WISCONSIN ELECTRIC POWER CO - Quarter Report: 2017 June (Form 10-Q)
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 June 30, 2017
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
June 30, 2017
All of the common stock of Wisconsin Electric Power Company is owned by WEC Energy Group, Inc.
WISCONSIN ELECTRIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2017
TABLE OF CONTENTS
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06/30/2017 Form 10-Q | i | Wisconsin Electric Power Company |
GLOSSARY OF TERMS AND ABBREVIATIONS
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Subsidiaries and Affiliates | ||
ATC | American Transmission Company LLC | |
Bluewater | Bluewater Natural Gas Holding, LLC | |
Bostco | Bostco LLC | |
Integrys | Integrys Holding, Inc. | |
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 | ||
AFUDC | Allowance for Funds Used During Construction | |
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 | ||
CO2 | Carbon Dioxide | |
CSAPR | Cross-State Air Pollution Rule | |
GHG | Greenhouse Gas | |
NAAQS | National Ambient Air Quality Standards | |
NOx | Nitrogen Oxide | |
SO2 | Sulfur Dioxide | |
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 | |
MCPP | Milwaukee County Power Plant | |
MISO | Midcontinent Independent System Operator, Inc. | |
06/30/2017 Form 10-Q | ii | Wisconsin Electric Power Company |
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 | |
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 | |
VAPP | Valley Power Plant | |
06/30/2017 Form 10-Q | iii | Wisconsin Electric Power Company |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the 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, 2016, and those identified below:
• | Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints; |
• | Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers; |
• | The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations; |
• | The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation; |
• | The timely completion of capital projects within budgets, as well as the recovery of the related costs through rates; |
• | The impact of federal, state, and local legislative and regulatory changes, including changes in rate-setting policies or procedures, tax law changes, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, and energy efficiency mandates; |
• | Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs; |
• | The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments; |
• | Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry 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; |
06/30/2017 Form 10-Q | 1 | Wisconsin Electric Power Company |
• | Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters; |
• | The direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber security intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns; |
• | The investment performance of WEC Energy Group's employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements; |
• | Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees; |
• | Advances in technology that result in competitive disadvantages and create the potential for impairment of existing assets; |
• | The timing, costs, and anticipated benefits associated with the remaining integration efforts relating to Wisconsin Energy Corporation's acquisition of Integrys; |
• | The timing and outcome of any audits, disputes, and other proceedings related to taxes; |
• | The effect of accounting pronouncements issued periodically by standard-setting bodies; and |
• | Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents. |
We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
06/30/2017 Form 10-Q | 2 | Wisconsin Electric Power Company |
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
WISCONSIN ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) | Three Months Ended | Six Months Ended | ||||||||||||||
June 30 | June 30 | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Operating revenues | $ | 855.4 | $ | 877.2 | $ | 1,827.4 | $ | 1,852.7 | ||||||||
Operating expenses | ||||||||||||||||
Cost of sales | 273.9 | 284.3 | 622.5 | 620.7 | ||||||||||||
Other operation and maintenance | 327.7 | 336.2 | 655.5 | 684.4 | ||||||||||||
Depreciation and amortization | 82.7 | 80.8 | 164.8 | 161.2 | ||||||||||||
Property and revenue taxes | 28.3 | 29.0 | 56.7 | 58.0 | ||||||||||||
Total operating expenses | 712.6 | 730.3 | 1,499.5 | 1,524.3 | ||||||||||||
Operating income | 142.8 | 146.9 | 327.9 | 328.4 | ||||||||||||
Equity in earnings of transmission affiliate | — | 11.4 | — | 26.1 | ||||||||||||
Other income, net | 4.4 | 3.2 | 8.8 | 6.2 | ||||||||||||
Interest expense | 29.1 | 29.4 | 58.7 | 58.5 | ||||||||||||
Other expense | (24.7 | ) | (14.8 | ) | (49.9 | ) | (26.2 | ) | ||||||||
Income before income taxes | 118.1 | 132.1 | 278.0 | 302.2 | ||||||||||||
Income tax expense | 42.5 | 49.2 | 100.3 | 111.7 | ||||||||||||
Net income | 75.6 | 82.9 | 177.7 | 190.5 | ||||||||||||
Preferred stock dividend requirements | 0.3 | 0.3 | 0.6 | 0.6 | ||||||||||||
Net income attributed to common shareholder | $ | 75.3 | $ | 82.6 | $ | 177.1 | $ | 189.9 | ||||||||
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.
06/30/2017 Form 10-Q | 3 | Wisconsin Electric Power Company |
WISCONSIN ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts) | June 30, 2017 | December 31, 2016 | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 1.6 | $ | 15.4 | ||||
Accounts receivable and unbilled revenues, net of reserves of $39.2 and $40.9, respectively | 452.4 | 503.2 | ||||||
Accounts and notes receivable from related parties | 82.1 | 58.2 | ||||||
Materials, supplies, and inventories | 278.2 | 271.0 | ||||||
Prepayments | 125.5 | 138.0 | ||||||
Other | 9.7 | 24.6 | ||||||
Current assets | 949.5 | 1,010.4 | ||||||
Long-term assets | ||||||||
Property, plant, and equipment, net of accumulated depreciation of $3,651.8 and $3,619.6 respectively | 9,859.0 | 9,832.3 | ||||||
Regulatory assets | 2,114.4 | 2,036.6 | ||||||
Equity investment in transmission affiliate | — | 402.0 | ||||||
Other | 83.6 | 90.2 | ||||||
Long-term assets | 12,057.0 | 12,361.1 | ||||||
Total assets | $ | 13,006.5 | $ | 13,371.5 | ||||
Liabilities and Equity | ||||||||
Current liabilities | ||||||||
Short-term debt | $ | 75.0 | $ | 159.0 | ||||
Current portion of long-term debt | 250.0 | — | ||||||
Current portion of capital lease obligations | 32.2 | 28.5 | ||||||
Subsidiary note payable to WEC Energy Group | — | 18.5 | ||||||
Accounts payable | 282.0 | 297.9 | ||||||
Accounts payable to related parties | 124.7 | 112.9 | ||||||
Accrued payroll and benefits | 47.2 | 51.8 | ||||||
Accrued taxes | 21.6 | 46.0 | ||||||
Other | 81.9 | 100.1 | ||||||
Current liabilities | 914.6 | 814.7 | ||||||
Long-term liabilities | ||||||||
Long-term debt | 2,411.2 | 2,661.1 | ||||||
Capital lease obligations | 2,839.9 | 2,756.5 | ||||||
Deferred income taxes | 2,170.2 | 2,333.3 | ||||||
Regulatory liabilities | 861.6 | 853.9 | ||||||
Pension and OPEB obligations | 157.4 | 167.6 | ||||||
Other | 263.3 | 260.2 | ||||||
Long-term liabilities | 8,703.6 | 9,032.6 | ||||||
Commitments and contingencies (Note 13) | ||||||||
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 | 815.2 | 1,020.1 | ||||||
Retained earnings | 2,209.8 | 2,140.8 | ||||||
Common shareholder's equity | 3,357.9 | 3,493.8 | ||||||
Preferred stock | 30.4 | 30.4 | ||||||
Total liabilities and equity | $ | 13,006.5 | $ | 13,371.5 | ||||
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.
