2015 Compared with 2014

Operating loss at the corporate and other segment increased $65.1 million when compared to 2014, driven by costs associated with the acquisition of Integrys on June 29, 2015. See Note 2, Acquisition, for more information regarding costs associated with the acquisition.

## 2014 Compared with 2013

Operating loss at the corporate and other segment increased $20.2 million when compared to 2013. This was primarily attributable to external costs incurred in 2014 related to the acquisition of Integrys.

## ELECTRIC TRANSMISSION SEGMENT OPERATIONS

<table><tr><td rowspan="2">(in millions)</td><td colspan="4">Year Ended December 31</td></tr><tr><td>2015</td><td>2014</td><td>2013</td><td></td></tr><tr><td>Earnings from ATC</td><td>$ 96.1</td><td>$ 66.0</td><td>$ 68.5</td><td></td></tr></table>

## 2015 Compared with 2014

Earnings from our ownership interest in ATC increased $30.1 million when compared to 2014, driven by the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys on June 29, 2015. This increase was partially offset by lower earnings recognized by ATC, as ATC further reduced earnings in 2015 related to an anticipated refund to customers resulting from a complaint filed with the FERC requesting a lower ROE for certain transmission owners. See Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – ATC Allowed ROE Complaint, for more information.

## 2014 Compared with 2013

Earnings from our ownership interest in ATC decreased $2.5 million when compared to 2013. ATC reduced its earnings in 2014, driven by a potential refund to customers related to a complaint filed with the FERC requesting lower ROE for certain transmission owners.

## CONSOLIDATED OTHER INCOME, NET

<table><tr><td rowspan="2">(in millions)</td><td colspan="4">Year Ended December 31</td></tr><tr><td>2015</td><td>2014</td><td>2013</td><td></td></tr><tr><td>AFUDC - Equity</td><td>$ 20.1</td><td>$ 5.6</td><td>$ 18.3</td><td></td></tr><tr><td>Gain on asset sales</td><td>22.9</td><td>7.5</td><td>0.8</td><td></td></tr><tr><td>Other, net</td><td>15.9</td><td>0.3</td><td>(0.3)</td><td></td></tr><tr><td>Other income, net</td><td>$ 58.9</td><td>$ 13.4</td><td>$ 18.8</td><td></td></tr></table>

## 2015 Compared with 2014

Other income, net increased by $45.5 million when compared to 2014. This increase was primarily due to the $20.8 million gain from the sale of Minergy LLC and its remaining financial assets in June 2015, as well as higher AFUDC – Equity due to the inclusion of AFUDC from the Integrys companies after the acquisition on June 29, 2015.

## 2014 Compared with 2013

Other income, net decreased by $5.4 million, when compared to 2013. This decrease primarily relates to lower AFUDC – Equity related to the biomass plant going into service in November 2013, which was partially offset by an increased gain on asset sales.



## CONSOLIDATED INTEREST EXPENSE

<table><tr><td rowspan="2">(in millions)</td><td colspan="4">Year Ended December 31</td></tr><tr><td>2015</td><td colspan="2">2014</td><td>2013</td></tr><tr><td>Interest expense</td><td>$ 331.4</td><td>$ 240.3</td><td>$ 250.9</td><td></td></tr></table>

## 2015 Compared with 2014

Interest expense increased by $91.1 million, or 37.9%, when compared to 2014, primarily due to higher debt levels. We assumed approximately $3.0 billion of debt from Integrys and its subsidiaries upon the closing of the acquisition on June 29, 2015. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys.

## 2014 Compared with 2013

Interest expense decreased by $10.6 million, or 4.2%, when compared to 2013, primarily because of lower debt levels and lower average interest rates on long-term debt.

## CONSOLIDATED INCOME TAX EXPENSE

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Effective tax rate</td><td>40.4%</td><td>38.0%</td><td>36.9%</td></tr></table>

## 2015 Compared with 2014

Our effective tax rate was 40.4% in 2015 compared to 38.0% in 2014. This increase was primarily due to an increase in non-deductible acquisition related expenses. See Note 15, Income Taxes, for more information. We expect our 2016 annual effective tax rate to be between 37.5% and 38.5%.

## 2014 Compared with 2013

Our effective tax rate applicable to continuing operations was 38.0% in 2014 compared to 36.9% in 2013. This increase in our effective tax rate was due to reduced tax benefits associated with Treasury Grant income, decreased AFUDC – Equity, and non-deductible acquisition related expenses.

## LIQUIDITY AND CAPITAL RESOURCES

## CASH FLOWS

The following summarizes our cash flows during 2015, 2014, and 2013:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td><td>Change in 2015 Over 2014</td><td>Change in 2014 Over 2013</td></tr><tr><td>Cash provided by (used in):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating activities</td><td>$ 1,293.6</td><td>$ 1,198.9</td><td>$ 1,232.2</td><td>$ 94.7</td><td>$ (33.3)</td></tr><tr><td>Investing activities</td><td>(2,517.5)</td><td>(756.8)</td><td>(745.8)</td><td>(1,760.7)</td><td>(11.0)</td></tr><tr><td>Financing activities</td><td>1,211.8</td><td>(406.2)</td><td>(496.0)</td><td>1,618.0</td><td>89.8</td></tr></table>

## Operating Activities

## 2015 Compared with 2014

Net cash provided by operating activities increased $94.7 million in 2015, driven by a $141.6 million increase related to net cash flows from the operating activities of Integrys in the last six months of 2015 as a result of the acquisition on June 29, 2015. See Note 2, Acquisition, for more information.



The remaining $46.9 million decrease in net cash provided by operating activities from legacy Wisconsin Energy Corporation companies was driven by:

• A $141.4 million decrease in cash related to higher payments for operating and maintenance costs in 2015.

• A $96.8 million increase in contributions to pension and OPEB plans in 2015.

These decreases in cash provided by operating activities from legacy Wisconsin Energy Corporation companies were partially offset by a $174.4 million net increase in cash related to lower payments for natural gas, fuel, and purchased power, partially offset by a decrease in cash driven by lower overall collections from customers in 2015. This net increase was primarily due to the impact of lower commodity prices in 2015.

## 2014 Compared with 2013

Net cash provided by operating activities decreased $33.3 million in 2014. During 2014, we experienced higher net income, higher depreciation expense and favorable cash flows from accounts receivable, primarily because of the timing of the Treasury Grant. More than offsetting these favorable items were increases in working capital related to natural gas in storage and increases in regulatory assets.

## Investing Activities

## 2015 Compared with 2014

Net cash used in investing activities increased $1,760.7 million in 2015, driven by:

• An investment of $1,329.9 million related to the June 29, 2015, acquisition of Integrys, which is net of cash acquired of $156.3 million. See Note 2, Acquisition, for more information.

• A $505.0 million increase in cash used for capital expenditures in 2015, which is discussed in more detail below.

These increases in cash used for investing activities were partially offset by:

• A $17.3 million increase in cash related to the receipt of the cash surrender value of Integrys corporate-owned life insurance policies in 2015.

• A $15.0 million increase in proceeds from asset sales, driven by the sale of Minergy LLC and its remaining financial assets in 2015.

## 2014 Compared with 2013

Net cash used in investing activities increased $11.0 million in 2014, driven by higher capital expenditures of $36.0 million, which is discussed in more detail below. This increase in cash used in investing activities was partially offset by an increase in proceeds received from asset sales.

## Capital Expenditures

The following table summarizes our capital expenditures by business segment by year:

<table><tr><td>Reportable Segment (in millions)</td><td colspan="2">2015</td><td colspan="2">2014</td><td colspan="2">2013</td><td colspan="2">Change in 2015 over 2014</td><td colspan="2">Change in 2014 over 2013</td></tr><tr><td>Wisconsin</td><td>$</td><td>950.3</td><td>$</td><td>715.0</td><td>$</td><td>695.7</td><td>$</td><td>235.3</td><td>$</td><td>19.3</td></tr><tr><td>Illinois</td><td></td><td>194.4</td><td></td><td>—</td><td></td><td>—</td><td></td><td>194.4</td><td></td><td>—</td></tr><tr><td>Other states</td><td></td><td>34.7</td><td></td><td>—</td><td></td><td>—</td><td></td><td>34.7</td><td></td><td>—</td></tr><tr><td>We Power</td><td></td><td>53.4</td><td></td><td>41.0</td><td></td><td>25.8</td><td></td><td>12.4</td><td></td><td>15.2</td></tr><tr><td>Corporate and other</td><td></td><td>33.4</td><td></td><td>5.2</td><td></td><td>3.7</td><td></td><td>28.2</td><td></td><td>1.5</td></tr><tr><td>Total</td><td></td><td>$</td><td>1,266.2</td><td>$</td><td>761.2</td><td>$</td><td>725.2</td><td>$</td><td>505.0</td><td>$</td></tr></table>



## 2015 Compared with 2014

The increase in capital expenditures in the Wisconsin segment in 2015 was primarily due to the inclusion of WPS as a result of the acquisition of Integrys on June 29, 2015. Significant projects included in 2015 capital expenditures for WPS include the ReACT \( ^{TM} \)  emission control technology project at Weston Unit 3 and the System Modernization and Reliability Project, which is a project to underground and upgrade certain electric distribution facilities in northern Wisconsin. The Wisconsin segment also included increased expenditures in 2015 related to Wisconsin Gas's Western Gas Lateral project, which was a project to improve the reliability of Wisconsin Gas's natural gas distribution network in the western part of Wisconsin and to better meet customer demand. These increases were partially offset by lower capital expenditures in 2015 for Wisconsin Electric's conversion of the fuel source for VAPP from coal to natural gas, as most of the capital expenditures related to this project were incurred in 2014. For additional discussion regarding ReACT \( ^{TM} \) , see Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements – Capital Expenditures and Significant Capital Projects.

The Illinois segment includes capital expenditures from PGL and NSG as a result of the acquisition of Integrys on June 29, 2015. In 2015, PGL incurred significant capital expenditures related to the AMRP.

The other states segment includes capital expenditures from MERC and MGU as a result of the acquisition of Integrys on June 29, 2015.

## 2014 Compared with 2013

The increase in capital expenditures in the Wisconsin segment in 2014 was primarily driven by the starting of the conversion of the fuel source for VAPP from coal to natural gas.

See Capital Expenditures and Significant Capital Projects below for more information.

## Financing Activities

## 2015 Compared with 2014

Net cash from financing activities increased $1,618.0 million in 2015, driven by:

• A $1,900.0 million increase in the issuance of long-term debt in 2015, of which $1,200.0 million related to the acquisition of Integrys.

• An $82.8 million increase in net borrowings of commercial paper in 2015.

These increases in net cash from financing activities were partially offset by:

• A $205.3 million increase in retirements of long-term debt in 2015, of which $130.1 million was attributable to legacy Integrys and its subsidiaries.

• A $103.4 million increase in dividends paid on common stock due to the issuance of 90.2 million shares associated with the Integrys acquisition and an increase in our quarterly dividend rate effective with the closing of the acquisition on June 29, 2015. See Note 2, Acquisition and Note 11, Common Equity, for more information.

• A $52.7 million decrease in cash due to the redemption of all of WPS's preferred stock in 2015. See Note 12, Preferred Stock, for more information.

## 2014 Compared with 2013

Net cash used in financing activities decreased $89.8 million in 2014, primarily driven by a decrease in common stock repurchased as a result of our Board of Directors terminating our share repurchase program in connection with the acquisition of Integrys. During 2014, we repurchased $18.6 million of common stock as compared to $126.0 million in 2013 as part of the share repurchase program. See Note 11, Common Equity, for more information on share repurchases. Our dividends paid on common stock increased $23.1 million in 2014 as a result of increases in the quarterly common stock dividend of 12.5% and 2.0% in the third quarter of 2013 and first quarter of 2014, respectively.



## Significant Financing Activities

For information on our short-term debt, see Note 13, Short-Term Debt and Lines of Credit.

For information on our long-term debt, see Note 14, Long-Term Debt and Capital Lease Obligations.

## CAPITAL RESOURCES AND REQUIREMENTS

## Capital Resources

## Liquidity

We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors.

We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets, and internally generated cash.

WEC Energy Group, Wisconsin Electric, Wisconsin Gas, WPS, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 13, Short-Term Debt and Lines of Credit, for more information about these credit facilities and other short-term credit agreements.

The following table shows our capitalization structure as of December 31, 2015 and 2014, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the rating agencies currently view our 2007 6.25% Series A Junior Subordinated Notes due 2067 (6.25% Junior Notes), Integrys's 2006 6.11% Junior Subordinated Notes due 2066 (6.11% Junior Notes), and Integrys's 2013 6.00% Junior Subordinated Notes due 2073 (6.00% Junior Notes) (collectively, Junior Notes):

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">2015</td><td colspan="3">2014</td></tr><tr><td>Actual</td><td>Adjusted</td><td>Actual</td><td>Adjusted</td><td>Actual</td><td>Adjusted</td></tr><tr><td>Common equity</td><td>$ 8,654.8</td><td>$ 9,239.7</td><td>$ 4,419.7</td><td>$ 4,669.7</td><td></td><td></td></tr><tr><td>Preferred stock of subsidiary</td><td>30.4</td><td>30.4</td><td>30.4</td><td>30.4</td><td></td><td></td></tr><tr><td>Long-term debt (including current maturities)</td><td>9,281.8</td><td>8,696.9</td><td>4,594.8</td><td>4,344.8</td><td></td><td></td></tr><tr><td>Short-term debt</td><td>1,095.0</td><td>1,095.0</td><td>617.6</td><td>617.6</td><td></td><td></td></tr><tr><td>Total capitalization</td><td>$ 19,062.0</td><td>$ 19,062.0</td><td>$ 9,662.5</td><td>$ 9,662.5</td><td></td><td></td></tr><tr><td>Total debt</td><td>$ 10,376.8</td><td>$ 9,791.9</td><td>$ 5,212.4</td><td>$ 4,962.4</td><td></td><td></td></tr><tr><td>Ratio of debt to total capitalization</td><td>54.4%</td><td>51.4%</td><td>53.9%</td><td>51.4%</td><td></td><td></td></tr></table>

Included in long-term debt on our balance sheets as of December 31, 2015 and 2014, is $1,169.8 million and $500.0 million aggregate principal amount of Junior Notes and 6.25% Junior Notes, respectively. The adjusted presentation attributes $584.9 million of the Junior Notes to common equity and $584.9 million to long-term debt in 2015 and $250.0 million of the 6.25% Junior Notes to common equity and $250.0 million to long-term debt in 2014. We believe this presentation is consistent with the 50% equity credit the majority of rating agencies currently attribute to the Junior Notes.

The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.



In February 2016, Integrys repurchased and retired approximately $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million, plus accrued and unpaid interest, through a modified "dutch auction" tender offer.

For a summary of the interest rate, maturity, and amount outstanding of each series of our long-term debt on a consolidated basis, see our capitalization statements.

As described in Note 11, Common Equity, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.

At December 31, 2015, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 13, Short-Term Debt and Lines of Credit, for more information about our credit facilities and other short-term credit agreements. See Note 14, Long-Term Debt and Capital Lease Obligations, for more information about our long-term debt.

## Working Capital

As of December 31, 2015, our current liabilities exceeded our current assets by $502.2 million. We do not expect this to have any impact on our liquidity because we believe we have adequate back-up lines of credit in place for ongoing operations. We also have access to the capital markets to finance our construction programs and to refinance current maturities of long-term debt if necessary.

## Capital Requirements

## Acquisition of Integrys

The acquisition of Integrys on June 29, 2015, was financed through the issuance of approximately 90.2 million shares of Wisconsin Energy Corporation common stock, $1.2 billion of long-term debt, and $300.0 million of commercial paper. See Note 2, Acquisition, for more information on the acquisition.

## Contractual Obligations

We have the following contractual obligations and other commercial commitments as of December 31, 2015:

<table><tr><td rowspan="2">(in millions)</td><td colspan="6">Payments Due by Period (1)</td></tr><tr><td>Total</td><td colspan="2">Less Than 1 Year</td><td>1-3 Years</td><td>3-5 Years</td><td>More Than 5 Years</td></tr><tr><td>Long-term debt obligations (2)</td><td>$ 18,155.9</td><td>$ 539.3</td><td>$ 1,763.0</td><td>$ 1,748.9</td><td>$ 14,104.7</td><td></td></tr><tr><td>Capital lease obligations (3)</td><td>130.5</td><td>45.1</td><td>28.6</td><td>31.9</td><td>24.9</td><td></td></tr><tr><td>Operating lease obligations (4)</td><td>107.1</td><td>9.8</td><td>18.8</td><td>11.9</td><td>66.6</td><td></td></tr><tr><td>Energy and transportation purchase obligations (5)</td><td>12,677.7</td><td>1,164.7</td><td>1,739.7</td><td>1,330.6</td><td>8,442.7</td><td></td></tr><tr><td>Purchase orders (6)</td><td>824.8</td><td>629.1</td><td>138.5</td><td>41.3</td><td>15.9</td><td></td></tr><tr><td>Pension and OPEB funding obligations (7)</td><td>68.6</td><td>30.4</td><td>38.2</td><td>—</td><td>—</td><td></td></tr><tr><td>Capital contributions to equity method investments</td><td>9.0</td><td>9.0</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 31,973.6</td><td>$ 2,427.4</td><td>$ 3,726.8</td><td>$ 3,164.6</td><td>$ 22,654.8</td><td></td></tr></table>

(1) The amounts included in the table are calculated using current market prices, forward curves, and other estimates.

(2) Principal and interest payments on long-term debt (excluding capital lease obligations).

(3) Capital lease obligations for power purchase commitments. This amount does not include We Power leases to Wisconsin Electric which are eliminated upon consolidation.

(4) Operating lease obligations for power purchase commitments and rail car leases.

(5) Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility operations.

(6) Purchase obligations related to normal business operations, information technology, and other services.

(7) Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2018.



The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note 15, Income Taxes.

AROs in the amount of $571.2 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years.

Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.

## Capital Expenditures and Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:

<table><tr><td>(in millions)</td><td>2016</td><td>2017</td><td>2018</td></tr><tr><td>Wisconsin \( ^{(1)} \)</td><td>$ 934.6</td><td>$ 998.0</td><td>$ 1,055.2</td></tr><tr><td>Illinois \) ^{(2)}</td><td>375.5</td><td>390.9</td><td>387.0</td></tr><tr><td>Other states</td><td>60.1</td><td>64.6</td><td>64.0</td></tr><tr><td>We Power</td><td>49.3</td><td>60.5</td><td>38.5</td></tr><tr><td>Corporate and other</td><td>90.9</td><td>48.5</td><td>5.3</td></tr><tr><td>Total</td><td>$ 1,510.4</td><td>$ 1,562.5</td><td>$ 1,550.0</td></tr></table>

(1) WPS is in the process of constructing a multi-pollutant control technology known as ReACT \( ^{™} \)  as part of Weston Unit 3. The control technology will help meet the requirements of a Consent Decree agreed to between WPS and the EPA. The technology will also assist with WPS's compliance with future air pollution regulations, as well as help maintain a balanced generation portfolio. The cost of the project is estimated at approximately $342.0 million, excluding AFUDC, with a targeted completion date of April 2016.

(2) PGL is continuing work on the AMRP, a 20-year project that began in 2011 under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved qualifying infrastructure plant rider, which is in effect through 2023. PGL expects to invest between $250 million and $280 million annually over the next three years.

We expect to provide capital contributions to ATC (not included in the above table) of approximately $317 million from 2016 through 2018.

## Common Stock Matters

For information related to our common stock matters, see Note 11, Common Equity.

On January 21, 2016, the Board of Directors increased the quarterly dividend to $0.4950 per share effective with the first quarter of 2016 dividend payment, which equates to an annual dividend of $1.98 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.

## Investments in Outside Trusts

We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $3.5 billion as of December 31, 2015. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $121 million, $13.9 million, and $22.8 million to our pension and OPEB plans in 2015, 2014, and 2013, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 17, Employee Benefits.

## Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or



future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources that is material to our investors. For additional information regarding guarantees and other off-balance sheet arrangements, see Note 16, Guarantees, and Note 21, Variable Interest Entities.

## FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

## MARKET RISKS AND OTHER SIGNIFICANT RISKS

We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to:

## Regulatory Recovery

Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions.

Regulated entities are allowed to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of these deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. In general, our regulatory assets are recovered over a period of between one to six years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2015, our regulatory assets totaled $3,101.7 million and our regulatory liabilities totaled $1,426.0 million.

Regarding our ReACT \( ^{™} \)  project, the PSCW approved deferral of costs above the originally authorized 275.0 million level through 2016. We will be required to obtain a separate approval for collection of these deferred costs. Also, prior to the acquisition, Integrys initiated an IT project with the goal of improving the customer experience. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of December 31, 2015, none of the costs have been disallowed in rate proceedings. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project. See Note 22, Regulatory Environment, for additional information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.

## Commodity Costs

In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.

Embedded within our utilities' rates are amounts to recover fuel, natural gas, and purchased power costs. Our utilities have recovery mechanisms in place that allow them to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts.

Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 1(d), Revenues and Customer Receivables, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.

## Weather

Our utilities' rates are based upon estimated normal temperatures. Our electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our natural gas revenues are unfavorably sensitive to above normal temperatures during the



winter heating season. Certain of our natural gas utilities have decoupling mechanisms in place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A summary of actual weather information in our utilities' service territories during 2015, 2014, and 2013, as measured by degree days, may be found in Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.

## Interest Rates

We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.

Based on the variable rate debt outstanding at December 31, 2015, and December 31, 2014, a hypothetical increase in market interest rates of one-percentage point would have increased annual interest expense by $11.0 million and $6.2 million, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

## Marketable Securities Return

We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.

The fair value of our trust fund assets and expected long-term returns were approximately:

<table><tr><td>(in millions)</td><td>As of December 31, 2015</td><td>Expected Return on Assets in 2016</td></tr><tr><td>Pension trust funds</td><td>$ 2,755.1</td><td>7.13%</td></tr><tr><td>OPEB trust funds</td><td>$ 749.8</td><td>7.25%</td></tr></table>

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

## Economic Conditions

We have electric and natural gas utility operations that serve customers in Wisconsin, Illinois, Michigan, and Minnesota. As such, we are exposed to market risks in the regional midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.

## Inflation

We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.



For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report.

## INDUSTRY RESTRUCTURING

## Electric Utility Industry

The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which affects the structure of the wholesale market. To this end, MISO implemented the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when retail choice might be implemented, if at all, in Wisconsin. However, Michigan has adopted retail choice.

## Restructuring in Wisconsin

Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW has been focused on electric reliability infrastructure issues for the state of Wisconsin in recent years. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.

## Restructuring in Michigan

Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. Some of our small retail customers have switched to an alternative electric supplier. The law limits customer choice to 10% of our Michigan retail load, but the two iron ore mines in our service territory are excluded from this cap. See Note 23, Michigan Settlement, for information on the mines' ability to switch to an alternative electric supplier. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

## Natural Gas Utility Industry

## Restructuring in Wisconsin

The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer classes with workably competitive market choices and has adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have workably competitive market choices and, therefore, can purchase natural gas directly from a third party supplier. However, work on deregulation of the natural gas distribution industry by the PSCW continues to be on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.

## Restructuring in Illinois

Since 2002, PGL and NSG have provided all of their customers with the option to choose an alternative retail natural gas supplier. PGL and NSG are not required by the ICC or state law to make this option available to customers, but since this option is currently provided to customers, PGL and NSG would need ICC approval to eliminate it.

PGL and NSG offer natural gas transportation service to customers that select an alternative retail natural gas supplier. Transportation customers purchase natural gas directly from an alternative retail natural gas supplier and use PGL's and NSG's distribution systems to transport the natural gas to their facilities. PGL and NSG still earn a distribution charge when they transport natural gas for these customers. As such, the loss of revenue associated with the natural gas that transportation customers purchase from an alternative retail natural gas supplier has little impact on our net income, since it is offset by an equal reduction to natural gas costs.



## Restructuring in Minnesota

We are unaware of any current efforts to deregulate the sale of natural gas in Minnesota. While potential future efforts to deregulate the sale of natural gas could occur, we are unable to predict the impact of any potential future deregulation on our results of operations or financial position.

## Restructuring in Michigan

The option to choose an alternative retail natural gas supplier has been provided to WPS's and MGU's customers since the late 1990s and 2005, respectively. WPS and MGU are not required by the MPSC or state law to make this option available to customers, but since this option is currently provided to customers, WPS and MGU would need MPSC approval to eliminate it.

WPS and MGU offer natural gas transportation service to customers that select an alternative retail natural gas supplier. Transportation customers purchase natural gas directly from an alternative retail natural gas supplier and use WPS's and MGU's distribution systems to transport the natural gas to their facilities. WPS and MGU still earn a distribution charge when they transport natural gas for these customers. As such, the loss of revenue associated with the natural gas that transportation customers purchase from an alternative retail natural gas supplier has little impact on our net income, since it is offset by an equal reduction to natural gas costs.

## ENVIRONMENTAL MATTERS

## Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule (CAIR). The purpose of the CSAPR was to limit the interstate transport of emissions of NOx and  \( SO_{2} \)  that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allocation plan and allowance trading scheme. The rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals) and CAIR was implemented during the stay period. In August 2012, the D.C. Circuit Court of Appeals issued a ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court). In April 2014, the Supreme Court issued a decision largely upholding CSAPR and remanded it to the D.C. Circuit Court of Appeals for further proceedings. In October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The compliance deadlines were also changed by three years, so that Phase I emissions budgets apply in 2015 and 2016, and Phase 2 emissions budgets will apply to 2017 and beyond.

