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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CORPORATE DEVELOPMENTS
Introduction
We are a diversified holding company with natural gas and electric utility operations (serving customers in Wisconsin, Illinois, Michigan, and Minnesota), an approximately 60% equity ownership interest in American Transmission Company LLC (ATC) (a for-profit electric transmission company regulated by the FERC and certain state regulatory commissions), and non-utility energy infrastructure operations through We Power (which owns generation assets in Wisconsin), Bluewater (which owns underground natural gas storage facilities in Michigan), and a 90% ownership interest in Bishop Hill III (a wind generating facility in Illinois).
In December 2018, WEC Energy Group acquired an 80% ownership interest in Coyote Ridge, a 97.5 MW wind farm under construction in Brookings County, South Dakota. This wind farm is expected to be in service by the end of 2019, and is included in the non-utility energy infrastructure segment. See Note 2, Acquisitions, for more information.
Corporate Strategy
Our goal is to continue to build and sustain long-term value for our shareholders and customers by focusing on the fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety.
Reshaping Our Generation Fleet
The planned reshaping of our generation fleet will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. In addition, we set a new long-term goal of reducing CO2 emissions by approximately 80% below 2005 levels by 2050. We expect to retire a total of approximately 1,800 MW of coal-fired generation by 2020, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. Our 1,190 MW Pleasant Prairie power plant was retired in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. It may take several years to finalize long-term plans for the site. The jointly owned Edgewater 4 generating unit was retired in September 2018 (our share of the capacity from this plant was 100 MW), and our 200 MW Pulliam power plant was retired in October 2018. See Note 6, Property, Plant, and Equipment, for more information related to these power plant retirements and the planned retirement of the Presque Isle power plant (PIPP).
As part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar of up to 350 MW within our Wisconsin segment. Wisconsin Public Service Corporation (WPS) has partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. Subject to Public Service Commission of Wisconsin (PSCW) approval, WPS will own 100 MW of the output of each project for a total of 200 MW. Commercial operation for both projects is targeted for the end of 2020.
In December 2018, Wisconsin Electric Power Company (WE) received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add 35 MW of solar to WE's portfolio, allowing commercial and industrial customers to site solar arrays on their property. The second program, the Dedicated Renewable Energy Resource pilot, would allow large commercial and industrial customers to access renewable resources that WE would operate, adding up to 150 MW of renewables to WE's portfolio, and allowing these larger customers to meet their sustainability and renewable energy goals.
As the cost of renewable energy generation installations continues to decline, both the WPS solar projects and the WE pilots have become cost effective opportunities for WEC Energy Group and our customers to participate in renewable energy.
Reliability
We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to
| 2018 Form 10-K | 42 | WEC Energy Group, Inc. |
operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility in the Midwest for the eighth year in a row.
Below are a few examples of reliability projects that are currently underway.
| • | Upper Michigan Energy Resources Corporation (UMERC), our Michigan electric and natural gas utility, is moving forward with its long-term generation solution for electric reliability in the Upper Peninsula of Michigan. The plan calls for UMERC to construct and operate approximately 180 MW of natural gas-fueled generation located in the Upper Peninsula. The new generation is expected to achieve commercial operation during the second quarter of 2019 and provide the region with affordable, reliable electricity that generates less emissions than the PIPP. Pursuant to a written approval letter received from the Midcontinent Independent System Operator, we must retire PIPP by May 31, 2019. |
| • | The Peoples Gas Light and Coke Company continues to work on its Natural Gas System Modernization Program, which primarily involves replacing old cast and ductile iron pipes and facilities in Chicago’s natural gas delivery system with modern polyethylene pipes to reinforce the long-term safety and reliability of the system. |
| • | WPS continues work on its System Modernization and Reliability Project, which involves modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WPS, WE, and Wisconsin Gas LLC also continue to upgrade their electric and natural gas distribution systems to enhance reliability. |
Operating Efficiency
We continually look for ways to optimize the operating efficiency of our company. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between our utilities and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.
We continue to focus on integrating and improving business processes and consolidating our IT infrastructure across all of our companies. We expect these efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.
Financial Discipline
A strong adherence to financial discipline is essential to meeting our earnings projections and maintaining a strong balance sheet, stable cash flows, a growing dividend, and quality credit ratings.
We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, equipment, and entire business units, that are no longer strategic to operations, are not performing as intended, or have an unacceptable risk profile.
| • | See Note 2, Acquisitions, for information about our acquisitions of natural gas storage facilities in Michigan and portions of wind energy generation facilities in Wisconsin, Illinois, Nebraska, and South Dakota. |
| • | See Note 3, Dispositions, for information on recent dispositions. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco LLC, and, in October 2018, Bostco was dissolved. In the second quarter of 2016, we sold certain assets of Wisvest LLC. The sale of Integrys Transportation Fuels, LLC was completed in the first quarter of 2016. |
Our investment focus remains in our regulated utility and non-utility energy infrastructure businesses, as well as our investment in ATC. We expect total capital expenditures for our regulated utility and non-utility energy infrastructure businesses to be almost $12.7 billion from 2019 to 2023. Specific projects are discussed in more detail below under Liquidity and Capital Resources.
From 2019 to 2023, we expect capital contributions to ATC and ATC Holdco, LLC to be approximately $250 million. ATC Holdco is a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. Capital investments at ATC and ATC Holdco will be funded utilizing these capital contributions, in addition to cash generated from operations
| 2018 Form 10-K | 43 | WEC Energy Group, Inc. |
and debt. We currently forecast that our share of ATC's and ATC Holdco's projected capital expenditures over the next five years will be $1.2 billion inside the traditional ATC footprint and $250 million outside of the traditional ATC footprint.
Exceptional Customer Care
Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.
One example of how we obtain feedback from our customers is through our "We Care" calls, through which employees of our utility subsidiaries contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance to improve customer satisfaction.
Safety
We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. Our corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.
RESULTS OF OPERATIONS
Consolidated Earnings
The following table compares our consolidated results:
| Year Ended December 31 | ||||||||||||
| (in millions, except per share data) | 2018 | 2017 | 2016 | |||||||||
| Wisconsin | $ | 800.2 | $ | 1,055.2 | $ | 1,017.8 | ||||||
| Illinois | 255.8 | 279.9 | 261.1 | |||||||||
| Other states | 68.8 | 54.4 | 51.2 | |||||||||
| Non-utility energy infrastructure | 365.8 | 400.5 | 375.6 | |||||||||
| Corporate and other | (22.2 | ) | (13.9 | ) | (9.4 | ) | ||||||
| Total operating income | 1,468.4 | 1,776.1 | 1,696.3 | |||||||||
| Equity in earnings of transmission affiliates | 136.7 | 154.3 | 146.5 | |||||||||
| Other income, net | 70.3 | 73.7 | 66.6 | |||||||||
| Interest expense | 445.1 | 415.7 | 402.7 | |||||||||
| Income before income taxes | 1,230.3 | 1,588.4 | 1,506.7 | |||||||||
| Income tax expense | 169.8 | 383.5 | 566.5 | |||||||||
| Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.2 | |||||||||
| Net income attributed to common shareholders | $ | 1,059.3 | $ | 1,203.7 | $ | 939.0 | ||||||
| Diluted earnings per share | $ | 3.34 | $ | 3.79 | $ | 2.96 |
| 2018 Form 10-K | 44 | WEC Energy Group, Inc. |
2018 Compared with 2017
Earnings decreased $144.4 million during 2018, compared with 2017. The table below shows the year-over-year income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017. As shown in the table below, the changes related to these items resulted in a decrease in net income attributed to common shareholders of $223.2 million during 2018, compared with 2017. This decrease was driven by the $206.7 million one-time net reduction in income tax expense recorded in 2017 related to the revaluation of our deferred taxes, primarily on our non-utility energy infrastructure and corporate and other segments, as a result of the enactment of the Tax Legislation. See Note 14, Income Taxes, and Note 24, Regulatory Environment, for more information.