06/30/2017 Form 10-Q | 4 | Wisconsin Electric Power Company |
WISCONSIN ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) | Six Months Ended | |||||||
June 30 | ||||||||
(in millions) | 2017 | 2016 | ||||||
Operating Activities | ||||||||
Net income | $ | 177.7 | $ | 190.5 | ||||
Reconciliation to cash provided by operating activities | ||||||||
Depreciation and amortization | 164.8 | 165.1 | ||||||
Deferred income taxes and investment tax credits, net | 64.1 | 113.4 | ||||||
Contributions and payments related to pension and OPEB plans | (5.6 | ) | (4.6 | ) | ||||
Equity income in transmission affiliate, net of distributions | — | (8.1 | ) | |||||
Proceeds from (payments for) liabilities transferred from (to) WBS | 0.9 | (107.0 | ) | |||||
Change in – | ||||||||
Accounts receivable and unbilled revenues | 26.7 | (8.1 | ) | |||||
Materials, supplies, and inventories | (7.2 | ) | 38.6 | |||||
Other current assets | 10.1 | 24.7 | ||||||
Accounts payable | (8.1 | ) | (3.9 | ) | ||||
Accrued taxes | (24.4 | ) | (13.8 | ) | ||||
Other current liabilities | (24.2 | ) | (10.4 | ) | ||||
Other, net | (14.9 | ) | (40.3 | ) | ||||
Net cash provided by operating activities | 359.9 | 336.1 | ||||||
Investing Activities | ||||||||
Capital expenditures | (246.9 | ) | (191.9 | ) | ||||
Capital contributions to transmission affiliate | — | (4.6 | ) | |||||
Proceeds from the sale of assets | 22.0 | 31.7 | ||||||
Proceeds from assets transferred to WBS | — | 13.1 | ||||||
Short-term notes receivable from related parties, net | (3.1 | ) | — | |||||
Other, net | 2.3 | 1.0 | ||||||
Net cash used in investing activities | (225.7 | ) | (150.7 | ) | ||||
Financing Activities | ||||||||
Change in short-term debt | (84.0 | ) | 2.5 | |||||
Repayment of subsidiary note to parent | (18.5 | ) | (2.5 | ) | ||||
Equity contribution from parent | 75.0 | — | ||||||
Payments of dividends to parent | (120.0 | ) | (220.0 | ) | ||||
Payments of preferred stock dividends | (0.6 | ) | (0.6 | ) | ||||
Other, net | 0.1 | 16.6 | ||||||
Net cash used in financing activities | (148.0 | ) | (204.0 | ) | ||||
Net change in cash and cash equivalents | (13.8 | ) | (18.6 | ) | ||||
Cash and cash equivalents at beginning of period | 15.4 | 27.1 | ||||||
Cash and cash equivalents at end of period | $ | 1.6 | $ | 8.5 | ||||
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.
06/30/2017 Form 10-Q | 5 | Wisconsin Electric Power Company |
WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
June 30, 2017
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.
Prior to January 1, 2017, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information on the transfer.
In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. UMERC holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan. The existing contract between the Tilden Mining Company and us will remain in place until a new power generation solution for the region is commercially operational. See Note 12, Related Parties, and Note 15, Regulatory Environment, for more information on UMERC.
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, 2016. 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 and six months ended June 30, 2017, are not necessarily indicative of expected results for 2017 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—DISPOSITIONS
Utility Segment
Sale of Milwaukee County Power Plant
In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ($6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
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.
06/30/2017 Form 10-Q | 6 | Wisconsin Electric Power Company |
NOTE 3—COMMON EQUITY
Stock-Based Compensation
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the six months ended June 30, 2017:
(in millions) | Retained Earnings | |||
Balance at December 31, 2016 | $ | 2,140.8 | ||
Net income | 177.7 | |||
Common stock dividends | (120.0 | ) | ||
Preferred stock dividends | (0.6 | ) | ||
Cumulative effect of adoption of ASU 2016-09 | 11.9 | |||
Balance at June 30, 2017 | $ | 2,209.8 | ||
ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating expected forfeitures and recording them over the vesting period.
As we did not record any excess tax benefits in 2017, adoption of this ASU had no impact on our financial statements other than the cumulative-effect adjustment discussed above.
Restrictions
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 9, Common Equity, in our 2016 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 4—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) | June 30, 2017 | December 31, 2016 | ||||||
Commercial paper | ||||||||
Amount outstanding | $ | 75.0 | $ | 159.0 | ||||
Weighted-average interest rate on amounts outstanding | 1.33 | % | 0.87 | % | ||||
Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2017, was $36.4 million with a weighted-average interest rate during the period of 0.97%.
In April 2017, our consolidated subsidiary, Bostco, paid off a note payable to our parent, WEC Energy Group.
06/30/2017 Form 10-Q | 7 | Wisconsin Electric Power Company |
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 | June 30, 2017 | ||||
Revolving credit facility | December 2020 | $ | 500.0 | |||
Less: | ||||||
Letters of credit issued inside credit facility | $ | 26.2 | ||||
Commercial paper outstanding | 75.0 | |||||
Available capacity under existing agreement | $ | 398.8 | ||||
NOTE 5—MATERIALS, SUPPLIES, AND INVENTORIES
Our inventory consisted of:
(in millions) | June 30, 2017 | December 31, 2016 | ||||||
Materials and supplies | $ | 153.2 | $ | 148.1 | ||||
Fossil fuel | 100.1 | 91.1 | ||||||
Natural gas in storage | 24.9 | 31.8 | ||||||
Total | $ | 278.2 | $ | 271.0 | ||||
Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
NOTE 6—FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).
Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs.
We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.