In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and plans to issue a final rule by August 2016. Starting in 2017, this proposed rule would reduce ozone season (May 1 through September 30) NOx emissions from power plants in 23 states in the eastern United States. In this rule, the EPA is proposing to update Phase II CSAPR NOx ozone season budgets for electric generating units in the 23 states. An approximate 60% reduction in NOx emissions is proposed for Wisconsin and an approximate 29% reduction is proposed for Michigan, beginning in May 2017. Additional investments in controls and/or shifts in generation may be required depending upon the final outcome of the rule. We submitted comments to the EPA on the potential impacts of the rule.

See Note 18, Commitments and Contingencies, for a discussion of additional environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, renewable energy requirements, and climate change.

## OTHER MATTERS

## American Transmission Company Allowed Return On Equity Complaint

In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, to 9.15%. ATC's current authorized ROE is 12.2%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 12, 2013. The FERC conducted hearings in August 2015, and the ALJ issued an initial decision in



December 2015. The ALJ's initial decision recommended that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The ALJ's recommendation is not binding to the FERC. A FERC order related to this complaint is expected during the fourth quarter of 2016.

In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to the filing date of the complaint. The FERC conducted hearings in February 2016 with respect to this second complaint, and an initial decision is expected by June 30, 2016.

In October 2014, the FERC issued an order, in regard to a similar complaint, reducing the base ROE for New England transmission owners from their existing rate of 11.14% to 10.57%. In this order, the FERC used a revised method for determining the appropriate ROE for FERC-jurisdictional electric utilities. The FERC expects its new methodology will narrow the "zone" of reasonable returns on equity. The FERC has stated that it expects future decisions on pending complaints related to similar ROE issues to be guided by the New England transmission decision.

Any change to ATC’s ROE could result in lower equity earnings and distributions from ATC in the future. We are currently unable to determine how the FERC may rule in these complaints. However, we believe it is probable that refunds will be required upon resolution of these issues. Based on the ALJ’s initial decision in December 2015, ATC reduced its earnings, which resulted in us recognizing lower earnings from our investment in ATC.

## Wisconsin Power and Light's (WP&L) Riverside Energy Center Facility

In April 2015, WP&L filed a CPCN application with the PSCW for approval to construct an approximate 650 MW natural gas-fired combined-cycle generating unit in Beloit, Wisconsin. Recent construction proposals received by WP&L indicate that the unit could generate up to 700 MWs. In the third quarter of 2015, Wisconsin Electric and WPS requested and received intervention in this proceeding. As intervenors, Wisconsin Electric and WPS proposed purchased power agreement alternatives to the new generating unit. In December 2015, Wisconsin Electric, WPS, and WP&L entered into a settlement agreement that was approved by the PSCW. Based on the settlement agreement, the generating unit cannot become commercially operational before June 1, 2020. In addition, WP&L must enter into a purchased power agreement with Wisconsin Electric for MISO planning years 2017, 2018, and 2019, whereby Wisconsin Electric will sell and WP&L will purchase capacity and energy at certain agreed upon prices. WPS also will have the option to purchase an undivided ownership interest of up to 100 MWs of generating capacity from the unit during the first two years of operation and up to an aggregate 200 MWs of generating capacity during the third and fourth years of operation. Other major terms of the settlement included agreement on ownership of future Wisconsin Electric and WPS natural gas units, negotiation of a renewable generation joint development plan, and ownership terms of the jointly-owned Columbia plant.

## Bonus Depreciation Provisions

The Protecting Americans from Tax Hikes Act of 2015 was signed into law on December 18, 2015. This act extended 50% bonus depreciation to assets placed in service during 2015 through 2017, 40% bonus depreciation to assets placed in service during 2018, and 30% bonus depreciation to assets placed in service during 2019. Bonus depreciation is an additional amount of deductible depreciation that is awarded above and beyond what would normally be available. Due to the resulting increase in federal tax depreciation, we did not make federal income tax payments for 2015, 2014, or 2013.

## CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgments.



## Goodwill Impairment

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. Goodwill is assessed for impairment at least annually or more frequently if a triggering event occurs. If the carrying amount of a reporting unit is greater than its fair value, impairment may be present. When evaluating goodwill for impairment, a qualitative assessment, referred to as the step zero approach, may first be performed to determine whether further quantitative analysis is necessary. If the qualitative assessment indicates that a reporting unit's fair value more likely than not exceeds its carrying value, the two-step quantitative analysis is unnecessary. However, the quantitative analysis needs to be performed if the qualitative assessment indicates that a reporting unit's carrying value more likely than not exceeds its fair value. The quantitative analysis involves calculating the estimated fair value of the reporting unit. Since the qualitative assessment is optional, companies are allowed to proceed directly to the quantitative analysis.

We completed our annual goodwill impairment test for all of our reporting units that carried a goodwill balance effective August 31, 2015. Our reporting units are the same as our reportable segments. We performed the step zero qualitative analysis since all of our reporting units were either valued recently in connection with the acquisition of Integrys or passed their most recent goodwill impairment test by a significant amount. In addition, no events occurred that would have more likely than not caused a significant decrease in the fair values of our reporting units. Events and circumstances we considered when performing the step zero analysis included, but were not limited to, macro-economic conditions, market and industry conditions, internal cost factors, share price fluctuations, competitive environment, and the operational stability and overall financial performance of the reporting units. After evaluating and weighing all relevant events and circumstances, we concluded that the carrying amounts of our reporting units were significantly exceeded by their respective fair values. Consequently, no reporting units were at risk of impairment. No impairment charges were recorded in 2015 as a result of our qualitative annual impairment assessment.

Our reporting units had the following goodwill balances at December 31, 2015:

<table><tr><td>(in millions, except percentages)</td><td>Goodwill</td><td>Percentage of Total Goodwill</td></tr><tr><td>Wisconsin</td><td>$ 2,109.5</td><td>69.8%</td></tr><tr><td>Illinois</td><td>731.2</td><td>24.2%</td></tr><tr><td>Other states</td><td>182.8</td><td>6.0%</td></tr><tr><td>Total goodwill</td><td>$ 3,023.5</td><td>100.0%</td></tr></table>

See Note 10, Goodwill and Other Intangible Assets, for more information.

## Pension and Other Postretirement Employee Benefits

The costs of providing non-contributory defined pension benefits and OPEB, described in Note 17, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.

Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded at our utilities through the ratemaking process.



The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.

<table><tr><td>Actuarial Assumption (in millions, except percentages)</td><td>Percentage-Point Change in Assumption</td><td>Impact on Projected Benefit Obligation</td><td>Impact on 2015 Pension Cost</td></tr><tr><td>Discount rate</td><td>(0.5)</td><td>$ 198.0</td><td>$ 10.6</td></tr><tr><td>Discount rate</td><td>0.5</td><td>(172.1)</td><td>(9.9)</td></tr><tr><td>Rate of return on plan assets</td><td>(0.5)</td><td>N/A</td><td>10.8</td></tr><tr><td>Rate of return on plan assets</td><td>0.5</td><td>N/A</td><td>(10.8)</td></tr></table>

The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.

<table><tr><td>Actuarial Assumption (in millions, except percentages)</td><td>Percentage-Point Change in Assumption</td><td>Impact on Postretirement Benefit Obligation</td><td>Impact on 2015 Postretirement Benefit Cost</td></tr><tr><td>Discount rate</td><td>(0.5)</td><td>$ 53.5</td><td>$ 2.1</td></tr><tr><td>Discount rate</td><td>0.5</td><td>(47.3)</td><td>(1.7)</td></tr><tr><td>Health care cost trend rate</td><td>(0.5)</td><td>(33.9)</td><td>(3.5)</td></tr><tr><td>Health care cost trend rate</td><td>0.5</td><td>38.5</td><td>4.0</td></tr><tr><td>Rate of return on plan assets</td><td>(0.5)</td><td>N/A</td><td>2.7</td></tr><tr><td>Rate of return on plan assets</td><td>0.5</td><td>N/A</td><td>(2.7)</td></tr></table>

In the fourth quarter of 2014, the Society of Actuaries published a new set of mortality tables, which updated life expectancy assumptions. We have adjusted the tables to better reflect our plan-specific mortality experience and other general assumptions. We have incorporated the revised mortality tables into the projected pension and OPEB obligations at December 31, 2015.

The discount rates are selected based on hypothetical bond portfolios consisting of noncallable (or callable with make-whole provisions), noncollateralized, high-quality corporate bonds with maturities between 0 and 30 years. The bonds are generally rated "Aa" with a minimum amount outstanding of $50.0 million. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.

We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.37% in 2015, and 7.25% in both 2014 and 2013, respectively. The actual rate of return on pension plan assets, net of fees, was (3.85%), 6.17%, and 10.92%, in 2015, 2014, and 2013, respectively.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 17, Employee Benefits.

## Regulatory Accounting

Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC. Our financial statements reflect the effects of the ratemaking principles followed by the various jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings at the electric and natural gas utilities, and the status of any pending or potential deregulation legislation.



The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer meet the criteria for application. Our regulatory assets and liabilities would be written off as a charge to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2015, we had $3,101.7 million in regulatory assets and $1,426.0 million in regulatory liabilities. See Note 6, Regulatory Assets and Liabilities, for more information.

## Unbilled Revenues

We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2015 of approximately $5.8 billion included accrued utility revenues of $418.3 million as of December 31, 2015.

## Income Tax Expense

We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to the provision for income taxes in the income statements.

Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(n), Income Taxes, and Note 15, Income Taxes, for a discussion of accounting for income taxes.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks, as well as Note 1(t), Derivative Instruments, Note 1(s), Fair Value Measurements, and Note 16, Guarantees, for information concerning potential market risks to which we are exposed.



## WEC ENERGY GROUP, INC.
CONSOLIDATED INCOME STATEMENTS

<table><tr><td colspan="4">Year Ended December 31</td></tr><tr><td>(in millions, except per share amounts)</td><td colspan="2">2015</td><td>2014</td></tr><tr><td>Operating revenues</td><td>$     5,926.1</td><td>$     4,997.1</td><td>$     4,519.0</td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td></tr><tr><td>Cost of sales</td><td>2,240.1</td><td>2,259.4</td><td>1,827.1</td></tr><tr><td>Other operation and maintenance</td><td>1,709.3</td><td>1,112.4</td><td>1,155.0</td></tr><tr><td>Depreciation and amortization</td><td>561.8</td><td>391.4</td><td>340.1</td></tr><tr><td>Property and revenue taxes</td><td>164.4</td><td>121.8</td><td>116.7</td></tr><tr><td>Total operating expenses</td><td>4,675.6</td><td>3,885.0</td><td>3,438.9</td></tr><tr><td>Operating income</td><td>1,250.5</td><td>1,112.1</td><td>1,080.1</td></tr><tr><td>Equity in earnings of transmission affiliate</td><td>96.1</td><td>66.0</td><td>68.5</td></tr><tr><td>Other income, net</td><td>58.9</td><td>13.4</td><td>18.8</td></tr><tr><td>Interest expense</td><td>331.4</td><td>240.3</td><td>250.9</td></tr><tr><td>Other expense</td><td>(176.4)</td><td>(160.9)</td><td>(163.6)</td></tr><tr><td>Income before income taxes</td><td>1,074.1</td><td>951.2</td><td>916.5</td></tr><tr><td>Income tax expense</td><td>433.8</td><td>361.7</td><td>337.9</td></tr><tr><td>Net income</td><td>640.3</td><td>589.5</td><td>578.6</td></tr><tr><td>Preferred stock dividends of subsidiaries</td><td>1.8</td><td>1.2</td><td>1.2</td></tr><tr><td>Net income attributed to common shareholders</td><td>$     638.5</td><td>$     588.3</td><td>$     577.4</td></tr><tr><td>Earnings per share</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$     2.36</td><td>$     2.61</td><td>$     2.54</td></tr><tr><td>Diluted</td><td>$     2.34</td><td>$     2.59</td><td>$     2.51</td></tr><tr><td>Weighted average common shares outstanding</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>271.1</td><td>225.6</td><td>227.6</td></tr><tr><td>Diluted</td><td>272.7</td><td>227.5</td><td>229.7</td></tr></table>

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



## WEC ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<table><tr><td>Year Ended December 31 (in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Net income</td><td>$     640.3</td><td>$     589.5</td><td>$     578.6</td></tr><tr><td>Other comprehensive income, net of tax</td><td></td><td></td><td></td></tr><tr><td>Derivatives accounted for as cash flow hedges</td><td></td><td></td><td></td></tr><tr><td>Gains on settlement, net of tax of $7.6</td><td>11.4</td><td>—</td><td>—</td></tr><tr><td>Reclassification of gains to net income, net of tax</td><td>(0.8)</td><td>—</td><td>—</td></tr><tr><td>Cash flow hedges, net</td><td>10.6</td><td>—</td><td>—</td></tr><tr><td>Defined benefit plans</td><td></td><td></td><td></td></tr><tr><td>Pension and OPEB costs arising during period, net of tax of $4.2</td><td>(6.3)</td><td>—</td><td>—</td></tr><tr><td>Other comprehensive income, net of tax</td><td>4.3</td><td>—</td><td>—</td></tr><tr><td>Comprehensive income</td><td>644.6</td><td>589.5</td><td>578.6</td></tr><tr><td>Preferred stock dividends of subsidiaries</td><td>1.8</td><td>1.2</td><td>1.2</td></tr><tr><td>Comprehensive income attributed to common shareholders</td><td>$     642.8</td><td>$     588.3</td><td>$     577.4</td></tr></table>

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



## WEC ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS

<table><tr><td colspan="4">At December 31(in millions, except share and per share amounts)</td></tr><tr><td></td><td>Assets</td><td>2015</td><td>2014</td></tr><tr><td>Property, plant, and equipment</td><td></td><td></td><td></td></tr><tr><td>In service</td><td>$ 26,249.5</td><td>$ 15,509.0</td><td></td></tr><tr><td>Accumulated depreciation</td><td>(7,919.1)</td><td>(4,485.1)</td><td></td></tr><tr><td></td><td>18,330.4</td><td>11,023.9</td><td></td></tr><tr><td>Construction work in progress</td><td>822.9</td><td>191.8</td><td></td></tr><tr><td>Leased facilities, net</td><td>36.4</td><td>42.0</td><td></td></tr><tr><td>Net property, plant, and equipment</td><td>19,189.7</td><td>11,257.7</td><td></td></tr><tr><td>Investments</td><td></td><td></td><td></td></tr><tr><td>Equity investment in transmission affiliate</td><td>1,380.9</td><td>424.1</td><td></td></tr><tr><td>Other</td><td>85.8</td><td>32.8</td><td></td></tr><tr><td>Total investments</td><td>1,466.7</td><td>456.9</td><td></td></tr><tr><td>Current assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>49.8</td><td>61.9</td><td></td></tr><tr><td>Accounts receivable and unbilled revenues, net of reserves of $113.3 and $74.5, respectively</td><td>1,028.6</td><td>643.4</td><td></td></tr><tr><td>Materials, supplies, and inventories</td><td>687.0</td><td>400.6</td><td></td></tr><tr><td>Assets held for sale</td><td>96.8</td><td>—</td><td></td></tr><tr><td>Prepayments</td><td>285.8</td><td>148.2</td><td></td></tr><tr><td>Other</td><td>58.8</td><td>38.6</td><td></td></tr><tr><td>Total current assets</td><td>2,206.8</td><td>1,292.7</td><td></td></tr><tr><td>Deferred charges and other assets</td><td></td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>3,064.6</td><td>1,271.2</td><td></td></tr><tr><td>Goodwill</td><td>3,023.5</td><td>441.9</td><td></td></tr><tr><td>Other</td><td>403.9</td><td>184.6</td><td></td></tr><tr><td>Total deferred charges and other assets</td><td>6,492.0</td><td>1,897.7</td><td></td></tr><tr><td>Total assets</td><td>$ 29,355.2</td><td>$ 14,905.0</td><td></td></tr><tr><td colspan="4">Capitalization and liabilities</td></tr><tr><td>Capitalization</td><td></td><td></td><td></td></tr><tr><td>Common stock - $0.01 par value; 325,000,000 shares authorized; 315,683,496 and 225,517,339 shares outstanding, respectively</td><td>$ 3.2</td><td>$ 2.3</td><td></td></tr><tr><td>Additional paid in capital</td><td>4,347.2</td><td>300.1</td><td></td></tr><tr><td>Retained earnings</td><td>4,299.8</td><td>4,117.0</td><td></td></tr><tr><td>Accumulated other comprehensive income</td><td>4.6</td><td>0.3</td><td></td></tr><tr><td>Preferred stock of subsidiary</td><td>30.4</td><td>30.4</td><td></td></tr><tr><td>Long-term debt</td><td>9,124.1</td><td>4,170.7</td><td></td></tr><tr><td>Total capitalization</td><td>17,809.3</td><td>8,620.8</td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td><td></td></tr><tr><td>Current portion of long-term debt</td><td>157.7</td><td>424.1</td><td></td></tr><tr><td>Short-term debt</td><td>1,095.0</td><td>617.6</td><td></td></tr><tr><td>Accounts payable</td><td>815.4</td><td>363.3</td><td></td></tr><tr><td>Accrued payroll and benefits</td><td>169.7</td><td>95.1</td><td></td></tr><tr><td>Other</td><td>471.2</td><td>168.6</td><td></td></tr><tr><td>Total current liabilities</td><td>2,709.0</td><td>1,668.7</td><td></td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td><td></td></tr><tr><td>Regulatory liabilities</td><td>1,392.2</td><td>830.6</td><td></td></tr><tr><td>Deferred income taxes</td><td>4,622.3</td><td>2,664.0</td><td></td></tr><tr><td>Deferred revenue, net</td><td>579.4</td><td>614.1</td><td></td></tr><tr><td>Pension and other postretirement benefit obligations</td><td>543.1</td><td>203.8</td><td></td></tr><tr><td>Environmental remediation</td><td>628.2</td><td>32.6</td><td></td></tr><tr><td>Other</td><td>1,071.7</td><td>270.4</td><td></td></tr><tr><td>Total deferred credits and other liabilities</td><td>8,836.9</td><td>4,615.5</td><td></td></tr><tr><td>Commitments and contingencies (Note 18)</td><td></td><td></td><td></td></tr><tr><td>Total capitalization and liabilities</td><td>$ 29,355.2</td><td>$ 14,905.0</td><td></td></tr></table>

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



## WEC ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

<table><tr><td colspan="5">Year Ended December 31</td></tr><tr><td>(in millions)</td><td colspan="2">2015</td><td>2014</td><td>2013</td></tr><tr><td>Operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     640.3</td><td>$     589.5</td><td>$     578.6</td><td></td></tr><tr><td>Reconciliation to cash provided by operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>583.5</td><td>417.0</td><td>396.0</td><td></td></tr><tr><td>Deferred income taxes and investment tax credits, net</td><td>418.7</td><td>328.1</td><td>312.7</td><td></td></tr><tr><td>Contributions to pension and OPEB plans</td><td>(121.0)</td><td>(13.9)</td><td>(22.8)</td><td></td></tr><tr><td>Change in -</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable and unbilled revenues</td><td>84.0</td><td>80.7</td><td>(162.9)</td><td></td></tr><tr><td>Materials, supplies, and inventories</td><td>(69.4)</td><td>(71.2)</td><td>31.3</td><td></td></tr><tr><td>Other current assets</td><td>(27.2)</td><td>(13.9)</td><td>2.8</td><td></td></tr><tr><td>Accounts payable</td><td>(9.3)</td><td>23.7</td><td>(14.8)</td><td></td></tr><tr><td>Accrued taxes, net</td><td>35.7</td><td>(11.4)</td><td>36.6</td><td></td></tr><tr><td>Other current liabilities</td><td>(21.6)</td><td>(33.9)</td><td>(1.5)</td><td></td></tr><tr><td>Other, net</td><td>(220.1)</td><td>(95.8)</td><td>76.2</td><td></td></tr><tr><td>Net cash provided by operating activities</td><td>1,293.6</td><td>1,198.9</td><td>1,232.2</td><td></td></tr><tr><td>Investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(1,266.2)</td><td>(761.2)</td><td>(725.2)</td><td></td></tr><tr><td>Business acquisition, net of cash acquired of $156.3</td><td>(1,329.9)</td><td>—</td><td>—</td><td></td></tr><tr><td>Investment in transmission affiliate</td><td>(8.7)</td><td>(13.1)</td><td>(10.5)</td><td></td></tr><tr><td>Proceeds from asset sales</td><td>28.9</td><td>13.9</td><td>2.5</td><td></td></tr><tr><td>Proceeds from cashout of corporate owned life insurance policies</td><td>17.3</td><td>—</td><td>—</td><td></td></tr><tr><td>Other, net</td><td>41.1</td><td>3.6</td><td>(12.6)</td><td></td></tr><tr><td>Net cash used in investing activities</td><td>(2,517.5)</td><td>(756.8)</td><td>(745.8)</td><td></td></tr><tr><td>Financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Exercise of stock options</td><td>30.1</td><td>50.3</td><td>48.5</td><td></td></tr><tr><td>Purchase of common stock</td><td>(74.7)</td><td>(123.2)</td><td>(223.4)</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(455.4)</td><td>(352.0)</td><td>(328.9)</td><td></td></tr><tr><td>Redemption of WPS preferred stock</td><td>(52.7)</td><td>—</td><td>—</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>2,150.0</td><td>250.0</td><td>251.0</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(529.6)</td><td>(324.3)</td><td>(397.2)</td><td></td></tr><tr><td>Change in short-term debt</td><td>163.0</td><td>80.2</td><td>142.8</td><td></td></tr><tr><td>Other, net</td><td>(18.9)</td><td>12.8</td><td>11.2</td><td></td></tr><tr><td>Net cash provided by (used in) financing activities</td><td>1,211.8</td><td>(406.2)</td><td>(496.0)</td><td></td></tr><tr><td>Net change in cash and cash equivalents</td><td>(12.1)</td><td>35.9</td><td>(9.6)</td><td></td></tr><tr><td>Cash and cash equivalents at beginning of year</td><td>61.9</td><td>26.0</td><td>35.6</td><td></td></tr><tr><td>Cash and cash equivalents at end of year</td><td>$     49.8</td><td>$     61.9</td><td>$     26.0</td><td></td></tr></table>

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



## WEC ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF EQUITY

<table><tr><td rowspan="2">(in millions, expect per share amounts)</td><td colspan="6">WEC Energy Group Common Shareholders&#x27; Equity</td><td rowspan="2">Preferred Stock of Subsidiaries</td><td rowspan="2">Total Equity</td></tr><tr><td>Common Stock</td><td>Additional Paid-In Capital</td><td>Retained Earnings</td><td>Accumulated Other Comprehensive Income</td><td>Total Common Shareholders&#x27; Equity</td></tr><tr><td>Balance at December 31, 2012</td><td>$ 2.3</td><td>$ 500.3</td><td>$ 3,632.2</td><td>$ 0.3</td><td>$ 4,135.1</td><td>$ 30.4</td><td>$ 4,165.5</td></tr><tr><td>Net income attributed to common shareholders</td><td>—</td><td>—</td><td>577.4</td><td>—</td><td>577.4</td><td>—</td><td>577.4</td></tr><tr><td>Common stock dividends of $1.45 per share</td><td>—</td><td>—</td><td>(328.9)</td><td>—</td><td>(328.9)</td><td>—</td><td>(328.9</td></tr><tr><td>Exercise of stock options</td><td>—</td><td>48.5</td><td>—</td><td>—</td><td>48.5</td><td>—</td><td>48.5</td></tr><tr><td>Purchase of common stock</td><td>—</td><td>(223.4)</td><td>—</td><td>—</td><td>(223.4)</td><td>—</td><td>(223.4</td></tr><tr><td>Stock-based compensation and other</td><td>—</td><td>24.3</td><td>—</td><td>—</td><td>24.3</td><td>—</td><td>24.3</td></tr><tr><td>Balance at December 31, 2013</td><td>2.3</td><td>349.7</td><td>3,880.7</td><td>0.3</td><td>4,233.0</td><td>30.4</td><td>4,263.4</td></tr><tr><td>Net income attributed to common shareholders</td><td>—</td><td>—</td><td>588.3</td><td>—</td><td>588.3</td><td>—</td><td>588.3</td></tr><tr><td>Common stock dividends of $1.56 per share</td><td>—</td><td>—</td><td>(352.0)</td><td>—</td><td>(352.0)</td><td>—</td><td>(352.0</td></tr><tr><td>Exercise of stock options</td><td>—</td><td>50.3</td><td>—</td><td>—</td><td>50.3</td><td>—</td><td>50.3</td></tr><tr><td>Purchase of common stock</td><td>—</td><td>(123.2)</td><td>—</td><td>—</td><td>(123.2)</td><td>—</td><td>(123.2</td></tr><tr><td>Stock-based compensation and other</td><td>—</td><td>23.3</td><td>—</td><td>—</td><td>23.3</td><td>—</td><td>23.3</td></tr><tr><td>Balance at December 31, 2014</td><td>2.3</td><td>300.1</td><td>4,117.0</td><td>0.3</td><td>4,419.7</td><td>30.4</td><td>4,450.1</td></tr><tr><td>Net income attributed to common shareholders</td><td>—</td><td>—</td><td>638.5</td><td>—</td><td>638.5</td><td>—</td><td>638.5</td></tr><tr><td>Other comprehensive income</td><td>—</td><td>—</td><td>—</td><td>4.3</td><td>4.3</td><td>—</td><td>4.3</td></tr><tr><td>Common stock dividends of $1.74 per share</td><td>—</td><td>—</td><td>(455.4)</td><td>—</td><td>(455.4)</td><td>—</td><td>(455.4</td></tr><tr><td>Exercise of stock options</td><td>—</td><td>30.1</td><td>—</td><td>—</td><td>30.1</td><td>—</td><td>30.1</td></tr><tr><td>Issuance of common stock for the acquisition of Integrys</td><td>0.9</td><td>4,072.0</td><td>—</td><td>—</td><td>4,072.9</td><td>—</td><td>4,072.9</td></tr><tr><td>Purchase of common stock</td><td>—</td><td>(74.7)</td><td>—</td><td>—</td><td>(74.7)</td><td>—</td><td>(74.7</td></tr><tr><td>Addition of WPS preferred stock</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>51.1</td><td>51.1</td></tr><tr><td>Redemption of WPS preferred stock</td><td>—</td><td>(1.6)</td><td>—</td><td>—</td><td>(1.6)</td><td>(51.1)</td><td>(52.7</td></tr><tr><td>Stock-based compensation and other</td><td>—</td><td>21.3</td><td>(0.3)</td><td>—</td><td>21.0</td><td>—</td><td>21.0</td></tr><tr><td>Balance at December 31, 2015</td><td>$ 3.2</td><td>$ 4,347.2</td><td>$ 4,299.8</td><td>$ 4.6</td><td>$ 8,654.8</td><td>$ 30.4</td><td>$ 8,685.2</td></tr></table>

