WELPP 10-Q Quarterly Report March 31, 2018

WISCONSIN ELECTRIC POWER CO

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10-Q 1 a2018q1we10q.htm WISCONSIN ELECTRIC MARCH 31, 2018 FORM 10-Q Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2018



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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [X] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.



	Large accelerated filer [ ]		Accelerated filer [ ]
	Non-accelerated filer [X] (Do not check if a smaller reporting company)
			Smaller reporting company [ ]
			Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ] No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Common Stock, $10 Par Value,

33,289,327 shares outstanding at

March 31, 2018

All of the common stock of Wisconsin Electric Power Company is owned by WEC Energy Group, Inc.

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY

QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2018

TABLE OF CONTENTS



				Page
	CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION			1
PART I.	FINANCIAL INFORMATION			3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)			3
	Condensed Consolidated Income Statements			3
	Condensed Consolidated Balance Sheets			4
	Condensed Consolidated Statements of Cash Flows			5
	Notes to Condensed Consolidated Financial Statements			6
			Page
	Note 1	General Information	6
	Note 2	Disposition	6
	Note 3	Operating Revenues	6
	Note 4	Property, Plant, and Equipment	9
	Note 5	Common Equity	10
	Note 6	Short-Term Debt and Lines of Credit	10
	Note 7	Materials, Supplies, and Inventories	10
	Note 8	Income Taxes	11
	Note 9	Fair Value Measurements	11
	Note 10	Derivative Instruments	13
	Note 11	Employee Benefits	14
	Note 12	Segment Information	15
	Note 13	Variable Interest Entities	16
	Note 14	Related Parties	16
	Note 15	Commitments and Contingencies	18
	Note 16	Supplemental Cash Flow Information	21
	Note 17	Regulatory Environment	21
	Note 18	New Accounting Pronouncements	22
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			23
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			32
ITEM 4.	CONTROLS AND PROCEDURES			33
PART II.	OTHER INFORMATION			34
ITEM 1.	LEGAL PROCEEDINGS			34
ITEM 1A.	RISK FACTORS			34
ITEM 6.	EXHIBITS			35
SIGNATURE				36



03/31/2018 Form 10-Q	i	Wisconsin Electric Power Company

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
Bluewater		Bluewater Natural Gas Holding, LLC
Bostco		Bostco LLC
UMERC		Upper Michigan Energy Resources Corporation
WBS		WEC Business Services LLC
We Power		W.E. Power, LLC
WEC Energy Group		WEC Energy Group, Inc.
WG		Wisconsin Gas LLC
WPS		Wisconsin Public Service Corporation

Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		United States Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Accounting Terms
AIA		Affiliated Interest Agreement
ASU		Accounting Standards Update
FASB		Financial Accounting Standards Board
GAAP		United States Generally Accepted Accounting Principles
OPEB		Other Postretirement Employee Benefits

Environmental Terms
CO ₂		Carbon Dioxide
CPP		Clean Power Plan
GHG		Greenhouse Gas
NAAQS		National Ambient Air Quality Standards

Measurements
Dth		Dekatherm
MW		Megawatt
MWh		Megawatt-hour

Other Terms and Abbreviations
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia Circuit
ERGS		Elm Road Generating Station
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
OCPP		Oak Creek Power Plant
OC 5		Oak Creek Power Plant Unit 5
OC 6		Oak Creek Power Plant Unit 6
OC 7		Oak Creek Power Plant Unit 7



03/31/2018 Form 10-Q	ii	Wisconsin Electric Power Company

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OC 8		Oak Creek Power Plant Unit 8
PIPP		Presque Isle Power Plant
PWGS		Port Washington Generating Station
ROE		Return on Equity
Supreme Court		United States Supreme Court
Tax Legislation		Tax Cuts and Jobs Act of 2017



03/31/2018 Form 10-Q	iii	Wisconsin Electric Power Company

Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our Annual Report on Form 10-K for the year ended December 31, 2017 , and those identified below:


•	Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;


•	Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;


•	The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;


•	The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;


•	The timely completion of capital projects within budgets, as well as the recovery of the related costs through rates;

•

The impact of federal, state, and local legislative and regulatory changes, including changes in rate-setting policies or procedures, 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;


•	The uncertainty surrounding the recently enacted Tax Legislation, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact, if any, on our credit ratings;


•	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;


•	Factors affecting the implementation of WEC Energy Group's generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;


•	Increased pressure on us by investors and other stakeholder groups to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases;

•

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;



03/31/2018 Form 10-Q	1	Wisconsin Electric Power Company

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•	Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;


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


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


•	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 attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns;


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


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


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


•	The timing, costs, and anticipated benefits associated with the remaining integration efforts relating to WEC Energy Group's acquisition of Integrys Holding, Inc.;


•	Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets;


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


•	The ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and continuing to consolidate WEC Energy Group's enterprise systems with those of its other utilities;


•	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.



03/31/2018 Form 10-Q	2	Wisconsin Electric Power Company

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited)	Three Months Ended
	March 31
(in millions)	2018			2017
Operating revenues	$	941.5		$	972.0

Operating expenses
Cost of sales	357.0			348.6
Other operation and maintenance	335.6			326.6
Depreciation and amortization	85.3			82.1
Property and revenue taxes	27.2			28.4
Total operating expenses	805.1			785.7

Operating income	136.4			186.3

Other (expense) income, net	(4.2		)	3.2
Interest expense	29.7			29.6
Other expense	(33.9		)	(26.4		)

Income before income taxes	102.5			159.9
Income tax (benefit) expense	(3.6		)	57.8
Net income	106.1			102.1

Preferred stock dividend requirements	0.3			0.3
Net income attributed to common shareholder	$	105.8		$	101.8