| (in millions) | 2018 Compared with 2017 B (W) | Change Related to Flow Through of Tax Repairs | Change Related to Tax Legislation | Remaining Change B (W) | ||||||||||||
| Wisconsin | $ | (255.0 | ) | $ | (165.9 | ) | $ | (142.2 | ) | $ | 53.1 | |||||
| Illinois | (24.1 | ) | — | (29.5 | ) | 5.4 | ||||||||||
| Other states | 14.4 | — | (8.0 | ) | 22.4 | |||||||||||
| Non-utility energy infrastructure | (34.7 | ) | — | (50.4 | ) | 15.7 | ||||||||||
| Corporate and other | (8.3 | ) | — | — | (8.3 | ) | ||||||||||
| Total operating income | (307.7 | ) | (165.9 | ) | (230.1 | ) | 88.3 | |||||||||
| Equity in earnings of transmission affiliates | (17.6 | ) | — | (34.3 | ) | 16.7 | ||||||||||
| Other income, net | (3.4 | ) | — | — | (3.4 | ) | ||||||||||
| Interest expense | (29.4 | ) | — | — | (29.4 | ) | ||||||||||
| Income before income taxes | (358.1 | ) | (165.9 | ) | (264.4 | ) | 72.2 | |||||||||
| Income tax expense | 213.7 | 165.9 | 41.2 | 6.6 | ||||||||||||
| Preferred stock dividends of subsidiary | — | — | — | — | ||||||||||||
| Net income attributed to common shareholders | $ | (144.4 | ) | $ | — | $ | (223.2 | ) | $ | 78.8 |
Absent the effect of the Tax Legislation, earnings increased by $78.8 million. The significant factors impacting this $78.8 million increase in earnings were:
| • | A $53.1 million remaining increase in operating income at the Wisconsin segment, driven by an increase in electric and natural gas margins related to higher retail sales volumes as a result of favorable weather and higher weather-normalized use per customer. This increase in margins was partially offset by higher operating expenses during 2018, which were driven by the earnings sharing mechanisms in place at our Wisconsin utilities. See Note 24, Regulatory Environment, for more information on our earnings sharing mechanisms. |
| • | A $22.4 million remaining increase in operating income at the other states segment. The increase was driven by higher natural gas margins, which were primarily a result of the colder winter weather in 2018 as well as customer growth and an interim rate increase at MERC. See Note 24, Regulatory Environment, for more information on the interim rate increase. |
| • | A $16.7 million remaining increase in earnings from our ownership interests in transmission affiliates. The increase was driven by expenses recorded in 2017 by ATC related to the refund ATC was required to provide customers as a result of its FERC financial audit. Continued capital investment by our transmission affiliates also contributed to the increase. |
| • | A $15.7 million remaining increase in operating income at the non-utility energy infrastructure segment, primarily driven by the inclusion of a full year of operations of Bluewater following its acquisition on June 30, 2017. |
These increases in earnings were partially offset by a $29.4 million increase in interest expense, driven by higher debt balances, primarily used to fund capital investments, and higher interest rates on both short-term and long-term debt.
| 2018 Form 10-K | 45 | WEC Energy Group, Inc. |
2017 Compared with 2016
Earnings increased $264.7 million during 2017, compared with 2016. The significant factors impacting the increase in earnings were:
| • | A $206.7 million one-time net reduction in income tax expense related to the revaluation of our deferred taxes primarily on our non-utility energy infrastructure and corporate and other segments at December 31, 2017, as a result of the enactment of the Tax Legislation. |
| • | A $37.4 million pre-tax increase in operating income at the Wisconsin segment, driven by lower operating expenses. A decrease in electric margins, driven by lower sales volumes, partially offset the decrease in operating expenses. |
| • | A $24.9 million pre-tax increase in operating income at the non-utility energy infrastructure segment. The increase was driven by higher revenues in connection with capital additions to the plants We Power owns and leases to WE and the inclusion of the operations of Bluewater following its acquisition on June 30, 2017. |
| • | An $18.8 million pre-tax increase in operating income at the Illinois segment. The increase was driven by higher natural gas margins at PGL due to continued capital investment in the SMP project under its QIP rider and lower operating expenses. |
Non-GAAP Financial Measures
The discussions below address the operating income contribution of each of our segments and include 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 useful basis for evaluating utility operations 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 segments 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 segment operating performance. Operating income for each of the last three fiscal years for each of our segments is presented in the “Consolidated Earnings” table above.
Each applicable segment operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, as applicable, along with a reconciliation to segment operating income.
| 2018 Form 10-K | 46 | WEC Energy Group, Inc. |
Wisconsin Segment Contribution to Operating Income
For the periods presented in this Annual Report on Form 10-K, our Wisconsin operations included operations of WE, WG, and WPS for all periods, and operations for UMERC beginning January 1, 2017, due to the transfer of customers and assets in the Upper Peninsula of Michigan from WE and WPS.
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Electric revenues | $ | 4,438.9 | $ | 4,559.0 | $ | 4,628.1 | ||||||
| Fuel and purchased power | 1,418.1 | 1,467.0 | 1,473.1 | |||||||||
| Total electric margins | 3,020.8 | 3,092.0 | 3,155.0 | |||||||||
| Natural gas revenues | 1,355.8 | 1,270.2 | 1,177.6 | |||||||||
| Cost of natural gas sold | 792.1 | 701.8 | 621.2 | |||||||||
| Total natural gas margins | 563.7 | 568.4 | 556.4 | |||||||||
| Total electric and natural gas margins | 3,584.5 | 3,660.4 | 3,711.4 | |||||||||
| Other operation and maintenance | 2,076.1 | 1,923.2 | 2,034.6 | |||||||||
| Depreciation and amortization | 546.6 | 523.9 | 496.6 | |||||||||
| Property and revenue taxes | 161.6 | 158.1 | 162.4 | |||||||||
| Operating income | $ | 800.2 | $ | 1,055.2 | $ | 1,017.8 |
The following table shows a breakdown of other operation and maintenance:
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Operation and maintenance not included in line items below | $ | 769.5 | $ | 833.3 | $ | 891.1 | ||||||
| We Power (1) | 506.9 | 513.0 | 513.2 | |||||||||
| Transmission (2) | 420.7 | 407.4 | 423.2 | |||||||||
| Transmission expense related to the flow through of tax repairs (3) | 77.8 | — | — | |||||||||
| Transmission expense related to Tax Legislation (4) | 67.7 | — | — | |||||||||
| Regulatory amortizations and other pass through expenses (5) | 159.1 | 158.1 | 157.4 | |||||||||
| Earnings sharing mechanisms (6) | 67.5 | 2.9 | 24.4 | |||||||||
| Other | 6.9 | 8.5 | 25.3 | |||||||||
| Total other operation and maintenance | $ | 2,076.1 | $ | 1,923.2 | $ | 2,034.6 |
| (1) | Represents costs associated with the We Power generation units, including operating and maintenance costs incurred by WE, as well as the lease payments that are billed from We Power to WE and then recovered in WE's rates. During 2018, 2017, and 2016, $485.3 million, $535.1 million, and $528.4 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by WE, 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 ATC and MISO network transmission expenses for our Wisconsin electric utilities. As a result, WE and WPS 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 2018, 2017, and 2016, $438.2 million, $451.4 million, and $486.0 million, respectively, of costs were billed to our electric utilities by transmission providers. |
| (3) | Represents additional transmission expense associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at their December 31, 2017 levels. See Note 24, Regulatory Environment, for more information. |
| (4) | Represents additional transmission expense associated with the May 2018 PSCW order requiring WE to use 80% of its current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce its transmission regulatory asset balance. See Note 24, Regulatory Environment, for more information. |
| (5) | Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income. |
| (6) | See Note 24, Regulatory Environment, for more information about our earnings sharing mechanisms. |
| 2018 Form 10-K | 47 | WEC Energy Group, Inc. |
The following tables provide information on delivered volumes by customer class and weather statistics:
| Year Ended December 31 | |||||||||
| MWh (in thousands) | |||||||||
| Electric Sales Volumes | 2018 | 2017 | 2016 | ||||||
| Customer class | |||||||||
| Residential | 11,195.0 | 10,636.3 | 10,998.9 | ||||||
| Small commercial and industrial * | 13,186.7 | 12,932.1 | 13,113.1 | ||||||
| Large commercial and industrial * | 12,946.5 | 12,822.0 | 13,418.6 | ||||||