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



## WEC ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF CAPITALIZATION

<table><tr><td colspan="5">At December 31</td></tr><tr><td colspan="2">(in millions)</td><td>2015</td><td>2014</td><td></td></tr><tr><td colspan="2">Common equity (see accompanying statement)</td><td>$ 8,654.8</td><td>$ 4,419.7</td><td></td></tr><tr><td colspan="2">Preferred stock of subsidiary (Note 12)</td><td>30.4</td><td>30.4</td><td></td></tr><tr><td>Long-term debt</td><td>Interest Rate</td><td>Year Due</td><td></td><td></td></tr><tr><td rowspan="3">WEC Energy Group Senior Notes (unsecured)</td><td>1.65%</td><td>2018</td><td>300.0</td><td>—</td></tr><tr><td>2.45%</td><td>2020</td><td>400.0</td><td>—</td></tr><tr><td>3.55%</td><td>2025</td><td>500.0</td><td>—</td></tr><tr><td></td><td>6.20%</td><td>2033</td><td>200.0</td><td>200.0</td></tr><tr><td>WEC Energy Group Junior Notes (unsecured)</td><td>6.25%</td><td>2067</td><td>500.0</td><td>500.0</td></tr><tr><td rowspan="10">Wisconsin Electric Debentures (unsecured)</td><td>6.25%</td><td>2015</td><td>—</td><td>250.0</td></tr><tr><td>1.70%</td><td>2018</td><td>250.0</td><td>250.0</td></tr><tr><td>4.25%</td><td>2019</td><td>250.0</td><td>250.0</td></tr><tr><td>2.95%</td><td>2021</td><td>300.0</td><td>300.0</td></tr><tr><td>3.10%</td><td>2025</td><td>250.0</td><td>—</td></tr><tr><td>6.50%</td><td>2028</td><td>150.0</td><td>150.0</td></tr><tr><td>5.625%</td><td>2033</td><td>335.0</td><td>335.0</td></tr><tr><td>5.70%</td><td>2036</td><td>300.0</td><td>300.0</td></tr><tr><td>3.65%</td><td>2042</td><td>250.0</td><td>250.0</td></tr><tr><td>4.25%</td><td>2044</td><td>250.0</td><td>250.0</td></tr><tr><td>4.30%</td><td>2045</td><td>250.0</td><td>—</td></tr><tr><td></td><td>6.875%</td><td>2095</td><td>100.0</td><td>100.0</td></tr><tr><td rowspan="5">WPS Notes (unsecured)</td><td>5.65%</td><td>2017</td><td>125.0</td><td>—</td></tr><tr><td>1.65%</td><td>2018</td><td>250.0</td><td>—</td></tr><tr><td>6.08%</td><td>2028</td><td>50.0</td><td>—</td></tr><tr><td>5.55%</td><td>2036</td><td>125.0</td><td>—</td></tr><tr><td>3.671%</td><td>2042</td><td>300.0</td><td>—</td></tr><tr><td></td><td>4.752%</td><td>2044</td><td>450.0</td><td>—</td></tr><tr><td rowspan="2">Wisconsin Gas Debentures (unsecured)</td><td>5.20%</td><td>2015</td><td>—</td><td>125.0</td></tr><tr><td>3.53%</td><td>2025</td><td>200.0</td><td>—</td></tr><tr><td rowspan="2">PGL First and Refunding Mortgage Bonds (secured) (1)</td><td>5.90%</td><td>2035</td><td>90.0</td><td>90.0</td></tr><tr><td>2.21%</td><td>2016</td><td>50.0</td><td>—</td></tr><tr><td></td><td>8.00%</td><td>2018</td><td>5.0</td><td>—</td></tr><tr><td></td><td>4.63%</td><td>2019</td><td>75.0</td><td>—</td></tr><tr><td></td><td>3.90%</td><td>2030</td><td>50.0</td><td>—</td></tr><tr><td></td><td>1.875%</td><td>2033</td><td>50.0</td><td>—</td></tr><tr><td></td><td>4.00%</td><td>2033</td><td>50.0</td><td>—</td></tr><tr><td></td><td>3.30%</td><td>2035</td><td>50.0</td><td>—</td></tr><tr><td></td><td>3.98%</td><td>2042</td><td>100.0</td><td>—</td></tr><tr><td></td><td>3.96%</td><td>2043</td><td>220.0</td><td>—</td></tr><tr><td></td><td>4.21%</td><td>2044</td><td>200.0</td><td>—</td></tr><tr><td>NSG First Mortgage Bonds (secured) (2)</td><td>3.43%</td><td>2027</td><td>28.0</td><td>—</td></tr><tr><td></td><td>3.96%</td><td>2043</td><td>54.0</td><td>—</td></tr><tr><td rowspan="3">We Power Subsidiary Notes (secured, nonrecourse)</td><td>4.91%</td><td>(3)</td><td>2015-2030</td><td>112.1</td></tr><tr><td>5.209%</td><td>(4)</td><td>2015-2030</td><td>215.0</td></tr><tr><td>4.673%</td><td>(4)</td><td>2015-2031</td><td>178.3</td></tr><tr><td></td><td>6.00%</td><td>(3)</td><td>2015-2033</td><td>130.5</td></tr><tr><td></td><td>6.09%</td><td>(4)</td><td>2030-2040</td><td>275.0</td></tr><tr><td></td><td>5.848%</td><td>(4)</td><td>2031-2041</td><td>215.0</td></tr><tr><td>WECC Notes (unsecured)</td><td>6.94%</td><td>2028</td><td>50.0</td><td>50.0</td></tr><tr><td>Integrys Senior Notes (unsecured)</td><td>8.00%</td><td>2016</td><td>50.0</td><td>—</td></tr><tr><td></td><td>4.17%</td><td>2020</td><td>250.0</td><td>—</td></tr><tr><td>Integrys Junior Notes (unsecured)</td><td>6.11%</td><td>2066</td><td>269.8</td><td>—</td></tr><tr><td></td><td>6.00%</td><td>2073</td><td>400.0</td><td>—</td></tr><tr><td>Other Notes (secured, nonrecourse)</td><td>4.81%</td><td>2030</td><td>2.0</td><td>2.0</td></tr></table>



<table><tr><td>Obligations under capital leases</td><td>59.9</td><td>84.5</td></tr><tr><td>Total long-term debt and capital lease obligations</td><td>9,314.6</td><td>4,636.9</td></tr><tr><td>Integrys acquisition fair value adjustment</td><td>41.1</td><td>—</td></tr><tr><td>Unamortized debt issuance costs</td><td>(37.8)</td><td>(15.7)</td></tr><tr><td>Unamortized discount, net and other</td><td>(36.1)</td><td>(26.4)</td></tr><tr><td>Total</td><td>9,281.8</td><td>4,594.8</td></tr><tr><td>Current portion of long-term debt and capital lease obligations</td><td>(157.7)</td><td>(424.1)</td></tr><tr><td>Total long-term debt and capital lease obligations</td><td>9,124.1</td><td>4,170.7</td></tr><tr><td>Total long-term capitalization</td><td>17,809.3</td><td>8,620.8</td></tr></table>

(1) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.

PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds.

(2) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.

(3) We Power senior notes, secured by a collateral assignment of the leases between PWGS and Wisconsin Electric related to PWGS 1 and 2.

(4) We Power senior notes, secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1 and 2.

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.



# WEC ENERGY GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

## NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) General Information—On June 29, 2015, Wisconsin Energy Corporation acquired Integrys and changed its name to WEC Energy Group, Inc. WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and it owns approximately 60% of ATC. See Note 2, Acquisition, for more information on this acquisition.

As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.

Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments:

• Wisconsin segment – Consists of Wisconsin Electric, Wisconsin Gas, and WPS, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin. Wisconsin Electric’s electric and WPS’s electric and natural gas operations in the state of Michigan are also included in this segment.

• Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.

- Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.

- Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a federally regulated electric transmission company.

• We Power segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

- Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF.

Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Facilities, for more information. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

(b) Reclassifications—On the income statements for the years ended December 31, 2014 and 2013, we reclassified $17.4 million and $48.0 million, respectively, from treasury grant to depreciation and amortization. We also reclassified $1.2 million from interest expense to preferred stock dividends of subsidiaries on the income statements for the years ended December 31, 2014 and 2013. These reclassifications were made to be consistent with the current year presentation on the income statements.

During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $15.7 million, previously reported as other long-term assets, were reclassified to offset long-term debt on the December 31, 2014 balance sheet. We also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes, during the fourth quarter of 2015. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $242.7 million, previously reported as a separate component of current assets, to offset long-term deferred income tax liabilities on the December 31, 2014 balance sheet.



On the statements of cash flows for the years ended December 31, 2014 and 2013, we reclassified $2.4 million and $4.2 million, respectively, from depreciation and amortization to other operating activities. In addition, we reclassified $13.9 million and $22.8 million of nonqualified pension and OPEB contributions from other operating activities to contributions to pension and OPEB plans on the statements of cash flows for the years ended December 31, 2014 and 2013, respectively. Preferred stock dividends of subsidiaries of $1.2 million were also reclassified from other financing activities to net income on the statements of cash flows for the years ended December 31, 2014 and 2013. These reclassifications were made to be consistent with the current year presentation on the statements of cash flows.

During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 24, Segment Information, for more information on our business segments.

(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.

(d) Revenues and Customer Receivables—We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers.

We present revenues net of pass-through taxes on the income statements.

Below is a summary of the significant mechanisms our utility subsidiaries had in place that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts:

- Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations.

- Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater return on common equity than authorized by the PSCW.

- Wisconsin Electric received payments from MISO under an SSR agreement for its PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 22, Regulatory Environment, and Note 23, Michigan Settlement, for more information.

- The rates for all of our natural gas utilities included one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.

- The rates of PGL and NSG included riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs.

- MERC's rates included a conservation improvement program rider for cost recovery of energy conservation and management program costs as well as a financial incentive for meeting energy savings goals.

- The rates of PGL and NSG, and the residential rates of Wisconsin Electric and Wisconsin Gas, included riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates.

- The rates of PGL, NSG, MERC, and MGU included decoupling mechanisms. These mechanisms differ by state and allow utilities to recover or refund differences between actual and authorized margins. MGU's decoupling mechanism was discontinued after December 31, 2015. See Note 22, Regulatory Environment, for more information.

• PGL's rates included a cost recovery mechanism for AMRP costs.



Revenues are also impacted by other accounting policies related to PGL's natural gas hub and our electric utilities' participation in the MISO Energy Markets. Amounts collected from PGL's wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers' charges for natural gas and services. Our electric utilities sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If our electric utilities were a net seller in a particular hour, the net amount was reported as operating revenue. If our electric utilities were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements.

ITF accounts for revenues from construction management projects using the percentage of completion method. Revenues are recognized based on the percentage of costs incurred to date compared to the total estimated costs of each contract. This method is used because management considers total costs to be the best available measure of progress on these contracts. See Note 3, Dispositions, for more information.

We provide regulated electric service to customers in Wisconsin and Michigan and regulated natural gas service to customers in Wisconsin, Illinois, Minnesota, and Michigan. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at Wisconsin Electric, Wisconsin Gas, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2015. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015.

(e) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Natural gas in storage</td><td>$ 284.1</td><td>$ 124.8</td></tr><tr><td>Materials and supplies</td><td>219.2</td><td>150.2</td></tr><tr><td>Fossil fuel</td><td>183.7</td><td>125.6</td></tr><tr><td>Total</td><td>$ 687.0</td><td>$ 400.6</td></tr></table>

PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the Last-in, First-out (LIFO) cost method. Inventories stated on a LIFO basis represented approximately 18.0% of total inventories at December 31, 2015. The estimated replacement cost of natural gas in inventory at December 31, 2015, exceeded the LIFO cost by $15.2 million. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $2.48 at December 31, 2015.

Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.

(f) Investments Held in Rabbi Trust— Integrys has a rabbi trust that is used to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. It holds investments that are classified as trading securities for accounting purposes. We do not intend to sell these investments in the near term. They are included in other investments on our balance sheet at December 31, 2015. The net unrealized loss included in earnings related to the investments held at the end of the period was not significant for the year ended December 31, 2015.

(g) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 6, Regulatory Assets and Liabilities, for more information.



(h) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and capitalized interest. Utility property also includes AFUDC – Equity. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:

<table><tr><td>Annual Utility Composite Depreciation Rates</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Wisconsin Electric</td><td>3.01%</td><td>2.93%</td><td>2.90%</td></tr><tr><td>WPS  \( {}^{(1)} \)</td><td>1.30%</td><td>N/A</td><td>N/A</td></tr><tr><td>Wisconsin Gas</td><td>2.36%</td><td>2.69%</td><td>2.68%</td></tr><tr><td>PGL  \( {}^{(1)} \)</td><td>1.67%</td><td>N/A</td><td>N/A</td></tr><tr><td>NSG  \( {}^{(1)} \)</td><td>1.22%</td><td>N/A</td><td>N/A</td></tr><tr><td>MERC  \( {}^{(1)} \)</td><td>1.26%</td><td>N/A</td><td>N/A</td></tr><tr><td>MGU  \( {}^{(1)} \)</td><td>1.32%</td><td>N/A</td><td>N/A</td></tr></table>

(1) The rates shown for 2015 are for a partial year as a result of the acquisition of Integrys on June 29, 2015. The full year rate would be approximately double the rate shown.

We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for OC 1 and OC 2.

We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.

(i) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - Debt) used during plant construction, and a return on stockholders' capital (AFUDC – Equity) used for construction purposes. AFUDC - Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net.

The majority of AFUDC is recorded at Wisconsin Electric, WPS, and Wisconsin Gas. Approximately 50% of Wisconsin Electric's, WPS's, and Wisconsin Gas's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. For 2015, Wisconsin Electric's average AFUDC retail rate was 8.45%, and its average AFUDC wholesale rate was 1.72%. For the six months ended December 31, 2015, WPS's average AFUDC retail rate was 7.92% and its average AFUDC wholesale rate was 5.04%. For 2015, Wisconsin Gas's average AFUDC retail rate was 8.33%. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while the other utilities AFUDC rates are determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities and WBS did not record significant AFUDC for 2015, 2014, or 2013.

Our regulated utilities recorded the following AFUDC for the years ended December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>AFUDC - Debt</td><td>$ 8.6</td><td>$ 2.3</td><td>$ 7.7</td></tr><tr><td>AFUDC - Equity</td><td>$ 20.1</td><td>$ 5.6</td><td>$ 18.3</td></tr></table>

(j) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Intangible assets with definite lives are reviewed for impairment on a quarterly basis. Other long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable.

An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

Our reporting units containing goodwill perform annual goodwill impairment tests during the third quarter of each year. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit



exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 10, Goodwill and Other Intangible Assets, for more information.

The carrying amounts of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.

(k) Deferred Revenue—As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheets and we are amortizing the deferred carrying costs to revenue over the individual lease terms.

(I) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. A liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.

(m) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 18, Commitments and Contingencies, for more information.

We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.

Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state Commission's approval.

We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.

(n) Income Taxes—We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. See Note 15, Income Taxes, for more information.



We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements.

(o) Guarantees— We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 16, Guarantees, for more information.

(p) Employee Benefits—The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are allocated among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information.

(q) Stock-Based Compensation— In accordance with stockholder approved plans, we provide long-term incentives through our equity interests to our outside directors, officers, and other key employees. The plans provide for the granting of stock options, restricted stock awards, performance shares, and other share-based awards. Awards may be paid in common stock, cash, or a combination thereof. We recognize share-based compensation expense on a straight-line basis. Accordingly, for employee awards classified as equity awards, share-based compensation expense is measured based on the grant-date fair value of the award and is recognized as expense ratably over the requisite service period.

## Stock Options

We grant non-qualified stock options that vest on a cliff-basis after a three-year period. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. There were no modifications to the terms of outstanding stock options during the year.

The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted along with the weighted-average assumptions used in the valuation models:

<table><tr><td></td><td colspan="2">2015</td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td>Non-qualified stock options granted</td><td colspan="2">516,475</td><td colspan="2">899,500</td><td colspan="2">1,418,560</td></tr><tr><td>Estimated fair value per non-qualified stock option</td><td>$</td><td>5.29</td><td>$</td><td>4.18</td><td>$</td><td>3.45</td></tr><tr><td>Assumptions used to value the options:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Risk-free interest rate</td><td colspan="2">0.1% - 2.1%</td><td colspan="2">0.1% - 3.0%</td><td colspan="2">0.1% - 1.9%</td></tr><tr><td>Dividend yield</td><td colspan="2">3.7%</td><td colspan="2">3.8%</td><td colspan="2">3.7%</td></tr><tr><td>Expected volatility</td><td colspan="2">18.0%</td><td colspan="2">18.0%</td><td colspan="2">18.0</td></tr><tr><td>Expected forfeiture rate</td><td colspan="2">2.0%</td><td colspan="2">2.0%</td><td colspan="2">2.0</td></tr><tr><td>Expected life (years)</td><td colspan="2">5.8</td><td colspan="2">5.8</td><td colspan="2">5.9</td></tr></table>

The risk-free interest rate is based on the U.S. Treasury interest rate with a term consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate, and expected life assumptions are based on our historical experience.

## Restricted Shares

Restricted shares have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.

## Performance Units

Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on our total stockholder return (stock price appreciation plus dividends) as compared to the total stockholder return of a peer group of companies over a three-year



period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash and are accounted for as liability awards accordingly. We accrue compensation costs over the three-year performance period based on our estimate of the final expected value of the awards.

See Note 11, Common Equity, for more information on our share-based compensation plans.

(r) Earnings Per Share—We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. Options to purchase 516,475 shares of common stock with an exercise price of $52.90 were outstanding at December 31, 2015, but were not included in the computation of diluted earnings per share because they were anti-dilutive. All stock options outstanding during 2014 and 2013 were included in the computation of diluted earnings per share.

(s) Fair Value Measurements—Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.

Derivatives were transferred between levels of the fair value hierarchy primarily due to observable pricing becoming available. We recognize transfers at their value as of the end of the reporting period.

Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a perpetual dividend discount model. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases, is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.



See Note 19, Fair Value Measurements, for more information.

(t) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.

We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Gains and losses on derivative instruments are primarily recorded in cost of sales on the income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 20, Derivative Instruments, for more information.

(u) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service.

Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within current liabilities on our balance sheets.

## NOTE 2—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. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy and CNG products and services. Integrys also held a 34% interest in ATC, a for-profit transmission company regulated by the FERC. The acquisition of Integrys provides increased scale, the potential for long-term cost savings through a combination of lower capital and operating costs, and the potential for operating efficiencies.



## Purchase Price

Pursuant to the Merger Agreement, Integrys's shareholders received 1.128 shares of Wisconsin Energy Corporation common stock and $18.58 in cash per share of Integrys common stock. The total consideration transferred was based on the closing price of Wisconsin Energy Corporation common stock on June 29, 2015, and was calculated as follows:

<table><tr><td rowspan="2">(in millions, except per share amounts)</td><td colspan="3">Consideration Paid</td></tr><tr><td>Stock</td><td>Cash</td><td>Total</td></tr><tr><td>Integrys common shares outstanding at June 29, 2015</td><td>79,963,091</td><td>79,963,091</td><td></td></tr><tr><td>Exchange ratio</td><td>1.128</td><td></td><td></td></tr><tr><td>Wisconsin Energy Corporation shares issued for Integrys shares  \( {}^{*} \)</td><td>90,187,884</td><td></td><td></td></tr><tr><td>Closing price of Wisconsin Energy Corporation common shares on June 29, 2015</td><td>45.16</td><td></td><td></td></tr><tr><td>Fair value of common stock issued</td><td>4,072.9</td><td></td><td>4,072.9</td></tr><tr><td>Cash paid per share of Integrys shares outstanding</td><td></td><td>18.58</td><td></td></tr><tr><td>Fair value of cash paid for Integrys shares  \( {}^{*} \)</td><td></td><td>1,486.2</td><td>1,486.2</td></tr><tr><td>Consideration attributable to settlement of equity awards, net of tax</td><td></td><td>24.0</td><td>24.0</td></tr><tr><td>Total purchase price</td><td>4,072.9</td><td>1,510.2</td><td>5,583.1</td></tr></table>

* Fractional shares of 10,483 totaling $0.5 million were paid in cash.

All Integrys unvested stock-based compensation awards became fully vested upon the close of the acquisition and were either paid to award recipients in cash, or the value of the awards was deferred into a deferred compensation plan. In addition, all vested but unexercised Integrys stock options were paid in cash. In accordance with accounting guidance for business combinations, the acceleration of the vesting was recorded as an acquisition-related expense.

## Allocation of Purchase Price

The Integrys assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the FASB ASC. Substantially all of Integrys's operations are subject to the rate-setting authority of federal and state regulatory commissions. These operations are accounted for following the accounting guidance under the Regulated Operations Topic of the FASB ASC. The underlying assets and liabilities of ATC are also regulated by the FERC. The fair values of Integrys's assets and liabilities subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The goodwill reflects the value paid for the increased scale and efficiencies as a result of the combination. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill. See Note 10, Goodwill and Other Intangible Assets, for the allocation of goodwill to our reportable segments.



The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The allocation is subject to change during the remainder of the measurement period, which ends one year from the acquisition date, as we obtain additional information, including with respect to certain regulatory and legal matters and the expected sale of ITF.

<table><tr><td colspan="2">(in millions)</td></tr><tr><td>Current assets</td><td>$ 1,069.9</td></tr><tr><td>Net property, plant, and equipment</td><td>7,091.8</td></tr><tr><td>Investments  \( * \)</td><td>1,062.5</td></tr><tr><td>Goodwill</td><td>2,581.6</td></tr><tr><td>Deferred charges and other assets, excluding goodwill</td><td>1,737.9</td></tr><tr><td>Current liabilities, including current maturities of long-term debt</td><td>(1,293.5)</td></tr><tr><td>Deferred credits and other liabilities</td><td>(3,668.5)</td></tr><tr><td>Long-term debt</td><td>(2,947.5)</td></tr><tr><td>Preferred stock of subsidiary</td><td>(51.1)</td></tr><tr><td>Total purchase price</td><td>$ 5,583.1</td></tr></table>

* Includes equity method goodwill related to Integrys's investment in ATC. See Note 4, Investment in American Transmission Company, for more information.

In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments, which requires that an acquirer recognize and disclose adjustments to provisional amounts that are identified during an acquisition measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. We early adopted ASU 2015-16 in the fourth quarter of 2015. Adoption had no impact on our financial statements.

## Conditions of Approval

The acquisition was subject to the approvals of various government agencies, including the FERC, Federal Communications Commission, PSCW, ICC, MPSC, and MPUC. Approvals were obtained from all agencies subject to several conditions.

The PSCW order includes the following conditions:

- Wisconsin Electric and Wisconsin Gas will be subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, if either company earns above its authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers. For Wisconsin Electric, the additional utility earnings will be used to reduce the company's transmission escrow. For Wisconsin Gas, additional utility earnings will be used to reduce the costs of the Western Gas Lateral. All utility earnings above the first 50 basis points will be used to reduce the transmission escrow for Wisconsin Electric and reduce the costs of the Western Gas Lateral for Wisconsin Gas.

- Any future electric generation projects affecting Wisconsin ratepayers submitted by us or our subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, WPS and Wisconsin Electric filed a joint integrated resource plan with the PSCW for their combined loads, which indicated that no new generation is currently needed.

The ICC order includes a base rate freeze for PGL and NSG effective for two years after the close of the acquisition. This base rate freeze does not impact PGL's or NSG's ability to adjust rates through various riders or GCRMs.

We do not believe that the conditions set forth in the various regulatory orders approving the acquisition will have a material impact on our operations or financial results.

## Pro Forma Information

The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information



is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results.

The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs.