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



03/31/2018 Form 10-Q	3	Wisconsin Electric Power Company

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts)	March 31, 2018		December 31, 2017
Assets
Current assets
Cash and cash equivalents	$	10.4	$	12.3
Accounts receivable and unbilled revenues, net of reserves of $43.5 and $39.5, respectively	489.1		513.8
Accounts receivable from related parties	146.3		109.1
Materials, supplies, and inventories	214.7		250.7
Prepayments	114.3		144.3
Other	7.1		9.4
Current assets	981.9		1,039.6

Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,798.9 and $3,741.8, respectively	10,086.2		10,007.7
Regulatory assets	2,122.4		1,984.9
Other	104.9		89.4
Long-term assets	12,313.5		12,082.0
Total assets	$	13,295.4	$	13,121.6

Liabilities and Equity
Current liabilities
Short-term debt	$	60.0	$	210.9
Current portion of long-term debt	250.0		250.0
Current portion of capital lease obligations	44.6		42.5
Accounts payable	217.6		329.3
Accounts payable to related parties	249.5		131.5
Accrued payroll and benefits	37.5		53.4
Accrued taxes	65.7		58.2
Other	142.1		111.8
Current liabilities	1,067.0		1,187.6

Long-term liabilities
Long-term debt	2,412.8		2,412.3
Capital lease obligations	2,811.5		2,823.8
Deferred income taxes	1,179.7		1,155.5
Regulatory liabilities	1,891.1		1,708.0
Pension and OPEB obligations	156.9		143.2
Other	288.1		276.9
Long-term liabilities	8,740.1		8,519.7

Commitments and contingencies (Note 15)

Common shareholder's equity
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9		332.9
Additional paid in capital	830.9		802.7
Retained earnings	2,294.1		2,248.3
Common shareholder's equity	3,457.9		3,383.9

Preferred stock	30.4		30.4
Total liabilities and equity	$	13,295.4	$	13,121.6

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



03/31/2018 Form 10-Q	4	Wisconsin Electric Power Company

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Three Months Ended
	March 31
(in millions)	2018			2017
Operating Activities
Net income	$	106.1		$	102.1
Reconciliation to cash provided by operating activities
Depreciation and amortization	85.3			82.1
Deferred income taxes and investment tax credits, net	(15.4		)	20.7
Contributions and payments related to pension and OPEB plans	(2.1		)	(3.3		)
(Payments for) proceeds from liabilities transferred (to) from WBS	(1.4		)	0.9
Change in –
Accounts receivable and unbilled revenues	(12.5		)	42.1
Materials, supplies, and inventories	36.0			19.4
Prepaid taxes	24.2			25.1
Other current assets	6.0			3.2
Accounts payable	12.3			(63.5		)
Accrued taxes	10.9			(15.9		)
Amounts refundable to customers	15.7			10.0
Other current liabilities	(1.8		)	(21.0		)
Other, net	106.6			7.9
Net cash provided by operating activities	369.9			209.8

Investing Activities
Capital expenditures	(141.9		)	(105.5		)
Proceeds from the sale of assets	0.5			12.9
Payment for assets received from WBS	(48.9		)	—
Other, net	1.7			0.4
Net cash used in investing activities	(188.6		)	(92.2		)

Financing Activities
Change in short-term debt	(150.9		)	(124.0		)
Repayment of subsidiary note to parent	—			(12.8		)
Equity contribution from parent	28.0			75.0
Payment of dividends to parent	(60.0		)	(60.0		)
Payment of preferred stock dividends	(0.3		)	(0.3		)
Net cash used in financing activities	(183.2		)	(122.1		)

Net change in cash and cash equivalents	(1.9		)	(4.5		)
Cash and cash equivalents at beginning of period	12.3			15.4
Cash and cash equivalents at end of period	$	10.4		$	10.9

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



03/31/2018 Form 10-Q	5	Wisconsin Electric Power Company

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

March 31, 2018

NOTE 1— GENERAL INFORMATION

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary, Bostco.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017 . Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31 , 2018 , are not necessarily indicative of expected results for 2018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2— DISPOSITION

Other Segment – Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

NOTE 3— OPERATING REVENUES

Adoption of ASU 2014-09, Revenues from Contracts with Customers

On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, revenues are recognized when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services.

We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods.

We adopted the following practical expedients and optional exemptions for the implementation of this standard:


•	We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.


•	When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.


•	We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.


•	We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.


•	We elected to apply this standard only to contracts that are not completed as of the date of initial application.



03/31/2018 Form 10-Q	6	Wisconsin Electric Power Company

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Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. There are no revenues associated with our other segment. Comparable amounts have not been presented for the three months ended March 31, 2017, due to our adoption of this standard under the modified retrospective method.



(in millions)	Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2018
Electric utility	$	779.6
Natural gas utility	160.8
Total revenues from contracts with customers	940.4
Other operating revenues	1.1
Total operating revenues	$	941.5

Revenues from Contracts with Customers

Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class for the current period:



(in millions)	Electric Utility Operating Revenues
Three Months Ended March 31, 2018
Residential	$	281.4
Small commercial and industrial	237.7
Large commercial and industrial	148.9
Other	5.4
Total retail revenues	673.4
Wholesale	28.5
Resale	63.7
Steam	9.7
Other utility revenues	4.3
Total electric utility operating revenues	$	779.6

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled and consists of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally



03/31/2018 Form 10-Q	7	Wisconsin Electric Power Company

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recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class for the current period:



(in millions)	Natural Gas Utility Operations
Three Months Ended March 31, 2018
Residential	$	114.7
Commercial and industrial	55.6
Total retail revenues	170.3
Transport	4.4
Other utility revenues *	(13.9		)
Total natural gas utility operating revenues	$	160.8


*	Includes amounts (refunded to) collected from customers for purchased gas adjustment costs.

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. Certain of our customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days .