06/30/2017 Form 10-Q | 8 | Wisconsin Electric Power Company |
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:
June 30, 2017 | |||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Derivative assets | |||||||||||||||||
Natural gas contracts | $ | 0.3 | $ | 0.2 | $ | — | $ | 0.5 | |||||||||
Petroleum products contracts | 0.2 | — | — | 0.2 | |||||||||||||
FTRs | — | — | 6.0 | 6.0 | |||||||||||||
Coal contracts | — | 0.7 | — | 0.7 | |||||||||||||
Total derivative assets | $ | 0.5 | $ | 0.9 | $ | 6.0 | $ | 7.4 | |||||||||
Derivative liabilities | |||||||||||||||||
Natural gas contracts | $ | 0.7 | $ | — | $ | — | $ | 0.7 | |||||||||
Petroleum products contracts | 0.1 | — | — | 0.1 | |||||||||||||
Coal contracts | — | 2.3 | — | — | 2.3 | ||||||||||||
Total derivative liabilities | $ | 0.8 | $ | 2.3 | $ | — | $ | 3.1 | |||||||||
December 31, 2016 | ||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Derivative assets | ||||||||||||||||
Natural gas contracts | $ | 6.0 | $ | 0.8 | $ | — | $ | 6.8 | ||||||||
Petroleum products contracts | 0.2 | — | — | 0.2 | ||||||||||||
FTRs | — | — | 3.1 | 3.1 | ||||||||||||
Coal contracts | — | 1.9 | — | 1.9 | ||||||||||||
Total derivative assets | $ | 6.2 | $ | 2.7 | $ | 3.1 | $ | 12.0 | ||||||||
Derivative liabilities | ||||||||||||||||
Natural gas contracts | $ | 0.1 | $ | — | $ | — | $ | 0.1 | ||||||||
Petroleum products contracts | 0.1 | — | — | 0.1 | ||||||||||||
Coal contracts | — | 0.5 | — | 0.5 | ||||||||||||
Total derivative liabilities | $ | 0.2 | $ | 0.5 | $ | — | $ | 0.7 | ||||||||
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 June 30 | Six Months Ended June 30 | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Balance at the beginning of the period | $ | 1.1 | $ | 0.6 | $ | 3.1 | $ | 1.6 | ||||||||
Purchases | 6.9 | 8.1 | 6.9 | 8.1 | ||||||||||||
Settlements | (2.0 | ) | (1.2 | ) | (4.0 | ) | (2.2 | ) | ||||||||
Balance at the end of the period | $ | 6.0 | $ | 7.5 | $ | 6.0 | $ | 7.5 | ||||||||
06/30/2017 Form 10-Q | 9 | Wisconsin Electric Power Company |
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
June 30, 2017 | December 31, 2016 | |||||||||||||||
(in millions) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Preferred stock | $ | 30.4 | $ | 30.5 | $ | 30.4 | $ | 28.8 | ||||||||
Long-term debt, including current portion | 2,661.2 | 2,939.2 | 2,661.1 | 2,923.4 | ||||||||||||
Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, short-term notes receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based on the quoted market prices for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
NOTE 7—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:
June 30, 2017 | December 31, 2016 | |||||||||||||||
(in millions) | Derivative Assets | Derivative Liabilities | Derivative Assets | Derivative Liabilities | ||||||||||||
Other current | ||||||||||||||||
Natural gas contracts | $ | 0.5 | $ | 0.6 | $ | 6.3 | $ | 0.1 | ||||||||
Petroleum products contracts | 0.2 | 0.1 | 0.2 | 0.1 | ||||||||||||
FTRs | 6.0 | — | 3.1 | — | ||||||||||||
Coal contracts | 0.7 | 1.5 | 1.5 | 0.5 | ||||||||||||
Total other current * | $ | 7.4 | $ | 2.2 | $ | 11.1 | $ | 0.7 | ||||||||
Other long-term | ||||||||||||||||
Natural gas contracts | $ | — | $ | 0.1 | $ | 0.5 | $ | — | ||||||||
Coal contracts | — | 0.8 | 0.4 | — | ||||||||||||
Total other long-term * | — | 0.9 | 0.9 | — | ||||||||||||
Total | $ | 7.4 | $ | 3.1 | $ | 12.0 | $ | 0.7 | ||||||||
* | 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. |
06/30/2017 Form 10-Q | 10 | Wisconsin Electric Power Company |
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 June 30, 2017 | Three Months Ended June 30, 2016 | |||||||||||
(in millions) | Volumes | Gains (Losses) | Volumes | Gains (Losses) | ||||||||
Natural gas contracts | 5.0 Dth | $ | 0.2 | 9.6 Dth | $ | (4.8 | ) | |||||
Petroleum products contracts | 4.9 gallons | (0.4 | ) | 2.6 gallons | (0.8 | ) | ||||||
FTRs | 7.3 MWh | 2.0 | 5.7 MWh | 0.5 | ||||||||
Total | $ | 1.8 | $ | (5.1 | ) | |||||||
Six Months Ended June 30, 2017 | Six Months Ended June 30, 2016 | |||||||||||
(in millions) | Volumes | Gains (Losses) | Volumes | Gains (Losses) | ||||||||
Natural gas contracts | 13.2 Dth | $ | 0.7 | 20.2 Dth | $ | (12.0 | ) | |||||
Petroleum products contracts | 9.8 gallons | (0.9 | ) | 4.2 gallons | (1.5 | ) | ||||||
FTRs | 14.3 MWh | 4.5 | 10.9 MWh | 2.3 | ||||||||
Total | $ | 4.3 | $ | (11.2 | ) | |||||||
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 June 30, 2017, we had posted cash collateral of $2.3 million in our margin accounts, and at December 31, 2016, we had received cash collateral of $3.4 million in our margin accounts. On our balance sheets, cash collateral provided to others is reflected in other current assets and cash collateral received is reflected in other current liabilities.
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
June 30, 2017 | December 31, 2016 | |||||||||||||||
(in millions) | Derivative Assets | Derivative Liabilities | Derivative Assets | Derivative Liabilities | ||||||||||||
Gross amount recognized on the balance sheet | $ | 7.4 | $ | 3.1 | $ | 12.0 | $ | 0.7 | ||||||||
Gross amount not offset on the balance sheet | (0.5 | ) | (0.7 | ) | (1) | (3.6 | ) | (2) | (0.2 | ) | ||||||
Net amount | $ | 6.9 | $ | 2.4 | $ | 8.4 | $ | 0.5 | ||||||||
(1) | Includes cash collateral posted of $0.2 million. |
(2) | Includes cash collateral received of $3.4 million. |
NOTE 8—EMPLOYEE BENEFITS
The following tables show the components of net periodic pension and OPEB costs for our benefit plans:
Pension Costs | ||||||||||||||||
Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Service cost | $ | 3.1 | $ | 2.5 | $ | 6.1 | $ | 5.2 | ||||||||
Interest cost | 11.6 | 12.3 | 23.5 | 24.9 | ||||||||||||
Expected return on plan assets | (19.1 | ) | (19.4 | ) | (38.3 | ) | (38.8 | ) | ||||||||
Loss on plan settlement | 2.8 | — | 2.8 | — | ||||||||||||
Amortization of prior service cost | 0.3 | 0.4 | 0.6 | 0.8 | ||||||||||||
Amortization of net actuarial loss | 8.9 | 8.2 | 17.7 | 16.2 | ||||||||||||
Net periodic benefit cost | $ | 7.6 | $ | 4.0 | $ | 12.4 | $ | 8.3 | ||||||||
06/30/2017 Form 10-Q | 11 | Wisconsin Electric Power Company |
OPEB Costs | ||||||||||||||||
Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Service cost | $ | 1.5 | $ | 3.5 | $ | 3.4 | $ | 3.6 | ||||||||
Interest cost | 3.1 | 4.7 | 6.2 | 6.6 | ||||||||||||
Expected return on plan assets | (3.6 | ) | (5.8 | ) | (7.2 | ) | (7.0 | ) | ||||||||
Amortization of prior service credit | (0.3 | ) | (0.2 | ) | (0.6 | ) | (0.5 | ) | ||||||||
Amortization of net actuarial (gain) loss | (0.3 | ) | 0.3 | — | 0.5 | |||||||||||
Net periodic benefit cost | $ | 0.4 | $ | 2.5 | $ | 1.8 | $ | 3.2 | ||||||||
During the six months ended June 30, 2017, we made payments of $4.3 million related to our pension plans and $1.3 million to our OPEB plans. We expect to make payments of $0.9 million related to our pension plans and $3.2 million related to our OPEB plans during the remainder of 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.