<table><tr><td rowspan="2">(in millions, except per share amounts)</td><td colspan="3">Year Ended December 31</td></tr><tr><td>2015</td><td>2014</td><td></td></tr><tr><td>Unaudited pro forma financial information</td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$     7,727.1</td><td>$     9,135.4</td><td></td></tr><tr><td>Net income attributed to common shareholders</td><td>$     873.5</td><td>$     869.9</td><td></td></tr><tr><td>Earnings per share (Basic)</td><td>$     2.77</td><td>$     2.76</td><td></td></tr><tr><td>Earnings per share (Diluted)</td><td>$     2.75</td><td>$     2.74</td><td></td></tr></table>

## Impact of Acquisition

As a result of the acquisition, our ownership of ATC increased to approximately 60%. We have made commitments with respect to our voting rights of the combined ownership of ATC, which are included as enforceable conditions in the FERC and PSCW orders approving the acquisition. Under GAAP, these commitments do not allow for the consolidation of ATC in our financial statements and the 60% ownership is accounted for as an equity method investment subsequent to the close of the acquisition. See Note 4, Investment in American Transmission Company, for more information.

In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $107.6 million and $12.5 million during 2015 and 2014, respectively. These costs consisted of employee-related expenses, professional fees, and other miscellaneous costs. They are primarily recorded in the other operation and maintenance line item on the income statements. No acquisition costs were recorded in 2013.

Included in the 2015 acquisition costs was $24.9 million of severance expense that resulted from employee reductions related to the post-acquisition integration. Severance payments of $16.9 million were made during 2015, leaving a severance accrual of $8.0 million on our balance sheet at December 31, 2015. Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments:

<table><tr><td>(in millions)</td><td>2015</td></tr><tr><td>Wisconsin</td><td>$ 11.1</td></tr><tr><td>Illinois</td><td>0.9</td></tr><tr><td>Other states</td><td>0.1</td></tr><tr><td>Corporate and other</td><td>12.8</td></tr><tr><td>Total severance expense</td><td>$ 24.9</td></tr></table>

Our revenues for the year ended December 31, 2015 include revenues attributable to Integrys of $1,416.8 million. Included in our net income for the year ended December 31, 2015, is net income attributable to Integrys of $65.9 million.

## NOTE 3—DISPOSITIONS

## Corporate and Other Segment – Pending Sale of Integrys Transportation Fuels

In February 2016, we reached an agreement to sell ITF. The sale is scheduled to close in the first quarter of 2016. ITF is a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation and maintenance. The pending sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. The pending sale of ITF does not represent a shift in our corporate strategy and will not have a major effect on our operations and financial results. Therefore, ITF's results of operations remain in continuing operations. The pre-tax profit or loss of this individually significant component was not material for the year ended December 31, 2015.

In November 2015, we sold our 30% joint interest in AMP Trillium LLC. This transaction was not significant, and there was no gain recorded on the sale. In addition, in the fourth quarter of 2015, we lowered the fair value of the remaining ITF assets to fair market value, less costs to sell. This fair value adjustment was reflected in the allocation of the purchase price for the acquisition. See Note 2, Acquisition, for more information.



The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31:

<table><tr><td>(in millions)</td><td>2015</td></tr><tr><td>Accounts receivable and unbilled revenues</td><td>$ 34.9</td></tr><tr><td>Materials, supplies, and inventories</td><td>18.4</td></tr><tr><td>Other current assets</td><td>2.6</td></tr><tr><td>Property, plant, and equipment</td><td>37.2</td></tr><tr><td>Other long-term assets</td><td>3.7</td></tr><tr><td>Total assets</td><td>$ 96.8</td></tr><tr><td>Accounts payable</td><td>$ 12.9</td></tr><tr><td>Accrued payroll and benefits</td><td>2.4</td></tr><tr><td>Other current liabilities</td><td>4.5</td></tr><tr><td>Pension and OPEB obligations</td><td>1.2</td></tr><tr><td>Other long-term liabilities</td><td>0.6</td></tr><tr><td>Total liabilities *</td><td>$ 21.6</td></tr></table>

* Included in other current liabilities on our balance sheet.

## NOTE 4—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

Due to the acquisition of Integrys on June 29, 2015, our ownership of ATC increased from 26.2% to approximately 60%. ATC is a for-profit, transmission-only company regulated by the FERC. We have one representative on ATC's ten-member board of directors. Each member of the board has only one vote. Due to voting requirements, no individual board member has more than 10% of the voting control. The following table shows changes to our investment in ATC during the years ended December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Balance at beginning of period</td><td>$ 424.1</td><td>$ 402.7</td><td>$ 378.3</td></tr><tr><td>Add: Earnings from equity method investment</td><td>96.1</td><td>66.0</td><td>68.5</td></tr><tr><td>Add: Capital contributions</td><td>8.7</td><td>13.1</td><td>10.5</td></tr><tr><td>Add: Acquisition of Integrys&#x27;s investment in ATC</td><td>541.5</td><td>—</td><td>—</td></tr><tr><td>Add: Equity method goodwill from the acquisition of Integrys *</td><td>395.8</td><td>—</td><td>—</td></tr><tr><td>Less: Distributions received</td><td>85.1</td><td>57.5</td><td>54.5</td></tr><tr><td>Less: Other</td><td>0.2</td><td>0.2</td><td>0.1</td></tr><tr><td>Balance at end of period</td><td>$ 1,380.9</td><td>$ 424.1</td><td>$ 402.7</td></tr></table>

* Represents the purchase price allocated to Integrys's investment in ATC in excess of the recorded value.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC during the years ended December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Charges to ATC for services and construction</td><td>$ 15.4</td><td>$ 8.1</td><td>$ 9.0</td></tr><tr><td>Charges from ATC for network transmission services</td><td>289.2</td><td>231.4</td><td>234.2</td></tr></table>

As of December 31, 2015 and 2014, our balance sheets included the following receivables and payables related to ATC:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Accounts receivable</td><td></td><td></td></tr><tr><td>Services provided to ATC</td><td>$ 1.0</td><td>$ 0.6</td></tr><tr><td>Accounts payable</td><td></td><td></td></tr><tr><td>Services received from ATC</td><td>28.3</td><td>19.3</td></tr></table>



Summarized financial data for ATC is included in the tables below:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Income statement data</td><td></td><td></td><td></td></tr><tr><td>Revenues</td><td>$ 615.8</td><td>$ 635.0</td><td>$ 626.3</td></tr><tr><td>Operating expenses</td><td>319.3</td><td>307.4</td><td>295.0</td></tr><tr><td>Other expense</td><td>96.1</td><td>88.9</td><td>83.7</td></tr><tr><td>Net income</td><td>$ 200.4</td><td>$ 238.7</td><td>$ 247.6</td></tr></table>

<table><tr><td>(in millions)</td><td>December 31, 2015</td><td>December 31, 2014</td></tr><tr><td>Balance sheet data</td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 80.5</td><td>$ 66.4</td></tr><tr><td>Noncurrent assets</td><td>3,957.6</td><td>3,728.7</td></tr><tr><td>Total assets</td><td>$ 4,038.1</td><td>$ 3,795.1</td></tr><tr><td>Current liabilities</td><td>$ 330.3</td><td>$ 313.1</td></tr><tr><td>Long-term debt</td><td>1,800.0</td><td>1,701.0</td></tr><tr><td>Other noncurrent liabilities</td><td>245.0</td><td>163.8</td></tr><tr><td>Shareholders&#x27; equity</td><td>1,662.8</td><td>1,617.2</td></tr><tr><td>Total liabilities and shareholders&#x27; equity</td><td>$ 4,038.1</td><td>$ 3,795.1</td></tr></table>

## NOTE 5—SUPPLEMENTAL CASH FLOW INFORMATION

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Cash paid for interest, net of amount capitalized</td><td>$ 329.6</td><td>$ 241.1</td><td>$ 250.4</td></tr><tr><td>Cash paid (received) for income taxes, net of refunds</td><td>9.3</td><td>22.0</td><td>(39.6)</td></tr><tr><td>Significant non-cash transactions:</td><td></td><td></td><td></td></tr><tr><td>Construction costs funded through accounts payable</td><td>177.1</td><td>1.8</td><td>4.7</td></tr><tr><td>Amortization of deferred revenue</td><td>39.9</td><td>55.7</td><td>56.5</td></tr><tr><td>Note receivable received related to the sale of AMP Trillium*</td><td>12.0</td><td>—</td><td>—</td></tr><tr><td>Capital assets received related to the sale of AMP Trillium *</td><td>6.3</td><td>—</td><td>—</td></tr></table>

 \( ^{*} \)  See Note 3, Dispositions, for more information.

At December 31, 2015, restricted cash of $118.4 million was recorded within other long-term assets on our balance sheet. This amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition.



## NOTE 6—REGULATORY ASSETS AND LIABILITIES

The following regulatory assets were reflected on our balance sheets as of December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>See Note</td></tr><tr><td>Regulatory assets (1) (2)</td><td></td><td></td><td></td></tr><tr><td>Unrecognized pension and OPEB costs (3)</td><td>$ 1,306.4</td><td>$ 669.1</td><td>17</td></tr><tr><td>Environmental remediation costs (4)</td><td>697.0</td><td>45.9</td><td>18</td></tr><tr><td>Income tax related items (5)</td><td>248.3</td><td>176.0</td><td></td></tr><tr><td>Electric transmission costs (6)</td><td>191.5</td><td>146.0</td><td></td></tr><tr><td>AROs</td><td>173.0</td><td>17.6</td><td>9</td></tr><tr><td>SSR</td><td>86.1</td><td>—</td><td>22</td></tr><tr><td>Derivatives</td><td>70.4</td><td>14.7</td><td>1(t)</td></tr><tr><td>Energy efficiency programs (7)</td><td>48.7</td><td>58.0</td><td></td></tr><tr><td>PTF (8)</td><td>45.4</td><td>66.6</td><td></td></tr><tr><td>Other, net</td><td>234.9</td><td>77.3</td><td></td></tr><tr><td>Total regulatory assets</td><td>$ 3,101.7</td><td>$ 1,271.2</td><td></td></tr><tr><td>Balance Sheet Presentation</td><td></td><td></td><td></td></tr><tr><td>Current assets (9)</td><td>$ 37.1</td><td>$ —</td><td></td></tr><tr><td>Regulatory assets</td><td>3,064.6</td><td>1,271.2</td><td></td></tr><tr><td>Total regulatory assets</td><td>$ 3,101.7</td><td>$ 1,271.2</td><td></td></tr></table>

(1) Based on prior and current rate treatment, we believe it is probable that our utility subsidiaries will continue to recover from customers the regulatory assets in the table above.

(2) As of December 31, 2015, we had $33.8 million of regulatory assets not earning a return and $136.6 million of regulatory assets earning a return based on short-term interest rates.

(3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans.

(4) As of December 31, 2015, we had not yet made cash expenditures for $628.2 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.

(5) Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years.

(6) Represents amounts recoverable from customers related to transmission costs incurred that exceed amounts authorized for recovery in our current rates.

(7) Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.

(8) Represents amounts recoverable from customers related to Wisconsin Electric’s costs of the PTF units, including subsequent capital additions.

(9) Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets.



The following regulatory liabilities were reflected on our balance sheets as of December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>See Note</td></tr><tr><td>Regulatory liabilities</td><td></td><td></td><td></td></tr><tr><td>Removal costs (1)</td><td>$ 1,209.6</td><td>$ 741.1</td><td></td></tr><tr><td>Energy costs refundable through rate adjustments (2)</td><td>76.9</td><td>18.9</td><td></td></tr><tr><td>Uncollectible expense (3)</td><td>31.8</td><td>30.1</td><td></td></tr><tr><td>Mines deferral (4)</td><td>31.6</td><td>—</td><td></td></tr><tr><td>Unrecognized pension and OPEB costs (5)</td><td>26.3</td><td>3.8</td><td>17</td></tr><tr><td>Other, net</td><td>49.8</td><td>36.7</td><td></td></tr><tr><td>Total regulatory liabilities</td><td>$ 1,426.0</td><td>$ 830.6</td><td></td></tr><tr><td>Balance Sheet Presentation</td><td></td><td></td><td></td></tr><tr><td>Other current liabilities</td><td>$ 33.8</td><td>$ —</td><td></td></tr><tr><td>Regulatory liabilities</td><td>1,392.2</td><td>830.6</td><td></td></tr><tr><td>Total regulatory liabilities</td><td>$ 1,426.0</td><td>$ 830.6</td><td></td></tr></table>

(1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.

(2) Represents energy costs that will be refunded to customers in the future.

(3) Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates.

(4) Represents the deferral of margins from the sales to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding.

(5) Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.

## NOTE 7—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Utility property, plant, and equipment</td><td>$ 22,803.7</td><td>$ 12,290.7</td></tr><tr><td>Less: Accumulated depreciation</td><td>7,358.2</td><td>4,044.6</td></tr><tr><td>Net</td><td>15,445.5</td><td>8,246.1</td></tr><tr><td>CWIP</td><td>672.7</td><td>170.1</td></tr><tr><td>Net utility property, plant, and equipment</td><td>16,118.2</td><td>8,416.2</td></tr><tr><td>Non-utility and other property, plant, and equipment</td><td>3,482.2</td><td>3,260.3</td></tr><tr><td>Less: Accumulated depreciation</td><td>560.9</td><td>440.5</td></tr><tr><td>Net</td><td>2,921.3</td><td>2,819.8</td></tr><tr><td>CWIP</td><td>150.2</td><td>21.7</td></tr><tr><td>Net non-utility and other property, plant, and equipment</td><td>3,071.5</td><td>2,841.5</td></tr><tr><td>Total property, plant, and equipment</td><td>$ 19,189.7</td><td>$ 11,257.7</td></tr></table>

## NOTE 8—JOINTLY OWNED FACILITIES

We Power and WPS hold joint ownership interests in certain electric generating facilities. They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest. They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects. We Power and WPS record their proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets.



We Power leases its ownership interest in the Oak Creek Expansion units to Wisconsin Electric, and Wisconsin Electric operates these units. Wisconsin Electric and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs. Wisconsin Electric's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements.

Information related to jointly owned facilities at December 31, 2015 was as follows:

<table><tr><td rowspan="2"></td><td colspan="2">We Power</td><td colspan="3">WPS</td></tr><tr><td>Oak Creek Expansion Units 1 and 2</td><td>Weston 4</td><td>Columbia Energy Center Units 1 and 2</td><td>Edgewater Unit 4</td><td></td></tr><tr><td>(in millions, except for percentages and MWs)</td><td>83.34%</td><td>70.0%</td><td>31.8%</td><td>31.8%</td><td></td></tr><tr><td>Ownership</td><td>1,056.8</td><td>374.5</td><td>352.9</td><td>96.3</td><td></td></tr><tr><td>Share of rated capacity (MWs)  \( {}^{*} \)</td><td>2010 and 2011</td><td>2008</td><td>1975 and 1978</td><td>1969</td><td></td></tr><tr><td>In-service date</td><td>2,359.6</td><td>591.5</td><td>404.6</td><td>47.6</td><td></td></tr><tr><td>Property, plant, and equipment</td><td>(283.4)</td><td>(150.5)</td><td>(122.6)</td><td>(30.6)</td><td></td></tr><tr><td>Accumulated depreciation</td><td>35.5</td><td>5.9</td><td>23.4</td><td>0.4</td><td></td></tr><tr><td>CWIP</td><td>35.5</td><td>5.9</td><td>23.4</td><td>0.</td><td></td></tr></table>

* Based on expected capacity ratings for summer 2016. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

## NOTE 9—ASSET RETIREMENT OBLIGATIONS

Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and polychlorinated biphenyls [PCBs]); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of generation facilities; the dismantling of wind generation projects; the disposal of PCB-contaminated transformers; the closure of fly-ash landfills at certain generation facilities; and the removal of above ground storage tanks. The utilities establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. PDL has AROs recorded for the removal of solar equipment components. On our balance sheets, AROs are recorded within other long-term liabilities.

The following table shows changes to our AROs:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Balance as of January 1</td><td>43.6</td><td>42.3</td><td>44.3</td></tr><tr><td>Integrys subsidiaries</td><td>491.0</td><td>—</td><td>—</td></tr><tr><td>Accretion</td><td>14.5</td><td>2.4</td><td>2.4</td></tr><tr><td>Additions and revisions to estimated cash flows</td><td>35.5  \( {}^{*} \)</td><td>—</td><td>—</td></tr><tr><td>Liabilities settled</td><td>(13.4)</td><td>(1.1)</td><td>(4.4)</td></tr><tr><td>Balance as of December 31</td><td>571.2</td><td>43.6</td><td>42.3</td></tr></table>

* An ARO of $16.1 million was recorded during 2015 for fly-ash landfills located at generation facilities owned by Wisconsin Electric and WPS. An ARO of $9.0 million was also recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. In addition, AROs increased $10.4 million in 2015 due to revisions made to estimated cash flows primarily for changes in the weighted average cost to retire natural gas distribution pipe at PGL and NSG.



## NOTE 10—GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table shows changes to our goodwill balances by segment during the years ended December 31, 2015 and 2014:

<table><tr><td rowspan="2">(in millions)</td><td colspan="2">Wisconsin</td><td colspan="2">Illinois</td><td colspan="2">Other States</td><td colspan="2">Total</td></tr><tr><td>2015</td><td>2014</td><td>2015</td><td>2014</td><td>2015</td><td>2014</td><td>2015</td><td></td></tr><tr><td>Balance as of January 1</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gross goodwill</td><td>$ 441.9</td><td>$ 441.9</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 441.9</td><td>$ 441.9</td></tr><tr><td>Accumulated impairment losses</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Net goodwill as of January 1</td><td>441.9</td><td>441.9</td><td>—</td><td>—</td><td>—</td><td>—</td><td>441.9</td><td>441.9</td></tr><tr><td>Acquisition of Integrys</td><td>1,667.6</td><td>—</td><td>731.2</td><td>—</td><td>182.8</td><td>—</td><td>2,581.6</td><td>—</td></tr><tr><td>Balance as of December 31</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gross goodwill</td><td>2,109.5</td><td>441.9</td><td>731.2</td><td>—</td><td>182.8</td><td>—</td><td>3,023.5</td><td>441.9</td></tr><tr><td>Accumulated impairment losses</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Net goodwill as of December 31</td><td>$ 2,109.5</td><td>$ 441.9</td><td>$ 731.2</td><td>$ —</td><td>$ 182.8</td><td>$ —</td><td>$ 3,023.5</td><td>$ 441.9</td></tr></table>

In the third quarter of 2015, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of August 31, 2015. No impairments resulted from these tests.

The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets. We had no material intangible assets other than goodwill at December 31, 2014.

<table><tr><td rowspan="2">(in millions)</td><td colspan="4">December 31, 2015</td></tr><tr><td>Gross Carrying Amount</td><td>Accumulated Amortization</td><td>Net Carrying Amount</td><td></td></tr><tr><td>Amortized intangible assets  \( {}^{(1)} \)</td><td>$ 16.0</td><td>$ (7.8)</td><td>$ 8.2</td><td></td></tr><tr><td>Unamortized intangible assets  \( {}^{(2)} \)</td><td>5.7</td><td>—</td><td>5.7</td><td></td></tr><tr><td>Total intangible assets</td><td>$ 21.7</td><td>$ (7.8)</td><td>$ 13.9</td><td></td></tr></table>

(1) Primarily relates to contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at WPS's Fox Energy Center. The remaining weighted-average amortization period for our amortized intangible assets at December 31, 2015, was approximately three years.

(1) Consists primarily of a trade name.

## NOTE 11—COMMON EQUITY

## Share-Based Compensation Plans

The following table summarizes our pre-tax share-based compensation expense and the related tax benefit for the year ended December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Stock options</td><td>$ 3.3</td><td>$ 3.7</td><td>$ 3.9</td></tr><tr><td>Restricted stock</td><td>7.0</td><td>2.8</td><td>2.4</td></tr><tr><td>Performance units</td><td>13.0</td><td>15.4</td><td>12.7</td></tr><tr><td>Share-based compensation expense</td><td>$ 23.3</td><td>$ 21.9</td><td>$ 19.0</td></tr><tr><td>Related tax benefit</td><td>$ 9.3</td><td>$ 8.8</td><td>$ 7.6</td></tr></table>

Stock-based compensation capitalized was not significant during 2015, 2014, and 2013.



## Stock Options

The following is a summary of our stock option activity during 2015:

<table><tr><td>Stock Options</td><td>Number of Options</td><td>Weighted-Average Exercise Price</td><td>Weighted-Average Remaining Contractual Life (in years)</td><td>Aggregate Intrinsic Value (in millions)</td></tr><tr><td>Outstanding as of January 1, 2015</td><td>6,770,194</td><td>$ 29.99</td><td></td><td></td></tr><tr><td>Granted</td><td>516,475</td><td>$ 52.90</td><td></td><td></td></tr><tr><td>Exercised</td><td>(1,302,005)</td><td>$ 23.09</td><td></td><td></td></tr><tr><td>Outstanding as of December 31, 2015</td><td>5,984,664</td><td>$ 33.47</td><td>5.6</td><td>$ 107.6</td></tr><tr><td>Exercisable as of December 31, 2015</td><td>3,280,334</td><td>$ 26.84</td><td>3.9</td><td>$ 80.3</td></tr></table>

The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2015. This is calculated as the difference between our closing stock price on December 31, 2015, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2015, 2014, and 2013 was $36.1 million, $50.5 million, and $44.5 million, respectively. Cash received from options exercised during the years ended December 31, 2015, 2014, and 2013, was $30.1 million, $50.3 million, and $48.5 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $14.5 million, $19.9 million, and $17.8 million, respectively.

At December 31, 2015, total compensation cost related to non-vested stock options not yet recognized was approximately $1.5 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

During the first quarter of 2016, the Compensation Committee awarded 752,085 non-qualified stock options with a weighted-average exercise price of $51.80 to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

## Restricted Shares

The following restricted stock activity occurred during 2015:

<table><tr><td>Restricted Shares</td><td>Number of Shares</td><td>Weighted-Average Grant Date Fair Value</td></tr><tr><td>Outstanding as of January 1, 2015</td><td>155,479</td><td>$ 38.45</td></tr><tr><td>Granted</td><td>143,107</td><td>$ 51.13</td></tr><tr><td>Released</td><td>(68,429)</td><td>$ 36.95</td></tr><tr><td>Forfeited</td><td>(1,139)</td><td>$ 46.26</td></tr><tr><td>Outstanding as of December 31, 2015</td><td>229,018</td><td>$ 46.78</td></tr></table>

On July 31, 2015, the Compensation Committee awarded certain of our officers and other employees an aggregate of 82,943 shares of restricted stock for the key role each played in our acquisition of Integrys. The restricted stock vests in three equal installments on January 29, 2016, January 31, 2017, and July 31, 2018.

The intrinsic value of restricted stock released was $3.7 million, $2.7 million, and $4.0 million for the years ended December 31, 2015, 2014, and 2013, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.3 million, $1.0 million, and $1.3 million, respectively.

As of December 31, 2015, total compensation cost related to restricted stock not yet recognized was approximately $3.1 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

During the first quarter of 2016, the Compensation Committee awarded 113,892 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation.

## Performance Units

In January 2015, 2014, and 2013, the Compensation Committee awarded 195,365; 233,735; and 239,120 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.



Performance units earned as of December 31, 2015, 2014, and 2013 vested and were settled during the first quarter of 2016, 2015, and 2014, and had a total intrinsic value of $13.2 million, $13.2 million, and $14.8 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units for the same years was approximately $4.5 million, $4.8 million, and $5.3 million, respectively.

As of December 31, 2015, total compensation cost related to performance units not yet recognized was approximately $11.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

During the first quarter of 2016, the Compensation Committee awarded 283,505 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

## Restrictions

Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly.

In accordance with their most recent rate orders, Wisconsin Electric, Wisconsin Gas, and WPS may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized levels of 51%, 49.5%, and 51%, respectively. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized levels.

Wisconsin Electric may not pay common dividends to us under Wisconsin Electric's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of Wisconsin Electric's 3.60% Serial Preferred Stock, Wisconsin Electric's ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.

Integrys has long-term debt obligations that contain financial and other covenants, including, but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%.

NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.

We and Integrys have the option to defer interest payments on our Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.

As of December 31, 2015, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of investees accounted for by the equity method totaled approximately $6.2 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2015.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

## Share Repurchase Program

We have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued in 2015, 2014, or 2013, other than for the Integrys acquisition discussed below.



In December 2013, our Board of Directors authorized a share repurchase program for the purchase of up to $300.0 million of our common stock through open market purchases or privately negotiated transactions from January 1, 2014, through the end of 2017. On June 22, 2014, in connection with entering into the Merger Agreement, the Board of Directors terminated this share repurchase program. The following table identifies shares purchased during the year ended December 31:

<table><tr><td rowspan="2">(in millions)</td><td colspan="2">2015</td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td>Shares</td><td>Cost</td><td>Shares</td><td>Cost</td><td>Shares</td><td>Cost</td></tr><tr><td>Under share repurchase programs</td><td>—</td><td>$ —</td><td>0.4</td><td>$ 18.6</td><td>3.0</td><td>$ 126.0</td></tr><tr><td>To fulfill exercised stock options and restricted stock awards</td><td>1.5</td><td>74.7</td><td>2.3</td><td>104.6</td><td>2.4</td><td>97.4</td></tr><tr><td>Total</td><td>1.5</td><td>$ 74.7</td><td>2.7</td><td>$ 123.2</td><td>$ 5.4</td><td>$ 223.4</td></tr></table>

## Integrys Acquisition

On June 29, 2015, we issued approximately 90.2 million common shares to acquire Integrys. All Integrys unvested stock-based compensation awards became fully vested upon the close of the transaction and were paid to award recipients in cash or deferred into a deferred compensation plan. In addition, all vested but unexercised Integrys stock options were paid in cash. See Note 2, Acquisition, for more information on this acquisition.