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Other Operating Revenues

Other operating revenues consist primarily of the following:



(in millions)	Three Months Ended March 31, 2018
Late payment charges	$	2.8
Leases	0.8
Alternative revenues *	(2.5		)
Total other operating revenues	$	1.1


*	Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

NOTE 4— PROPERTY, PLANT, AND EQUIPMENT

Utility Segment Plant to be Retired

We have evaluated future plans for our older and less efficient fossil fuel generating units and have announced the retirement of the plants identified below. The net book value of these plants was classified as plant to be retired within property, plant, and equipment on our balance sheet at March 31, 2018 . In addition, severance expense in the amount of $25.8 million was recorded within the utility segment in 2017 related to these announced plant retirements.

Pleasant Prairie Power Plant

As a result of a MISO ruling in December 2017, the Pleasant Prairie power plant was retired effective April 10, 2018. Retirement of the Pleasant Prairie power plant was considered probable at March 31, 2018 . The net book value of this generating unit was $674.1 million at March 31, 2018 , and was classified as plant to be retired within property, plant, and equipment on our balance sheet. This unit is included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 15, Commitments and Contingencies, for more information regarding the new natural gas-fired generation.

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. These new units are expected to begin commercial operation by mid-2019. Upon receiving the MPSC's approval, retirement of the PIPP generating units became probable. As a result of a MISO ruling received in April 2018, the PIPP units must be retired no later than May 31, 2019. The net book value of these units was $188.7 million at March 31, 2018 , and was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 15, Commitments and Contingencies, for more information .



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NOTE 5— COMMON EQUITY

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 8, Common Equity, in our 2017 Annual Report on Form 10-K for additional information on these and other restrictions.

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

NOTE 6—

SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:



(in millions, except percentages)	March 31, 2018			December 31, 2017
Commercial paper
Amount outstanding	$	60.0		$	210.9
Weighted-average interest rate on amounts outstanding	2.05		%	1.81		%

Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2018 , was $96.2 million with a weighted-average interest rate during the period of 1.86% .

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:



(in millions)	Maturity	March 31, 2018
Revolving credit facility	October 2022	$	500.0

Less:
Letters of credit issued inside credit facility		$	1.2
Commercial paper outstanding		60.0
Available capacity under existing agreement		$	438.8

NOTE 7— MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:



(in millions)	March 31, 2018		December 31, 2017
Materials and supplies	$	136.2	$	140.7
Fossil fuel	73.9		74.8
Natural gas in storage	4.6		35.2
Total	$	214.7	$	250.7

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



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NOTE 8— INCOME TAXES

The provision for income taxes for the quarter ended March 31, 2018, differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:



	Amount			Effective Tax Rate
Statutory federal income tax	$	21.5		21.0	%
State income taxes net of federal tax benefit	6.7			6.5	%
Federal tax reform	(5.4		)	(5.2	)%
Tax repairs	(25.5		)	(24.9	)%
Other	(0.9		)	(0.9	)%
Total income tax benefit	$	(3.6	)	(3.5	)%

The effective tax rate of (3.5)% for the first quarter of 2018 differs from the United States statutory federal income tax rate of 21% primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required us to remeasure our deferred income taxes and begin to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see Federal tax reform line above). See Note 17, Regulatory Environment, for more information on the Tax Legislation and the Wisconsin rate settlement.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and subject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting.

NOTE 9— 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 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



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inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs.

We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.

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:



	March 31, 2018
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.4	$	—	$	—	$	0.4
Petroleum products contracts	0.5		—		—		0.5
FTRs	—		—		0.8		0.8
Coal contracts	—		0.7		—		0.7
Total derivative assets	$	0.9	$	0.7	$	0.8	$	2.4

Derivative liabilities
Natural gas contracts	$	0.5	$	0.1	$	—	$	0.6



	December 31, 2017
(in millions)	Level 1		Level 2		Level 3		Total
Derivative assets
Natural gas contracts	$	0.5	$	0.1	$	—	$	0.6
Petroleum products contracts	0.9		—		—		0.9
FTRs	—		—		2.4		2.4
Coal contracts	—		0.7		—		0.7
Total derivative assets	$	1.4	$	0.8	$	2.4	$	4.6

Derivative liabilities
Natural gas contracts	$	2.0	$	0.1	$	—	$	2.1
Coal contracts	—		0.3		—		0.3
Total derivative liabilities	$	2.0	$	0.4	$	—	$	2.4

The derivative assets and liabilities listed in the tables above include options, 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.

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



	Three Months Ended March 31
(in millions)	2018			2017
Balance at the beginning of the period	$	2.4		$	3.1
Settlements	(1.6		)	(2.0		)
Balance at the end of the period	$	0.8		$	1.1

Fair Value of Financial Instruments

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



	March 31, 2018				December 31, 2017
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred stock	$	30.4	$	29.1	$	30.4	$	30.5
Long-term debt, including current portion	2,662.8		2,903.7		2,662.3		2,976.3

The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.



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NOTE 10— DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW.

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, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

The following table shows our derivative assets and derivative liabilities:



	March 31, 2018				December 31, 2017
(in millions)	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Other current
Natural gas contracts	$	0.4	$	0.3	$	0.6	$	1.9
Petroleum products contracts	0.5		—		0.9		—
FTRs	0.8		—		2.4		—
Coal contracts	0.7		—		0.6		0.1
Total other current *	$	2.4	$	0.3	$	4.5	$	2.0

Other long-term
Natural gas contracts	$	—	$	0.3	$	—	$	0.2
Coal contracts	—		—		0.1		0.2
Total other long-term *	—		0.3		0.1		0.4
Total	$	2.4	$	0.6	$	4.6	$	2.4


*	On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

Realized gains (losses) on derivative instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:



	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
(in millions)	Volumes	Gains (Losses)			Volumes	Gains (Losses)
Natural gas contracts	11.7 Dth	$	(1.8	)	8.2 Dth	$	0.5
Petroleum products contracts	1.4 gallons	0.4			4.9 gallons	(0.5		)
FTRs	5.8 MWh	0.8			7.0 MWh	2.5
Total		$	(0.6	)		$	2.5

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At March 31, 2018 and December 31, 2017 , we had posted cash collateral of $3.8 million and $4.9 million , respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets.