| Other | 169.0 | 175.6 | 172.2 | ||||||
| Total retail * | 37,497.2 | 36,566.0 | 37,702.8 | ||||||
| Wholesale | 3,612.7 | 3,768.0 | 3,704.6 | ||||||
| Resale | 6,019.3 | 9,000.3 | 8,761.6 | ||||||
| Total sales in MWh * | 47,129.2 | 49,334.3 | 50,169.0 |
| * | Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan. |
| Year Ended December 31 | |||||||||
| Therms (in millions) | |||||||||
| Natural Gas Sales Volumes | 2018 | 2017 | 2016 | ||||||
| Customer class | |||||||||
| Residential | 1,131.1 | 1,028.3 | 1,004.0 | ||||||
| Commercial and industrial | 733.1 | 654.7 | 621.4 | ||||||
| Total retail | 1,864.2 | 1,683.0 | 1,625.4 | ||||||
| Transport | 1,411.5 | 1,316.4 | 1,270.6 | ||||||
| Total sales in therms | 3,275.7 | 2,999.4 | 2,896.0 |
| Year Ended December 31 | |||||||||
| Degree Days | |||||||||
| Weather | 2018 | 2017 | 2016 | ||||||
| WE and WG (1) | |||||||||
| Heating (6,515 normal) | 6,685 | 5,908 | 6,068 | ||||||
| Cooling (731 normal) | 929 | 772 | 991 | ||||||
| WPS (2) | |||||||||
| Heating (7,324 normal) | 7,554 | 6,942 | 6,715 | ||||||
| Cooling (507 normal) | 678 | 450 | 572 | ||||||
| UMERC (3) | |||||||||
| Heating (8,326 normal) | 8,611 | 8,145 | N/A | ||||||
| Cooling (325 normal) | 478 | 235 | N/A |
| (1) | Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin. |
| (2) | Normal degree days are based on a 20-year moving average of monthly temperatures from the Green Bay, Wisconsin weather station. |
| (3) | Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station. |
| 2018 Form 10-K | 48 | WEC Energy Group, Inc. |
2018 Compared with 2017
Electric Utility Margins
Electric utility margins at the Wisconsin segment decreased $71.2 million during 2018, compared with 2017. The significant factors impacting the lower electric utility margins were:
| • | An $88.1 million decrease in margins associated with WE's flow through of tax benefits of its repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. See Note 24, Regulatory Environment, for more information. |
| • | A $30.0 million decrease in margins related to savings from the Tax Legislation that we are required to return to customers through bill credits or reductions in other regulatory assets. See Note 14, Income Taxes, and Note 24, Regulatory Environment, for more information. |
| • | A $29.7 million decrease in wholesale margins driven both by lower sales volumes and reduced capacity rates due in part to the Tax Legislation. |
| • | A $9.1 million year-over-year negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities 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 electric utility margins were partially offset by:
| • | A $67.5 million increase related to higher retail sales volumes during 2018, primarily driven by favorable weather and higher overall use per retail customer due in part to a stronger economy. Colder winter weather and a warmer summer in 2018 contributed to the increase. As measured by heating degree days, 2018 was 13.2% and 8.8% colder than 2017 in the Milwaukee and Green Bay areas, respectively. As measured by cooling degree days, 2018 was 20.3% and 50.7% warmer than 2017 in the Milwaukee area and Green Bay area, respectively. |
| • | A $25.9 million increase related to SSR payments WE refunded to MISO in 2017 as directed by a FERC order received in October 2017. The FERC order reduced the costs eligible for reimbursement to WE for the operation and maintenance of its PIPP units under an SSR agreement between MISO and WE. A portion of these payments was returned to WE through the MISO allocation process and reduced transmission expense in 2017 as discussed below. |
Natural Gas Utility Margins
Natural gas utility margins at the Wisconsin segment decreased $4.7 million during 2018, compared with 2017. The most significant factor impacting the lower natural gas utility margins was $39.0 million of savings from the Tax Legislation that we are required to return to customers through bill credits. See Note 14, Income Taxes, and Note 24, Regulatory Environment, for more information. This decrease in natural gas utility margins was partially offset by a $34.5 million increase related to higher sales volumes, primarily driven by colder winter weather, customer growth, and higher use per retail customer due in part to a stronger economy.
Operating Income
Operating income at the Wisconsin segment decreased $255.0 million during 2018, compared with 2017. This decrease was driven by $179.1 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), and the $75.9 million decrease in margins discussed above.
The significant factors impacting the increase in operating expenses during 2018, compared with 2017, were:
| • | A $77.8 million increase in transmission expense related to the flow through of tax repairs, as discussed in the other operation and maintenance table above. |
| • | A $67.7 million increase in transmission expense associated with the May 2018 order from the PSCW related to our required treatment of the benefits associated with the Tax Legislation, as discussed in the other operation and maintenance table above. |
| 2018 Form 10-K | 49 | WEC Energy Group, Inc. |
| • | A $64.6 million increase in expense related to the earnings sharing mechanisms in place at our Wisconsin utilities. See Note 24, Regulatory Environment, for more information. |
| • | A $22.7 million increase in depreciation and amortization, driven by an increase in capital expenditures as we continue to execute on our capital plan. This increase in depreciation and amortization was partially offset by a decrease related to the reduction of certain WPS regulatory deferrals as a result of the PSCW's May 2018 order addressing the Tax Legislation. |
| • | A $13.3 million increase in transmission expense in 2018, driven by lower expense in 2017 related to a FERC order received in October 2017 to reduce SSR costs related to PIPP. A portion of the payments we initially refunded to MISO were returned to us, as discussed under electric utility margins. |
These increases in operating expenses were partially offset by a $69.9 million decrease in expenses across all of our plants, in part due to the retirements of the Pleasant Prairie power plant in April 2018, Edgewater Unit 4 in September 2018, and Pulliam Units 7 and 8 in October 2018. This resulted in lower maintenance and labor costs during 2018. See Note 6, Property, Plant, and Equipment, for more information on the plant retirements.
2017 Compared with 2016
Electric Utility Margins
Electric utility margins at the Wisconsin segment decreased $63.0 million during 2017, compared with 2016. The significant factors impacting the lower electric utility margins were:
| • | A $72.6 million decrease related to lower sales volumes during 2017, primarily driven by unfavorable weather as well as lower overall retail use per customer. Cooler summer and warmer winter weather in 2017, and an additional day of sales during 2016 due to leap year, contributed to the decrease. As measured by cooling degree days, 2017 was 22.1% and 21.3% cooler than 2016 in the Milwaukee and Green Bay areas, respectively. As measured by heating degree days, 2017 was 2.6% warmer than 2016 in the Milwaukee area. |
| • | A $25.9 million decrease related to SSR payments WE refunded to MISO as directed by a FERC order received in October 2017. The FERC order reduced the costs eligible for reimbursement to WE for the operation and maintenance of its PIPP units under an SSR agreement between MISO and WE. A portion of these payments was returned to WE through the MISO allocation process and reduced transmission expense as discussed below. See Note 24, Regulatory Environment, for more information. |
| • | A $3.5 million decrease in steam margins driven by the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information. |
| • | A $3.3 million period-over-period negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, the margins of our electric utilities 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 electric utility margins were partially offset by $36.5 million of lower capacity payments to a counterparty during 2017, related to improved contract terms.
Natural Gas Utility Margins
Natural gas utility margins at the Wisconsin segment increased $12.0 million during 2017, compared with 2016. The most significant factor impacting the higher natural gas utility margins was higher retail sales volumes, primarily driven by higher overall retail use per customer and customer growth. The higher retail sales volumes in 2017 were partially offset by an additional day of sales during 2016 due to leap year.
| 2018 Form 10-K | 50 | WEC Energy Group, Inc. |
Operating Income
Operating income at the Wisconsin segment increased $37.4 million during 2017, compared with 2016. This increase was driven by $88.4 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $51.0 million net decrease in margins discussed above.