## Common Stock Dividends

During the year ended December 31, 2015, our Board of Directors declared common stock dividends which are summarized below:

<table><tr><td>Date Declared</td><td>Date Payable</td><td>Per Share</td><td>Period</td></tr><tr><td>January 15, 2015</td><td>March 1, 2015</td><td>$0.4225</td><td>First quarter</td></tr><tr><td>April 16, 2015</td><td>June 1, 2015</td><td>$0.4225</td><td>Second quarter</td></tr><tr><td>June 12, 2015 (1)</td><td>July 6, 2015 (2)</td><td>$0.2067</td><td>45 days through June 28, 2015</td></tr><tr><td>June 12, 2015 (1)</td><td>September 1, 2015 (3)</td><td>$0.2337</td><td>47 days through Aug. 14, 2015</td></tr><tr><td>October 15, 2015</td><td>December 1, 2015</td><td>$0.4575</td><td>Fourth quarter</td></tr></table>

(1) Pro rata dividends were declared on June 12, 2015, in anticipation of closing the acquisition of Integrys.

(2) The dividend payable on July 6, 2015, was based on a quarterly rate of $0.4225 per share.

(3) The dividend payable on September 1, 2015, was based on our new quarterly rate of $0.4575 per share, which represents an 8.3% increase over the prior quarterly rate. Pursuant to the terms of the Merger Agreement, our Board of Directors adopted a new dividend policy.



## NOTE 12—PREFERRED STOCK

The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014:

<table><tr><td>2015 (in millions, except share and per share amounts)</td><td>Shares Authorized</td><td>Shares Outstanding</td><td>Redemption Price Per Share</td><td>Total</td></tr><tr><td>WEC Energy Group</td><td></td><td></td><td></td><td></td></tr><tr><td>$0.01 par value Preferred Stock</td><td>15,000,000</td><td>—</td><td>—</td><td>$—</td></tr><tr><td>Wisconsin Electric</td><td></td><td></td><td></td><td></td></tr><tr><td>$100 par value, Six Per Cent. Preferred Stock</td><td>45,000</td><td>44,498</td><td>—</td><td>4.4</td></tr><tr><td>$100 par value, Serial Preferred Stock</td><td>2,286,500</td><td></td><td></td><td></td></tr><tr><td>3.60% Series</td><td></td><td>260,000</td><td>$ 101</td><td>26.0</td></tr><tr><td>$25 par value, Serial Preferred Stock</td><td>5,000,000</td><td>—</td><td>—</td><td>—</td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td>WPS</td><td></td><td></td><td></td><td></td></tr><tr><td>$100 par value, Preferred Stock</td><td>1,000,000</td><td>—</td><td>—</td><td>—</td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td>PGL</td><td></td><td></td><td></td><td></td></tr><tr><td>$100 par value, Cumulative Preferred Stock</td><td>430,000</td><td>—</td><td>—</td><td>—</td></tr><tr><td></td><td></td><td></td><td></td><td></td></tr><tr><td>NSG</td><td></td><td></td><td></td><td></td></tr><tr><td>$100 par value, Cumulative Preferred Stock</td><td>160,000</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total</td><td></td><td></td><td></td><td>$30.4</td></tr></table>

<table><tr><td>2014 (in millions, except share and per share amounts)</td><td>Shares Authorized</td><td>Shares Outstanding</td><td>Redemption Price Per Share</td><td>Total</td></tr><tr><td>WEC Energy Group</td><td></td><td></td><td></td><td></td></tr><tr><td>$0.01 par value Preferred Stock</td><td>15,000,000</td><td>—</td><td>—</td><td>$—</td></tr><tr><td>Wisconsin Electric</td><td></td><td></td><td></td><td></td></tr><tr><td>$100 par value, Six Per Cent. Preferred Stock</td><td>45,000</td><td>44,498</td><td>—</td><td>4.4</td></tr><tr><td>$100 par value, Serial Preferred Stock</td><td>2,286,500</td><td></td><td></td><td></td></tr><tr><td>3.60% Series</td><td></td><td>260,000</td><td>$ 101</td><td>26.0</td></tr><tr><td>$25 par value, Serial Preferred Stock</td><td>5,000,000</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total</td><td></td><td></td><td></td><td>$30.4</td></tr></table>

On November 13, 2015, WPS redeemed all 511,882 outstanding shares of its five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and (v) 150,000 shares of 6.88% Series. The aggregate redemption price was $52.7 million, plus accumulated and unpaid dividends.

## NOTE 13—SHORT-TERM DEBT AND LINES OF CREDIT

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

<table><tr><td rowspan="2">(in millions, except percentages)</td><td colspan="2">2015</td><td colspan="2">2014</td></tr><tr><td colspan="2">Balance</td><td colspan="2">Balance</td></tr><tr><td>Commercial paper</td><td></td><td></td><td></td><td></td></tr><tr><td>Amount outstanding at December 31</td><td>$</td><td>1,095.0</td><td>$</td><td>617.6</td></tr><tr><td>Average interest rate on amounts outstanding at December 31</td><td></td><td>0.68%</td><td></td><td>0.22%</td></tr><tr><td>Average amounts outstanding during the year  \( {}^{*} \)</td><td></td><td>817.8</td><td></td><td>468.1</td></tr></table>

 \( ^{*} \)  Based on daily outstanding balances during the year.



WEC Energy Group, Wisconsin Electric, WPS, Wisconsin Gas, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require us to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70.0%, 65.0%, 65.0%, 65.0%, and 65.0% respectively. All companies are in compliance with their respective ratio.

As of December 31, 2015, we had $1,387.0 million of available capacity under our bank back-up credit facilities and $1,095.0 million of commercial paper outstanding that was supported by the credit facilities.

The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31:

<table><tr><td>(in millions)</td><td>Maturity</td><td>2015</td></tr><tr><td>WEC Energy Group</td><td>December 2020</td><td>$ 1,050.0</td></tr><tr><td>Wisconsin Electric</td><td>December 2020</td><td>500.0</td></tr><tr><td>WPS *</td><td>December 2016</td><td>250.0</td></tr><tr><td>Wisconsin Gas</td><td>December 2020</td><td>350.0</td></tr><tr><td>PGL</td><td>December 2020</td><td>350.0</td></tr><tr><td>Total short-term credit capacity</td><td></td><td>$ 2,500.0</td></tr><tr><td>Less:</td><td></td><td></td></tr><tr><td>Letters of credit issued inside credit facilities</td><td></td><td>$ 18.0</td></tr><tr><td>Commercial paper outstanding</td><td></td><td>1,095.0</td></tr><tr><td>Available capacity under existing agreements</td><td></td><td>$ 1,387.0</td></tr></table>

* WPS plans to request approval from the PSCW to extend the maturity through December 2020.

In December 2015, WEC Energy Group, Wisconsin Electric, and Wisconsin Gas amended their credit facilities to extend their expirations to December 2020. At the same time, WPS and PGL terminated their prior credit facilities and entered into new credit facilities. The lenders under the WPS facility have agreed that its maturity can be extended to December 2020, subject to the receipt of PSCW approval. Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval.

The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of our credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein.

## NOTE 14—LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

See our statements of capitalization for details on our long-term debt.

Our outstanding long-term debt, including current maturities as of December 31, 2015, included approximately $3.0 billion of Integrys debt assumed on June 29, 2015. The amount assumed included $46.2 million of fair value adjustments recorded in connection with purchase accounting, which will be amortized over the estimated remaining life of the debt and will not be a part of future principal payments. See Note 2, Acquisition, for more information regarding the acquisition.

## WEC Energy Group

In June 2015, we issued $300.0 million of 1.65% Senior Notes due June 15, 2018, $400.0 million of 2.45% Senior Notes due June 15, 2020, and $500.0 million of 3.55% Senior Notes due June 15, 2025. The net proceeds were used to pay a portion of the cash consideration for the acquisition of Integrys and related transaction costs, and for general corporate purposes.

## Wisconsin Electric Power Company

In May 2015, Wisconsin Electric issued $250.0 million of 3.10% Debentures due June 1, 2025. The net proceeds were used to repay short-term debt and for general corporate purposes.



In November 2015, Wisconsin Electric issued $250.0 million of 4.30% Debentures due December 15, 2045. The proceeds were used to repay short-term debt, to repay a portion of Wisconsin Electric's $250.0 million of 6.25% Debentures that matured on December 1, 2015, and for working capital and general corporate purposes.

## Wisconsin Public Service Corporation

In November 2015, WPS redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7.125% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption. Following the redemption, WPS discharged its mortgage indenture and does not intend to issue additional first mortgage bonds. All of WPS's senior notes outstanding are now senior unsecured obligations and rank equally with all of its other unsecured obligations.

In December 2015, WPS's $125.0 million of 6.375% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2015, WPS issued $250.0 million of 1.65% Senior Notes due December 4, 2018. The proceeds were used to repay short-term debt incurred to repay all of WPS's $125.0 million of 6.375% Senior Notes at maturity, and for working capital and general corporate purposes.

## Wisconsin Gas

In September 2015, Wisconsin Gas issued $200.0 million of 3.53% Debentures due September 30, 2025. The net proceeds were used to repay short-term debt and for general corporate purposes.

In December 2015, Wisconsin Gas's $125.0 million of 5.20% Debentures matured, and the outstanding principal balance was repaid.

## The Peoples Gas Light and Coke Company

In August 2015, the interest rate on PGL's $50.0 million of 2.625% Series WW Bonds was reset. The new interest rate is 1.875%. The new mandatory interest reset date is August 1, 2020. The final maturity of these bonds is February 1, 2033.

In November 2016, PGL's 2.21% First and Refunding Mortgage Bonds will mature. As a result, the $50.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheet at December 31, 2015.

## W.E. Power

During 2016, $5.4 million of We Power's outstanding $112.1 million of 4.91% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2015.

During 2016, $4.4 million of We Power's outstanding $130.5 million of 6.00% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2015.

During 2016, $10.2 million of We Power's outstanding $215.0 million of 5.209% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2015.

During 2016, $7.4 million of We Power's outstanding $178.3 million of 4.673% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2015.

## Integrys Holding

In July 2015, Integrys tendered an offer to repurchase all $55.0 million outstanding of its 8.00% Senior Notes due June 1, 2016, and $5.0 million of this amount was tendered and purchased. The $50.0 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2015.



## Bonds and Notes

The following table shows the future maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2015:

<table><tr><td>(in millions)</td><td>Payments</td></tr><tr><td>2016</td><td>$ 127.4</td></tr><tr><td>2017</td><td>154.5</td></tr><tr><td>2018</td><td>836.1</td></tr><tr><td>2019</td><td>357.7</td></tr><tr><td>2020</td><td>684.4</td></tr><tr><td>Thereafter</td><td>7,094.6</td></tr><tr><td>Total</td><td>$ 9,254.7</td></tr></table>

We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.

Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in an outstanding principal amount of $147.0 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2015 and 2014, the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt or included on our capitalization statements because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

In connection with our outstanding 2007 6.25% Series A Junior Subordinated Notes (6.25% Junior Notes), we executed a Replacement Capital Covenant dated May 11, 2007 (RCC), which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 6.25% Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities.

Effective May 2017, the $500.0 million of 6.25% Junior Notes will bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 211.25 basis points and will reset quarterly.

In connection with Integrys's outstanding 2006 6.11% Junior Subordinated Notes (6.11% Junior Notes), Integrys executed a Replacement Capital Covenant dated December 1, 2006, as replaced by a new Replacement Capital Covenant on December 1, 2010 (Integrys RCC) for the benefit of persons that buy, hold, or sell a specified series of its long-term indebtedness (covered debt). Integrys's 4.17% Senior Notes due November 1, 2020, have been designated as the covered debt under the Integrys RCC. The Integrys RCC provides that Integrys may not redeem, defease, or purchase, and that its subsidiaries may not purchase, any 6.11% Junior Notes on or before December 1, 2036, unless, subject to certain limitations described in the Integrys RCC. Integrys has received a specified amount of proceeds from the sale of qualifying securities.

In February 2016, Integrys repurchased and retired $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million, plus accrued and unpaid interest, through a modified “dutch auction” tender offer. Effective December 1, 2016, the remaining $114.9 million aggregate principal amount of the 6.11% Junior Notes will bear interest at the three-month LIBOR rate plus 212 basis points and will reset quarterly.

In connection with the transaction, Integrys issued approximately $66.4 million of additional common stock to WEC Energy Group in satisfaction of its obligations under the Integrys RCC.

Effective August 2023, Integrys's $400.0 million of 2013 6.00% Junior Subordinated Notes due 2073 will bear interest at the three-month LIBOR Rate plus 322 basis points and will reset quarterly.



Certain long-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

## Obligations Under Capital Leases

In 1997, Wisconsin Electric entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, Wisconsin Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as cost of sales on our income statements. We paid a total of $36.2 million and $34.9 million in lease payments during 2015 and 2014, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $59.9 million as of December 31, 2015, and will decrease to zero over the remaining life of the contract.

The following is a summary of our capitalized leased facilities as of December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Long-term power purchase commitment</td><td>$ 140.3</td><td>$ 140.3</td></tr><tr><td>Accumulated amortization</td><td>(103.9)</td><td>(98.3)</td></tr><tr><td>Total leased facilities</td><td>$ 36.4</td><td>$ 42.0</td></tr></table>

Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2015 are as follows:

<table><tr><td>(in millions)</td><td colspan="2">Payments</td></tr><tr><td>2016</td><td>$</td><td>45.1</td></tr><tr><td>2017</td><td></td><td>13.9</td></tr><tr><td>2018</td><td></td><td>14.7</td></tr><tr><td>2019</td><td></td><td>15.5</td></tr><tr><td>2020</td><td></td><td>16.4</td></tr><tr><td>Thereafter</td><td></td><td>24.9</td></tr><tr><td>Total minimum lease payments</td><td></td><td>130.5</td></tr><tr><td>Less: Estimated executory costs</td><td></td><td>(47.4)</td></tr><tr><td>Net minimum lease payments</td><td></td><td>83.1</td></tr><tr><td>Less: Interest</td><td></td><td>(23.2)</td></tr><tr><td>Present value of net minimum lease payments</td><td></td><td>59.9</td></tr><tr><td>Less: Due currently</td><td></td><td>(30.3)</td></tr><tr><td>Long-term obligations under capital lease</td><td></td><td>$ 29.6</td></tr></table>



## NOTE 15—INCOME TAXES

## Income Tax Expense

The following table is a summary of income tax expense for each of the years ended December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Current tax expense</td><td>$ 15.1</td><td>$ 33.6</td><td>$ 25.2</td></tr><tr><td>Deferred income taxes, net</td><td>420.4</td><td>329.2</td><td>313.8</td></tr><tr><td>Investment tax credit, net</td><td>(1.7)</td><td>(1.1)</td><td>(1.1)</td></tr><tr><td>Total income tax expense</td><td>$ 433.8</td><td>$ 361.7</td><td>$ 337.9</td></tr></table>

## Statutory Rate Reconciliation

The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes as a result of the following:

<table><tr><td rowspan="2">(in millions)</td><td colspan="2">2015</td><td colspan="2">2014</td><td colspan="2">2013</td></tr><tr><td colspan="3">Effective</td><td colspan="2">Effective</td><td>Effective</td></tr><tr><td>Expected tax at statutory federal tax rates</td><td>$ 375.5</td><td>35.0 %</td><td>$ 332.5</td><td>35.0 %</td><td>$ 320.3</td><td>35.0 %</td></tr><tr><td>State income taxes net of federal tax benefit</td><td>73.1</td><td>6.8 %</td><td>50.5</td><td>5.3 %</td><td>49.0</td><td>5.3 %</td></tr><tr><td>Production tax credits</td><td>(17.4)</td><td>(1.6)%</td><td>(17.4)</td><td>(1.8)%</td><td>(16.7)</td><td>(1.8)%</td></tr><tr><td>AFUDC - Equity</td><td>(7.1)</td><td>(0.7)%</td><td>(1.9)</td><td>(0.2)%</td><td>(6.4)</td><td>(0.7)%</td></tr><tr><td>Investment tax credit restored</td><td>(1.7)</td><td>(0.2)%</td><td>(1.1)</td><td>(0.1)%</td><td>(1.1)</td><td>(0.1)%</td></tr><tr><td>Treasury grant</td><td>(1.7)</td><td>(0.2)%</td><td>(3.8)</td><td>(0.4)%</td><td>(7.4)</td><td>(0.8)%</td></tr><tr><td>Other, net</td><td>13.1</td><td>1.3 %</td><td>2.9</td><td>0.2 %</td><td>0.2</td><td>— %</td></tr><tr><td>Total income tax expense</td><td>$ 433.8</td><td>40.4 %</td><td>$ 361.7</td><td>38.0 %</td><td>$ 337.9</td><td>36.9 %</td></tr></table>

## Deferred Income Tax Assets and Liabilities

The components of deferred income taxes as of December 31 are as follows:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Deferred tax assets</td><td></td><td></td></tr><tr><td>Future tax benefits</td><td>$ 382.8</td><td>$ 221.7</td></tr><tr><td>Employee benefits and compensation</td><td>229.9</td><td>111.9</td></tr><tr><td>Deferred revenues</td><td>219.9</td><td>221.3</td></tr><tr><td>Property-related</td><td>59.5</td><td>28.8</td></tr><tr><td>Other</td><td>177.1</td><td>118.4</td></tr><tr><td>Total deferred tax assets</td><td>1,069.2</td><td>702.1</td></tr><tr><td>Valuation allowance</td><td>(17.1)</td><td>—</td></tr><tr><td>Net deferred tax assets</td><td>$ 1,052.1</td><td>$ 702.1</td></tr><tr><td>Deferred tax liabilities</td><td></td><td></td></tr><tr><td>Property-related</td><td>4,451.5</td><td>2,750.4</td></tr><tr><td>Employee benefits and compensation</td><td>428.9</td><td>242.5</td></tr><tr><td>Investment in transmission affiliate</td><td>420.4</td><td>188.6</td></tr><tr><td>Deferred transmission costs</td><td>76.7</td><td>58.5</td></tr><tr><td>Other</td><td>296.9</td><td>126.1</td></tr><tr><td>Total deferred tax liabilities</td><td>5,674.4</td><td>3,366.1</td></tr><tr><td>Deferred tax liability, net</td><td>$ 4,622.3</td><td>$ 2,664.0</td></tr></table>

Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities.



The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2015 and 2014 are summarized in the table below:

<table><tr><td>2015 (in millions)</td><td>Gross Value</td><td>Deferred Tax Effect</td><td>Valuation Allowance</td><td>Earliest Year of Expiration</td></tr><tr><td>Future tax benefits as of December 31, 2015</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal net operating loss</td><td>$ 412.3</td><td>$ 144.3</td><td>$ —</td><td>2031</td></tr><tr><td>Federal foreign tax credit</td><td>—</td><td>15.2</td><td>(15.2)</td><td>2017</td></tr><tr><td>Other federal tax credit</td><td>—</td><td>207.8</td><td>—</td><td>2025</td></tr><tr><td>Charitable contribution</td><td>4.7</td><td>1.9</td><td>(1.9)</td><td>2016</td></tr><tr><td>State net operating loss</td><td>185.9</td><td>9.3</td><td>—</td><td>2024</td></tr><tr><td>State tax credit</td><td>—</td><td>4.3</td><td>—</td><td>2016</td></tr><tr><td>Balance as of December 31, 2015</td><td>$ 602.9</td><td>$ 382.8</td><td>$ (17.1)</td><td></td></tr></table>

<table><tr><td>2014 (in millions)</td><td>Gross Value</td><td>Deferred Tax Effect</td><td>Valuation Allowance</td><td>Earliest Year of Expiration</td></tr><tr><td>Future tax benefits as of December 31, 2014</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal net operating loss</td><td>$ 416.2</td><td>$ 145.7</td><td>$ —</td><td>2029</td></tr><tr><td>Federal tax credit</td><td>—</td><td>76.0</td><td>—</td><td>2029</td></tr><tr><td>Balance as of December 31, 2014</td><td>$ 416.2</td><td>$ 221.7</td><td>$ —</td><td></td></tr></table>

Valuation allowances of approximately $17.1 million have been established for certain tax benefit carryforwards obtained in the Integrys acquisition based on our projected ability to realize such benefits by offsetting future tax liabilities. This is primarily the result of the extension of bonus depreciation. Realization is dependent on generating sufficient tax liabilities prior to expiration of the tax benefit carryforwards.

## Unrecognized Tax Benefits

We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Balance as of January 1</td><td>$ 7.2</td><td>$ 8.4</td></tr><tr><td>Acquired legacy Integrys unrecognized tax benefits</td><td>3.6</td><td>—</td></tr><tr><td>Additions for tax positions of prior years</td><td>0.3</td><td>—</td></tr><tr><td>Additions based on tax positions related to the current year</td><td>0.2</td><td>—</td></tr><tr><td>Reductions for tax positions of prior years</td><td>(1.1)</td><td>(1.2)</td></tr><tr><td>Settlements during the period</td><td>(0.7)</td><td>—</td></tr><tr><td>Balance as of December 31</td><td>$ 9.5</td><td>$ 7.2</td></tr></table>

The amount of unrecognized tax benefits as of December 31, 2015 and 2014, excludes deferred tax assets related to uncertainty in income taxes of $6.2 million and $7.2 million, respectively. As of December 31, 2015, our effective tax rate could be affected by recognition of approximately $2.2 million of unrecognized tax benefits. As of December 31, 2014, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the year ended December 31, 2015, we recognized no accrued interest in our income statements. For the years ended December 31, 2014 and 2013, we recognized approximately $0.3 million and $0.2 million, respectively, of accrued interest in our income statements. For the years ended December 31, 2015, 2014, and 2013, we recognized no penalties in our income statements. For the year ended December 31, 2015, we had $0.7 million of interest accrued and $0.1 million of penalties accrued on our balance sheets. For the year ended December 31, 2014, we had approximately $0.7 million of interest accrued and no penalties accrued on our balance sheets.

We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months.

We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and



local jurisdictions with varying statutes of limitations. As of December 31, 2015, we were subject to examination by state or local tax authorities for the 2008 through 2015 tax years in our major state operating jurisdictions as follows:

<table><tr><td>Jurisdiction</td><td>Years</td></tr><tr><td>Federal</td><td>2012-2015</td></tr><tr><td>Illinois</td><td>2008-2015</td></tr><tr><td>Michigan</td><td>2008-2015</td></tr><tr><td>Minnesota</td><td>2011-2015</td></tr><tr><td>Wisconsin</td><td>2011-2015</td></tr></table>

## NOTE 16—GUARANTEES

The following table shows our outstanding guarantees:

<table><tr><td rowspan="2">(in millions)</td><td rowspan="2">Total Amounts Committed at December 31, 2015</td><td colspan="3">Expiration</td></tr><tr><td>Less Than 1 Year</td><td>1 to 3 Years</td><td>Over 3 Years</td></tr><tr><td>Guarantees</td><td></td><td></td><td></td><td></td></tr><tr><td>Guarantees supporting commodity transactions of subsidiaries (1)</td><td>$ 174.5</td><td>$ 95.0</td><td>$ —</td><td>$ 79.5</td></tr><tr><td>Standby letters of credit (2)</td><td>28.4</td><td>18.5</td><td>9.7</td><td>0.2</td></tr><tr><td>Surety bonds (3)</td><td>38.6</td><td>38.6</td><td>—</td><td>—</td></tr><tr><td>Other guarantees (4)</td><td>70.5</td><td>20.6</td><td>0.1</td><td>49.8</td></tr><tr><td>Total guarantees</td><td>$ 312.0</td><td>$ 172.7</td><td>$ 9.8</td><td>$ 129.5</td></tr></table>

(1) Consists of (a) $5.0 million and $11.0 million to support the business operations of WBS and PDL, respectively; and (b) $117.6 million, $40.3 million, and $0.6 million related to natural gas supply at MERC, MGU, and ITF, respectively. These amounts are not reflected on our balance sheets.

(2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.

(3) Primarily for the construction and operation of CNG fueling stations by ITF, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.

(4) Consists of (a) $19.1 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party; (b) $20.0 million for an interconnection agreement between WPS and ATC; (c) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys; (d) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (e) $10.2 million related to other indemnifications. The amounts discussed in items (a), (b) and (d) are not reflected on our balance sheets. An insignificant liability was recorded for item (c) related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the law. In addition, a liability of $9.6 million related to workers compensation coverage was recorded for item (e).

## NOTE 17—EMPLOYEE BENEFITS

## Pension and Other Postretirement Employee Benefits

We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded nonqualified retirement plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.

Generally, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Approximately half of the projected benefit obligation for legacy Wisconsin Energy Corporation employees relates to benefits based upon years of service and final average salary. New Wisconsin Energy Corporation management employees hired after December 31, 2014 receive a 6% annual company contribution to their 401(k) plan instead of being enrolled in the defined benefit plans.



For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year.

We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.