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



	March 31, 2018								December 31, 2017
(in millions)	Derivative Assets			Derivative Liabilities					Derivative Assets			Derivative Liabilities
Gross amount recognized on the balance sheet	$	2.4		$	0.6				$	4.6		$	2.4
Gross amount not offset on the balance sheet	(0.4		)	(0.5		)	⁽¹	⁾	(1.3		)	(2.0		)	⁽²	⁾
Net amount	$	2.0		$	0.1				$	3.3		$	0.4



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⁽¹⁾ Includes cash collateral posted of $0.1 million .

⁽²⁾ Includes cash collateral posted of $0.7 million .

NOTE 11— EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:



	Pension Costs
	Three Months Ended March 31
(in millions)	2018			2017
Service cost	$	3.3		$	3.0
Interest cost	10.6			11.9
Expected return on plan assets	(19.0		)	(19.2		)
Amortization of prior service cost	0.2			0.3
Amortization of net actuarial loss	9.4			8.8
Net periodic benefit cost	$	4.5		$	4.8



	OPEB Costs
	Three Months Ended March 31
(in millions)	2018			2017
Service cost	$	1.8		$	1.9
Interest cost	2.8			3.1
Expected return on plan assets	(3.9		)	(3.6		)
Amortization of prior service credit	(0.6		)	(0.3		)
Amortization of net actuarial loss	—			0.3
Net periodic benefit cost	$	0.1		$	1.4

During the three months ended March 31, 2018 , we made contributions and payments of $1.5 million related to our pension plans and $0.6 million related to our OPEB plans. We expect to make contributions and payments of $2.4 million related to our pension plans and $4.3 million related to our OPEB plans during the remainder of 2018 , dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for the quarters ended March 31, 2018 and 2017, we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service cost components in other income, net. For the quarter ended March 31, 2018, the non-service cost components of net benefit cost were in a net credit position, in the amount of $(1.7) million . For the quarter ended March 31, 2017, the non-service cost components of net benefit cost were in a net debit position, in the amount of $1.2 million , and were reclassified from other operation and maintenance to other income, net, on our income statements.



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As required by ASU 2017-07, our income statements for the years ended December 31, 2017, 2016, and 2015 were retroactively restated from what was previously presented in our 2017 Annual Report on Form 10-K. The impacts to our income statements from adoption of this standard are reflected in the table below.



	Year Ended December 31, 2017							Year Ended December 31, 2016							Year Ended December 31, 2015
(in millions)	Form 10-K Income Statement		Impact of ASU 2017-07			Income Statement After Adoption		Form 10-K Income Statement		Impact of ASU 2017-07			Income Statement After Adoption		Form 10-K Income Statement		Impact of ASU 2017-07			Income Statement After Adoption
Operating expenses
Other operation and maintenance	$	1,358.5	$	(6.5	)	$	1,352.0	$	1,430.2	$	(4.7	)	$	1,425.5	$	1,384.9	$	(4.3	)	$	1,380.6

Other expense
Other income, net	19.7		(6.5		)	13.2		9.1		(4.7		)	4.4		11.2		(4.3		)	6.9

In addition, under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, will be presented as regulatory assets or liabilities rather than property, plant, and equipment.

NOTE 12— SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At March 31, 2018 , we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin, and to one customer in the Upper Peninsula of Michigan. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.

Our other segment includes Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 2, Disposition, for more information .

The following tables show summarized financial information for the three months ended March 31 , 2018 and 2017 , related to our reportable segments:



(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2018
Operating revenues	$	941.5	$	—	$	941.5
Other operation and maintenance	335.6		—		335.6
Depreciation and amortization	85.3		—		85.3
Operating income	136.4		—		136.4
Interest expense	29.7		—		29.7



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(in millions)	Utility		Other		Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2017
Operating revenues	$	972.0	$	—	$	972.0
Other operation and maintenance *	326.6		—		326.6
Depreciation and amortization	82.1		—		82.1
Operating income *	186.3		—		186.3
Interest expense	29.3		0.3		29.6


*	Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 11, Employee Benefits, for more information on this new standard.

NOTE 13— 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 transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.

Purchased Power Agreement

We have 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 four years . We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.

We have approximately $67.7 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 three months ended March 31, 2018 and 2017 were $4.7 million and $4.5 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 14— RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group.

On January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016, to another subsidiary of WEC Energy Group. In addition, we transferred $186.8 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

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 by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs.



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Our balance sheets included the following receivables and payables related to transactions entered into with ATC:



(in millions)	March 31, 2018		December 31, 2017
Accounts receivable
Services provided to ATC	$	1.3	$	0.8
Accounts payable
Services received from ATC	16.4		22.2

The following table shows activity associated with our related party transactions:



	Three Months Ended March 31
(in millions)	2018		2017
Lease agreements
Lease payments to We Power ⁽¹⁾	$	92.2	$	104.4
Construction work in progress billed to We Power	3.8		16.3
Transactions with WBS ⁽²⁾
Billings to WBS ⁽³⁾	5.9		56.5
Billings from WBS ⁽⁴⁾	108.1		49.8
Transactions with WPS ⁽²⁾
Billings to WPS	3.0		2.5
Billings from WPS	3.2		1.1
Transactions with WG
Natural gas purchases from WG	1.3		1.3
Billings to WG	13.9		15.8
Billings from WG	4.7		5.5
Transactions with UMERC
Electric sales to UMERC	8.1		7.7
Billings to UMERC ⁽²⁾	4.2		4.7
Transactions with Bluewater ⁽⁵⁾
Storage service fees	1.3		—
Transactions with ATC
Charges to ATC for services and construction	3.0		2.8
Charges from ATC for network transmission services	58.0		60.3
Refund from ATC per FERC ROE order	—		19.4


⁽¹⁾	We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2.


