Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 6. Exhibits
Exhibits
EX-31.1
a2019q1we10qexhibit311.htm
EX-31.2
a2019q1we10qexhibit312.htm
EX-32.1
a2019q1we10qexhibit321.htm
EX-32.2
a2019q1we10qexhibit322.htm
Wisconsin Electric Power Earnings 2019-03-31
WEP 10Q Quarterly Report
Balance Sheet
Income Statement
Cash Flow
10-Q 1 a2019q1we10q.htm WISCONSIN ELECTRIC MARCH 31, 2019 FORM 10-Q Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2019
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________________ to ___________________
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
Securities registered pursuant to Section 12(b) of the Act:
None
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 every Interactive Data File required to be submitted 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 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]
Smaller reporting company [ ]
Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Common Stock, $10 Par Value,
33,289,327 shares outstanding at
March 31, 2019
All of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.
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 rates, 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 2018 Annual Report on Form 10-K, 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/or regulatory changes, including changes in rate-setting policies or procedures, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, energy efficiency mandates, and tax laws that affect our ability to use production tax credits and investment tax credits;
•
The remaining uncertainty surrounding the Tax Legislation enacted in December 2017, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact, if any, on our credit ratings;
•
Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;
•
Factors affecting the implementation of WEC Energy Group's generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;
•
Increased pressure on WEC Energy Group and us by investors and other stakeholder groups to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases;
•
The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities,
or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;
•
Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;
•
Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;
•
The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;
•
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;
•
The direct or indirect effect on our business resulting from terrorist attacks and cyber security intrusions, as well as the threat of such incidents, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns and to comply with state notification laws;
•
The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;
•
Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;
•
Advances in technology, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;
•
Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely, if at all, or within budgets;
•
The timing and outcome of any audits, disputes, and other proceedings related to taxes;
•
The ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and continuing to consolidate WEC Energy Group's enterprise systems with those of its other utilities;
•
The effect of accounting pronouncements issued periodically by standard-setting bodies; and
•
Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.
We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
March 31, 2019
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, statements of cash flows, and statements of equity, 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, which was dissolved in October 2018.
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, 2018. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2019 are not necessarily indicative of expected results for 2019 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—OPERATING REVENUES
For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues, in our 2018 Annual Report on Form 10-K.
Disaggregation of Operating Revenues
The following table presents our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions.
The following table disaggregates electric utility operating revenues into customer class:
Electric Utility Operating Revenues
Three Months Ended March 31
(in millions)
2019
2018
Residential
$
302.6
$
281.4
Small commercial and industrial
245.1
237.7
Large commercial and industrial
156.0
148.9
Other
5.6
5.4
Total retail revenues
709.3
673.4
Wholesale
28.9
28.5
Resale
31.3
63.7
Steam
10.1
9.7
Other utility revenues *
(0.8
)
4.3
Total electric utility operating revenues
$
778.8
$
779.6
*
Negative amounts are driven by the reduction in revenues related to tax repairs. In accordance with a settlement agreement with the PSCW in May 2018, we flowed through the tax benefits of our repair-related deferred tax liabilities to maintain certain regulatory assets at their December 31, 2017 levels.
Natural Gas Utility Operating Revenues
The following table disaggregates natural gas utility operating revenues into customer class:
Natural Gas Utility Operating Revenues
Three Months Ended March 31
(in millions)
2019
2018
Residential
$
125.6
$
114.7
Commercial and industrial
60.9
55.6
Total retail revenues
186.5
170.3
Transport
4.2
4.4
Other utility revenues *
(12.8
)
(13.9
)
Total natural gas utility operating revenues
$
177.9
$
160.8
*
Includes amounts refunded to customers for purchased gas adjustment costs.
Other Operating Revenues
Other operating revenues consist primarily of the following:
Three Months Ended March 31
(in millions)
2019
2018
Late payment charges
$
2.7
$
2.8
Rental revenues
0.7
0.8
Alternative revenues *
0.7
(2.5
)
Total other operating revenues
$
4.1
$
1.1
*
Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups.