The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">Pension Costs</td><td colspan="3">OPEB Costs</td></tr><tr><td>2015</td><td>2014</td><td>2015</td><td>2014</td><td></td><td></td></tr><tr><td>Change in benefit obligation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Obligation at January 1</td><td>$ 1,505.5</td><td>$ 1,410.2</td><td>$ 397.7</td><td>$ 362.7</td><td></td><td></td></tr><tr><td>Obligation assumed from acquisition</td><td>1,594.0</td><td>—</td><td>493.0</td><td>—</td><td></td><td></td></tr><tr><td>Service cost</td><td>30.4</td><td>10.1</td><td>20.7</td><td>8.5</td><td></td><td></td></tr><tr><td>Interest cost</td><td>94.3</td><td>68.1</td><td>26.7</td><td>17.8</td><td></td><td></td></tr><tr><td>Participant contributions</td><td>—</td><td>—</td><td>12.7</td><td>9.1</td><td></td><td></td></tr><tr><td>Plan amendments</td><td>—</td><td>—</td><td>—</td><td>(4.6)</td><td></td><td></td></tr><tr><td>Actuarial loss (gain)</td><td>14.6</td><td>120.4</td><td>(74.0)</td><td>29.4</td><td></td><td></td></tr><tr><td>Benefit payments</td><td>(156.0)</td><td>(103.3)</td><td>(36.2)</td><td>(26.4)</td><td></td><td></td></tr><tr><td>Federal subsidy on benefits paid</td><td>N/A</td><td>N/A</td><td>1.6</td><td>1.2</td><td></td><td></td></tr><tr><td>Plan curtailment</td><td>0.2</td><td>—</td><td>(0.2)</td><td>—</td><td></td><td></td></tr><tr><td>Obligation at December 31</td><td>$ 3,083.0</td><td>$ 1,505.5</td><td>$ 842.0</td><td>$ 397.7</td><td></td><td></td></tr><tr><td>Change in fair value of plan assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair Value at January 1</td><td>$ 1,444.6</td><td>$ 1,451.0</td><td>$ 333.5</td><td>$ 327.6</td><td></td><td></td></tr><tr><td>Assets received from acquisition</td><td>1,420.9</td><td>—</td><td>442.1</td><td>—</td><td></td><td></td></tr><tr><td>Actual return on plan assets</td><td>(62.1)</td><td>88.5</td><td>(15.6)</td><td>17.7</td><td></td><td></td></tr><tr><td>Employer contributions</td><td>107.7</td><td>8.4</td><td>13.3</td><td>5.5</td><td></td><td></td></tr><tr><td>Participant contributions</td><td>—</td><td>—</td><td>12.7</td><td>9.1</td><td></td><td></td></tr><tr><td>Benefit payments</td><td>(156.0)</td><td>(103.3)</td><td>(36.2)</td><td>(26.4)</td><td></td><td></td></tr><tr><td>Fair value at December 31</td><td>$ 2,755.1</td><td>$ 1,444.6</td><td>$ 749.8</td><td>$ 333.5</td><td></td><td></td></tr></table>

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">Pension Costs</td><td colspan="3">OPEB Costs</td></tr><tr><td>2015</td><td>2014</td><td>2015</td><td>2014</td><td></td><td></td></tr><tr><td>Other long-term assets</td><td>$ 74.1</td><td>$ 39.2</td><td>$ 50.1</td><td>$ 39.5</td><td></td><td></td></tr><tr><td>Pension and other postretirement benefit obligations  \( * \)</td><td>402.0</td><td>100.1</td><td>142.3</td><td>103.7</td><td></td><td></td></tr><tr><td>Total net liabilities</td><td>$ 327.9</td><td>$ 60.9</td><td>$ 92.2</td><td>$ 64.2</td><td></td><td></td></tr></table>

* Includes $0.8 million of pension and $0.4 million of OPEB obligations classified as liabilities held for sale as of December 31, 2015. These amounts are included in other current liabilities on our balance sheets.

The accumulated benefit obligation for all defined pension plans was $2,936.4 million and $1,504.6 million as of December 31, 2015, and 2014, respectively.

The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Projected benefit obligation</td><td>$ 1,706.6</td><td>$ 100.1</td></tr><tr><td>Accumulated benefit obligation</td><td>1,560.5</td><td>99.8</td></tr></table>



The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31:

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">Pension Costs</td><td colspan="3">OPEB Costs</td></tr><tr><td>2015</td><td>2014</td><td>2015</td><td>2014</td><td></td><td></td></tr><tr><td>Accumulated other comprehensive loss (pre-tax) (1)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net actuarial loss (gain)</td><td>$ 11.4</td><td>$ —</td><td>$ (0.6)</td><td>$ —</td><td></td><td></td></tr><tr><td>Total</td><td>$ 11.4</td><td>$ —</td><td>$ (0.6)</td><td>$ —</td><td></td><td></td></tr><tr><td>Net regulatory assets (2)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net actuarial loss</td><td>$ 798.1</td><td>$ 622.7</td><td>$ 23.7</td><td>$ 44.1</td><td></td><td></td></tr><tr><td>Prior service costs (credits)</td><td>4.7</td><td>6.8</td><td>(3.3)</td><td>(4.6)</td><td></td><td></td></tr><tr><td>Total</td><td>$ 802.8</td><td>$ 629.5</td><td>$ 20.4</td><td>$ 39.5</td><td></td><td></td></tr></table>

(1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.

(2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities.

The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2016:

<table><tr><td>(in millions)</td><td>Pension Costs</td><td>OPEB Costs</td></tr><tr><td>Net actuarial loss</td><td>$ 41.6</td><td>$ 1.9</td></tr><tr><td>Prior service costs</td><td>1.7</td><td>(1.2)</td></tr><tr><td>Total 2016 - estimated amortization</td><td>$ 43.3</td><td>$ 0.7</td></tr></table>

The components of net periodic benefit cost for the years ended December 31 are as follows:

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">Pension Costs</td><td colspan="3">OPEB Costs</td></tr><tr><td>2015</td><td>2014</td><td>2013</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Service cost</td><td>$ 30.4</td><td>$ 10.1</td><td>$ 14.6</td><td>$ 20.7</td><td>$ 8.5</td><td>$ 10.0</td></tr><tr><td>Interest cost</td><td>94.3</td><td>68.1</td><td>60.4</td><td>26.7</td><td>17.8</td><td>15.6</td></tr><tr><td>Expected return on plan assets</td><td>(155.6)</td><td>(98.6)</td><td>(95.8)</td><td>(39.6)</td><td>(23.7)</td><td>(21.3)</td></tr><tr><td>Plan curtailment</td><td>(0.3)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of prior service cost (credit)</td><td>2.2</td><td>2.1</td><td>2.3</td><td>(6.4)</td><td>(1.8)</td><td>(2.0)</td></tr><tr><td>Amortization of net actuarial loss</td><td>68.5</td><td>36.7</td><td>54.5</td><td>3.9</td><td>1.2</td><td>3.7</td></tr><tr><td>Settlement charge</td><td>—</td><td>—</td><td>2.5</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Net periodic benefit cost</td><td>$ 39.5</td><td>$ 18.4</td><td>$ 38.5</td><td>$ 5.3</td><td>$ 2.0</td><td>$ 6.0</td></tr></table>

The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:

<table><tr><td rowspan="2"></td><td colspan="3">Pension</td><td colspan="2">OPEB</td></tr><tr><td>2015</td><td>2014</td><td>2015</td><td>2014</td><td></td></tr><tr><td>Discount rate</td><td>4.46%</td><td>4.15%</td><td>4.38%</td><td>4.20%</td><td></td></tr><tr><td>Rate of compensation increase</td><td>4.00%</td><td>4.00%</td><td>N/A</td><td>N/A</td><td></td></tr><tr><td>Assumed medical cost trend rate</td><td>N/A</td><td>N/A</td><td>7.50%</td><td>7.50%</td><td></td></tr><tr><td>Ultimate trend rate</td><td>N/A</td><td>N/A</td><td>5.00%</td><td>5.00%</td><td></td></tr><tr><td>Year ultimate trend rate is reached</td><td>N/A</td><td>N/A</td><td>2021</td><td>2021</td><td></td></tr></table>

The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:

<table><tr><td rowspan="2"></td><td colspan="3">Pension Costs</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Discount rate</td><td>4.11%</td><td>5.00%</td><td>4.10%</td></tr><tr><td>Expected return on plan assets</td><td>7.37%</td><td>7.25%</td><td>7.25%</td></tr><tr><td>Rate of compensation increase</td><td>4.0%</td><td>4.0%</td><td>4.0%</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">OPEB Costs</td></tr><tr><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Discount rate</td><td>4.09%</td><td>4.95%</td><td>4.15%</td></tr><tr><td>Expected return on plan assets</td><td>7.54%</td><td>7.50%</td><td>7.50%</td></tr><tr><td>Assumed medical cost trend rate (Pre 65/Post 65)</td><td>7.50%</td><td>7.50%</td><td>7.50%</td></tr><tr><td>Ultimate trend rate</td><td>5.00%</td><td>5.00%</td><td>5.00%</td></tr><tr><td>Year ultimate trend rate is reached</td><td>2021</td><td>2021</td><td>2021</td></tr></table>

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2016, the expected return on assets assumption is 7.13% for the pension plans and 7.25% for the OPEB plans.

Assumed health care cost trend rates have a significant effect on the amounts reported by us for health care plans. For the year ended December 31, 2015, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:

<table><tr><td>(in millions)</td><td>1% Increase</td><td>1% Decrease</td></tr><tr><td>Effect on total of service and interest cost components of net periodic postretirement health care benefit cost</td><td>$     6.5</td><td>$      (5.3)</td></tr><tr><td>Effect on health care component of the accumulated postretirement benefit obligations</td><td>79.4</td><td>(65.9)</td></tr></table>

## Plan Assets

Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

Previously, the Wisconsin Energy Corporation pension trust target allocation was 45% equity investments and 55% fixed income investments. A transition to a target asset allocation of 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments began in late 2014. The Integrys pension trust target allocation moved from 70% equity investments and 30% fixed income investments in 2014 to 60% equity investments and 40% fixed income investments for 2015. The current OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments for Wisconsin Energy Corporation, and 70% equity investments and 30% fixed income investments for Integrys. Equity securities include investments in large-cap, mid-cap, and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and U.S. Treasuries.

Pension and OPEB plan investments are recorded at fair value. See Note 1(s), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.



The following tables provide the fair values of our investments by asset class:

December 31, 2015

<table><tr><td rowspan="2">(in millions)</td><td colspan="5">Pension Plan Assets</td><td colspan="5">OPEB Assets</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td></tr><tr><td>Asset Class</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 17.0</td><td>$ 45.8</td><td>$ —</td><td>$ 62.8</td><td>$ 9.8</td><td>$ 1.3</td><td>$ —</td><td>$ 11.1</td><td></td><td></td></tr><tr><td>Equity securities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Equity</td><td>524.1</td><td>291.0</td><td>—</td><td>815.1</td><td>146.4</td><td>136.3</td><td>—</td><td>282.7</td><td></td><td></td></tr><tr><td>International Equity</td><td>192.2</td><td>351.2</td><td>—</td><td>543.4</td><td>57.2</td><td>133.3</td><td>—</td><td>190.5</td><td></td><td></td></tr><tr><td>Fixed income securities: *</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Bonds</td><td>53.2</td><td>1,019.2</td><td>—</td><td>1,072.4</td><td>122.3</td><td>116.1</td><td>—</td><td>238.4</td><td></td><td></td></tr><tr><td>International Bonds</td><td>67.4</td><td>140.3</td><td>—</td><td>207.7</td><td>16.0</td><td>6.7</td><td>—</td><td>22.7</td><td></td><td></td></tr><tr><td>Private Equity and Real Estate</td><td>—</td><td>—</td><td>53.7</td><td>53.7</td><td>—</td><td>—</td><td>4.4</td><td>4.4</td><td></td><td></td></tr><tr><td>Total</td><td>$ 853.9</td><td>$ 1,847.5</td><td>$ 53.7</td><td>$ 2,755.1</td><td>$ 351.7</td><td>$ 393.7</td><td>$ 4.4</td><td>$ 749.8</td><td></td><td></td></tr></table>

* This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

December 31, 2014

<table><tr><td rowspan="2">(in millions)</td><td colspan="5">Pension Plan Assets</td><td colspan="5">OPEB Assets</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td></tr><tr><td>Asset Class</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 6.4</td><td>$ —</td><td>$ —</td><td>$ 6.4</td><td>$ 1.4</td><td>$ —</td><td>$ —</td><td>$ 1.4</td><td></td><td></td></tr><tr><td>Equity securities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Equity</td><td>503.8</td><td>—</td><td>—</td><td>503.8</td><td>146.0</td><td>—</td><td>—</td><td>146.0</td><td></td><td></td></tr><tr><td>International Equity</td><td>128.6</td><td>29.8</td><td>—</td><td>158.4</td><td>42.2</td><td>2.5</td><td>—</td><td>44.7</td><td></td><td></td></tr><tr><td>Fixed income securities: *</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Bonds</td><td>42.5</td><td>599.3</td><td>—</td><td>641.8</td><td>3.5</td><td>112.4</td><td>—</td><td>115.9</td><td></td><td></td></tr><tr><td>International Bonds</td><td>79.3</td><td>43.3</td><td>—</td><td>122.6</td><td>17.5</td><td>7.0</td><td>—</td><td>24.5</td><td></td><td></td></tr><tr><td>Private Equity and Real Estate</td><td>—</td><td>—</td><td>11.6</td><td>11.6</td><td>—</td><td>—</td><td>1.0</td><td>1.0</td><td></td><td></td></tr><tr><td>Total</td><td>$ 760.6</td><td>$ 672.4</td><td>$ 11.6</td><td>$ 1,444.6</td><td>$ 210.6</td><td>$ 121.9</td><td>$ 1.0</td><td>$ 333.5</td><td></td><td></td></tr></table>

* This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:

<table><tr><td rowspan="2">(in millions)</td><td colspan="2">Private Equity and Real Estate</td></tr><tr><td>Pension</td><td>OPEB</td></tr><tr><td>Beginning balance at January 1, 2015</td><td>$ 11.6</td><td>$ 1.0</td></tr><tr><td>Realized and unrealized gains (losses)</td><td>1.8</td><td>0.1</td></tr><tr><td>Purchases</td><td>51.1</td><td>4.2</td></tr><tr><td>Liquidations</td><td>(10.8)</td><td>(0.9)</td></tr><tr><td>Ending balance at December 31, 2015</td><td>$ 53.7</td><td>$ 4.4</td></tr></table>

<table><tr><td rowspan="2">(in millions)</td><td colspan="2">Private Equity and Real Estate</td></tr><tr><td>Pension</td><td>OPEB</td></tr><tr><td>Beginning balance at January 1, 2014</td><td>$ —</td><td>$ —</td></tr><tr><td>Purchases</td><td>11.6</td><td>1.0</td></tr><tr><td>Ending balance at December 31, 2014</td><td>$ 11.6</td><td>$ 1.0</td></tr></table>

## Cash Flows

We expect to contribute $23.8 million to the pension plans and $6.9 million to OPEB plans in 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.



The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB:

<table><tr><td>(in millions)</td><td>Pension Costs</td><td>OPEB Costs</td></tr><tr><td>2016</td><td>$ 305.7</td><td>$ 48.4</td></tr><tr><td>2017</td><td>215.4</td><td>53.4</td></tr><tr><td>2018</td><td>211.9</td><td>52.2</td></tr><tr><td>2019</td><td>223.2</td><td>54.7</td></tr><tr><td>2020</td><td>224.9</td><td>57.1</td></tr><tr><td>2021-2025</td><td>1,105.2</td><td>307.0</td></tr></table>

## Savings Plans

We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution or cash contribution up to certain limits. The ESOPs held 5.5 million shares of our common stock (market value of $280.6 million) at December 31, 2015. Certain employees participate in a defined contribution pension plan, in which amounts are contributed to an employee's account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $48.0 million in 2015 and $14.2 million in both 2014 and 2013.

## NOTE 18—COMMITMENTS AND CONTINGENCIES

We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental remediation, and enforcement and litigation matters.

## Unconditional Purchase Obligations

## Energy Related Purchased Power Agreements

We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates.

The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2015, including those of our subsidiaries.

<table><tr><td></td><td>Date Contracts Extend Through</td><td>Total Amounts Committed</td><td>2016</td><td>2017</td><td>2018</td><td>2019</td><td>2020</td><td>Later Years</td></tr><tr><td>Electric utility:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>2027</td><td>$ 811.9</td><td>$ 110.1</td><td>$ 78.4</td><td>$ 74.9</td><td>$ 62.1</td><td>$ 62.4</td><td>$ 424.0</td></tr><tr><td>Coal supply and transportation</td><td>2019</td><td>608.7</td><td>310.2</td><td>177.4</td><td>110.0</td><td>11.1</td><td>—</td><td>—</td></tr><tr><td>Nuclear</td><td>2033</td><td>10,012.5</td><td>412.8</td><td>415.3</td><td>420.0</td><td>445.4</td><td>475.1</td><td>7,843.9</td></tr><tr><td>Natural gas utility supply and transportation</td><td>2028</td><td>1,244.6</td><td>331.6</td><td>263.6</td><td>200.1</td><td>159.3</td><td>115.2</td><td>174.8</td></tr><tr><td>Total</td><td></td><td>$ 12,677.7</td><td>$ 1,164.7</td><td>$ 934.7</td><td>$ 805.0</td><td>$ 677.9</td><td>$ 652.7</td><td>$ 8,442.7</td></tr></table>

## Operating Leases

We lease various property, plant, and equipment with various terms in the operating leases. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value, or (b) exercise a renewal option, as set forth in the lease agreement.



Rental expense attributable to operating leases was $12.7 million, $4.8 million, and $4.0 million in 2015, 2014, and 2013, respectively.

Future minimum payments under noncancelable operating leases are payable as follows:

<table><tr><td>Year Ending December 31</td><td>Payments (in millions)</td></tr><tr><td>2016</td><td>$ 9.8</td></tr><tr><td>2017</td><td>9.8</td></tr><tr><td>2018</td><td>9.0</td></tr><tr><td>2019</td><td>6.2</td></tr><tr><td>2020</td><td>5.7</td></tr><tr><td>Later years</td><td>66.6</td></tr><tr><td>Total</td><td>$ 107.1</td></tr></table>

## Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as  \( SO_{2} \) , NO \( _{x} \) , fine particulate, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:

• the development of additional sources of renewable electric energy supply;

- the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;

- the addition of emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules;

- the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;

- the retirement of old coal plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation;

• the beneficial use of ash and other products from coal-fired and biomass generating units; and

• the remediation of former manufactured gas plant sites.

## Air Quality

Sulfur Dioxide National Air Ambient Quality Standards – The EPA issued a revised 1-Hour  \( SO_{2} \)  NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard.

The final rule affords state agencies latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make attainment designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area would be classified as nonattainment. A plan would need to be developed requiring emission reductions to bring the area back into attainment by 2023. Alternatively, if a state opted out of modeling and instead chose to install air quality monitors, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area.



In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of  \( SO_{2} \) . The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016.  \( SO_{2} \)  emissions from PIPP are above the emission threshold, which means that the Marquette area requires action earlier than would otherwise be required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. Based upon this modeling, the state of Michigan recommended to the EPA that the Marquette area be designated as attainment. We expect that the EPA will act on this recommendation in 2016.

We believe our fleet overall is well positioned to meet the new regulation.

8-Hour Ozone National Air Ambient Quality Standards – The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule.

Mercury and Other Hazardous Air Pollutants – In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect while the EPA completes its cost evaluation.

Our compliance plans currently include capital projects for PIPP and for WPS's jointly owned plants to achieve the required reductions for MATS. Construction on the addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP is essentially complete and going through final startup and tuning. In addition, construction of the ReACT \( ^{™} \)  multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date of July 2016. Controls for acid gases and mercury are already in operation at the Pulliam units.

In April 2013, Wisconsin Electric received a one year MATS compliance extension from the MDEQ for PIPP through April 2016. Although WPS also received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is shut down to complete the construction of the ReACT \( ^{™} \)  system.

Climate Change – In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and requires states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources.

Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's  \( CO_{2} \)  equivalent reduction goal by about 10%. The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted



comments on the draft Federal Plan and Model Trading Rule. Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency. A stakeholder process began in the middle of January 2016. Michigan plans to submit an interim plan by September 6, 2016, with a request for a two year extension for submittal of a final plan.

We are in the process of reviewing the final rule for existing generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants and biomass facility, and could have a material adverse impact on our operating costs. In October 2015, following publication of the final rule, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but on February 9, 2016, the Supreme Court stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of state plans until the litigation is complete. In addition, on February 15, 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.

We are required to report our  \( CO_{2} \)  equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, Wisconsin Energy Corporation reported aggregated  \( CO_{2} \)  equivalent emissions of approximately 23.3 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that WEC Energy Group will report  \( CO_{2} \)  equivalent emissions of approximately 31.0 million metric tonnes to the EPA for 2015. The level of  \( CO_{2} \)  and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report  \( CO_{2} \)  equivalent amounts related to the natural gas that our natural gas utilities distribute and sell. For 2014, Wisconsin Energy Corporation reported aggregated  \( CO_{2} \)  equivalent emissions of approximately 10.8 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that WEC Energy Group will report  \( CO_{2} \)  equivalent emissions of approximately 27.1 million metric tonnes to the EPA for 2015.

The increase in  \( CO_{2} \)  equivalent amounts reported between 2014 and 2015 for the electric generating facilities, as well as the amounts related to the distribution and sale of natural gas, are primarily related to the addition of the Integrys regulated companies, which were acquired on June 29, 2015.

## Water Quality

Clean Water Act Cooling Water Intake Structure Rule – In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for VAPP Units 1 and 2, Pulliam Units 7 and 8, and Weston Unit 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in October 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in September 2016. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our proposed intake modification at VAPP. BTA determinations for EM will be made in future



permit reissuances for Pulliam Units 7 and 8, Weston Units 2 through 4, Port Washington Generating Station, Pleasant Prairie Power Plant, PIPP, and Oak Creek Power Plant Units 5 through 8.

During 2016–2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and will commence in January 2016 at PIPP.

Steam Electric Effluent Guidelines – The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years. We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will likely require additional biological treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Oak Creek Units 5 and 6, the Pleasant Prairie units, PIPP Units 5 through 9, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $70 million to $100 million for these biological treatment and bottom ash transport systems.

Valley Power Plant Wisconsin Pollution Discharge Elimination System Permit – The WDNR issued a WPDES permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure is complete. An identical modification is planned for VAPP Unit 1 in 2016. We are also currently involved in planning to meet the remaining long-term requirements.

## Land Quality

Coal Combustion Residuals Rule – In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. We do not expect the compliance costs will be significant because we currently have a program of beneficial utilization for most of our coal combustion products. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources.

Coal Combustion Product Landfill Sites – We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015, 2014, and 2013, landfill remediation expenses were not material. See Note 9, Asset Retirement Obligations, for more information about obligations related to these sites.



## Renewables, Efficiency, and Conservation

## Wisconsin Act 141

In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, Wisconsin Electric and WPS are required to increase their renewable energy percentage to 8.27% and 9.74%, respectively. To comply with these requirements, Wisconsin Electric constructed the Blue Sky Green Field wind park, the Glacier Hills wind park, and the Rothschild biomass facility. WPS constructed the Crane Creek wind park. Wisconsin Electric and WPS also rely on renewable energy purchases to meet their respective renewable portfolio standard commitments.

Wisconsin Electric and WPS are in compliance with Act 141's 2015 standard and have entered into agreements for renewable energy credits, that should allow Wisconsin Electric and WPS to remain in compliance through 2022 and 2023, respectively. If market conditions are favorable, Wisconsin Electric and WPS may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of annual operating revenues of each utility.

## Michigan Act 295

In 2008, Michigan revised the requirements for renewable energy generation by enacting Act 295. Act 295 requires 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. Wisconsin Electric and WPS are currently in compliance with this requirement. Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

## Manufactured Gas Plant Remediation

We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.

In addition, some of these sites are coordinating the investigation and cleanup subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td></tr><tr><td>Regulatory assets</td><td>$ 697.0</td><td>$ 45.9</td></tr><tr><td>Reserves for future remediation</td><td>628.0</td><td>32.6</td></tr></table>

The increases in the regulatory assets and reserves are primarily related to balances associated with the Integrys regulated companies, which were acquired on June 29, 2015. See Note 2, Acquisition, for more information.



## Enforcement and Litigation Matters

We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.

## Paris Generating Station Wisconsin Pollution Discharge Elimination System Permit

In November 2014, the WDNR reissued the WPDES permit for the PSGS. We believed that the WDNR imposed unreasonable permit conditions with respect to temperature monitoring, the control of water treatment additive, and phosphorus discharges. To address these permit conditions, Wisconsin Electric filed a petition for a contested case hearing with the WDNR in January 2015. On the same day, Wisconsin Electric also filed a request to be covered by the statewide phosphorus variance to address one of its concerns with the permit. Wisconsin Electric reached an agreement with the WDNR with respect to the permit conditions for temperature monitoring and for restrictions related to the use of a water treatment additive. In March 2015, the WDNR issued a final WPDES permit with agreed upon modifications, and Wisconsin Electric withdrew its petition for a contested case hearing. In July 2015, the Milwaukee County Circuit Court entered a stipulation and Order for Judgment between the WDNR and Wisconsin Department of Justice. This order resolves the litigation by allowing Wisconsin Electric to maintain the ability to apply for and be covered by the statewide phosphorus variance.

## Paris Generating Station Units 1 and 4 Construction Permit

In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to PSGS Units 1 and 4, allowing those units to restart after a temporary outage related to a construction permit matter with the WDNR. We received an “after the fact” permit from the WDNR, and the units are now available for service. In October, 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit.

In February 2013, the Sierra Club also filed for a contested case hearing with the WDNR in connection with the administration order issued in this matter, which was granted. However, a hearing has not yet been scheduled.

## Valley Power Plant Title V Air Permit

In February 2011, the WDNR renewed VAPP's Title V operating permit for five years. In March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of this proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

## Weston Title V Air Permit

In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The ALJ dismissed some of the petition issues relating to the averaging period and monitoring issues.

In May 2014, the WDNR issued a Notice of Violation (NOV) alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler.

In June 2015, the WDNR issued a NOV alleging that WPS failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied its request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV.