⁽²⁾	Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs.


⁽³⁾	Includes $0.9 million for the transfer of certain benefit-related liabilities from WBS for the three months ended March 31, 2017 . There were no benefit-related liabilities transferred from WBS for the three months ended March 31, 2018 .


⁽⁴⁾	Includes $1.4 million for the transfer of certain benefit-related liabilities to WBS for the three months ended March 31, 2018 . Also includes $48.9 million for the transfer of certain software assets from WBS for the three months ended March 31, 2018 . There were no benefit-related liabilities transferred to WBS or assets transferred from WBS for the three months ended March 31, 2017 .


⁽⁵⁾	WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.

Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets, including the related deferred income tax liabilities, transferred to UMERC from us in 2017 was $61.1 million . This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under



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common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS.

WEC Energy Group's Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, WEC Energy Group completed the acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that will provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage, which was then approved by the PSCW in November 2017. See Note 17, Regulatory Environment, for more information .

NOTE 15— COMMITMENTS AND CONTINGENCIES

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

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2018 , were $9,890.7 million .

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 sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

8-Hour Ozone National Ambient Air Quality Standards

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. In December 2017, the EPA informed Wisconsin of its intended area designations of all the counties along Wisconsin's Lake Michigan shoreline, except Brown, Kewaunee, Marinette, and Oconto Counties, as either partial or full nonattainment. Waukesha and Washington counties were also included due to the counties being in the Milwaukee combined statistical area. The EPA issued final nonattainment area designations on May 1, 2018. The final designations differ significantly from the intended nonattainment areas EPA proposed late in December 2017. The following counties were designated as partial nonattainment: Manitowoc, Sheboygan, Northern Milwaukee/Ozaukee shoreline, and Kenosha. Racine, Waukesha, and Washington counties will be designated attainment/unclassifiable. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and, to the extent that further appellate review is sought, at the Supreme Court. The



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D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.

The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39% , respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In October 2017, the EPA issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan to implement the CPP.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. WEC Energy Group's plan, which includes us, is to work with its industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO ₂ emissions by approximately 40% below 2005 levels by 2030. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO ₂ reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 1,547 MW of coal generation by 2020, including Pleasant Prairie power plant (now retired) and PIPP. See Note 4, Property, Plant, and Equipment, for more information . In addition, we are evaluating our goal, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

We are required to report our CO ₂ equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2017, we reported aggregated CO ₂ equivalent emissions of 23.5 million metric tonnes to the EPA. The level of CO ₂ and other GHG emissions varies from year to year and is 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 operations distribute and sell. For 2017, we reported aggregated CO ₂ equivalent emissions of 3.7 million metric tonnes to the EPA.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

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

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next



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several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements.

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at Valley Power Plant. Due to our plans to retire PIPP and Pleasant Prairie power plant (now retired), we do not believe that BTA determinations for EM will be necessary for these units. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the EM BTA requirements, BTA determinations to address EM reduction requirements will not be made until discharge permits are renewed for these units. Until that time, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements for these units. During 2018, we will continue to evaluate options to address the EM BTA requirements for these units.

We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ during 2018, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. Various petitions challenging the rule were consolidated and are pending in the United States Fifth Circuit Court of Appeals. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule ("Postponement Rule") to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurization wastewater requirements . This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.

After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years . Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would phase 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 would require additional zero liquid discharge or other advanced treatment capital improvements for the OCPP and ERGS. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7 and OC 8. We are beginning preliminary engineering for compliance with the rule and estimate approximately $50 million would be required to design and install these advanced treatment and bottom ash transport systems. This estimate reflects the planned retirements of certain of our generation plants as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. 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.



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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:



(in millions)	March 31, 2018		December 31, 2017
Regulatory assets	$	30.1	$	30.4
Reserves for future remediation *	18.5		18.5


*	Recorded within other long-term liabilities on our balance sheets.

Enforcement and Litigation Matters

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

NOTE 16— SUPPLEMENTAL CASH FLOW INFORMATION



	Three Months Ended March 31
(in millions)	2018			2017
Cash (paid) for interest, net of amount capitalized	$	(4.7	)	$	(4.8	)
Cash (paid) for income taxes, net	—			(52.1		)
Significant noncash transactions:
Accounts payable related to construction costs	7.3			11.0
Transfer of investment in ATC to another subsidiary of WEC Energy Group ^{(1) (2)}	—			415.4
Transfer of net assets to UMERC ⁽¹⁾	—			68.9
Accounts receivable related to the sale of Bostco real estate holdings ⁽³⁾	—			7.0


⁽¹⁾	See Note 14, Related Parties, for more information on these transactions.


⁽²⁾	The amount transferred included a $13.4 million receivable for distributions approved and recorded in December 2016.


⁽³⁾	See Note 2, Disposition, for more information on this transaction.

NOTE 17— REGULATORY ENVIRONMENT

Tax Cuts and Jobs Act of 2017

We deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,065 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes in December 2017. The current 2018 tax benefit related to the Tax Legislation, which reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018, is also being deferred for return to ratepayers.

In April 2018, the PSCW issued a preliminary determination regarding the benefits associated with the Tax Legislation. For our electric utility operations, the PSCW indicated that 80% of the current 2018 and 2019 tax benefits should be used to reduce our transmission regulatory asset, with the remaining 20% returned to our electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to our natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting for our electric operations should be used to reduce our transmission regulatory asset, while the timing and method of returning the remaining net tax benefit associated with the revaluation of deferred



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taxes was not addressed and will be determined in a future rate proceeding. Until we receive the final written order, the specific terms are subject to change.