The Wisconsin segment experienced lower overall operating expenses related to synergy savings resulting from the Integrys acquisition. The significant factors impacting the decrease in operating expenses during 2017, compared with 2016, which were due in part to synergy savings, were:
| • | A $29.1 million decrease in electric and natural gas distribution expenses, primarily related to lower metering costs and other cost savings. |
| • | A $21.5 million decrease in expenses related to the earnings sharing mechanisms in place at WE and WG. See Note 24, Regulatory Environment, for more information. |
| • | A $16.8 million decrease in expenses related to charitable projects supporting our customers and the communities within our service territories. |
| • | A $15.8 million decrease in transmission expenses, driven by a FERC order received in October 2017 to reduce SSR costs related to PIPP. A portion of the payments we initially refunded to MISO were returned to us, as discussed under electric utility margins. |
| • | An $11.5 million decrease in expenses related to an information technology project completed in 2016 to improve the billing, call center, and credit collection functions of certain WEC Energy Group subsidiaries. Lower expenses were due in part to a decrease in asset usage charges from WBS, driven by the transfer of this project from WBS to certain WEC Energy Group subsidiaries, including WPS, during 2017. The portion of these lower expenses related to the transfer was offset through higher depreciation and amortization, discussed below. |
| • | A $10.5 million decrease in operation and maintenance expenses at our plants, primarily related to the seasonal operation of the Pleasant Prairie power plant during 2017, lower operating costs at the plants, the timing of planned outages and maintenance, and the sale of the MCPP in April 2016. See Note 3, Dispositions, for more information on the sale of the MCPP. These decreases were partially offset by severance costs related to planned plant retirements. See Note 6, Property, Plant, and Equipment, for more information. |
| • | A $5.7 million decrease in customer service expenses, partially related to lower contracted meter reading rates and cost savings. |
These decreases in operating expenses were partially offset by:
| • | A $27.3 million increase in depreciation and amortization, driven by an overall increase in utility plant in service, the completion of the ReACTTM multi-pollutant control system at Weston Unit 3 during the fourth quarter of 2016, and WBS's transfer of the information technology project to WPS during 2017. |
| • | A $10.9 million gain recorded in April 2016 related to the sale of the MCPP. |
| 2018 Form 10-K | 51 | WEC Energy Group, Inc. |
Illinois Segment Contribution to Operating Income
Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Natural gas revenues | $ | 1,400.0 | $ | 1,355.5 | $ | 1,242.2 | ||||||
| Cost of natural gas sold | 480.5 | 438.9 | 365.2 | |||||||||
| Total natural gas margins | 919.5 | 916.6 | 877.0 | |||||||||
| Other operation and maintenance | 472.3 | 464.2 | 463.6 | |||||||||
| Depreciation and amortization | 170.3 | 152.6 | 134.0 | |||||||||
| Property and revenue taxes | 21.1 | 19.9 | 18.3 | |||||||||
| Operating income | $ | 255.8 | $ | 279.9 | $ | 261.1 |
The following table shows a breakdown of other operation and maintenance:
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Operation and maintenance not included in the line items below | $ | 372.9 | $ | 361.5 | $ | 363.8 | ||||||
| Riders * | 95.3 | 98.1 | 82.3 | |||||||||
| Regulatory amortizations * | (1.4 | ) | 1.0 | 2.7 | ||||||||
| Other | 5.5 | 3.6 | 14.8 | |||||||||
| Total other operation and maintenance | $ | 472.3 | $ | 464.2 | $ | 463.6 |
| * | These riders and regulatory amortizations are substantially offset in margins and therefore do not have a significant impact on operating income. |
The following tables provide information on delivered volumes by customer class and weather statistics:
| Therms (in millions) | |||||||||
| Natural Gas Sales Volumes | 2018 | 2017 | 2016 | ||||||
| Customer Class | |||||||||
| Residential | 896.2 | 759.6 | 771.8 | ||||||
| Commercial and industrial | 358.3 | 313.9 | 321.4 | ||||||
| Total retail | 1,254.5 | 1,073.5 | 1,093.2 | ||||||
| Transport | 905.1 | 853.4 | 855.3 | ||||||
| Total sales in therms | 2,159.6 | 1,926.9 | 1,948.5 |
| Degree Days | |||||||||
| Weather * | 2018 | 2017 | 2016 | ||||||
| Heating (6,059 normal) | 6,327 | 5,470 | 5,713 |
| * | Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport. |
2018 Compared with 2017
Natural Gas Utility Margins
Natural gas utility margins at the Illinois segment, net of the $2.8 million impact of the riders referenced in the table above, increased $5.7 million during 2018, compared with 2017. The increase was primarily driven by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider. PGL currently recovers the costs related to the SMP through a surcharge on customer bills pursuant to an ICC approved QIP rider, which is in effect through 2023. This increase was substantially offset by a decrease in margins related to savings from the Tax Legislation that we are required to return to customers through the VITA. See Note 14, Income Taxes, and Note 24, Regulatory Environment, for more information.
| 2018 Form 10-K | 52 | WEC Energy Group, Inc. |
Operating Income
Operating income at the Illinois segment decreased $24.1 million during 2018, compared with 2017. This decrease was driven by $29.8 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), net of the impact of the riders referenced in the table above, partially offset by the $5.7 million increase in margins discussed above.
The significant factors impacting the increase in operating expenses during 2018, compared with 2017, were:
| • | A $17.7 million increase in depreciation expense primarily driven by PGL's continued capital investment in the SMP project. |
| • | An $11.4 million increase in natural gas maintenance costs related to our Illinois utilities’ distribution systems. |
2017 Compared with 2016
Natural Gas Utility Margins
Natural gas utility margins at the Illinois segment, net of the $15.8 million impact of the riders referenced in the table above, increased $23.8 million during 2017, compared with 2016. The increase was primarily driven by an increase in revenue at PGL due to continued capital investment in the SMP project under its QIP rider.
Operating Income
Operating income at the Illinois segment increased $18.8 million during 2017, compared with 2016. This increase was due to the $23.8 million increase in margins discussed above, partially offset by $5.0 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes), net of the impact of the riders referenced in the table above.
The significant factors impacting the increase in operating expenses during 2017, compared with 2016, were:
| • | An $18.6 million increase in depreciation and amortization expense, driven by continued capital investment at PGL in the SMP project and the transfer of an information technology project to PGL and NSG in 2017. This information technology project was created to improve the billing, call center, and credit collection facilities of certain WEC subsidiaries. |
| • | An increase in natural gas distribution expenses, driven by increased repair activity in 2017. |
These increases were partially offset by:
| • | A $9.8 million decrease in expenses related to charitable projects supporting our customers and the communities within our service territories. |
| • | A $6.5 million decrease in benefit related expenses driven by lower pension costs. |
| • | A $6.0 million decrease in expenses related to the information technology project completed in 2016 to improve certain functions of some WEC Energy Group subsidiaries. Lower expenses were due in part to a decrease in asset usage charges from WBS, driven by the transfer of this project from WBS to certain WEC Energy Group subsidiaries, including PGL and NSG, during 2017. The portion of these lower expenses related to the transfer are offset through higher depreciation and amortization, discussed above. |
| 2018 Form 10-K | 53 | WEC Energy Group, Inc. |
Other States Segment Contribution to Operating Income
Since the majority of MERC and MGU customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Natural gas revenues | $ | 438.2 | $ | 411.2 | $ | 376.5 | ||||||
| Cost of natural gas sold | 232.8 | 215.3 | 182.3 | |||||||||
| Total natural gas margins | 205.4 | 195.9 | 194.2 | |||||||||
| Other operation and maintenance | 101.0 | 101.1 | 108.8 | |||||||||
| Depreciation and amortization | 24.1 | 24.8 | 21.1 | |||||||||
| Property and revenue taxes | 11.5 | 15.6 | 13.1 | |||||||||
| Operating income | $ | 68.8 | $ | 54.4 | $ | 51.2 |
The following table shows a breakdown of other operation and maintenance:
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Operation and maintenance not included in line items below | $ | 76.1 | $ | 78.1 | $ | 85.1 | ||||||
| Regulatory amortizations and other pass through expenses * | 24.8 | 23.0 | 23.6 | |||||||||
| Other | 0.1 | — | 0.1 | |||||||||
| Total other operation and maintenance | $ | 101.0 | $ | 101.1 | $ | 108.8 |
| * | 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 delivered volumes by customer class and weather statistics:
| Therms (in millions) | |||||||||
| Natural Gas Sales Volumes | 2018 | 2017 | 2016 | ||||||
| Customer Class | |||||||||
| Residential | 336.1 | 285.6 | 278.5 | ||||||
| Commercial and industrial | 218.5 | 199.4 | 178.2 | ||||||
| Total retail | 554.6 | 485.0 | 456.7 | ||||||
| Transport | 738.7 | 693.3 | 696.2 | ||||||
| Total sales in therms | 1,293.3 | 1,178.3 | 1,152.9 |
| Degree Days | |||||||||
| Weather * | 2018 | 2017 | 2016 | ||||||
| MERC | |||||||||
| Heating (7,864 normal) | 8,490 | 7,625 | 7,188 | ||||||
| MGU | |||||||||
| Heating (6,240 normal) | 6,368 | 5,707 | 5,712 |
| * | Normal heating degree days for MERC and MGU are based on a 20-year moving average and 15-year moving average, respectively, of monthly temperatures from various weather stations throughout their respective territories. |
2018 Compared with 2017
Natural Gas Utility Margins
Natural gas utility margins increased $9.5 million during 2018, compared with 2017. The increase was primarily driven by colder winter weather as well as customer growth and an interim rate increase at MERC, partially offset by an $8.0 million decrease in margins related to savings from the Tax Legislation that we are required to return to customers through bill credits or reductions in
| 2018 Form 10-K | 54 | WEC Energy Group, Inc. |
future rates, related to the Tax Legislation signed into law in December 2017. See Note 14, Income Taxes, and Note 24, Regulatory Environment, for more information.
Operating Income
Operating income at the other states segment increased $14.4 million during 2018, compared with 2017. The increase was due to the $9.5 million increase in margins discussed above and a $4.9 million decrease in operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes). The decrease in operating expenses was primarily driven by lower property and revenue taxes resulting from a favorable judgment that MERC received related to a property tax matter. Because property taxes were under-recovered from rate payers in prior years, MERC will receive $4.8 million of the judgment, with any remaining amount passed back to customers through the property tax tracker that is now in place. The property tax tracker will allow for any future over- or under-recovered property tax expense to be recorded as a regulatory asset or liability. The balance in the regulatory asset or liability account will be reflected in the revenue requirement calculation in MERC's next general rate case.
2017 Compared with 2016
Operating Income
Operating income at the other states segment increased $3.2 million during 2017, compared with 2016. The increase was primarily driven by lower operation and maintenance expense due to effective cost control measures, partially offset by higher depreciation and amortization due to an increase in capital investment.