The contested case has been stayed for a period of months, and no hearing date has been set. We do not expect these matters to have a material impact on our financial statements.

## Solvay Coke and Gas Site

In August 2004, Wisconsin Electric and Wisconsin Gas were identified as potentially responsible parties at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company of Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site. In 2007, Wisconsin Electric, Wisconsin Gas, and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. The final remedial investigation report was submitted to the EPA in December 2015, and work will now begin on the feasibility study. Under the Administrative Settlement Agreement, neither Wisconsin Electric nor Wisconsin Gas admits to any liability for the site, waives any liability defenses, or commits to perform future site remedial activities. The companies' share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported above.

## Consent Decrees

Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam – In November 2009, the EPA issued a NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the U.S. District Court for the Eastern District of Wisconsin in March 2013. The final Consent Decree includes:

• the installation of emission control technology, including ReACT \( ^{™} \)  on Weston 3,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects totaling $6.0 million, and

• a civil penalty of $1.2 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, WPS retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023.

WPS received approval from the PSCW in its rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. The majority of the beneficial environmental projects proposed by WPS have been approved by the EPA. WPS is currently working with the EPA on certain changes to the environmental projects, but these changes are not expected to materially impact the overall cost.

Also, in May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2015. It is unknown whether the Sierra Club will take further action in the future.

Joint Ownership Power Plants Consent Decree – Columbia and Edgewater – In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, Wisconsin Electric (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, Wisconsin Power and Light, Madison Gas and Electric, and Wisconsin Electric entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the



Western District of Wisconsin in June 2013. Wisconsin Electric paid an immaterial portion of the assessed penalty but has no further obligations under the Consent Decree. The final Consent Decree includes:

• the installation of emission control technology, including scrubbers at the Columbia plant,

• changed operating conditions (including refueling, repowering, and/or retirement of units),

• limitations on plant emissions,

• beneficial environmental projects, with WPS's portion totaling $1.3 million, and

• WPS's portion of a civil penalty and legal fees totaling $0.4 million.

As mentioned above, the Consent Decree contains a requirement to refuel, repower, or retire Edgewater Unit 4, of which WPS is a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available. All of the beneficial environmental projects that WPS proposed have been approved by the EPA.

## NOTE 19—FAIR VALUE MEASUREMENTS

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

<table><tr><td rowspan="2">(in millions)</td><td colspan="5">December 31, 2015</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Derivative assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas contracts</td><td>$ 1.6</td><td>$ 1.5</td><td>$ —</td><td>$ 3.1</td><td></td></tr><tr><td>FTRs</td><td>—</td><td>—</td><td>3.6</td><td>3.6</td><td></td></tr><tr><td>Petroleum products contracts</td><td>1.2</td><td>—</td><td>—</td><td>1.2</td><td></td></tr><tr><td>Coal contracts</td><td>—</td><td>2.0</td><td>—</td><td>2.0</td><td></td></tr><tr><td>Total derivative assets</td><td>$ 2.8</td><td>$ 3.5</td><td>$ 3.6</td><td>$ 9.9</td><td></td></tr><tr><td>Investments held in rabbi trust</td><td>$ 39.8</td><td>$ —</td><td>$ —</td><td>$ 39.8</td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Derivative liabilities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas contracts</td><td>$ 16.5</td><td>$ 25.3</td><td>$ —</td><td>$ 41.8</td><td></td></tr><tr><td>Petroleum products contracts</td><td>4.9</td><td>—</td><td>—</td><td>4.9</td><td></td></tr><tr><td>Coal contracts</td><td>—</td><td>12.3</td><td>—</td><td>12.3</td><td></td></tr><tr><td>Total derivative liabilities</td><td>$ 21.4</td><td>$ 37.6</td><td>$ —</td><td>$ 59.0</td><td></td></tr></table>



<table><tr><td rowspan="2">(in millions)</td><td colspan="5">December 31, 2014</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Derivative assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas contracts</td><td>$ 1.1</td><td>$ 3.9</td><td>$ —</td><td>$ 5.0</td><td></td></tr><tr><td>FTRs</td><td>—</td><td>—</td><td>7.0</td><td>7.0</td><td></td></tr><tr><td>Coal contracts</td><td>—</td><td>3.3</td><td>—</td><td>3.3</td><td></td></tr><tr><td>Total derivative assets</td><td>$ 1.1</td><td>$ 7.2</td><td>$ 7.0</td><td>$ 15.3</td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Derivative liabilities</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas contracts</td><td>$ 11.5</td><td>$ 0.8</td><td>$ —</td><td>$ 12.3</td><td></td></tr><tr><td>Coal contracts</td><td>—</td><td>0.2</td><td>—</td><td>0.2</td><td></td></tr><tr><td>Total derivative liabilities</td><td>$ 11.5</td><td>$ 1.0</td><td>$ —</td><td>$ 12.5</td><td></td></tr></table>

The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 20, Derivative Instruments, for more information.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:

<table><tr><td>(in millions)</td><td>2015</td><td>2014</td><td>2013</td></tr><tr><td>Balance at the beginning of the period</td><td>$ 7.0</td><td>$ 3.5</td><td>$ 4.7</td></tr><tr><td>Realized and unrealized gains</td><td>1.3</td><td>—</td><td>—</td></tr><tr><td>Purchases</td><td>3.9</td><td>15.6</td><td>10.6</td></tr><tr><td>Sales</td><td>(0.1)</td><td>—</td><td>—</td></tr><tr><td>Settlements</td><td>(11.9)</td><td>(12.1)</td><td>(11.8)</td></tr><tr><td>Acquisition of Integrys</td><td>(1.3)</td><td>—</td><td>—</td></tr><tr><td>Net transfers out of level 3</td><td>4.7</td><td>—</td><td>—</td></tr><tr><td>Balance at the end of the period</td><td>$ 3.6</td><td>$ 7.0</td><td>$ 3.5</td></tr></table>

Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the income statements.

## Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31:

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">2015</td><td colspan="3">2014</td></tr><tr><td>Carrying Amount</td><td>Fair Value</td><td>Carrying Amount</td><td>Fair Value</td><td></td><td></td></tr><tr><td>Preferred stock</td><td>$ 30.4</td><td>$ 27.3</td><td>$ 30.4</td><td>$ 27.1</td><td></td><td></td></tr><tr><td>Long-term debt, including current portion  \( * \)</td><td>$ 9,221.9</td><td>$ 9,681.0</td><td>$ 4,510.3</td><td>$ 5,126.0</td><td></td><td></td></tr></table>

* Long-term debt excludes capital lease obligations.



## NOTE 20—DERIVATIVE INSTRUMENTS

The following table shows our derivative assets and derivative liabilities:

<table><tr><td rowspan="2">(in millions)</td><td rowspan="2">Balance Sheet Presentation</td><td colspan="3">December 31, 2015</td><td colspan="3">December 31, 2014</td></tr><tr><td>Derivative Assets</td><td>Derivative Liabilities</td><td>Derivative Assets</td><td>Derivative Liabilities</td><td></td><td></td></tr><tr><td>Natural gas</td><td>Other current</td><td>$ 2.6</td><td>$ 38.5</td><td>$ 5.0</td><td>$ 11.5</td><td></td><td></td></tr><tr><td>Natural gas</td><td>Other long-term</td><td>0.5</td><td>3.3</td><td>—</td><td>0.8</td><td></td><td></td></tr><tr><td>Petroleum products</td><td>Other current</td><td>0.9</td><td>3.8</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Petroleum products</td><td>Other long-term</td><td>0.3</td><td>1.1</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>FTRs</td><td>Other current</td><td>3.6</td><td>—</td><td>7.0</td><td>—</td><td></td><td></td></tr><tr><td>Coal</td><td>Other current</td><td>1.7</td><td>6.7</td><td>2.7</td><td>0.2</td><td></td><td></td></tr><tr><td>Coal</td><td>Other long-term</td><td>0.3</td><td>5.6</td><td>0.6</td><td>—</td><td></td><td></td></tr><tr><td></td><td>Other current</td><td>8.8</td><td>49.0</td><td>14.7</td><td>11.7</td><td></td><td></td></tr><tr><td></td><td>Other long-term</td><td>1.1</td><td>10.0</td><td>0.6</td><td>0.8</td><td></td><td></td></tr><tr><td>Total</td><td></td><td>$ 9.9</td><td>$ 59.0</td><td>$ 15.3</td><td>$ 12.5</td><td></td><td></td></tr></table>

Our estimated notional sales volumes and gains (losses) were as follows:

<table><tr><td rowspan="2">(in millions)</td><td colspan="2">December 31, 2015</td><td colspan="2">December 31, 2014</td><td colspan="2">December 31, 2013</td></tr><tr><td>Volume</td><td>Gains (Losses)</td><td>Volume</td><td>Gains</td><td>Volume</td><td>Gains (Losses)</td></tr><tr><td>Natural gas</td><td>86.2 Dth</td><td>$ (50.5)</td><td>40.5 Dth</td><td>$ 7.3</td><td>48.6 Dth</td><td>$ (8.5)</td></tr><tr><td>Petroleum products</td><td>7.8 gallons</td><td>(1.9)</td><td>9.2 gallons</td><td>0.5</td><td>8.6 gallons</td><td>0.5</td></tr><tr><td>FTRs</td><td>27.3 MWh</td><td>6.7</td><td>26.1 MWh</td><td>12.7</td><td>25.3 MWh</td><td>14.9</td></tr><tr><td>Total</td><td></td><td>$ (45.7)</td><td></td><td>$ 20.5</td><td></td><td>$ 6.9</td></tr></table>

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">December 31, 2015</td><td colspan="3">December 31, 2014</td></tr><tr><td>Derivative Assets</td><td>Derivative Liabilities</td><td>Derivative Assets</td><td>Derivative Liabilities</td><td></td><td></td></tr><tr><td>Gross amount recognized on the balance sheet</td><td>$ 9.9</td><td>$ 59.0</td><td>$ 15.3</td><td>$ 12.5</td><td></td><td></td></tr><tr><td>Gross amount not offset on the balance sheet  \( * \)</td><td>(3.0)</td><td>(22.5)</td><td>(0.4)</td><td>(11.5)</td><td></td><td></td></tr><tr><td>Net amount</td><td>$ 6.9</td><td>$ 36.5</td><td>$ 14.9</td><td>$ 1.0</td><td></td><td></td></tr></table>

* Includes cash collateral posted of $19.5 million and $10.3 million as of December 31, 2015 and 2014, respectively.

As of December 31, 2015 and 2014, we posted collateral of $42.3 million and $11.2 million, respectively, in our margin accounts. Certain of our derivative and non-derivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a net liability position at December 31, 2015 was $23.8 million, and zero at December 31, 2014. At December 31, 2015, we had not posted any cash collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at December 31, 2015, we would have been required to post collateral of $18.0 million.

During 2015, we settled several forward interest rate swap agreements entered into to mitigate interest risk associated with the issuance of $1.2 billion of long-term debt related to the acquisition of Integrys. As these agreements qualified for cash flow hedging accounting treatment, the payments of $19.0 million received upon settlement of these agreements were deferred in accumulated other comprehensive income and are being amortized as a decrease to interest expense over the periods in which the interest costs are recognized in earnings.

During 2015, we reclassified $1.2 million of forward interest rate swap agreement settlements deferred in accumulated other comprehensive income as a reduction to interest expense. We estimate that during the next twelve months, $2.2 million will be reclassified from accumulated other comprehensive income as a reduction to interest expense.



## NOTE 21—VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.

We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal and natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

## American Transmission Company

We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We instead account for ATC as an equity method investment. See Note 4, Investment in American Transmission Company, for more information.

The significant assets and liabilities related to ATC recorded on our balance sheet at December 31, 2015 included our equity investment and accounts payable. At December 31, 2015, our equity investment was $1,380.9 million, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $28.3 million of accounts payable due to ATC at December 31, 2015 for network transmission services.

## Purchased Power Agreement

We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately six years. We have examined the risks of the entity, including operations and maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.

We have approximately $130.5 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the years ended December 31, 2015, 2014, and 2013 were $53.6 million, $53.0 million, and $50.3 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

## NOTE 22—REGULATORY ENVIRONMENT

## Wisconsin Electric Power Company

## 2015 Wisconsin Rate Order

In May 2014, Wisconsin Electric applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015:

- A net bill increase related to non-fuel costs for Wisconsin Electric's retail electric customers of approximately $2.7 million (0.1%) in 2015. This amount reflects Wisconsin Electric's receipt of SSR payments from MISO that were higher than Wisconsin Electric anticipated when it filed its rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from a Treasury Grant that Wisconsin Electric received in connection with its biomass facility. The majority of this $26.6 million was returned to customers in the form of bill credits in 2015.

- A rate increase for Wisconsin Electric’s retail electric customers of $26.6 million (0.9%) in 2016 related to the expiration of the bill credits provided to customers in 2015.



• A rate decrease of $13.9 million (-0.5%) in 2015 related to a forecasted decrease in fuel costs.

- A rate decrease of $10.7 million (-2.4%) for Wisconsin Electric's natural gas customers in 2015, with no rate adjustment in 2016.

- A rate increase of approximately $0.5 million (2.0%) for Wisconsin Electric's Downtown Milwaukee (Valley) steam utility customers in 2015, with no rate adjustment in 2016.

- A rate increase of approximately $1.2 million (7.3%) for Wisconsin Electric's Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016.

The authorized ROE for Wisconsin Electric was set at 10.2%, and its common equity component remained at an average of 51%. The PSCW order reaffirmed the deferral of Wisconsin Electric's transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for Wisconsin Electric, which includes higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues Wisconsin Electric will receive under the PIPP SSR agreements. Under escrow accounting, Wisconsin Electric will record SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference will be deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference will be deferred and recovered from customers with interest, in a future rate case.

In January 2015, certain parties appealed a portion of the PSCW's final decision adopting Wisconsin Electric's specific rate design changes, including new charges for customer-owned generation within its service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in Wisconsin Electric's rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate case were impacted by the Dane County Circuit Court order.

## Earnings Sharing Agreement

In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for Wisconsin Electric. See Note 2, Acquisition, for more information on this earnings sharing mechanism.

## 2013 Wisconsin Rate Order

In March 2012, Wisconsin Electric initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved the following rate adjustments, effective January 1, 2013:

- A net bill increase related to non-fuel costs for Wisconsin Electric's retail electric customers of approximately $70.0 million (2.6%) in 2013. This amount reflected an offset of approximately $63.0 million (2.3%) for bill credits related to the proceeds of the Treasury Grant, including associated tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133.0 million (4.8%) in 2013.

- An electric rate increase for Wisconsin Electric's electric customers of approximately $28.0 million (1.0%) in 2014, and a $45.0 million (-1.6%) reduction in bill credits.

• Recovery of a forecasted increase in fuel costs of approximately $44.0 million (1.6%) in 2013.

- A rate decrease of approximately $8.0 million (-1.9%) for Wisconsin Electric's natural gas customers in 2013, with no rate adjustment in 2014. The Wisconsin Electric rates reflect a $6.4 million reduction in bad debt expense.

- An increase of approximately $1.3 million (6.0%) for Wisconsin Electric's Downtown Milwaukee (Valley) steam utility customers in 2013 and another $1.3 million (6.0%) in 2014.

- An increase of approximately $1.0 million (7.0%) in 2013 and $1.0 million (6.0%) in 2014 for Wisconsin Electric's Milwaukee County steam utility customers.



Based on the PSCW order, the authorized ROE for Wisconsin Electric remained at 10.4%. In addition, the PSCW approved escrow accounting treatment for the Treasury Grant. The PSCW also determined the construction costs for the Oak Creek expansion units were prudently incurred, and it approved the recovery of the majority of these costs in rates.

## Wisconsin Gas LLC

## 2015 Wisconsin Rate Order

In May 2014, Wisconsin Gas applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved rate increases of $17.1 million (2.6%) in 2015 and $21.4 million (3.2%) in 2016 for Wisconsin Gas's natural gas customers. These rate adjustments were effective January 1, 2015. The authorized ROE for Wisconsin Gas was set at 10.3%. The PSCW also authorized an increase in Wisconsin Gas's common equity component to an average of 49.5%.

## Earnings Sharing Agreement

In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for Wisconsin Gas. See Note 2, Acquisition, for more information on this earnings sharing mechanism.

## 2013 Wisconsin Rate Order

In March 2012, Wisconsin Gas initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved a rate decrease of approximately $34.0 million (-5.5%) for Wisconsin Gas's natural gas customers in 2013, with no rate adjustment in 2014. The Wisconsin Gas rates reflect a $43.8 million reduction in bad debt expense. The rate adjustments were effective January 1, 2013, and the authorized ROE for Wisconsin Gas remained at 10.5%.

## Wisconsin Public Service Corporation

## 2016 Wisconsin Rate Order

In April 2015, WPS initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order for WPS, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0%, authorized a net retail electric rate decrease of $7.9 million (-0.8%) and a net retail natural gas rate decrease of $6.2 million (-2.1%). Based on the order, the PSCW will continue to allow escrow treatment for ATC and MISO network transmission expenses, including any future SSR payments. This allows WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. In addition, the PSCW approved a deferral for ReACT \( ^{™} \) , which requires WPS to defer the revenue requirement of ReACT \( ^{™} \)  costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window.

## 2015 Wisconsin Rate Order

In April 2014, WPS initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% ROE. The order authorized a common equity component average of 50.28%. The PSCW approved a change in rate design for WPS, which includes higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014.

The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million. In addition, 2015 rates included approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, WPS would have realized an electric rate decrease. In addition, WPS received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 18, Commitments and Contingencies, for more information. The PSCW is allowing WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS defers as a regulatory asset or liability the differences between actual transmission expenses and those included in rates.



until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window.

The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, WPS refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, WPS would have realized a retail natural gas rate increase.

## 2015 Michigan Rate Order

In October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflect a 10.2% ROE and a common equity component average of 50.48%. The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston Unit 3 ReACT \( ^{™} \)  environmental project costs. On the second anniversary of the order, WPS will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. WPS also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. Lastly, WPS will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.

## The Peoples Gas Light and Coke Company and North Shore Gas Company

## Base Rate Freeze

In June 2015, the ICC approved the acquisition of Integrys subject to the condition that PGL and NSG will not seek increases of their base rates that would become effective earlier than two years after the close of the acquisition.

## Illinois Investigations

In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding the AMRP. The Illinois Attorney General's office is also conducting an inquiry into the same allegations. Since the investigations are ongoing, it is too early to determine what effect, if any, the investigations will have on the AMRP. In July 2015, we engaged a nationally recognized engineering and construction firm to conduct an independent, bottom up review of the AMRP's long-term cost, scope, and schedule. We filed the results of that review with the ICC on November 30, 2015.

In November 2015, the ICC initiated an investigation into whether we, PGL, or Integrys knowingly misled or withheld material information from the ICC at its open meeting on May 20, 2015. The investigation relates to the ICC Staff's presentation of the independent audit findings reached for the AMRP. The Illinois Attorney General's office is conducting an inquiry into this matter as well. It is too early to estimate the outcome of these inquiries since they are still ongoing.

In December 2015, the ICC ordered a series of stakeholder workshops to evaluate the AMRP. This ICC action does not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provides the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops are expected to result in an ICC order with final and binding recommendations for the AMRP. Since the workshops only commenced in January 2016, we are currently unable to determine what, if any, long-term impact there will be on the AMRP.

## 2015 Illinois Rate Order

In February 2014, PGL and NSG initiated a rate proceeding with the ICC. In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC issued an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflect a 9.05% ROE and a common equity component average of 50.33%.



rates for NSG reflect a 9.05% ROE and a common equity component average of 50.48%. The rate order allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL recovers a return on certain investments and depreciation expense through the qualifying infrastructure plant rider, and accordingly, such costs are not subject to PGL's rate order. In February 2015, the Attorney General and certain intervenors filed requests for rehearing on certain issues, which the ICC denied in March 2015. No appeals were filed related to the rehearing requests.

## Minnesota Energy Resources Corporation

## 2016 Minnesota Rate Case

In September 2015, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $14.8 million (5.5%). MERC's request reflects a 10.3% ROE and a common equity component average of 50.32%. The proposed retail natural gas rate increase is primarily driven by higher construction and capital expenditures, general inflation, and improvements to customer service programs. The request also includes increases in costs related to the acquisition of Alliant Energy Corporation's Minnesota natural gas operations in April 2015. MERC is requesting authority from the MPUC to continue the use of its currently authorized decoupling mechanism.

In November 2015, the MPUC approved an interim rate order, effective January 1, 2016, authorizing a retail natural gas rate increase for MERC of $9.7 million (3.7%). The interim rates reflect a 9.35% ROE and a common equity component average of 50.32%. The interim rate increase is subject to refund pending the final rate order.

## 2015 Minnesota Rate Case

In September 2013, MERC initiated a rate proceeding with the MPUC. In October 2014, the MPUC issued a final written order for MERC, effective April 1, 2015. The order authorized a retail natural gas rate increase of $7.6 million. The rates reflect a 9.35% ROE and a common equity component average of 50.31%. The order approved a deferral of customer billing system costs, for which recovery will be requested in a future rate case. A decoupling mechanism with a 10% cap remains in effect for MERC's residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, MERC refunded $4.7 million to customers in 2015.

## Michigan Gas Utilities Corporation

## 2016 Michigan Rate Order

In June 2015, MGU initiated a rate proceeding with the MPSC. In December 2015, the MPSC issued a final written order, approving a settlement agreement for MGU. The order, which reflects a 9.9% ROE and a common equity component average of 52.0%, authorized a retail natural gas rate increase of $3.4 million (2.4%), effective January 1, 2016. Based on the settlement agreement, MGU discontinued the use of its decoupling mechanism after December 31, 2015. In addition, since bonus depreciation is in effect in 2016, MGU is required to establish a regulatory liability for the resulting cost savings and must refund the liability in its next general rate case.

## NOTE 23—MICHIGAN SETTLEMENT

In March 2015, we entered into an Amended and Restated Settlement Agreement with the Attorney General of the State of Michigan, the Staff of the MPSC, Tilden Mining Company, and Empire Iron Mining Partnership (Amended Agreement) to resolve all objections these parties raised with the MPSC related to our acquisition of Integrys. The agreement includes the following provisions:

- The parties to the Amended Agreement agree that the acquisition satisfies the applicable requirements under Michigan law and should be approved by the MPSC.

- Wisconsin Electric will not enter into an SSR agreement for the operation of PIPP so long as both mines, if operational, remain full requirements customers of Wisconsin Electric until the earlier of: (a) the date a new, clean generation plant located in the Upper Peninsula of Michigan commences commercial operation; or (b) December 31, 2019. The prior SSR agreement was terminated effective February 1, 2015, with the return of the mines as full requirements customers.



• We commit to invest, either through an ownership interest or a purchased power agreement, or to have, if formed, our future Michigan jurisdictional utility invest, in a plant subject to the issuance of a Certificate of Necessity from the MPSC. The costs of this plant would be recovered from Michigan customers.

In addition, in March 2015, Wisconsin Electric entered into a special contract with each of the mines to provide full requirements electric service through December 31, 2019.

In April 2015, the MPSC approved our acquisition of Integrys, the Amended Agreement, and the special contracts with the two mines.

## NOTE 24—SEGMENT INFORMATION

During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation. We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2015, we reported six segments, which are described below.

- The Wisconsin segment includes the electric and natural gas utility and non-utility operations of Wisconsin Electric, Wisconsin Gas, and WPS, including Wisconsin Electric's electric and WPS's electric and natural gas operations in the state of Michigan.

• The Illinois segment includes the natural gas utility and non-utility operations of NSG and PGL.

• The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.

- The electric transmission segment includes our approximate 60% ownership interest in ATC, a federally regulated electric transmission company.

- The We Power segment includes our nonregulated entity that owns and leases generating facilities to Wisconsin Electric.

- The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF.

All of our operations and assets are located within the United States. The following tables show summarized financial information concerning our reportable segments for the years ended December 31, 2015, 2014, and 2013.

Regulated Operations

<table><tr><td>2015 (in millions)</td><td>Wisconsin</td><td>Illinois</td><td>Other States</td><td>Electric Transmission</td><td>Total Regulated Operations</td><td>We Power</td><td>Corporate and Other</td><td>Reconciling Eliminations</td><td>WEC Energy Group Consolidated</td></tr><tr><td>External revenues</td><td>$ 5,186.1</td><td>$ 503.4</td><td>$ 149.3</td><td>$ —</td><td>$ 5,838.8</td><td>$ 40.0</td><td>$ 47.3</td><td>$ —</td><td>$ 5,926.1</td></tr><tr><td>Intersegment revenues</td><td>5.0</td><td>—</td><td>—</td><td>—</td><td>5.0</td><td>405.2</td><td>—</td><td>(410.2)</td><td>—</td></tr><tr><td>Other operation and maintenance</td><td>1,741.0</td><td>219.6</td><td>50.0</td><td>—</td><td>2,010.6</td><td>4.3</td><td>103.7</td><td>(409.3)</td><td>1,709.3</td></tr><tr><td>Depreciation and amortization</td><td>408.6</td><td>63.3</td><td>10.0</td><td>—</td><td>481.9</td><td>67.5</td><td>12.4</td><td>—</td><td>561.8</td></tr><tr><td>Operating income (loss)</td><td>884.2</td><td>78.1</td><td>6.0</td><td>—</td><td>968.3</td><td>373.4</td><td>(91.2)</td><td>—</td><td>1,250.5</td></tr><tr><td>Equity in earnings of transmission affiliate</td><td>—</td><td>—</td><td>—</td><td>96.1</td><td>96.1</td><td>—</td><td>—</td><td>—</td><td>96.1</td></tr><tr><td>Interest expense</td><td>157.1</td><td>19.9</td><td>5.1</td><td>—</td><td>182.1</td><td>63.4</td><td>91.0</td><td>(5.1)</td><td>331.4</td></tr><tr><td>Capital expenditures</td><td>950.3</td><td>194.4</td><td>34.7</td><td>—</td><td>1,179.4</td><td>53.4</td><td>33.4</td><td>—</td><td>1,266.2</td></tr><tr><td>Total assets  \( {}^{*} \)</td><td>21,113.5</td><td>5,462.9</td><td>918.0</td><td>1,381.0</td><td>28,875.4</td><td>2,779.0</td><td>1,132.5</td><td>(3,431.7)</td><td>29,355.2</td></tr></table>

* Total assets at December 31, 2015 reflect an elimination of $2,105.3 million for all PTF activity between We Power and Wisconsin Electric.