We currently serve one retail electric customer in Michigan, and have reached a settlement with that customer. That settlement was filed with the MPSC in March 2018 and addresses all base rate impacts of the Tax Legislation.

2018 and 2019 Rates

During April 2017, we, along with WG and WPS, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which will freeze base rates through 2019 for electric and natural gas customers. Based on the PSCW order, our authorized ROE remains at 10.2% , and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We will flow through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at our December 31, 2017 levels. While we would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income.

Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

Natural Gas Storage Facilities in Michigan

In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that are providing a portion of the current storage needs for our natural gas operations. As a result of this agreement, we, along with WG and WPS, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreement and interstate natural gas transportation contracts related to the storage facilities. We also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. The PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we finalized the long-term service agreement for the natural gas storage, which was approved by the PSCW in November 2017. See Note 14, Related Parties, for more information .

NOTE 18— NEW ACCOUNTING PRONOUNCEMENTS

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.



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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2017 .

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We have combined common functions with WG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See

Note 12, Segment Information , for more information on our reportable business segments.

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. See Note 2, Disposition , for more information.

Corporate Strategy

Our goal is to continue to build and sustain long-term value for customers and shareholders by focusing on the fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety.

Reshaping Our Generation Fleet

WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO ₂ emissions by approximately 40% below 2005 levels by 2030. WEC Energy Group expects to retire approximately 1,800 MW of coal generation by 2020 across its electric utilities, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. Our 1,190 MW Pleasant Prairie power plant was retired in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. It may take several years to finalize long-term plans for the site. See

Note 4, Property, Plant, and Equipment , for information related to the Pleasant Prairie power plant retirement and the planned retirement of PIPP as part of WEC Energy Group's plan.

Reliability

We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility in the United States in 2017 and, for the seventh year in a row, as the most reliable utility in the Midwest.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.

WEC Energy Group continues to focus on integrating and improving business processes and consolidating its IT infrastructure across all of its companies. We expect these efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.



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Financial Discipline

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

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

Note 2, Disposition , for information on the sale of Bostco's remaining real estate holdings.

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, demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

One example of how we obtain feedback from our customers is through our "We Care" calls, where our employees contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance to improve customer satisfaction.

Safety

We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. WEC Energy Group's corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.

RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2018

Consolidated Earnings

Our consolidated earnings for the first quarter of 2018 were $105.8 million , compared to $101.8 million for the same quarter in 2017 . See below for additional information on the $4.0 million increase in consolidated earnings.

Non-GAAP Financial Measures

The discussion below addresses the operating income contribution of our utility segment and includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the first quarter of 2018 and 2017 was $136.4 million and $186.3 million , respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.



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Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the first quarter of 2018 with the same quarter of 2017 , including favorable or better, "B", and unfavorable or worse, "W", variances.



	Three Months Ended March 31
(in millions)	2018		2017		B (W)
Electric revenues	$	780.3	$	821.8	$	(41.5	)
Fuel and purchased power	252.1		252.7		0.6
Total electric margins	528.2		569.1		(40.9		)

Natural gas revenues	161.2		150.2		11.0
Cost of natural gas sold	104.9		95.9		(9.0		)
Total natural gas margins	56.3		54.3		2.0

Total electric and natural gas margins	584.5		623.4		(38.9		)

Other operation and maintenance	335.6		326.6		(9.0		)
Depreciation and amortization	85.3		82.1		(3.2		)
Property and revenue taxes	27.2		28.4		1.2
Operating income	$	136.4	$	186.3	$	(49.9	)

The following table shows a breakdown of other operation and maintenance:



	Three Months Ended March 31
(in millions)	2018		2017		B (W)
Operation and maintenance not included in line items below	$	102.0	$	107.6	$	5.6
We Power ⁽¹⁾	127.2		127.6		0.4
Transmission ⁽²⁾	66.1		67.0		0.9
Transmission expense related to the flow through of tax repairs ⁽³⁾	14.7		—		(14.7		)
Regulatory amortizations and other pass through expenses ⁽⁴⁾	25.6		24.4		(1.2		)
Total other operation and maintenance	$	335.6	$	326.6	$	(9.0	)

⁽¹⁾

Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During the three months ended March 31, 2018 and 2017 , $110.5 million and $124.7 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by us, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

⁽²⁾

The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended March 31, 2018 and 2017 , $56.3 million and $55.0 million, respectively, of costs were billed to us by transmission providers.


⁽³⁾	Represents additional transmission expense associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at our December 31, 2017 levels. See Note 17, Regulatory Environment, for more information .


⁽⁴⁾	Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.



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



	Three Months Ended March 31
	MWh (in thousands)
Electric Sales Volumes	2018	2017	B (W)
Customer Class
Residential	1,911.9	1,825.0	86.9
Small commercial and industrial	2,181.6	2,197.6	(16.0	)
Large commercial and industrial	2,025.8	1,985.6	40.2
Other	37.6	38.6	(1.0	)
Total retail	6,156.9	6,046.8	110.1
Wholesale	425.9	447.1	(21.2	)
Resale	2,191.4	2,132.4	59.0
Total sales in MWh	8,774.2	8,626.3	147.9



	Three Months Ended March 31
	Therms (in millions)
Natural Gas Sales Volumes	2018	2017	B (W)
Customer Class
Residential	177.4	155.6	21.8
Commercial and industrial	96.1	85.8	10.3
Total retail	273.5	241.4	32.1
Transport	95.1	89.0	6.1
Total sales in therms	368.6	330.4	38.2



	Three Months Ended March 31
	Degree Days
Weather *	2018	2017	B(W)
Heating (3,255 normal)	3,225	2,849	376


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

Electric Utility Margins

Electric utility margins decreased $40.9 million during the first quarter of 2018, compared with the same quarter in 2017. The significant factors impacting the lower electric utility margins were:


•	A $25.1 million decrease in margins related to amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation signed into law in December 2017. See Note 8, Income Taxes , and Note 17, Regulatory Environment , for more information.