Non-Utility Energy Infrastructure Segment Contribution to Operating Income
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Operating income | $ | 365.8 | $ | 400.5 | $ | 375.6 |
2018 Compared with 2017
Operating income at the non-utility energy infrastructure segment decreased $34.7 million during 2018, compared with 2017. The decrease was driven by a $50.3 million decrease in revenue related to the Tax Legislation signed into law in December 2017. As a result of the Tax Legislation, the lease payments charged by We Power to WE were reduced to account for the lower tax rate. The reduction in the lease payments was offset by a decrease in income tax expense, resulting in no impact on net income. See Note 14, Income Taxes for more information. Partially offsetting the impact of the Tax Legislation was a $22.0 million contribution to operating income from Bluewater in 2018, compared to an $8.4 million contribution in 2017. Bluewater was acquired on June 30, 2017. See Note 2, Acquisitions, for more information.
2017 Compared with 2016
Operating income at the non-utility energy infrastructure segment increased $24.9 million during 2017, compared with 2016. Bluewater, which was acquired on June 30, 2017, contributed $8.4 million to 2017 operating income. The remaining increase of $16.5 million was driven by higher revenues in connection with capital additions to the plants We Power owns and leases to WE.
Corporate and Other Segment Contribution to Operating Income
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Operating loss | $ | (22.2 | ) | $ | (13.9 | ) | $ | (9.4 | ) |
2018 Compared with 2017
The operating loss at the corporate and other segment increased $8.3 million during 2018, compared with 2017, driven by a $4.0 million impairment loss recorded in 2018 on certain nonregulated assets that were acquired as a part of the acquisition of Integrys. Also contributing to the increase in operating loss was the transfer of assets from WBS, our centralized services company, to
| 2018 Form 10-K | 55 | WEC Energy Group, Inc. |
our regulated utilities in mid-2017 and early 2018. As a result of these transfers, the return on these assets is now recognized within our regulated utility operations.
2017 Compared with 2016
The operating loss at the corporate and other segment increased $4.5 million during 2017, compared with 2016, driven by the transfer of assets from WBS to our regulated utilities in mid-2017. As a result of these transfers, the return on these assets is now recognized within our regulated utility operations. Partially offsetting this increase in operating loss was the impact from $3.5 million of costs incurred in 2016 related to the acquisition of Integrys.
Electric Transmission Segment Operations
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Equity in earnings of transmission affiliates | $ | 136.7 | $ | 154.3 | $ | 146.5 |
2018 Compared with 2017
Earnings from our ownership interests in transmission affiliates decreased $17.6 million during 2018, compared with 2017, driven by the Tax Legislation signed into law in December 2017. The $34.3 million decrease in our equity earnings from ATC due to the Tax Legislation did not affect our net income as it was offset by an equal reduction in our income tax expense. See Note 14, Income Taxes, for more information. The negative impact of the Tax Legislation was partially offset by expenses recorded in 2017 by ATC related to the refund ATC was required to provide customers as a result of its FERC financial audit. Continued capital investment by our transmission affiliates also increased our equity earnings year over year.
2017 Compared with 2016
Earnings from our ownership interests in transmission affiliates increased $7.8 million during 2017, compared with 2016. The lower earnings during 2016 as compared to 2017 were primarily the result of an ALJ recommendation related to the FERC ROE complaints. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information.
Consolidated Other Income, Net
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| AFUDC – Equity | $ | 15.2 | $ | 11.4 | $ | 25.1 | ||||||
| Non-service credit (cost) components of net periodic benefit costs | 26.0 | 9.1 | (14.2 | ) | ||||||||
| Gain on repurchase of notes | — | — | 23.6 | |||||||||
| Other, net | 29.1 | 53.2 | 32.1 | |||||||||
| Other income, net | $ | 70.3 | $ | 73.7 | $ | 66.6 |
2018 Compared with 2017
Other income, net decreased $3.4 million during 2018, compared with 2017. A decrease of $23.3 million was due to $1.8 million of net losses from investments held in our rabbi trust during 2018, compared with net gains of $21.5 million during 2017. Partially offsetting this decrease was a $16.9 million increase in income due to higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 18, Employee Benefits, for more information on our benefit costs.
2017 Compared with 2016
Other income, net increased $7.1 million during 2017, compared with 2016, driven by the year-over-year increase in income from the non-service components of our net periodic pension and OPEB costs. Also contributing to the increase were higher gains on investments held in our rabbi trust during 2017, compared with 2016. These increases were partially offset by a $23.6 million gain recorded in February 2016 on the repurchase of a portion of Integrys's 2006 Junior Notes at a discount and lower AFUDC in 2017
| 2018 Form 10-K | 56 | WEC Energy Group, Inc. |
largely due to the ReACTTM emission control technology project at Weston Unit 3 going into service during the fourth quarter of 2016.
Consolidated Interest Expense
| Year Ended December 31 | ||||||||||||
| (in millions) | 2018 | 2017 | 2016 | |||||||||
| Interest expense | $ | 445.1 | $ | 415.7 | $ | 402.7 |
2018 Compared with 2017
Interest expense increased $29.4 million during 2018, compared with 2017. The increase was primarily due to higher debt balances and higher interest rates on both short-term and long-term debt. This increase in debt balances was primarily related to continued capital investments.
2017 Compared with 2016
Interest expense increased $13.0 million during 2017, compared with 2016. The increase was primarily due to higher debt levels in 2017 to fund continued capital investments and lower capitalized interest during 2017, primarily as a result of the completion of the ReACTTM emission control project in 2016.
Consolidated Income Tax Expense
| Year Ended December 31 | |||||||||
| 2018 | 2017 | 2016 | |||||||
| Effective tax rate | 13.8 | % | 24.1 | % | 37.6 | % |
2018 Compared with 2017
Our effective tax rate was 13.8% in 2018, compared to 24.1% in 2017. This decrease was primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement. See Note 14, Income Taxes, and Note 24, Regulatory Environment, for more information.
We expect our 2019 annual effective tax rate to be between 10.5% and 11.5%, which includes an estimated 9.5% effective tax rate benefit due to the flow through of tax repairs in connection with the Wisconsin rate settlement. Excluding the impact of the tax repairs, the expected 2019 range would be between 20% and 21%.
2017 Compared with 2016
Our effective tax rate was 24.1% in 2017, compared to 37.6% in 2016. The 13.5% decrease in the effective tax rate was driven by a $206.7 million one-time net reduction in income tax expense related to the revaluation of our deferred taxes primarily on our non-utility energy infrastructure and corporate and other segments at December 31, 2017, as a result of the enactment of the Tax Legislation. Our effective tax rate in 2017 excluding the one-time net reduction in income tax expense due to revaluation of our deferred taxes was 37.2%.
| 2018 Form 10-K | 57 | WEC Energy Group, Inc. |
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following table summarizes our cash flows during the years ended December 31:
| (in millions) | 2018 | 2017 | 2016 | Change in 2018 Over 2017 | Change in 2017 Over 2016 | |||||||||||||||
| Cash provided by (used in): | ||||||||||||||||||||
| Operating activities | $ | 2,445.5 | $ | 2,078.6 | $ | 2,103.8 | $ | 366.9 | $ | (25.2 | ) | |||||||||
| Investing activities | (2,384.4 | ) | (2,254.1 | ) | (1,354.2 | ) | (130.3 | ) | (899.9 | ) | ||||||||||
| Financing activities | 26.4 | 161.4 | (845.7 | ) | (135.0 | ) | 1,007.1 |
Operating Activities
2018 Compared with 2017
Net cash provided by operating activities increased $366.9 million during 2018, compared with 2017, driven by:
| • | A $396.1 million increase in cash related to higher overall collections from customers, primarily due to favorable weather during 2018, compared with 2017. |
| • | A $97.5 million increase in cash from lower payments for other operation and maintenance expenses. During 2018, our payments related to plant maintenance and labor costs decreased, due in part to the retirements in 2018 of the Pleasant Prairie power plant, Edgewater Unit 4, and Pulliam Units 7 and 8. See Note 6, Property, Plant, and Equipment, for more information about the retirement of our plants. In addition, our payments for transmission costs decreased during 2018. |
These increases in net cash provided by operating activities were partially offset by a $127.6 million decrease in cash resulting from higher payments during 2018, compared with 2017, for natural gas we purchased at the end of 2017 and during 2018 to meet the requirements of our customers during the colder winter weather.