<table><tr><td rowspan="2">2014 (in millions)</td><td colspan="9">Regulated Operations</td><td rowspan="2">WEC Energy Group Consolidated</td></tr><tr><td>Wisconsin</td><td>Illinois</td><td>Other States</td><td>Electric Transmission</td><td>Total Regulated Operations</td><td>We Power</td><td>Corporate and Other</td><td>Reconciling Eliminations</td><td></td></tr><tr><td>External revenues</td><td>$ 4,932.1</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 4,932.1</td><td>$ 55.7</td><td>$ 9.3</td><td>$ —</td><td>$ 4,997.1</td><td></td></tr><tr><td>Intersegment revenues</td><td>9.2</td><td>—</td><td>—</td><td>—</td><td>9.2</td><td>383.4</td><td>—</td><td>(392.6)</td><td>—</td><td></td></tr><tr><td>Other operation and maintenance</td><td>1,462.7</td><td>—</td><td>—</td><td>—</td><td>1,462.7</td><td>4.4</td><td>33.0</td><td>(387.7)</td><td>1,112.4</td><td></td></tr><tr><td>Depreciation and amortization</td><td>323.2</td><td>—</td><td>—</td><td>—</td><td>323.2</td><td>66.7</td><td>1.5</td><td>—</td><td>391.4</td><td></td></tr><tr><td>Operating income (loss)</td><td>770.2</td><td>—</td><td>—</td><td>—</td><td>770.2</td><td>368.0</td><td>(26.1)</td><td>—</td><td>1,112.1</td><td></td></tr><tr><td>Equity in earnings of transmission affiliate</td><td>—</td><td>—</td><td>—</td><td>—</td><td>66.0</td><td>66.0</td><td>—</td><td>—</td><td>66.0</td><td></td></tr><tr><td>Interest expense</td><td>127.6</td><td>—</td><td>—</td><td>—</td><td>127.6</td><td>64.6</td><td>48.8</td><td>(0.7)</td><td>240.3</td><td></td></tr><tr><td>Capital expenditures</td><td>715.0</td><td>—</td><td>—</td><td>—</td><td>715.0</td><td>41.0</td><td>5.2</td><td>—</td><td>761.2</td><td></td></tr><tr><td>Total assets *</td><td>14,403.8</td><td>—</td><td>—</td><td>—</td><td>424.1</td><td>14,827.9</td><td>2,789.9</td><td>253.3</td><td>(2,966.1)</td><td>14,905.0</td></tr></table>

* Total assets at December 31, 2014 reflect an elimination of $2,172.9 million for all PTF activity between We Power and Wisconsin Electric.

<table><tr><td rowspan="2">2013 (in millions)</td><td colspan="9">Regulated Operations</td><td rowspan="2">WEC Energy Group Consolidated</td></tr><tr><td>Wisconsin</td><td>Illinois</td><td>Other States</td><td>Electric Transmission</td><td>Total Regulated Operations</td><td>We Power</td><td>Corporate and Other</td><td>Reconciling Eliminations</td><td></td></tr><tr><td>External revenues</td><td>$ 4,451.9</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 4,451.9</td><td>$ 56.6</td><td>$ 10.5</td><td>$ —</td><td>$ 4,519.0</td><td></td></tr><tr><td>Intersegment revenues</td><td>10.1</td><td>—</td><td>—</td><td>—</td><td>10.1</td><td>380.9</td><td>—</td><td>(391.0)</td><td>—</td><td></td></tr><tr><td>Other operation and maintenance</td><td>1,522.0</td><td>—</td><td>—</td><td>—</td><td>1,522.0</td><td>4.6</td><td>14.2</td><td>(385.8)</td><td>1,155.0</td><td></td></tr><tr><td>Depreciation and amortization</td><td>272.2</td><td>—</td><td>—</td><td>—</td><td>272.2</td><td>66.3</td><td>1.6</td><td>—</td><td>340.1</td><td></td></tr><tr><td>Operating income</td><td>719.4</td><td>—</td><td>—</td><td>—</td><td>719.4</td><td>366.6</td><td>(5.9)</td><td>—</td><td>1,080.1</td><td></td></tr><tr><td>Equity in earnings of transmission affiliate</td><td>—</td><td>—</td><td>—</td><td>—</td><td>68.5</td><td>68.5</td><td>—</td><td>—</td><td>68.5</td><td></td></tr><tr><td>Interest expense</td><td>135.0</td><td>—</td><td>—</td><td>—</td><td>135.0</td><td>65.7</td><td>50.8</td><td>(0.6)</td><td>250.9</td><td></td></tr><tr><td>Capital expenditures</td><td>695.7</td><td>—</td><td>—</td><td>—</td><td>695.7</td><td>25.8</td><td>3.7</td><td>—</td><td>725.2</td><td></td></tr><tr><td>Total assets *</td><td>13,934.6</td><td>—</td><td>—</td><td>—</td><td>402.7</td><td>14,337.3</td><td>2,814.6</td><td>213.6</td><td>(2,922.3)</td><td>14,443.2</td></tr></table>

* Total assets at December 31, 2013 reflect an elimination of $2,231.2 million for all PTF activity between We Power and Wisconsin Electric.

## NOTE 25—QUARTERLY FINANCIAL INFORMATION (Unaudited)

<table><tr><td>(in millions, except per share amounts)</td><td>First Quarter</td><td>Second Quarter</td><td>Third Quarter</td><td>Fourth Quarter</td><td>Total</td></tr><tr><td>2015</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 1,387.9</td><td>$ 991.2</td><td>$ 1,698.7</td><td>$ 1,848.3</td><td>$ 5,926.1</td></tr><tr><td>Operating income</td><td>358.8</td><td>165.8</td><td>345.7</td><td>380.2</td><td>1,250.5</td></tr><tr><td>Net income attributed to common shareholders</td><td>195.8</td><td>80.9</td><td>182.5</td><td>179.3</td><td>638.5</td></tr><tr><td>Earnings per share *</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ 0.87</td><td>$ 0.36</td><td>$ 0.58</td><td>$ 0.57</td><td>$ 2.36</td></tr><tr><td>Diluted</td><td>0.86</td><td>0.35</td><td>0.58</td><td>0.57</td><td>2.34</td></tr><tr><td>2014</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 1,695.0</td><td>$ 1,043.7</td><td>$ 1,033.3</td><td>$ 1,225.1</td><td>$ 4,997.1</td></tr><tr><td>Operating income</td><td>381.8</td><td>240.7</td><td>246.1</td><td>243.5</td><td>1,112.1</td></tr><tr><td>Net income attributed to common shareholders</td><td>207.6</td><td>133.0</td><td>126.3</td><td>121.4</td><td>588.3</td></tr><tr><td>Earnings per share *</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ 0.92</td><td>$ 0.59</td><td>$ 0.56</td><td>$ 0.54</td><td>$ 2.61</td></tr><tr><td>Diluted</td><td>0.91</td><td>0.58</td><td>0.56</td><td>0.53</td><td>2.59</td></tr></table>

* Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.



Due to various factors, including the acquisition of Integrys on June 29, 2015, the quarterly results of operations are not necessarily comparable.

## NOTE 26—NEW ACCOUNTING PRONOUNCEMENTS

## Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements.

## Classification and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements.

## Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We are currently assessing the effects this guidance may have on our financial statements.



## REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

## To the Board of Directors and Stockholders of WEC Energy Group, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of WEC Energy Group Inc. and subsidiaries (the "Company") as of December 31, 2015 and 2014, and the related consolidated income statements, statements of comprehensive income, statements of equity, and statements of cash flows for each of the three years in the period ended December 31, 2015. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of WEC Energy Group, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2016 expressed an unqualified opinion on the Company's internal control over financial reporting.

Deloitte & Touche LLP

February 26, 2016



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

## To the Board of Directors and Stockholders of WEC Energy Group, Inc.:

We have audited the internal control over financial reporting of WEC Energy Group, Inc. and subsidiaries (the "Company") as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2015 of the Company and our report dated February 26, 2016 expressed an unqualified opinion on those financial statements.



February 26, 2016



# INTERNAL CONTROL OVER FINANCIAL REPORTING

## MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our and our subsidiaries' internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our and our subsidiaries' internal control over financial reporting was effective as of December 31, 2015.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

## REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

For Deloitte & Touche LLP's Report of Independent Registered Public Accounting Firm, attesting to the effectiveness of our internal controls over financial reporting, see pages F-89 and F-90.

## CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in our internal control over financial reporting during the fourth quarter of 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

On June 29, 2015, our acquisition of Integrys closed. We are currently in the process of integrating and aligning the operations, processes, and internal controls of the combined company. See Note 2, Acquisition, for more information regarding the acquisition.



## WEC ENERGY GROUP, INC.
COMPARATIVE SELECTED FINANCIAL DATA AND OTHER STATISTICS

<table><tr><td colspan="7">As of or for Year Ended December 31 (in millions, except per share information)</td></tr><tr><td></td><td>2015 (1)</td><td>2014</td><td>2013</td><td>2012</td><td>2011</td><td></td></tr><tr><td>Operating revenues</td><td>$ 5,926.1</td><td>$ 4,997.1</td><td>$ 4,519.0</td><td>$ 4,246.4</td><td>$ 4,486.4</td><td></td></tr><tr><td>Net income attributed to common shareholders</td><td>638.5</td><td>588.3</td><td>577.4</td><td>546.3</td><td>526.2</td><td></td></tr><tr><td>Total assets (2) (3)</td><td>29,355.2</td><td>14,905.0</td><td>14,443.2</td><td>14,163.0</td><td>13,823.3</td><td></td></tr><tr><td>Preferred stock of subsidiary</td><td>30.4</td><td>30.4</td><td>30.4</td><td>30.4</td><td>30.3</td><td></td></tr><tr><td>Long-term debt (excluding current portion) (2)</td><td>9,124.1</td><td>4,170.7</td><td>4,347.0</td><td>4,437.1</td><td>4,597.1</td><td></td></tr><tr><td>Weighted average common shares outstanding</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>271.1</td><td>225.6</td><td>227.6</td><td>230.2</td><td>232.6</td><td></td></tr><tr><td>Diluted</td><td>272.7</td><td>227.5</td><td>229.7</td><td>232.8</td><td>235.4</td><td></td></tr><tr><td>Earnings per share</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ 2.36</td><td>$ 2.61</td><td>$ 2.54</td><td>$ 2.37</td><td>$ 2.26</td><td></td></tr><tr><td>Diluted</td><td>$ 2.34</td><td>$ 2.59</td><td>$ 2.51</td><td>$ 2.35</td><td>$ 2.24</td><td></td></tr><tr><td>Dividends per share of common stock</td><td>$ 1.74</td><td>$ 1.56</td><td>$ 1.45</td><td>$ 1.20</td><td>$ 1.04</td><td></td></tr></table>

(1) Includes the impact of the Integrys acquisition for the last two quarters of 2015. See Note 2, Acquisition, for more information.

(2) 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 $15.7 million in 2014, $16.2 million in 2013, $16.7 million in 2012, and $17.2 million in 2011.

(3) 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 for all periods presented. Amounts reclassified were $242.7 million in 2014, $310.0 million in 2013, $105.3 million in 2012, and $21.6 million in 2011.



# PERFORMANCE GRAPH

The performance graph below shows a comparison of the cumulative total return, assuming reinvestment of dividends, over the last five years had $100 been invested at the close of business on December 31, 2010, in each of:

• WEC Energy Group common stock;

• a Custom Peer Group Index;

• a recomprised Custom Peer Group Index; and

• the Standard & Poor's 500 Index ("S&P 500").

Custom Peer Group Index. We have used the Custom Peer Group Index for peer comparison purposes because we believe the Index provided an accurate representation of our peers. The Custom Peer Group Index is a market capitalization-weighted index of companies, including WEC Energy Group, that are similar to us in terms of business model and long-term strategies.

In addition to WEC Energy Group, the companies in the Custom Peer Group Index are Alliant Energy Corporation; Ameren Corporation; American Electric Power Company, Inc.; Avista Corporation; CMS Energy Corporation, Consolidated Edison, Inc.; DTE Energy Company; Duke Energy Corp.; Eversource Energy; FirstEnergy Corp.; Great Plains Energy, Inc.; NiSource Inc.; OGE Energy Corp.; P&G Corporation; Pinnacle West Capital Corporation; Portland General Electric; SCANA Corporation; The Southern Company; TECO Energy, Inc.; Westar Energy, Inc.; and Xcel Energy Inc.

Custom Peer Group Index – Recomprised. In September 2015, Emera, Inc., headquartered in Halifax, Nova Scotia, announced its acquisition of TECO Energy. Therefore, beginning in 2016, we recomprised our custom peer group to remove TECO Energy, Inc. We also added Edison International to the peer group and removed Avista Corporation and Portland General Electric. We believe the Custom Peer Group Index, as recomprised, continues to be made up of companies that are similar to us in terms of business model and long-term strategies.

Five-Year Cumulative Return Chart



Value of Investment at Year-End

<table><tr><td></td><td>12/31/10</td><td>12/31/11</td><td>12/31/12</td><td>12/31/13</td><td>12/31/14</td><td>12/31/15</td></tr><tr><td>WEC Energy Group, Inc.</td><td>$100</td><td>$122.93</td><td>$133.88</td><td>$155.47</td><td>$205.35</td><td>$206.97</td></tr><tr><td>Custom Peer Group Index</td><td>$100</td><td>$121.91</td><td>$124.34</td><td>$136.05</td><td>$175.97</td><td>$173.85</td></tr><tr><td>Custom Peer Group Index - Recomprised</td><td>$100</td><td>$121.42</td><td>$124.68</td><td>$136.03</td><td>$177.17</td><td>$173.47</td></tr><tr><td>S&amp;P 500</td><td>$100</td><td>$102.11</td><td>$118.43</td><td>$156.77</td><td>$178.21</td><td>$180.66</td></tr></table>



# MARKET FOR OUR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

## NUMBER OF COMMON STOCKHOLDERS

As of January 31, 2016, based upon the number of WEC Energy Group stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had approximately 55,000 registered stockholders.

## COMMON STOCK LISTING AND TRADING

Our common stock is listed on the New York Stock Exchange under the ticker symbol "WEC."

## DIVIDENDS AND COMMON STOCK PRICES

## Common Stock Dividends of WEC Energy Group

Cash dividends on our common stock, as declared by our Board of Directors, are normally paid on or about the first day of March, June, September, and December of each year. We review our dividend policy on a regular basis. Subject to any regulatory restrictions or other limitations on the payment of dividends, future dividends will be at the discretion of the Board of Directors and will depend upon, among other factors, earnings, financial condition, and other requirements. For information regarding restrictions on the ability of our subsidiaries to pay us dividends, see Note 11, Common Equity.

On January 21, 2016, the Board of Directors increased the quarterly dividend to $0.4950 per share effective with the first quarter of 2016 dividend payment, which equates to an annual dividend of $1.98 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65–70% of earnings.

Range of WEC Energy Group Common Stock Prices and Dividends

<table><tr><td rowspan="2"></td><td colspan="4">2015</td><td colspan="4">2014</td></tr><tr><td>High</td><td>Low</td><td>Dividend</td><td>High</td><td>Low</td><td>Dividend</td><td></td><td></td></tr><tr><td>Quarter</td><td>High</td><td>Low</td><td>Dividend</td><td>High</td><td>Low</td><td>Dividend</td><td></td><td></td><td></td></tr><tr><td>First</td><td>$ 58.01</td><td>$ 47.51</td><td>$ 0.4225</td><td>$ 46.76</td><td>$ 40.17</td><td>$ 0.39</td><td></td><td></td><td></td></tr><tr><td>Second</td><td>$ 51.54</td><td>$ 44.93</td><td>$ 0.4225</td><td>$ 49.21</td><td>$ 44.03</td><td>$ 0.39</td><td></td><td></td><td></td></tr><tr><td>Third</td><td>$ 52.29</td><td>$ 44.97</td><td>$ 0.4404</td><td>$ 47.02</td><td>$ 41.90</td><td>$ 0.39</td><td></td><td></td><td></td></tr><tr><td>Fourth</td><td>$ 53.88</td><td>$ 47.98</td><td>$ 0.4575</td><td>$ 55.39</td><td>$ 43.01</td><td>$ 0.39</td><td></td><td></td><td></td></tr><tr><td>Annual</td><td>$ 58.01</td><td>$ 44.93</td><td>$ 1.7429</td><td>$ 55.39</td><td>$ 40.17</td><td>$ 1.56</td><td></td><td></td><td></td></tr></table>
















## BOARD OF DIRECTORS

## John F. Bergstrom

Director since 1987.
Chairman and Chief Executive Officer of Bergstrom Corporation, which owns and operates numerous automobile sales and leasing companies.

## Barbara L. Bowles

Director since 1998.
Retired Vice Chair of Profit Investment Management and Retired Chairman of The Kenwood Group, Inc., investment advisory firms. The Kenwood Group, Inc. was merged into Profit Investment Management in 2006.

## William J. Brodsky

Director since 2015.
Chairman of the Board of CBOE Holdings, Inc., which is the holding company for the Chicago Board Options Exchange, an exchange that focuses on options contracts for individual equities, indexes and volatility, and CBOE Futures Exchange which offers volatility futures.

## Albert J. Budney, Jr.
Director since 2015.

Retired President and Director of Niagara Mohawk Holdings, Inc., a holding company which, through its subsidiaries, distributes electricity in areas of New York.

## Patricia W. Chadwick

Director since 2006.
President of Ravengate Partners, LLC, which provides businesses and not-for-profit institutions with advice about the financial markets, business management, and global economics.

## Curt S. Culver

Director since 2004.
Non-Executive Chairman of the Board of MGIC Investment Corporation and Mortgage Guaranty Insurance Corporation, a private mortgage insurance company.

## Thomas J. Fischer

Director since 2005.
Principal of Fischer Financial Consulting LLC, which provides consulting on corporate financial, accounting, and governance matters.













## Paul W. Jones

Director since 2015.
Retired Executive Chairman and Chief Executive Officer of A.O. Smith Corporation, a leading manufacturer of residential and commercial water heaters and boilers. Non-Executive Chairman of Rexnord Corporation.

## Gale E. Klappa

Director since 2003.
Chairman and Chief Executive Officer of WEC Energy Group, Inc.

## Henry W. Knueppel
Director since 2013.

Retired Chairman and Chief Executive Officer of Regal Beloit Corporation, a manufacturer of electric motors, mechanical and electrical motion controls, and power generation products.

## Allen L. Leverett

Director since 2016.
President of WEC Energy Group, Inc.

## Ulice Payne, Jr.

Director since 2003.
Managing Member of Addison-Clifton, LLC, which provides global trade compliance advisory services.

## Mary Ellen Stanek
Director since 2012.

Managing Director and Director of Asset Management of Baird Financial Group; Chief Investment Officer, Baird Advisors; President, Baird Funds, Inc. Baird Financial Group provides wealth management, capital markets, private equity, and asset management services to clients worldwide.



## OFFICERS

The names and positions as of December 31, 2015 of WEC Energy Group’s officers are listed below.

Gale E. Klappa \( ^{(1)} \)  – Chairman of the Board and Chief Executive Officer.

Allen L. Leverett \( ^{(1)} \)  – President.

Robert M. Garvin \( ^{(1)} \)  – Executive Vice President – External Affairs.

J. Patrick Keyes \( ^{(1)} \)  – Executive Vice President and Chief Financial Officer.

Susan H. Martin \( ^{(1)} \)  – Executive Vice President, General Counsel and Corporate Secretary.

M. Beth Straka \( ^{(1)} \)  – Senior Vice President – Corporate Communications and Investor Relations.

Darnell K. DeMasters – Vice President – Federal Government Affairs.

William J. Guc \( ^{(1)} \)  – Vice President and Controller.

Scott J. Lauber \( ^{(1)} \)  – Vice President and Treasurer.

Keith H. Ecke – Assistant Corporate Secretary.

David L. Hughes – Assistant Treasurer.

(1) Executive Officer of WEC Energy Group as of December 31, 2015. In addition, the following individuals are also executive officers of WEC Energy Group:

• J. Kevin Fletcher is Executive Vice President – Customer Service and Operations of several of WEC Energy Group’s utility subsidiaries.

• Charles R. Matthews is President of Peoples Energy, LLC, and President and Chief Executive Officer of The Peoples Gas Light and Coke Company and North Shore Gas Company.
• Joan M. Shafer is Executive Vice President – Human Resources and Organizational Effectiveness of WEC Energy Group’s Wisconsin utility subsidiaries.

On January 27, 2016, Mr. Klappa notified WEC Energy Group’s Board of Directors of his decision to retire as Chief Executive Officer effective May 1, 2016. On the same day, the Board appointed Mr. Leverett as CEO effective upon Mr. Klappa’s retirement.

The following actions with respect to the executive leadership team have also been announced:

- Effective April 1, 2016, J. Patrick Keyes has been named President of Michigan Gas Utilities and Minnesota Energy Resources Corporation, as well as President of WEC Business Services LLC. In addition, Mr. Keyes will remain an Executive Vice President of WEC Energy Group.

- Effective April 1, 2016, Scott J. Lauber has been named Executive Vice President and Chief Financial Officer of WEC Energy Group.

- Effective April 1, 2016, James A. Schubilske has been named Vice President and Treasurer. In addition, James A. Schubilske will become an executive officer of WEC Energy Group effective April 1, 2016.

- Effective April 1, 2016, Tom Metcalfe has been named Executive Vice President – Generation of Wisconsin Electric Power Company and Wisconsin Public Service Corporation. In addition, Tom Metcalfe will become an executive officer of WEC Energy Group effective April 1, 2016.

- Effective May 1, 2016, J. Kevin Fletcher has been named President of WEC Energy Group’s Wisconsin segment, which includes Wisconsin Electric, Wisconsin Gas LLC, and Wisconsin Public Service Corporation.



## ACCOUNT INFORMATION

- Visit www.computershare.com/investor. WEC Energy Group’s transfer agent, Computershare, provides our registered stockholders with secure account access. Stockholders can view share balances, market value, tax documents, and account statements; review answers to frequently asked questions; perform many transactions; and sign up for eDelivery, the paperless communication program from Computershare. eDelivery also provides electronic delivery of your annual meeting materials.

• Write to:

WEC Energy Group

c/o Computershare

P.O. Box 30170

College Station, TX 77842-3170

- If sending overnight correspondence, mail to: WEC Energy Group
c/o Computershare
211 Quality Circle, Suite 210
College Station, TX 77845

- Call Computershare at 800-558-9663. Service representatives are available from 7 a.m. to 7 p.m. Central time on business days. An automated voice-response system also provides information 24 hours a day, seven days a week.

Securities analysts and institutional investors may contact our Investor Relations Line at 414-221-2592. Stockholders who hold WEC Energy Group stock in brokerage accounts should contact their brokerage firm for account information.

## STOCK PURCHASE PLAN

WEC Energy Group’s Stock Plus Investment Plan provides a convenient way to purchase our common stock and reinvest dividends. To review the Prospectus and enroll, go to wecenergygroup.com and select the Investors tab. You also may contact Computershare at 800-558-9663 to request an enrollment package. This is not an offer to sell, or a solicitation of an offer to buy, any securities. Any stock offering will be made only by Prospectus.

## STOCKHOLDER INFORMATION

## DIVIDENDS

Dividends, as declared by the board of directors, typically are payable on the first day of March, June, September, and December. Stockholders may have their dividends deposited directly into their bank accounts. Please contact Computershare to request an authorization form.

## INTERNET ACCESS HELPS REDUCE COSTS

You may access wecenergygroup.com for the latest information about the company. The site provides access to financial, corporate governance, and other information, including Securities and Exchange Commission reports.

## ANNUAL CERTIFICATIONS

WEC Energy Group has filed the required certifications of its Chief Executive Officer and Chief Financial Officer under the Sarbanes-Oxley Act regarding the quality of its public disclosures. These exhibits can be found in the company’s Form 10-K for the year ended Dec. 31, 2015. The certification of WEC Energy Group’s Chief Executive Officer regarding compliance with the New York Stock Exchange (NYSE) corporate governance listing standards will be filed with the NYSE following the 2016 Annual Meeting of Stockholders. Last year, we filed this certification on June 5, 2015.

## CORPORATE RESPONSIBILITY

WEC Energy Group is committed to corporate responsibility and sustainable business practices — aligning our policies and practices with the needs of key stakeholders, and managing risk while accounting for the company’s economic, environmental, and social impacts. For additional information, visit www.wecenergygroup.com/csr.




231 W. MICHIGAN ST.

P.O. BOX 1331

MILWAUKEE, WI 53201

414-221-2345

wecenergygroup.com