•	A $20.4 million decrease in margins related to a settlement agreement with the PSCW to flow through the tax benefit of our repair-related deferred tax liabilities through reductions in certain regulatory assets, as discussed in the table above and in Note 17, Regulatory Environment .


•	A $1.9 million decrease in wholesale margins driven by reduced capacity rates reflecting the Tax Legislation signed into law in December 2017.

These decreases in margins were partially offset by a $9.8 million increase related to higher retail sales volumes during the first quarter of 2018, primarily driven by colder winter weather. As measured by heating degree days, the first quarter of 2018 was 13.2% colder than the same quarter in 2017.



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Natural Gas Utility Margins

Natural gas utility margins increased $2.0 million during the first quarter of 2018, compared with the same quarter in 2017. The most significant factor impacting the higher natural gas utility margins was a $5.2 million increase in sales volumes, primarily driven by colder winter weather, higher overall retail use per customer, and customer growth. This increase in margins was partially offset by $3.1 million of amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation signed into law in December 2017.

Operating Income

Operating income at the utility segment decreased $49.9 million during the first quarter of 2018, compared with the same quarter in 2017. This decrease was driven by the $38.9 million decrease in net margins discussed above and $11.0 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

The significant factors impacting the increase in operating expenses during the first quarter of 2018, compared with the same quarter in 2017, were:


•	A $14.7 million increase in transmission expenses related to the flow through of tax repairs, as discussed in the table above.


•	A $3.2 million increase in depreciation and amortization driven by an overall increase in utility plant in service and the implementation of an enterprise resource planning system in January 2018.

These increases in operating expenses were partially offset by:


•	A $4.6 million decrease in benefit costs.


•	A $3.9 million decrease in expenses at our plants, primarily related to the winding down of operations in anticipation of expected plant retirements. This resulted in lower maintenance and labor costs during the first quarter of 2018. See Note 4, Property, Plant, and Equipment, for more information on the plant retirements.

Consolidated Other (Expense) Income, Net



	Three Months Ended March 31
(in millions)	2018			2017		B (W)
Allowance for funds used during construction – Equity	$	1.0		$	0.7	$	0.3
Other	(5.2		)	2.5		(7.7		)
Other (expense) income, net	$	(4.2	)	$	3.2	$	(7.4	)

Other income, net decreased $7.4 million when compared to the first quarter of 2017, due in part to the timing of the recognition of returns related to certain regulatory assets in the first quarter of 2018.

Consolidated Interest Expense



	Three Months Ended March 31
(in millions)	2018		2017		B (W)
Interest expense	$	29.7	$	29.6	$	(0.1	)

Consolidated Income Tax (Benefit) Expense



	Three Months Ended March 31
	2018		2017		B (W)
Effective tax rate	(3.5	)%	36.1	%	39.6	%

Our effective tax rate decreased by 39.6% when compared with the first quarter of 2017 , primarily due to a 25% effective tax rate benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to the decrease in



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the effective tax rate was the impact of the Tax Legislation. See

Note 8, Income Taxes , and Note 17, Regulatory Environment , for more information.

We expect our 2018 annual effective tax rate to be between (11)% and (10)%, which includes an estimated 32% effective tax rate benefit due to the flow through of tax repairs.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the three months ended March 31 :



(in millions)	2018			2017			Change in 2018 Over 2017
Cash provided by (used in):
Operating activities	$	369.9		$	209.8		$	160.1
Investing activities	(188.6		)	(92.2		)	(96.4		)
Financing activities	(183.2		)	(122.1		)	(61.1		)

Operating Activities

Net cash provided by operating activities increased $160.1 million during the first quarter of 2018 , compared with the same period in 2017 , driven by :


•	A $155.4 million increase in cash from lower payments for operating and maintenance costs primarily due to lower payments of accounts payable to related parties for the first quarter of 2018 , compared with the same period in 2017 . In addition, our lease payments to We Power as well as payments for employee benefits and plant operating and maintenance costs also decreased.


•	A $52.1 million net increase in cash related to a decrease in cash paid for income taxes during the first quarter of 2018 , compared with the same period in 2017 . This increase in cash was primarily the result of statutory changes in the due date for certain tax payments.

These increases in net cash provided by operating activities were partially offset by a $56.8 million decrease in cash resulting from higher payments in the first quarter of 2018 for natural gas we purchased at the end of 2017 and during the first quarter of 2018 to meet the requirements of our customers during the colder winter weather.

Investing Activities

Net cash used in investing activities increased $96.4 million during the first quarter of 2018 , compared with the same period in 2017 , driven by:


•	A payment of $48.9 million to WBS during the first quarter of 2018 , related to transfers of an enterprise resource planning system and other software from WBS. There were no similar transfers in 2017 .


•	A $36.4 million increase in cash paid for capital expenditures during the first quarter of 2018 , compared with the same period in 2017 , which is discussed in more detail below.


•	A $12.4 million decrease in the proceeds received from the sale of assets during the first quarter of 2018 , compared with the same period in 2017 . See Note 2, Disposition, for more information .



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Capital Expenditures

Capital expenditures for the three months ended March 31 were as follows:



(in millions)	2018		2017		Change in 2018 Over 2017
Capital expenditures	$	141.9	$	105.5	$	36.4

The increase in cash paid for capital expenditures during the first quarter of 2018 was driven by upgrades of our natural gas and electric distribution systems, including main replacement projects, and various software projects.

See Capital Resources and Requirements – Capital Requirements – Significant Capital Projects for more information.