NOTE 9—INVESTMENT IN AMERICAN TRANSMISSION COMPANY
At December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. On January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in the recognition of a gain or loss. The following table shows changes to our investment in ATC:
Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Balance at beginning of period | $ | — | $ | 394.3 | $ | 402.0 | $ | 382.2 | ||||||||
Less: Transfer of ownership interest | — | — | 402.0 | — | ||||||||||||
Add: Earnings from equity method investment | — | 11.4 | — | 26.1 | ||||||||||||
Add: Capital contributions | — | 1.1 | — | 4.6 | ||||||||||||
Less: Distributions | — | 12.0 | — | 18.0 | ||||||||||||
Less: Other | — | — | — | 0.1 | ||||||||||||
Balance at end of period | $ | — | $ | 394.8 | $ | — | $ | 394.8 | ||||||||
See Note 12, Related Parties, for more information on transactions with ATC.
NOTE 10—SEGMENT INFORMATION
We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2017, 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 in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, northern Wisconsin, and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 12, Related Parties, and Note 15, Regulatory Environment, for additional information. 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 developed and invested in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 2, Dispositions, for more information. Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 9, Investment in American Transmission Company, for more information.
06/30/2017 Form 10-Q | 12 | Wisconsin Electric Power Company |
The following tables show summarized financial information related to our reportable segments for the three and six months ended June 30, 2017 and 2016:
(in millions) | Utility | Other | Wisconsin Electric Power Company Consolidated | |||||||||
Three Months Ended June 30, 2017 | ||||||||||||
Operating revenues | $ | 855.4 | $ | — | $ | 855.4 | ||||||
Other operation and maintenance | 327.7 | — | 327.7 | |||||||||
Depreciation and amortization | 82.7 | — | 82.7 | |||||||||
Operating income | 142.8 | — | 142.8 | |||||||||
Interest expense | 29.1 | — | 29.1 | |||||||||
(in millions) | Utility | Other | Wisconsin Electric Power Company Consolidated | |||||||||
Three Months Ended June 30, 2016 | ||||||||||||
Operating revenues | $ | 877.2 | $ | — | $ | 877.2 | ||||||
Other operation and maintenance | 336.2 | — | 336.2 | |||||||||
Depreciation and amortization | 80.8 | — | 80.8 | |||||||||
Operating income | 146.9 | — | 146.9 | |||||||||
Equity in earnings of transmission affiliate | — | 11.4 | 11.4 | |||||||||
Interest expense | 29.1 | 0.3 | 29.4 | |||||||||
(in millions) | Utility | Other | Wisconsin Electric Power Company Consolidated | |||||||||
Six Months Ended June 30, 2017 | ||||||||||||
Operating revenues | $ | 1,827.4 | $ | — | $ | 1,827.4 | ||||||
Other operation and maintenance | 655.5 | — | 655.5 | |||||||||
Depreciation and amortization | 164.8 | — | 164.8 | |||||||||
Operating income | 327.9 | — | 327.9 | |||||||||
Interest expense | 58.4 | 0.3 | 58.7 | |||||||||
(in millions) | Utility | Other | Wisconsin Electric Power Company Consolidated | |||||||||
Six Months Ended June 30, 2016 | ||||||||||||
Operating revenues | $ | 1,852.7 | $ | — | $ | 1,852.7 | ||||||
Other operation and maintenance | 684.4 | — | 684.4 | |||||||||
Depreciation and amortization | 161.2 | — | 161.2 | |||||||||
Operating income | 328.4 | — | 328.4 | |||||||||
Equity in earnings of transmission affiliate | — | 26.1 | 26.1 | |||||||||
Interest expense | 58.0 | 0.5 | 58.5 | |||||||||
NOTE 11—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.
06/30/2017 Form 10-Q | 13 | Wisconsin Electric Power Company |
American Transmission Company
As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 9, Investment in American Transmission Company, for more information.
The significant assets and liabilities related to ATC recorded on our balance sheet at December 31, 2016 included our equity investment, distributions receivable, and accounts payable. At December 31, 2016, our equity investment was $402.0 million, which approximated our maximum exposure to loss as a result of our involvement with ATC. In addition, we had a receivable of $13.4 million recorded at December 31, 2016 for distributions from ATC. We also had $20.0 million of accounts payable due to ATC at December 31, 2016 for network transmission services.
Purchased Power Agreement
We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately five years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.
We have approximately $78.4 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 six months ended June 30, 2017 and 2016 were $9.0 million and $26.9 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.
NOTE 12—RELATED PARTIES
We and our consolidated subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its 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.
A new AIA took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. In June 2017, the PSCW approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater, which is discussed in more detail below. The proposal to incorporate Bluewater into the AIA is pending before the Minnesota Public Utilities Commission.
Bostco, our consolidated subsidiary, had a note payable to our parent company, WEC Energy Group. The balance of this note payable was $18.5 million at December 31, 2016. This note payable was paid off in the first half of 2017.
In connection with the sale of Bostco’s remaining real estate holdings, Wispark LLC, a subsidiary of WEC Energy Group, provided $7.0 million of financing to the buyer and established a corresponding note receivable. Bostco had a $7.0 million related party receivable from Wispark LLC that was paid in April 2017. See Note 2, Dispositions, for more information on the real estate sale.
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 $195.1 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.
06/30/2017 Form 10-Q | 14 | Wisconsin Electric Power Company |
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.