The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2019 and December 31, 2018. For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2018 Annual Report on Form 10-K.
(in millions)
March 31, 2019
December 31, 2018
Regulatory assets
Plant retirements *
$
953.2
$
754.1
Finance and capital leases
885.1
869.3
Pension and OPEB costs
483.3
490.6
Income tax related items
332.9
317.9
SSR
317.8
316.7
Electric transmission costs
41.4
57.8
We Power generation
36.1
43.0
Asset retirement obligations
30.5
28.7
Other, net
20.3
24.2
Total regulatory assets
$
3,100.6
$
2,902.3
Balance sheet presentation
Other current assets
$
—
$
0.1
Regulatory assets
3,100.6
2,902.2
Total regulatory assets
$
3,100.6
$
2,902.3
*
On March 31, 2019, we retired the PIPP generating units. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP units.
(in millions)
March 31, 2019
December 31, 2018
Regulatory liabilities
Income tax related items
$
1,021.1
$
1,024.8
Removal costs
757.3
748.1
Mines deferral
129.1
120.8
Pension and OPEB costs
74.8
74.7
Uncollectible expense
15.6
16.4
Energy efficiency programs
14.1
13.5
Other, net
28.8
15.9
Total regulatory liabilities
$
2,040.8
$
2,014.2
Balance sheet presentation
Other current liabilities
$
27.0
$
11.9
Regulatory liabilities
2,013.8
2,002.3
Total regulatory liabilities
$
2,040.8
$
2,014.2
NOTE 4—PROPERTY, PLANT, AND EQUIPMENT
We have evaluated future plans for our older and less efficient fossil fuel generating units and have retired the PIPP and the Pleasant Prairie power plant. In addition, a severance liability was recorded in other current liabilities on our balance sheets within the utility segment related to these plant retirements.
Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The carrying value of the PIPP units was $172.1 million at March 31, 2019. This amount included the net book value of $183.1 million, which was classified as a regulatory asset on our balance sheet. In addition, an $11.0 million cost of removal reserve related to the PIPP units remained classified as a regulatory liability at March 31, 2019. We will amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired.
NOTE 5—COMMON EQUITY
Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 8, Common Equity, in our 2018 Annual Report on Form 10-K for additional information on these and other restrictions.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
NOTE 6—SHORT-TERM DEBT AND LINES OF CREDIT
The following table shows our short-term borrowings and their corresponding weighted-average interest rates:
(in millions, except percentages)
March 31, 2019
December 31, 2018
Commercial paper
Amount outstanding
$
75.5
$
134.9
Weighted-average interest rate on amounts outstanding
2.64
%
2.96
%
Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2019, was $64.4 million with a weighted-average interest rate during the period of 2.80%.
The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:
(in millions)
Maturity
March 31, 2019
Revolving credit facility
October 2022
$
500.0
Less:
Letters of credit issued inside credit facility
$
1.2
Commercial paper outstanding
75.5
Available capacity under existing agreement
$
423.3
NOTE 7—LEASES
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded.
As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance.
•
We did not reassess whether any expired or existing contracts were leases or contained leases.
•
We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases).
•
We did not reassess the accounting for initial direct costs for any existing leases.
We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with Accounting Standards Codification 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract.
We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842.
In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842.
In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842.
Both the right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $13.0 million. Regarding our finance leases, while the adoption of Topic 842 changed the classification of expense related to these leases on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the finance lease assets and related liability amounts recorded on our balance sheets.
Obligations Under Operating Leases
We have recorded right of use assets and lease liabilities associated with the following operating leases.
•
Land we are leasing related to our Rothschild biomass plant through June 2051.
•
Rail cars we are leasing to transport coal to various generating facilities through February 2021.
•
Various office space leases.
The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement.
Obligations Under Finance Leases
We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under finance lease accounting, we have recorded the leased plants and corresponding obligations as right of use assets and lease liabilities on our balance sheets. We treat these agreements as operating leases for rate-making purposes.
Prior to our adoption of Topic 842 on January 1, 2019, we accounted for these finance leases under Topic 980-840, Regulated Operations – Leases, as follows:
•
We recorded our minimum lease payments under the power purchase contract as purchased power expense on our income statement.