2017 Compared with 2016
Net cash provided by operating activities decreased $25.2 million during 2017, compared with 2016, driven by:
| • | A $217.9 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power in 2017, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 13.6% during 2017, compared with 2016. |
| • | A $91.8 million increase in contributions and payments to our pension and OPEB plans during 2017, compared with 2016. |
| • | A $34.5 million net decrease in cash received from income taxes during 2017, compared with 2016. This decrease in cash was primarily due to the extension of bonus depreciation in December 2015, which resulted in the receipt of an income tax refund during 2016. |
| • | A $26.5 million decrease in cash due to higher collateral requirements during 2017, compared with 2016, driven by a decrease in the fair value of our derivative instruments. See Note 16, Derivative Instruments, for more information. |
These decreases in net cash provided by operating activities were partially offset by:
| • | A $158.7 million increase in cash from lower payments for operating and maintenance expenses. During 2017, our payments related to transmission, electric and natural gas distribution, charitable projects, employee benefits, and electric generation decreased. |
| • | A $129.2 million increase in cash related to higher overall collections from customers, primarily due to higher commodity prices during 2017, compared with 2016. |
| 2018 Form 10-K | 58 | WEC Energy Group, Inc. |
| • | A $49.6 million increase in cash distributions provided by ATC during 2017, compared with 2016. |
Investing Activities
2018 Compared with 2017
Net cash used in investing activities increased $130.3 million during 2018, compared with 2017, driven by:
| • | The acquisition of a 90% ownership interest in Bishop Hill III during 2018 for $162.9 million, which is net of restricted cash acquired of $4.5 million. See Note 2, Acquisitions, for more information. |
| • | A $156.2 million increase in cash paid for capital expenditures during 2018, compared with 2017, which is discussed in more detail below. |
| • | The acquisition of a portion of Forward Wind Energy Center during April 2018 for $77.1 million. See Note 2, Acquisitions, for more information. |
| • | The acquisition of an 80% ownership interest in Coyote Ridge during December 2018 for $61.4 million. See Note 2, Acquisitions, for more information. |
These increases in net cash used in investing activities were partially offset by:
| • | The acquisition of Bluewater during June 2017 for $226.0 million. See Note 2, Acquisitions, for more information. |
| • | A $56.1 million decrease in our capital contributions to ATC and ATC Holdco during 2018, compared with 2017, due to the restructuring of DATC's ownership. During the fourth quarter of 2017, ATC Holdco purchased ATC's ownership interest in DATC, which resulted in higher capital contributions during 2017. Our capital contributions also decreased due to the refunds ATC paid in 2017 as a result of the ATC ROE complaints filed with the FERC, which were partially funded by capital contributions. See Factors Affecting Results, Liquidity, and Capital Resources – Other Matters – American Transmission Company Allowed Return on Equity Complaints for more information on the ATC ROE complaints. |
| • | A $48.6 million net increase in restricted cash during 2018, compared with 2017, due to a $109.9 million increase in the proceeds received from the sale of investments held in the Integrys rabbi trust, partially offset by a $61.3 million increase in the purchase of investments held in the rabbi trust. |
2017 Compared with 2016
Net cash used in investing activities increased $899.9 million during 2017, compared with 2016, driven by:
| • | A $535.8 million increase in cash paid for capital expenditures during 2017, compared with 2016, which is discussed in more detail below. |
| • | The acquisition of Bluewater during June 2017 for $226.0 million. See Note 2, Acquisitions, for more information. |
| • | A $142.3 million decrease in the proceeds received from the sale of assets and businesses during 2017, compared with 2016. See Note 3, Dispositions, for more information. |
| • | A $67.3 million increase in our capital contributions to ATC and ATC Holdco during 2017, compared with 2016, due to the continued investment in equipment and facilities by ATC to improve reliability and the restructuring of DATC's ownership. In addition, the refunds paid by ATC in 2017 and ATC's lower earnings in 2016, as a result of the ATC ROE complaints filed with the FERC, also contributed to the year-over-year increase in our capital contributions. |
These increases in net cash used in investing activities were partially offset by a $62.5 million increase in restricted cash during 2017, compared with 2016, due to a $55.5 million decrease in the purchase of investments held in the Integrys rabbi trust and a $7.0 million increase in the proceeds received from the sale of investments held in the rabbi trust.
| 2018 Form 10-K | 59 | WEC Energy Group, Inc. |
Capital Expenditures
Capital expenditures by segment for the years ended December 31 were as follows:
| Reportable Segment (in millions) | 2018 | 2017 | 2016 | Change in 2018 Over 2017 | Change in 2017 Over 2016 | |||||||||||||||
| Wisconsin | $ | 1,389.0 | $ | 1,152.3 | $ | 910.9 | $ | 236.7 | $ | 241.4 | ||||||||||
| Illinois | 547.1 | 545.2 | 293.2 | 1.9 | 252.0 | |||||||||||||||
| Other states | 103.6 | 74.5 | 59.5 | 29.1 | 15.0 | |||||||||||||||
| Non-utility energy infrastructure | 36.3 | 35.4 | 62.3 | 0.9 | (26.9 | ) | ||||||||||||||
| Corporate and other | 39.7 | 152.1 | 97.8 | (112.4 | ) | 54.3 | ||||||||||||||
| Total capital expenditures | $ | 2,115.7 | $ | 1,959.5 | $ | 1,423.7 | $ | 156.2 | $ | 535.8 |
2018 Compared with 2017
The increase in cash paid for capital expenditures at the Wisconsin segment during 2018, compared with 2017, was primarily driven by the construction of the new natural gas-fired generation facility in the Upper Peninsula of Michigan and an advanced metering infrastructure program. An information technology project created to improve WE's and WG's billing, call center, and credit collection functions, a natural gas lateral project at WPS's Fox Energy Center, and various other software projects also contributed to the increase in our capital expenditures.
The increase in cash paid for capital expenditures at the other states segment during 2018, compared with 2017, was primarily driven by upgrades to MERC's natural gas distribution systems.
The decrease in cash paid for capital expenditures at the corporate and other segment during 2018, compared with 2017, was primarily driven by the implementation of a new enterprise resource planning system during the first quarter of 2018. The 2017 completion of an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries reduced our capital expenditures as well. Various other software projects, the majority of which were completed during 2017, also contributed to the decrease in our capital expenditures.
See Capital Resources and Requirements – Capital Requirements – Capital Expenditures and Significant Capital Projects below for more information.
2017 Compared with 2016
The increase in cash paid for capital expenditures at the Wisconsin segment during 2017, compared with 2016, was primarily driven by upgrades to our electric and natural gas distribution systems, including main replacement projects and an advanced metering infrastructure program, as well as WPS's SMRP and various projects at the OCPP. These increases in capital expenditures were partially offset by reduced construction activity at WPS related to the ReACTTM emission control technology project at Weston Unit 3, which was completed in 2016, and the combustion turbine project at the Fox Energy Center, which was completed in June 2017.
The increase in cash paid for capital expenditures at the Illinois segment during 2017, compared with 2016, was primarily driven by increased construction activity related to PGL's SMP, its natural gas storage field, and a project to relocate one of PGL's service facilities.
The increase in cash paid for capital expenditures at the other states segment during 2017, compared with 2016, was primarily driven by upgrades to MERC’s natural gas distribution systems and mains as well as the construction of an office building due to the relocation of MERC's headquarters during 2017.
The decrease in cash paid for capital expenditures at the non-utility energy infrastructure segment during 2017, compared with 2016, was primarily driven by reduced construction activity for We Power's fuel flexibility project at the Oak Creek Expansion units, which was completed during December 2017.
The increase in cash paid for capital expenditures at the corporate and other segment during 2017, compared with 2016, was primarily driven by a project to implement a new enterprise resource planning system and various other software projects.
| 2018 Form 10-K | 60 | WEC Energy Group, Inc. |
Financing Activities
2018 Compared with 2017
Net cash provided by financing activities decreased $135.0 million during 2018, compared with 2017, driven by:
| • | A $798.8 million decrease in cash related to higher repayments of long-term debt during 2018, compared with 2017. |
| • | A $588.9 million net decrease in cash due to $4.5 million of net repayments of commercial paper during 2018, compared with $584.4 million of net borrowings of commercial paper during 2017. |
| • | A $40.8 million decrease in cash due to higher dividends paid on our common stock during 2018, compared with 2017. In January 2018, our Board of Directors increased our quarterly dividend by $0.0325 per share (6.25%) effective with the first quarter of 2018 dividend payment. |
These decreases in net cash provided by financing activities were partially offset by a $1,305.0 million increase in cash due to the issuance of more long-term debt during 2018, compared with 2017.
2017 Compared with 2016
Net cash related to financing activities increased $1,007.1 million during 2017, compared with 2016, driven by:
| • | An $819.2 million net increase in cash due to $584.4 million of net borrowings of commercial paper during 2017, compared with $234.8 million of net repayments of commercial paper during 2016. |
| • | A $151.5 million increase in cash related to lower repayments of long-term debt during 2017, compared with 2016. In February 2016, we repurchased a portion of Integrys's 2006 Junior Notes at a discount. |
| • | A $36.7 million increase in cash due to fewer shares of our common stock purchased during 2017, compared with 2016, to satisfy requirements of our stock-based compensation plans. |
| • | A $35.0 million increase in cash due to the issuance of more long-term debt during 2017, compared with 2016. |
These increases in net cash related to financing activities were partially offset by a $31.6 million decrease in cash related to higher dividends paid on our common stock during 2017, compared with 2016. In January 2017, our Board of Directors increased our quarterly dividend by $0.025 per share effective with the first quarter of 2017 dividend payment.