Financing Activities

Net cash used in financing activities increased $61.1 million during the first quarter of 2018 , compared with the same period in 2017 , primarily driven by:


•	A $47.0 million decrease in equity contributions received from our parent to balance our capital structure during the first quarter of 2018 , compared with the same period in 2017 .


•	A $26.9 million increase in net repayments of commercial paper during the first quarter of 2018 , compared with the same period in 2017 .

These increases in net cash used in financing activities were partially offset by a $12.8 million net repayment of our subsidiary's note to our parent during the first quarter of 2017.

For more information on our short-term financing activities, see Note 6, Short-Term Debt and Lines of Credit .

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, and equity contributions from our parent.

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 arrangement, access to capital markets, and internally generated cash.

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 6, Short-Term Debt and Lines of Credit, for more information on our credit facility.

As of March 31, 2018 , we were the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, we terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of March 31, 2018 , the repurchased bonds were still outstanding but are not reported in our long-term debt since they are held by us.



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Working Capital

As of March 31, 2018 , our current liabilities exceeded our current assets by $85.1 million . We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt.

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings and/or Baa3 at Moody's Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue future debt securities and certain other types of financing and could increase borrowing costs under our credit facility.

Capital Requirements

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, impacts from the Tax Legislation, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:



(in millions)
2018	$	598.5
2019	552.5
2020	807.5
Total	$	1,958.5

The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI) program. AMI is an integrated system of smart meters, communication networks and data management systems that enable two-way communication between utilities and customers.

Additionally, as part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

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 letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or



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expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see

Note 6, Short-Term Debt and Lines of Credit , and

Note 13, Variable Interest Entities .

Contractual Obligations

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 2017 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 2017 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Environmental Matters

See Note 15, Commitments and Contingencies , for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. The FERC, PSCW, and MPSC are working with us to return any tax savings from the Tax Legislation to customers. If the amounts our regulators order us to return to customers exceed the actual tax savings realized or if our regulators require the tax savings to be applied in a manner other than we had expected, it could have a material adverse effect on our financial condition, results of operations, and cash flow. See Note 17, Regulatory Environment, for more information .



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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our Annual Report on Form 10-K for the year ended December 31, 2017 . In addition to the Form 10-K disclosures, see

Note 9, Fair Value Measurements , and

Note 10, Derivative Instruments , in this report for information concerning our market risk exposures.



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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (i) in recording, processing, summarizing, and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the first quarter of 2018 , WEC Energy Group completed an enterprise resource planning (ERP) system integration project to bring all of its subsidiaries, including us, onto a consolidated ERP system. Accordingly, we are modifying the design and documentation of certain internal control processes and procedures related to the integrated ERP system. We do not believe that the implementation of the ERP system will have an adverse effect on our internal control over financial reporting.

With the exception of the ERP system implementation described above, there were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2017 Annual Report on Form 10-K. See Note 15, Commitments and Contingencies , and Note 17, Regulatory Environment , in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings discussed in

Note 15, Commitments and Contingencies ,

Note 17, Regulatory Environment , and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

Presque Isle Power Plant Matter

In March 2018, the EPA issued a Finding of Violation to us regarding alleged violations of mercury emission limits for PIPP Units 5, 6, 8, and 9, as well as failing to conduct low emitting electric utility steam generating units mercury testing once every 12 months. We observed atypical initial mercury test results in June 2017 and immediately began to troubleshoot the potential cause. We found that the supplier of dry sorbent injection material for the air quality control system that controls mercury had delivered material that was out of specification per our contract and permit requirements. In June 2017, we notified the MDEQ, who notified the EPA that the EPA had jurisdiction regarding this matter. We have been working with the EPA to resolve this matter and do not expect it to have a material impact on our financial statements.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2017 . See Item 1A. Risk Factors in Part I of our 2017 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.



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ITEM 6. EXHIBITS



Number	Exhibit
12	Statements re Computation of Ratios

	12.1	Ratio of Earnings to Fixed Charges

31	Rule 13a-14(a) / 15d-14(a) Certifications

	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Section 1350 Certifications

	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	Interactive Data File



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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		WISCONSIN ELECTRIC POWER COMPANY
		(Registrant)

		/s/ WILLIAM J. GUC
Date:	May 4, 2018	William J. Guc
		Vice President and Controller

		(Duly Authorized Officer and Chief Accounting Officer)



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Part I. Financial Information Item 1. Financial Statements Note 1 General Information Note 2 Disposition Note 3 Operating Revenues Note 4 Property, Plant, and Equipment Note 5 Common Equity Note 6 Short-term Debt and Lines Of Credit Note 7 Materials, Supplies, and Inventories Note 8 Income Taxes Note 9 Fair Value Measurements Note 10 Derivative Instruments Note 11 Employee Benefits Note 12 Segment Information Note 13 Variable Interest Entities Note 14 Related Parties Note 15 Commitments and Contingencies Note 16 Supplemental Cash Flow Information Note 17 Regulatory Environment Note 18 New Accounting Pronouncements Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Note 12, Segment Information Note 2, Disposition Note 4, Property, Plant, and Equipment Note 8, Income Taxes Note 17, Regulatory Environment Note 6, Short-term Debt and Lines Of Credit Note 13, Variable Interest Entities Note 15, Commitments and Contingencies Item 3. Quantitative and Qualitative Disclosures About Market Risk Note 9, Fair Value Measurements Note 10, Derivative Instruments Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 6. Exhibits

Exhibits

12.1 Ratio of Earnings to Fixed Charges 31.1 Certification Pursuant to Rule13a-14(a) or 15d-14(a), as Adopted Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification Pursuant to Rule13a-14(a) or 15d-14(a), as Adopted Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley Act of 2002.

WELPP 10-Q Quarter ended March 31, 2018

Exhibits