•
We recorded our minimum lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements.
•
We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets.
In conjunction with our adoption of Topic 842, while the timing of expense recognition related to our finance leases did not change, the classification of the lease expense changed as follows:
•
Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within purchased power expense, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases.
•
Similarly, the lease payments related to our leases with We Power were no longer classified as rent expense within other operation and maintenance in our income statements, but were also divided between amortization expense and interest expense in accordance with Topic 980-842.
•
In order to ensure the timing of lease expense did not change for these finance leases upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842.
•
We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets.
Power Purchase Commitment
In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years, purchase the generating facility at fair market value, or allow the contract to expire. We originally recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities.
As previously discussed, we treat the long-term power purchase contract as an operating lease for rate-making purposes. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $22.1 million at March 31, 2019, and will decrease to zero over the remaining life of the contract.
Port Washington Generating Station
We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units, which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.3 million in the year 2021 for PWGS 1 and to approximately $126.0 million in the year 2023 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases for the units was $631.5 million as of March 31, 2019, and will decrease to zero over the remaining lives of the contracts.
The only variability associated with the PWGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.
When the PWGS 1 and PWGS 2 contracts expire in 2030 and 2033, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.
We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8 generating units, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30-year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $524.1 million in the year 2028 for ER 1 and to approximately $430.6 million in the year 2029 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases was $2,212.2 million as of March 31, 2019, and will decrease to zero over the remaining lives of the contracts.
The only variability associated with the ER lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.
When the ER 1 and ER 2 contracts expire in 2040 and 2041, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.
Amounts Recognized in the Financial Statements
The components of lease expense and supplemental cash flow information related to our leases for the quarters ended March 31 are as follows:
(in millions)
2019
2018
Long-term power purchase commitment
$
2.0
$
1.9
We Power leases
91.8
91.8
Total finance/capital lease expense (1)
$
93.8
$
93.7
Operating lease expense (2)
0.7
0.7
Total lease expense
$
94.5
$
94.4
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance/capital leases (3)
$
89.8
$
94.2
Operating cash flows from operating leases
$
0.7
$
0.7
Financing cash flows from finance leases (3)
$
5.7
$
—
Non-cash activity - right of use assets obtained in exchange for operating lease liabilities
$
13.0
Weighted-average remaining lease term – finance leases
19.3 years
Weighted-average remaining lease term – operating leases
Weighted average discount rate – operating leases (4)
4.6
%
(1)
For the quarter ended March 31, 2019, total finance lease expense included amortization of right of use assets in the amount of $5.7 million (included in depreciation and amortization expense) and interest on lease liabilities of $88.1 million (included in interest expense). For the quarter ended March 31, 2018, total finance lease cost related to the long-term power purchase agreement was included in cost of sales and total finance lease cost related to the PWGS and ERGS units was included in other operation and maintenance.
(2)
Operating lease expense was included as a component of operation and maintenance for the quarters ended March 31, 2019 and 2018.
Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to finance leases were recorded as a component of operating cash flows.
(4)
Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our financing leases, the rate implicit in each lease was readily determinable.
The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets:
(in millions)
March 31, 2019
December 31, 2018
Long-term power purchase commitment
Under finance/capital lease
$
140.3
$
140.3
Accumulated amortization
(122.3
)
(120.9
)
Total long-term power purchase commitment
$
18.0
$
19.4
PWGS
Under finance/capital lease
$
739.2
$
736.9
Accumulated amortization
(343.9
)
(335.9
)
Total PWGS
$
395.3
$
401.0
ERGS
Under finance/capital lease
$
2,184.5
$
2,166.3
Accumulated amortization
(617.2
)
(598.8
)
Total ERGS
$
1,567.3
$
1,567.5
Total finance lease right of use assets/capital lease assets
$
1,980.6
$
1,987.9
Right of use assets related to operating leases were $12.5 million at March 31, 2019, and were included in other long-term assets on our balance sheets.
Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of March 31, 2019 were as follows:
(in millions)
Total Operating Leases
Power Purchase Commitment
PWGS
ERGS
Total Finance Leases
Nine months ended December 31, 2019
$
2.0
$
6.2
$
73.5
$
219.8
$
299.5
2020
2.7
8.8
98.0
293.1
399.9
2021
0.7
9.4
98.0
293.1
400.5
2022
0.6
4.2
98.0
292.9
395.1
2023
0.5
—
98.0
292.8
390.8
2024
0.5
—
97.9
292.7
390.6
Thereafter
13.5
—
677.8
4,538.5
5,216.3
Total minimum lease payments
20.5
28.6
1,241.2
6,222.9
7,492.7
Less: Interest
(8.0
)
(6.5
)
(609.7
)
(4,010.7
)
(4,626.9
)
Present value of minimum lease payments
12.5
22.1
631.5
2,212.2
2,865.8
Less: Short-term lease liabilities
(2.2
)
(5.2
)
(23.1
)
(23.7
)
(52.0
)
Long-term lease liabilities
$
10.3
$
16.9
$
608.4
$
2,188.5
$
2,813.8
Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively.
Significant Judgments and Other Information
We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind farms. We have not classified our easements as leases because we view the entire parcel of land specified in our easement
agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.
As of May 3, 2019, we have not entered into any material operating leases that have not yet commenced.
NOTE 8—MATERIALS, SUPPLIES, AND INVENTORIES
Our inventory consisted of:
(in millions)
March 31, 2019
December 31, 2018
Materials and supplies
$
143.7
$
146.1
Fossil fuel
41.2
58.7
Natural gas in storage
6.9
36.6
Total
$
191.8
$
241.4
Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
NOTE 9—INCOME TAXES
The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:
Three Months Ended March 31, 2019
Three Months Ended March 31, 2018
(in millions)
Amount
Effective Tax Rate
Amount
Effective Tax Rate
Statutory federal income tax
$
22.7
21.0
%
$
21.5
21.0
%
State income taxes net of federal tax benefit
7.1
6.6
%
6.7
6.5
%
Tax repairs
(29.6
)
(27.3
)%
(25.5
)
(24.9
)%
Federal excess deferred tax amortization
(6.2
)
(5.7
)%
(5.4
)
(5.2
)%
Wind production tax credits
(2.8
)
(2.6
)%
(3.2
)
(3.1
)%
Other
2.3
2.0
%
2.3
2.2
%
Total income tax benefit
$
(6.5
)
(6.0
)%
$
(3.6
)
(3.5
)%
The effective tax rates of (6.0)% and (3.5)% for the first quarter of 2019 and 2018, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement, the impact of the Tax Legislation, and wind production tax credits, partially offset by state income taxes.
The Tax Legislation, signed into law in December 2017, required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 18, Regulatory Environment, for more information about the Wisconsin rate settlement.
NOTE 10—FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).
Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs.
We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.
The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
March 31, 2019
(in millions)
Level 1
Level 2
Level 3
Total
Derivative assets
Natural gas contracts
$
1.3
$
—
$
—
$
1.3
FTRs
—
—
2.0
2.0
Coal contracts
—
0.5
—
0.5
Total derivative assets
$
1.3
$
0.5
$
2.0
$
3.8
Derivative liabilities
Coal contracts
$
—
$
0.1
$
—
$
0.1
December 31, 2018
(in millions)
Level 1
Level 2
Level 3
Total
Derivative assets
Natural gas contracts
$
0.7
$
—
$
—
$
0.7
FTRs
—
—
4.4
4.4
Total derivative assets
$
0.7
$
—
$
4.4
$
5.1
Derivative liabilities
Natural gas contracts
$
1.2
$
—
$
—
$
1.2
Coal contracts
—
0.1
—
0.1
Total derivative liabilities
$
1.2
$
0.1
$
—
$
1.3
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 and Operating Reserves Markets.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended March 31
(in millions)
2019
2018
Balance at the beginning of the period
$
4.4
$
2.4
Settlements
(2.4
)
(1.6
)
Balance at the end of the period
$
2.0
$
0.8
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that were not recorded at fair value:
March 31, 2019
December 31, 2018
(in millions)
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Preferred stock
$
30.4
$
28.3
$
30.4
$
28.3
Long-term debt, including current portion
2,710.1
2,981.2
2,709.6
2,881.6
The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
NOTE 11—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, none of which are designated as hedging instruments.