Significant Financing Activities
For more information on our financing activities, see Note 12, Short-Term Debt and Lines of Credit, and Note 13, Long-Term Debt and Capital Lease Obligations.
Capital Resources and Requirements
Capital Resources
Liquidity
We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors.
We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets, and internally generated cash.
| 2018 Form 10-K | 61 | WEC Energy Group, Inc. |
WEC Energy Group, WE, WG, WPS, and PGL maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 12, Short-Term Debt and Lines of Credit, for more information about these credit facilities.
The following table shows our capitalization structure as of December 31, 2018 and 2017, as well as an adjusted capitalization structure that we believe is consistent with how a majority of the rating agencies currently view our 2007 Junior Notes:
| 2018 | 2017 | |||||||||||||||
| (in millions) | Actual | Adjusted | Actual | Adjusted | ||||||||||||
| Common equity | $ | 9,788.9 | $ | 10,038.9 | $ | 9,461.4 | $ | 9,711.4 | ||||||||
| Preferred stock of subsidiary | 30.4 | 30.4 | 30.4 | 30.4 | ||||||||||||
| Long-term debt (including current portion) | 10,359.0 | 10,109.0 | 9,588.7 | 9,338.7 | ||||||||||||
| Short-term debt | 1,440.1 | 1,440.1 | 1,444.6 | 1,444.6 | ||||||||||||
| Total capitalization | $ | 21,618.4 | $ | 21,618.4 | $ | 20,525.1 | $ | 20,525.1 | ||||||||
| Total debt | $ | 11,799.1 | $ | 11,549.1 | $ | 11,033.3 | $ | 10,783.3 | ||||||||
| Ratio of debt to total capitalization | 54.6 | % | 53.4 | % | 53.8 | % | 52.5 | % |
Included in long-term debt on our balance sheets as of December 31, 2018 and 2017, is $500.0 million principal amount of 2007 Junior Notes. The adjusted presentation attributes $250.0 million of the 2007 Junior Notes to common equity and $250.0 million to long-term debt.
The adjusted presentation of our consolidated capitalization structure is included as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages our capitalization structure, including our total debt to total capitalization ratio, using the GAAP calculation as adjusted by certain rating agencies' treatment of the 2007 Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.
For a summary of the interest rate, maturity, and amount outstanding of each series of our long-term debt on a consolidated basis, see our capitalization statements.
As described in Note 10, Common Equity, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.
At December 31, 2018, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 12, Short-Term Debt and Lines of Credit, for more information about our credit facilities and other short-term credit agreements. See Note 13, Long-Term Debt and Capital Lease Obligations, for more information about our long-term debt.
Working Capital
As of December 31, 2018, our current liabilities exceeded our current assets by $1,084.1 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, 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.
| 2018 Form 10-K | 62 | WEC Energy Group, Inc. |
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 January 2018, Moody's downgraded the rating outlook for WG to negative from stable as a result of the new Tax Legislation. The change in rating outlook has not had, and we do not believe that it will have, a material impact on our ability to access capital markets.
In July 2018, Moody's downgraded the ratings of WEC Energy Group (senior unsecured), WECC (senior unsecured), and Integrys (senior unsecured) to Baa1 from A3. Moody's also downgraded the ratings of WEC Energy Group (junior subordinated) and Integrys (junior subordinated) to Baa2 from Baa1. Reduced cash flow due to Tax Legislation, which impacted the majority of companies in our industry, was a catalyst for the downgrade. Moody's affirmed the commercial paper ratings of WEC Energy Group (senior unsecured, P-2), and Integrys (senior unsecured, P-2) and changed the rating outlook for WEC Energy Group, WECC, and Integrys, to stable from rating under review.
Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.
If we are unable to successfully take actions to manage any additional adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our or our subsidiaries’ credit ratings on negative outlook or additional downgrading of our or our subsidiaries' credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us and our subsidiaries to issue future debt securities and certain other types of financing and could increase borrowing costs under our and our subsidiaries’ credit facilities.
Capital Requirements
Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31, 2018:
| Payments Due by Period (1) | ||||||||||||||||||||
| (in millions) | Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years | |||||||||||||||
| Long-term debt obligations (2) | $ | 19,244.9 | $ | 810.8 | $ | 2,854.8 | $ | 820.0 | $ | 14,759.3 | ||||||||||
| Capital lease obligations (3) | 56.7 | 15.5 | 33.6 | 7.6 | — | |||||||||||||||
| Operating lease obligations (4) | 86.9 | 8.7 | 15.5 | 14.0 | 48.7 | |||||||||||||||
| Energy and transportation purchase obligations (5) | 12,002.8 | 1,211.9 | 1,926.7 | 1,755.2 | 7,109.0 | |||||||||||||||
| Purchase orders (6) | 834.2 | 411.3 | 260.4 | 85.6 | 76.9 | |||||||||||||||
| Pension and OPEB funding obligations (7) | 69.7 | 12.6 | 57.1 | — | — | |||||||||||||||
| Total contractual obligations | $ | 32,295.2 | $ | 2,470.8 | $ | 5,148.1 | $ | 2,682.4 | $ | 21,993.9 |
| (1) | The amounts included in the table are calculated using current market prices, forward curves, and other estimates. |
| (2) | Principal and interest payments on long-term debt (excluding capital lease obligations). The interest due on our variable rate debt is based on the interest rates that were in effect on December 31, 2018. |
| (3) | Capital lease obligations for power purchase commitments. This amount does not include We Power leases to WE which are eliminated upon consolidation. |
| (4) | Operating lease obligations for office space, land, and rail car leases. |
| (5) | Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility and non-utility operations. |
| (6) | Purchase obligations related to normal business operations, information technology, and other services. |
| 2018 Form 10-K | 63 | WEC Energy Group, Inc. |
| (7) | Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2021. |
The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note 14, Income Taxes.
The table above also does not reflect estimated future payments related to the manufactured gas plant remediation liability of $616.4 million at December 31, 2018, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 22, Commitments and Contingencies, for more information about environmental liabilities.
AROs in the amount of $461.4 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years. See Note 8, Asset Retirement Obligations, for more information.
Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.
Capital Expenditures and Significant Capital Projects
We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, impacts from the Tax Legislation, additional changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures and acquisitions for the next three years are as follows:
| (in millions) | 2019 | 2020 | 2021 | |||||||||
| Wisconsin | $ | 1,344.9 | $ | 1,677.5 | $ | 1,559.1 | ||||||
| Illinois | 765.2 | 684.0 | 602.4 | |||||||||
| Other states | 155.4 | 135.8 | 105.5 | |||||||||
| Non-utility energy infrastructure | 424.2 | 418.8 | 242.8 | |||||||||
| Corporate and other | 15.7 | 11.0 | 1.1 | |||||||||
| Total | $ | 2,705.4 | $ | 2,927.1 | $ | 2,510.9 |
WPS is continuing work on the SMRP. This project includes modernizing parts of its electric distribution system, including burying or upgrading lines. The project focuses on constructing facilities to improve the reliability of electric service WPS provides to its customers. WPS expects to invest approximately $185 million between 2019 and 2022 on this project. WE, WPS, and WG will also continue to upgrade their 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.
As part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar of up to 350 MW within our Wisconsin segment. WPS has partnered with an unaffiliated utility to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. WPS will own 100 MW of the output of each project for a total of 200 MW. WPS's share of the cost of both projects is estimated to be $260 million. Subject to the receipt of PSCW approval, commercial operation for both projects is targeted for the end of 2020. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.
In connection with the formation of UMERC, we entered into an agreement with Tilden under which it will purchase electric power from UMERC for 20 years, contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. The new generation is expected to begin commercial operation during the second quarter of 2019. The estimated cost of this project is approximately $266 million ($277 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers.
PGL is continuing work on the SMP, a project under which PGL is replacing approximately 2,000 miles of Chicago's aging natural gas pipeline infrastructure. PGL currently recovers these costs through a surcharge on customer bills pursuant to an ICC approved QIP
| 2018 Form 10-K | 64 | WEC Energy Group, Inc. |
rider, which is in effect through 2023. PGL's projected average annual investment through 2021 is between $280 million and $300 million. See Note 24, Regulatory Environment, for more information on the SMP.
The non-utility energy infrastructure segment includes our investments in Bishop Hill III, Coyote Ridge, and Upstream. See Note 2, Acquisitions, for more information on these wind projects.
We expect to provide capital contributions to ATC and ATC Holdco (not included in the above table) of approximately $185 million from 2019 through 2021.