Our balance sheets included the following receivables and payables related to transactions entered into with ATC:
(in millions) | June 30, 2017 | December 31, 2016 | ||||||
Accounts receivable | ||||||||
Services provided to ATC | $ | 0.9 | $ | 1.1 | ||||
Accounts payable | ||||||||
Services received from ATC | 20.1 | 20.0 | ||||||
The following table shows activity associated with our related party transactions:
Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Lease agreements | ||||||||||||||||
Lease payments to We Power (1) | $ | 106.7 | $ | 110.0 | $ | 211.1 | $ | 217.4 | ||||||||
Construction work in progress billed to We Power | 8.9 | 16.4 | 25.2 | 17.7 | ||||||||||||
Transactions with WBS (2) | ||||||||||||||||
Billings to WBS (3) | 60.5 | 53.1 | 117.0 | 109.8 | ||||||||||||
Billings from WBS (4) | 52.9 | 62.2 | 102.7 | 225.6 | ||||||||||||
Transactions with WPS (2) | ||||||||||||||||
Billings to WPS | 5.2 | 1.9 | 7.7 | 2.9 | ||||||||||||
Billings from WPS | 1.1 | 0.6 | 2.2 | 1.0 | ||||||||||||
Transactions with WG | ||||||||||||||||
Natural gas purchases from WG | 1.3 | 1.3 | 2.6 | 2.7 | ||||||||||||
Services received from WG | 5.8 | 5.6 | 11.3 | 10.5 | ||||||||||||
Services provided to WG | 16.1 | 15.8 | 31.9 | 29.9 | ||||||||||||
Transactions with UMERC (5) | ||||||||||||||||
Electric sales to UMERC | 6.4 | — | 14.1 | — | ||||||||||||
Billings to UMERC (2) | 29.3 | — | 33.9 | — | ||||||||||||
Billings from UMERC (2) | 16.1 | — | 30.5 | — | ||||||||||||
Transactions with ATC | ||||||||||||||||
Charges to ATC for services and construction | 2.4 | 2.4 | 5.2 | 4.5 | ||||||||||||
Charges from ATC for network transmission services | 60.4 | 63.3 | 120.7 | 126.6 | ||||||||||||
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 six months ended June 30, 2017. There were no transfers of assets to WBS or liabilities transferred from WBS for the three months ended June 30, 2017. For the three and six months ended June 30, 2016, includes $3.2 million and $13.1 million, respectively, for the transfer of certain software assets to WBS. |
(4) | Includes $107.0 million, for the transfer of certain benefit-related liabilities to WBS for the six months ended June 30, 2016. There were no benefit-related liabilities transferred to WBS for the three and six months ended June 30, 2017, or for the three months ended June 30, 2016. |
(5) | UMERC became operational effective January 1, 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
06/30/2017 Form 10-Q | 15 | Wisconsin Electric Power Company |
assets to UMERC. The book value of net assets (including the related deferred income tax liabilities) transferred to UMERC from us was $60.0 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. The Tilden Mining Company will remain a customer of ours until UMERC's proposed generation solution for the Upper Peninsula of Michigan begins commercial operation.
UMERC obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with us and WPS.
Parent Company's Acquisition of Natural Gas Storage Facilities in Michigan
On June 30, 2017, our parent company completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that will provide for some of our current storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement with Bluewater to take the allocated storage. See Note 15, Regulatory Environment, for more information.
NOTE 13—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 June 30, 2017, were $9,926.0 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 SO2, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
Air Quality
Cross-State Air Pollution Rule
In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.
The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015, and issued the final rule in September 2016. We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.
Sulfur Dioxide National Ambient Air Quality Standards
The EPA issued a revised 1-Hour SO2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. We believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant costs to comply with this regulation.
06/30/2017 Form 10-Q | 16 | Wisconsin Electric Power Company |
8-Hour Ozone National Ambient Air Quality Standards
Sheboygan County and the eastern portion of Kenosha County are currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has updated the 2008 ozone NAAQS attainment plan for Kenosha County and submitted it to the EPA for approval. The plan concluded that Wisconsin will not need to implement any new regulatory measures or programs. The area is forecasted to meet the standard by the 2018 compliance date due to emission control measures already in place. Wisconsin has prepared a draft attainment plan for Sheboygan County, which is out for public comment and is expected to submit a final plan to the EPA for approval this summer. A final EPA action regarding Wisconsin's attainment plan is expected later in 2017.
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. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. 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 will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.
Although we are still in the process of reviewing and determining potential impacts resulting from this rule, we believe we are well positioned to meet 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 (CPP), 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 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. The EPA announced that it has initiated this review. 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 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.
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. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO2 reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing
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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.
Water Quality
Clean Water Act Cooling Water Intake Structure Rule
In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.
Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities 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 VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8.
During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived.
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 guidelines (ELG) rule took effect in January 2016. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In June 2017, the EPA issued a proposed rule to codify this stay. 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 Oak Creek site and Pleasant Prairie facilities. 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, OC 8, and the Pleasant Prairie units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55 million to $75 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not
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expecting to retire the plant. See the UMERC discussion in Note 15, Regulatory Environment, regarding the potential retirement of PIPP.
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.
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) | June 30, 2017 | December 31, 2016 | ||||||
Regulatory assets | $ | 29.7 | $ | 29.9 | ||||
Reserves for future remediation | 19.0 | 19.0 | ||||||
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 14—SUPPLEMENTAL CASH FLOW INFORMATION
Six Months Ended June 30 | ||||||||
(in millions) | 2017 | 2016 | ||||||
Cash (paid) for interest, net of amount capitalized | $ | (57.6 | ) | $ | (58.1 | ) | ||
Cash (paid) received for income taxes, net | (63.4 | ) | 0.6 | |||||
Significant noncash transactions: | ||||||||
Accounts payable related to construction costs | 13.0 | 12.4 | ||||||
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) | 415.4 | — | ||||||
Transfer of net assets to UMERC (1) | 60.0 | — | ||||||
(1) | See Note 12, Related Parties, for more information on these transactions. |
(2) | The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. |
NOTE 15—REGULATORY ENVIRONMENT
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 this proposed settlement agreement, we agreed to keep electric and natural gas base rates frozen for our customers through 2019. In addition, we agreed to extend and expand the electric real-time pricing options for large commercial and industrial customers, and we agreed to prevent the continued growth of certain escrowed costs. Deferral of the revenue requirement impacts of any federal corporate tax reform enacted in 2017, or during the rate freeze period, was included in the agreement as well. Pursuant to the settlement agreement, we
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also agreed to keep our earnings sharing mechanism, which applies only to earnings above our authorized ROE, in place through 2019.
In July 2017, the PSCW staff issued a commission memorandum in response to the settlement agreement, and we expect the PSCW to issue a final order on the agreement during the third quarter of 2017. If the PSCW rejects the proposed settlement agreement, we expect we will file a traditional rate proceeding.
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 would provide some of the current storage needs for our natural gas distribution service customers. 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 agreements 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. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. See Note 12, Related Parties, for more information.
Formation of Upper Michigan Energy Resources Corporation
In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan.
In August 2016, WEC Energy Group entered into an agreement with the Tilden Mining Company (Tilden), under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years. The agreement also calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation. We expect the MPSC to issue final orders on the Tilden agreement and the proposed generation during the fourth quarter of 2017.
NOTE 16—NEW ACCOUNTING PRONOUNCEMENTS
Revenue Recognition
In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.
We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.
We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition.
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Recognition and Measurement of Financial Instruments
In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We do not believe the adoption of this guidance will have a significant impact on our financial statements.
Leases
In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements.
Financial Instruments Credit Losses
In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.
Classification of Certain Cash Receipts and Cash Payments
In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We do not believe the adoption of this guidance will have a significant impact on our financial statements.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. 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, 2016.
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 10, Segment Information, for more information on our reportable business segments.
Effective January 1, 2017, our customers and electric distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information.
Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information.
Corporate Strategy
Our goal is to continue to create long-term value for our customers and WEC Energy Group's shareholders by focusing on the following:
Reliability
We have made significant reliability related investments in recent years, and plan to continue making significant capital investments to strengthen and modernize the reliability of our generation and distribution networks.
Operating Efficiency
We continually look for ways to optimize the operating efficiency of our company. For example, we received approval from the PSCW to make changes at ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.
WEC Energy Group continues to focus on integrating and improving business processes and IT infrastructure across all of its companies. We expect these integration efforts to continue to drive operational efficiency.