March 31, 2019
December 31, 2018
(in millions)
Derivative Assets
Derivative Liabilities
Derivative Assets
Derivative Liabilities
Other current
Natural gas contracts
$
1.1
$
—
$
0.7
$
1.2
FTRs
2.0
—
4.4
—
Coal contracts
0.5
0.1
—
0.1
Total other current *
$
3.6
$
0.1
$
5.1
$
1.3
Other long-term *
Natural gas contracts
$
0.2
$
—
$
—
$
—
Total
$
3.8
$
0.1
$
5.1
$
1.3
*
On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.
Realized gains (losses) on derivative instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:
Three Months Ended March 31, 2019
Three Months Ended March 31, 2018
(in millions)
Volumes
Gains (Losses)
Volumes
Gains (Losses)
Natural gas contracts
18.1 Dth
$
(1.4
)
11.7 Dth
$
(1.8
)
Petroleum products contracts
— gallons
—
1.4 gallons
0.4
FTRs
5.5 MWh
1.6
5.8 MWh
0.8
Total
$
0.2
$
(0.6
)
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 both March 31, 2019 and December 31, 2018, we had posted cash collateral of $1.1 million in our margin accounts. These amounts were recorded on our balance sheets in other current assets.
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
March 31, 2019
December 31, 2018
(in millions)
Derivative Assets
Derivative Liabilities
Derivative Assets
Derivative Liabilities
Gross amount recognized on the balance sheet
$
3.8
$
0.1
$
5.1
$
1.3
Gross amount not offset on the balance sheet
—
—
(0.6
)
(1.3
)
*
Net amount
$
3.8
$
0.1
$
4.5
$
—
*
Includes cash collateral posted of $0.7 million.
NOTE 12—GUARANTEES
As of March 31, 2019, we had $26.2 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.
NOTE 13—EMPLOYEE BENEFITS
The following tables show the components of net periodic pension and OPEB costs for our benefit plans:
During the three months ended March 31, 2019, we made contributions and payments of $1.7 million related to our pension plans and $0.2 million related to our OPEB plans. We expect to make contributions and payments of $2.1 million related to our pension plans and $3.5 million related to our OPEB plans during the remainder of 2019, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.
NOTE 14—SEGMENT INFORMATION
We use operating income to measure segment profitability and to allocate resources to our businesses. At March 31, 2019, we reported two segments, which are described below.
Our utility segment includes both our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. Prior to April 1, 2019, we also provided electric service to an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 as UMERC's new generation in the Upper Peninsula of Michigan is now operational. In addition, our electric utility operations include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee. 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.
Prior to October 2018, our other segment included Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. No significant items were reported in the other segment during the three months ended March 31, 2019 and 2018.
NOTE 15—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.
Power Purchase Agreement
We have a power purchase 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 finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately three 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 power purchase agreement.
We have $28.6 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.
NOTE 16—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.
We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2019, were $10,016.7 million.
Environmental Matters
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
Air Quality
National Ambient Air Quality Standards
After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service area were designated as partial nonattainment: Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.
Mercury and Air Toxics Standards
In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the mercury and air toxics standards (MATS) rule as well as the CAA required risk and technology review (RTR). The EPA was required by the United States Supreme Court to review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. As a result, under the proposed rule, the emission standards and other requirements of the MATS rule first enacted in 2012 would remain in place. The EPA is not proposing to remove coal-and oil-fired power plants from the list of sources that are regulated under Section 112. The EPA also proposes that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the proposed rule to have a material impact on our financial condition or operations.
Climate Change
In August 2018, the EPA issued a proposed replacement rule for the Clean Power Plan, the Affordable Clean Energy (ACE) rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants.
In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA determined that the best system of emission reduction (BSER) for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and st