Financial Discipline
A strong adherence to financial discipline is essential to earning our authorized ROE and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.
We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Dispositions, for information on the sale of the MCPP and 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, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.
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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 in order 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.
RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, 2017
Consolidated Earnings
Our consolidated earnings for the three months ended June 30, 2017 were $75.3 million, compared to $82.6 million for the same quarter in 2016. See below for additional information on the $7.3 million decrease 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 three months ended June 30, 2017 and 2016, was $142.8 million and $146.9 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 second quarter of 2017 with the second quarter of 2016, including favorable or better, "B", and unfavorable or worse, "W", variances. Effective January 1, 2017, we transferred our electric customers located in the Upper Peninsula of Michigan to UMERC. See Note 12, Related Parties, for more information.
Three Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Electric revenues | $ | 793.6 | $ | 815.1 | $ | (21.5 | ) | |||||
Fuel and purchased power | 241.2 | 253.4 | 12.2 | |||||||||
Total electric margins | 552.4 | 561.7 | (9.3 | ) | ||||||||
Natural gas revenues | 61.8 | 62.1 | (0.3 | ) | ||||||||
Cost of natural gas sold | 32.7 | 30.9 | (1.8 | ) | ||||||||
Total natural gas margins | 29.1 | 31.2 | (2.1 | ) | ||||||||
Total electric and natural gas margins | 581.5 | 592.9 | (11.4 | ) | ||||||||
Other operation and maintenance | 327.7 | 336.2 | 8.5 | |||||||||
Depreciation and amortization | 82.7 | 80.8 | (1.9 | ) | ||||||||
Property and revenue taxes | 28.3 | 29.0 | 0.7 | |||||||||
Operating income | $ | 142.8 | $ | 146.9 | $ | (4.1 | ) | |||||
The following table shows a breakdown of other operation and maintenance:
Three Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Operation and maintenance not included in line items below | $ | 109.9 | $ | 117.1 | $ | 7.2 | ||||||
We Power (1) | 127.1 | 127.3 | 0.2 | |||||||||
Transmission (2) | 67.5 | 68.7 | 1.2 | |||||||||
Regulatory amortizations and other pass through expenses (3) | 23.2 | 23.1 | (0.1 | ) | ||||||||
Total other operation and maintenance | $ | 327.7 | $ | 336.2 | $ | 8.5 | ||||||
(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 June 30, 2017 and 2016, $139.2 million and $139.5 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 June 30, 2017 and 2016, $79.6 million and $82.7 million, respectively, of costs were billed to us by transmission providers. |
(3) | 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 sales volumes by customer class and weather statistics:
Three Months Ended June 30 | |||||||||
MWh (in thousands) | |||||||||
Electric Sales Volumes | 2017 | 2016 | B (W) | ||||||
Customer Class | |||||||||
Residential | 1,797.8 | 1,840.9 | (43.1 | ) | |||||
Small commercial and industrial | 2,104.2 | 2,180.9 | (76.7 | ) | |||||
Large commercial and industrial | 2,092.1 | 2,405.4 | (313.3 | ) | |||||
Other | 33.6 | 34.5 | (0.9 | ) | |||||
Total retail | 6,027.7 | 6,461.7 | (434.0 | ) | |||||
Wholesale | 397.2 | 270.1 | 127.1 | ||||||
Resale | 1,064.6 | 1,751.1 | (686.5 | ) | |||||
Total sales in MWh | 7,489.5 | 8,482.9 | (993.4 | ) | |||||
Three Months Ended June 30 | |||||||||
Therms (in millions) | |||||||||
Natural Gas Sales Volumes | 2017 | 2016 | B (W) | ||||||
Customer Class | |||||||||
Residential | 46.7 | 56.6 | (9.9 | ) | |||||
Commercial and industrial | 27.8 | 30.4 | (2.6 | ) | |||||
Total retail | 74.5 | 87.0 | (12.5 | ) | |||||
Transport | 71.4 | 75.2 | (3.8 | ) | |||||
Total sales in therms | 145.9 | 162.2 | (16.3 | ) | |||||
Three Months Ended June 30 | |||||||||
Degree Days | |||||||||
Weather * | 2017 | 2016 | B(W) | ||||||
Heating (937 normal) | 748 | 926 | (178 | ) | |||||
Cooling (161 normal) | 203 | 196 | 7 | ||||||
* | 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 $9.3 million during the second quarter of 2017, compared with the same quarter in 2016. The significant factors impacting the lower electric utility margins were:
• | A $10.3 million decrease related to lower retail sales volumes during the second quarter of 2017, primarily driven by lower overall retail use per customer and the transfer of customers and their related sales to UMERC. |
• | A $2.0 million negative impact from collections of fuel and purchased power costs compared with costs approved in rates in the second quarter of 2017, as compared with the same quarter in 2016. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred. |
• | A $2.4 million decrease in margins from both the iron ore mines located in the Upper Peninsula of Michigan and our steam operations. In November 2016, one of the iron ore mines closed. With the return of the mines as retail customers in 2015, we continue to defer the majority of the margin from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. Our steam operations were impacted by the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information. |
These decreases in margins were partially offset by $9.0 million of lower capacity payments to a counterparty during the second quarter of 2017.
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Natural Gas Utility Margins
Natural gas utility margins decreased $2.1 million during the second quarter of 2017, compared with the same quarter in 2016. The most significant factor impacting the lower natural gas utility margins were lower retail sales volumes, primarily driven by warmer weather. As measured by heating degree days, the second quarter of 2017 was 19.2% warmer than the same quarter in 2016.
Operating Income
Operating income at the utility segment decreased $4.1 million during the second quarter of 2017, compared with the same quarter in 2016. This decrease was driven by the $11.4 million decrease in margins discussed above, partially offset by $7.3 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).
We experienced lower overall operating expenses related to synergy savings resulting from the Integrys acquisition. The significant factors impacting the decrease in operating expenses, which were due in part to synergy savings, were:
• | An $11.5 million decrease in operation and maintenance expenses at our plants, partially related to the seasonal operation of the Pleasant Prairie Power Plant and the timing of planned outages and maintenance. |
• | A $3.1 million decrease in electric and natural gas distribution expenses, due in part to the transfer of customers and their related sales to UMERC. |
These decreases in operating expenses were partially offset by a $10.9 million gain on the sale of the MCPP, which was sold in April 2016. See Note 2, Dispositions, for more information on the sale of the MCPP.
Equity in Earnings of Transmission Affiliate
Three Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Equity in earnings of transmission affiliate | $ | — | $ | 11.4 | $ | (11.4 | ) | |||||
At December 31, 2016, we owned approximately 23% of ATC. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information.
Consolidated Other Income, Net
Three Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
AFUDC – Equity | $ | 0.7 | $ | 1.4 | $ | (0.7 | ) | |||||
Other | 3.7 | 1.8 | 1.9 | |||||||||
Other income, net | $ | 4.4 | $ | 3.2 | $ | 1.2 | ||||||
Consolidated Interest Expense
Three Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Interest expense | $ | 29.1 | $ | 29.4 | $ | 0.3 | ||||||
Income Tax Expense
Three Months Ended June 30 | |||||||||
2017 | 2016 | B (W) | |||||||
Effective tax rate | 36.0 | % | 37.2 | % | 1.2 | % | |||
Our effective tax rate decreased by 1.2% when compared to the second quarter of 2016, primarily due to increased renewable energy credits related to wind and favorable compensation expense in the second quarter of 2017.
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SIX MONTHS ENDED JUNE 30, 2017
Consolidated Earnings
Our consolidated earnings for the six months ended June 30, 2017 were $177.1 million, compared to $189.9 million for the same period in 2016. See below for additional information on the $12.8 million decrease 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 six months ended June 30, 2017 and 2016, was $327.9 million and $328.4 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.
Utility Segment Contribution to Operating Income
The following table compares our utility segment's contribution to operating income for the first six months of 2017 with the first six months of 2016, including favorable or better, "B", and unfavorable or worse, "W", variances. Effective January 1, 2017, we transferred our electric customers located in the Upper Peninsula of Michigan to UMERC. See Note 12, Related Parties, for more information.
Six Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Electric revenues | $ | 1,615.4 | $ | 1,650.7 | $ | (35.3 | ) | |||||
Fuel and purchased power | 493.9 | 504.7 | 10.8 | |||||||||
Total electric margins | 1,121.5 | 1,146.0 | (24.5 | ) | ||||||||
Natural gas revenues | 212.0 | 202.0 | 10.0 | |||||||||
Cost of natural gas sold | 128.6 | 116.0 | (12.6 | ) | ||||||||
Total natural gas margins | 83.4 | 86.0 | (2.6 | ) | ||||||||
Total electric and natural gas margins | 1,204.9 | 1,232.0 | (27.1 | ) | ||||||||
Other operation and maintenance | 655.5 | 684.4 | 28.9 | |||||||||
Depreciation and amortization | 164.8 | 161.2 | (3.6 | ) | ||||||||
Property and revenue taxes | 56.7 | 58.0 | 1.3 | |||||||||
Operating income | $ | 327.9 | $ | 328.4 | $ | (0.5 | ) | |||||
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The following table shows a breakdown of other operation and maintenance:
Six Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Operation and maintenance not included in line items below | $ | 218.7 | $ | 243.0 | $ | 24.3 | ||||||
We Power (1) | 254.7 | 255.9 | 1.2 | |||||||||
Transmission (2) | 134.5 | 137.5 | 3.0 | |||||||||
Regulatory amortizations and other pass through expenses (3) | 47.6 | 48.0 | 0.4 | |||||||||
Total other operation and maintenance | $ | 655.5 | $ | 684.4 | $ | 28.9 | ||||||
(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 six months ended June 30, 2017 and 2016, $265.0 million and $263.5 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 six months ended June 30, 2017 and 2016, $134.7 million and $168.3 million, respectively, of costs were billed to us by transmission providers. |
(3) | Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income. |
The following tables provide information on sales volumes by customer class and weather statistics:
Six Months Ended June 30 | |||||||||
MWh (in thousands) | |||||||||
Electric Sales Volumes | 2017 | 2016 | B (W) | ||||||
Customer Class | |||||||||
Residential | 3,622.8 | 3,760.7 | (137.9 | ) | |||||
Small commercial and industrial | 4,301.8 | 4,410.4 | (108.6 | ) | |||||
Large commercial and industrial | 4,077.7 | 4,753.4 | (675.7 | ) | |||||
Other | 72.2 | 73.7 | (1.5 | ) | |||||
Total retail | 12,074.5 | 12,998.2 | (923.7 | ) | |||||
Wholesale | 844.3 | 513.6 | 330.7 | ||||||
Resale | 3,197.0 | 3,856.2 | (659.2 | ) | |||||
Total sales in MWh | 16,115.8 | 17,368.0 | (1,252.2 | ) | |||||
Six Months Ended June 30 | |||||||||
Therms (in millions) | |||||||||
Natural Gas Sales Volumes | 2017 | 2016 | B (W) | ||||||
Customer Class | |||||||||
Residential | 202.3 | 215.9 | (13.6 | ) | |||||
Commercial and industrial | 113.5 | 115.5 | (2.0 | ) | |||||
Total retail | 315.8 | 331.4 | (15.6 | ) | |||||
Transport | 160.5 | 171.1 | (10.6 | ) | |||||
Total sales in therms | 476.3 | 502.5 | (26.2 | ) | |||||
Six Months Ended June 30 | |||||||||
Degree Days | |||||||||
Weather * | 2017 | 2016 | B(W) | ||||||
Heating (4,215 normal) | 3,597 | 4,031 | (434 | ) | |||||
Cooling (161 normal) | 203 | 196 | 7 | ||||||
* | Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin. |
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Electric Utility Margins
Electric utility margins decreased $24.5 million during the first six months of 2017, compared with the same period in 2016. The significant factors impacting the lower electric utility margins were:
• | A $24.8 million decrease related to lower sales volumes during the first six months of 2017, primarily driven by lower overall retail use per customer and the transfer of customers and their related sales to UMERC. Warmer winter weather and an additional day of sales during the same period in 2016 due to leap year also contributed to the decrease. As measured by heating degree days, the first six months of 2017 were 10.8% warmer than the same period in 2016. |
• | A $4.7 million decrease in steam margins related to the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information. |
• | A $3.3 million decrease in margins from the iron ore mines located in the Upper Peninsula of Michigan. In November 2016, one of the iron ore mines closed. With the return of the mines as retail customers in 2015, we continue to defer the majority of the margin from those sales and apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding. |
• | A $2.9 million negative impact from collections of fuel and purchased power costs compared with costs approved in rates in the first six months of 2017, as compared with the same period in 2016. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred. |
These decreases in margins were partially offset by $18.0 million of lower capacity payments to a counterparty during the first six months of 2017.
Natural Gas Utility Margins
Natural gas utility margins decreased $2.6 million during the first six months of 2017, compared with the same period in 2016. The most significant factor impacting the lower natural gas utility margins were lower retail sales volumes, primarily driven by warmer weather. As measured by heating degree days, the first six months of 2017 were 10.8% warmer than the same period in 2016. An additional day of sales during 2016 due to leap year also contributed to the decrease.
Operating Income
Operating income at the utility segment decreased $0.5 million during the first six months of 2017, compared with the same period in 2016. The decrease was driven by the $27.1 million decrease in margins discussed above, partially offset by $26.6 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).
We experienced lower overall operating expenses related to synergy savings resulting from the Integrys acquisition. The significant factors impacting the decrease in operating expenses, which were due in part to synergy savings, were:
• | A $17.0 million decrease in operation and maintenance expenses at our plants, partially related to the seasonal operation of the Pleasant Prairie Power Plant, the timing of planned outages and maintenance, and the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information on the sale of the MCPP. |
• | An $8.4 million decrease in electric and natural gas distribution expenses, due in part to the transfer of customers and their related sales to UMERC. |
• | A $4.6 million decrease in transmission expenses, We Power costs, and regulatory amortizations and other pass-through expenses included in the table above. |
These decreases in operating expenses were partially offset by a $10.9 million gain on the sale of the MCPP, which was sold in April 2016. See Note 2, Dispositions, for more information on the sale of the MCPP.
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Equity in Earnings of Transmission Affiliate
Six Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Equity in earnings of transmission affiliate | $ | — | $ | 26.1 | $ | (26.1 | ) | |||||
At December 31, 2016, we owned approximately 23% of ATC. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information.
Consolidated Other Income, Net
Six Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
AFUDC – Equity | $ | 1.4 | $ | 2.9 | $ | (1.5 | ) | |||||
Other | 7.4 | 3.3 | 4.1 | |||||||||
Other income, net | $ | 8.8 | $ | 6.2 | $ | 2.6 | ||||||
Consolidated Interest Expense
Six Months Ended June 30 | ||||||||||||
(in millions) | 2017 | 2016 | B (W) | |||||||||
Interest expense | $ | 58.7 | $ | 58.5 | $ | (0.2 | ) | |||||
Income Tax Expense
Six Months Ended June 30 | |||||||||
2017 | 2016 | B (W) | |||||||
Effective tax rate | 36.1 | % | 37.0 | % | 0.9 | % | |||
Our effective tax rate decreased by 0.9% when compared to the first six months of 2016, primarily due to increased renewable energy credits related to wind and favorable compensation expense in the first six months of 2017. We expect our 2017 annual effective tax rate to be between 36.0% and 37.0%.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following table summarizes our cash flows during the six months ended June 30:
(in millions) | 2017 | 2016 | Change in 2017 Over 2016 | |||||||||
Cash provided by (used in): | ||||||||||||
Operating activities | $ | 359.9 | $ | 336.1 | $ | 23.8 | ||||||
Investing activities | (225.7 | ) | (150.7 | ) | (75.0 | ) | ||||||
Financing activities | (148.0 | ) | (204.0 | ) | 56.0 | |||||||
Operating Activities
Net cash provided by operating activities increased $23.8 million during the first six months of 2017, compared with the same period in 2016, driven by:
• | A $107.0 million increase in cash related to a cash payment to WBS in the first six months of 2016 for transfers of certain benefit-related liabilities to WBS. |
06/30/2017 Form 10-Q | 30 | Wisconsin Electric Power Company |
• | A $47.8 million increase in cash from lower payments for operating and maintenance costs. During the first six months of 2017, our payments related to transmission, electric and natural gas distribution costs, electric generation costs, and employee benefits decreased. |
These increases in net cash provided by operating activities were partially offset by:
• | A $64.0 million net decrease in cash related to $63.4 million of cash paid for income taxes during the first six months of 2017, compared with $0.6 million of cash received during the same period in 2016. This decrease in cash was primarily the result of the extension of bonus depreciation in December 2015. |
• | A $42.9 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 23.8% during the first six months of 2017, compared with the same period in 2016. |
• | An $18.0 million decrease in distributions received during the first six months of 2017, compared with the same period in 2016, due to the transfer of our investment in ATC to another subsidiary of WEC Energy Group. See Note 9, Investment in American Transmission Company, for more information. |
Investing Activities
Net cash used in investing activities increased $75.0 million during the first six months of 2017, compared with the same period in 2016, driven by:
• | A $55.0 million increase in cash paid for capital expenditures during the first six months of 2017, compared with the same period in 2016, which is discussed in more detail below. |
• | Cash of $13.1 million received during the first six months of 2016, related to transfers of certain software to WBS. |
• | A $9.7 million decrease in the proceeds received from the sale of assets and businesses during the first six months of 2017, compared with the same period in 2016. See Note 2, Dispositions, for more information. |
Capital Expenditures
Capital expenditures for the six months ended June 30 were as follows:
(in millions) | 2017 | 2016 | Change in 2017 Over 2016 | |||||||||
Capital expenditures | $ | 246.9 | $ | 191.9 | $ | 55.0 | ||||||
The increase in cash paid for capital expenditures during the first six months of 2017 was driven by upgrades of our natural gas and electric distribution systems, including meter and main replacement projects, and various projects at the OCPP.
See Significant Capital Projects below for more information.
Financing Activities
Net cash used in financing activities decreased $56.0 million during the first six months of 2017, compared with the same period in 2016, primarily driven by:
• | A $100.0 million decrease in dividends paid on common stock. We paid a special dividend to our parent to balance our capital structure during the first six months of 2016. |
• | A $75.0 million equity contribution received from our parent to balance the capital structure during the first six months of 2017. |
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These decreases in net cash used in financing activities were partially offset by:
• | An $86.5 million net decrease in cash related to $84.0 million of net repayments of commercial paper during the first six months of 2017, compared with $2.5 million of net borrowings during the same period of 2016. |
• | A $16.0 million increase in net repayments of our subsidiary's note to our parent during the first six months of 2017. |
For more information on our short-term financing activities, see Note 4, 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 4, Short-Term Debt and Lines of Credit, for more information on our credit facility.
As of June 30, 2017, 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 June 30, 2017, the repurchased bonds were still outstanding but are not reported in our long-term debt since they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties.
Working Capital
Although not the case as of June 30, 2017, our current liabilities sometimes exceed our current assets. If this were to occur, we would not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for ongoing operations. We also can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.
Credit Rating Risk
We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings and/or Baa3 at Moody's Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.
In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.
In July 2017, Moody's downgraded our senior unsecured rating to A2 from A1. Moody's affirmed our P-1 commercial paper rating. We do not believe this change in rating will have a material impact on our ability to access capital markets.
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Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.
Capital Requirements
Significant Capital Projects
We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:
(in millions) | ||||
2017 | $ | 656.6 | ||
2018 | 595.3 | |||
2019 | 574.3 | |||
Total | $ | 1,826.2 | ||
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.
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 expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 4, Short-Term Debt and Lines of Credit, and Note 11, 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 2016 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 2016 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 13, 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.
06/30/2017 Form 10-Q | 33 | Wisconsin Electric Power Company |
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, 2016. In addition to the Form 10-K disclosures, see Note 6, Fair Value Measurements, and Note 7, Derivative Instruments, in this report for information concerning our market risk exposures.
06/30/2017 Form 10-Q | 34 | Wisconsin Electric Power Company |
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
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)) during the second quarter of 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
06/30/2017 Form 10-Q | 35 | Wisconsin Electric Power Company |
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 2016 Annual Report on Form 10-K. See Note 13, Commitments and Contingencies, in this report for more information on material legal proceedings and matters related to us.
In addition to those legal proceedings referenced above, 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.
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, 2016. See Item 1A. Risk Factors in Part I of our 2016 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.
06/30/2017 Form 10-Q | 36 | Wisconsin Electric Power Company |
ITEM 6. EXHIBITS
Number | Exhibit | ||
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 | ||
06/30/2017 Form 10-Q | 37 | Wisconsin Electric Power Company |
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: | August 4, 2017 | William J. Guc |
Vice President and Controller | ||
(Duly Authorized Officer and Chief Accounting Officer) | ||
06/30/2017 Form 10-Q | 38 | Wisconsin Electric Power Company |