Common Stock Matters
For information related to our common stock matters, see Note 10, Common Equity.
On January 17, 2019, our Board of Directors increased our quarterly dividend to $0.59 per share effective with the first quarter of 2019 dividend payment, which equates to an annual dividend of $2.36 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.
Investments in Outside Trusts
We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $3.5 billion as of December 31, 2018. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $77.6 million, $120.5 million, and $28.7 million to our pension and OPEB plans in 2018, 2017, and 2016, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 18, Employee Benefits.
Off-Balance Sheet Arrangements
We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit that support construction projects, commodity contracts, and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future 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 12, Short-Term Debt and Lines of Credit, Note 17, Guarantees, and Note 21, Variable Interest Entities.
FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES
Market Risks and Other Significant Risks
We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks, described in further detail below, include but are not limited to:
Regulatory Recovery
Our utilities account for their regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by various regulatory commissions. See Item 1. Business – D. Regulation for more information on these commissions.
Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs, including those referenced below, is not approved by our regulators, the costs would be charged to income in the current period. In general, our regulatory assets are recovered over a period of between one to six years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2018, our regulatory assets were $3,855.8 million, and our regulatory liabilities were $4,288.4 million.
| 2018 Form 10-K | 65 | WEC Energy Group, Inc. |
Due to the Tax Legislation signed into law in December 2017, our regulated utilities remeasured their deferred taxes and recorded a tax benefit of $2,450 million. Our utilities have been returning this tax benefit to ratepayers through refunds, bill credits, riders, and reductions to other regulatory assets, which we expect to continue. See Note 14, Income Taxes, and Note 24, Regulatory Environment, for more information.
We expect to request or have requested recovery of the costs related to the following projects discussed in recent or pending rate proceedings, orders, and investigations involving our utilities:
| • | In June 2016, the PSCW approved the deferral of costs related to WPS's ReACT™ project above the originally authorized $275.0 million level through 2017. The total cost of the ReACT™ project, excluding $51 million of AFUDC, was $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. See Note 24, Regulatory Environment, for more information. WPS will be required to obtain a separate approval for collection of these deferred costs in a future rate case. |
| • | Prior to its acquisition by us, Integrys initiated an information technology project with the goal of improving the customer experience at its subsidiaries. Specifically, the project is expected to provide functional and technological benefits to the billing, call center, and credit collection functions. As of December 31, 2018, we had not received any significant disallowances of the costs incurred for this project. We will be required to obtain approval for the recovery of additional costs incurred through the completion of this long-term project. |
| • | In January 2014, the ICC approved PGL's use of the QIP rider as a recovery mechanism for costs incurred related to investments in QIP. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2018, PGL filed its 2017 reconciliation with the ICC, which, along with the 2016 and 2015 reconciliations, are still pending. In 2018, PGL agreed to a settlement of the 2014 reconciliation, which included a rate base reduction of $5.4 million and a $4.7 million refund to ratepayers. As of December 31, 2018, there can be no assurance that all costs incurred under the QIP rider during the open reconciliation years will be deemed recoverable by the ICC. |
See Note 24, Regulatory Environment, for more information regarding recent and pending rate proceedings, orders, and investigations involving our utilities.
Commodity Costs
In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.
Embedded within our utilities' rates are amounts to recover fuel, natural gas, and purchased power costs. Our utilities have recovery mechanisms in place that allow them to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – D. Regulation for more information on these mechanisms.
Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 1(d), Operating Revenues, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.
Weather
Our utilities' rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating season. PGL, NSG, and MERC have decoupling mechanisms in place that help reduce the impacts of weather. Decoupling mechanisms differ by state and allow utilities to recover or refund certain differences between actual and authorized margins. A
| 2018 Form 10-K | 66 | WEC Energy Group, Inc. |
summary of actual weather information in our utilities' service territories during 2018, 2017, and 2016, as measured by degree days, may be found in Results of Operations.
Interest Rates
We are exposed to interest rate risk resulting from our short-term and long-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt. We may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure.
Based on the variable rate debt outstanding at December 31, 2018, and December 31, 2017, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $16.9 million and $20.6 million in 2018 and 2017, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.
Marketable Securities Return
We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.
The fair value of our trust fund assets and expected long-term returns were approximately:
| (in millions) | As of December 31, 2018 | Expected Return on Assets in 2019 | |||||
| Pension trust funds | $ | 2,690.8 | 7.12 | % | |||
| OPEB trust funds | $ | 771.7 | 7.25 | % |
Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.
We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.
Economic Conditions
We have electric and natural gas utility operations that serve customers in Wisconsin, Illinois, Michigan, and Minnesota. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.
Inflation
We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.
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For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.
Competitive Markets
Electric Utility Industry
The regulated energy industry continues to experience significant changes. The FERC continues to support large RTOs, which affects the structure of the wholesale market. To this end, MISO implemented the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when, if at all, retail choice might be implemented in Wisconsin. However, Michigan has adopted a limited retail choice program.
Wisconsin
Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.
Michigan
Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. As a result, some of our small retail customers have switched to an alternative electric supplier. At December 31, 2018, Michigan law limited customer choice to 10% of an electric utility's Michigan retail load, but this cap could potentially be reduced in future years due to the December 2016 passage of Michigan Act 341. Based on current law, our iron ore mine customer, Tilden, is exempt from the 10% cap. In addition, certain load increases by facilities already using an alternative electric supplier can still be serviced by their alternative electric supplier, when various conditions exist, even if the cap has already been met. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.
Natural Gas Utility Industry
We offer natural gas transportation services to our customers that elect to purchase natural gas from an alternative retail natural gas supplier. Since these transportation customers continue to use our distribution systems to transport natural gas to their facilities, we earn distribution revenues from them. As such, there is little impact on our net income from customers purchasing natural gas from an alternative retail natural gas supplier as natural gas costs are passed through to customers in rates on a one-for-one basis.
Wisconsin
The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to provide customer classes with competitive markets the option to choose an alternative retail natural gas supplier. The PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates. All of our Wisconsin customer classes have competitive market choices and, therefore, can purchase natural gas directly from either an alternative retail natural gas supplier or their local natural gas utility. We are currently unable to predict the impact of potential future industry restructuring on our results of operations or financial position.
Illinois
Since 2002, PGL and NSG have provided their customers with the option to choose an alternative retail natural gas supplier. We are not required by the ICC or state law to make this option available to customers, but since this option is currently provided to our Illinois customers, we would need ICC approval to eliminate it.
| 2018 Form 10-K | 68 | WEC Energy Group, Inc. |
Minnesota
MERC has provided its commercial and industrial customers with the option to choose an alternative retail natural gas supplier since 2006. We are not required by the MPUC or state law to make this option available to customers, but since this option is currently provided to our Minnesota commercial and industrial customers, we would need MPUC approval to eliminate it.
Michigan
The option to choose an alternative retail natural gas supplier has been provided to UMERC’s customers (formerly WPS’s Michigan customers) since the late 1990s and MGU's customers since 2005. We are not required by the MPSC or state law to make this option available to customers, but since this option is currently provided to our Michigan customers, we would need MPSC approval to eliminate it.
Environmental Matters
See Note 22, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.
Other Matters
Tax Cuts and Jobs Act of 2017
In December 2017, the Tax Legislation was signed into law. The PSCW and the MPSC have issued written orders regarding how to refund certain tax savings from the Tax Legislation to ratepayers in Wisconsin and Michigan, respectively, and the ICC has approved the VITA in Illinois. In Minnesota, the MPUC addressed the various impacts of the Tax Legislation in MERC's 2018 rate case. We are also working with the FERC to modify our formula rate tariffs for the impacts of the Tax Legislation, and we expect to receive FERC approval for the modified tariffs in 2019. See Note 24, Regulatory Environment, for more information.
American Transmission Company Allowed Return on Equity Complaints
In November 2013, a group of MISO industrial customer organizations filed a complaint with the FERC requesting to reduce the base ROE used by MISO transmission owners, including ATC, from 12.2% to 9.15%. In October 2014, the FERC issued an order to hear the complaint on ROE and set a refund effective date retroactive to November 2013. In December 2015, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 10.32%, as well as the 0.5% incentive adder approved by the FERC in January 2015 for MISO transmission owners. The incentive adder only applies to revenues collected after January 6, 2015. In September 2016, the FERC issued an order related to this complaint affirming the use of the ROE stated in the ALJ's initial decision, effective as of the order date, on a going-forward basis. The order also required ATC to provide refunds, with interest, for the 15-month refund period from November 12, 2013, through February 11, 2015. The $28.3 million refund that ATC provided to WE and WPS for transmission costs paid during the refund period reduced the regulatory assets recorded under the PSCW-approved escrow accounting for transmission expense and resulted in a net regulatory liability for WPS.
In February 2015, a second complaint was filed with the FERC requesting a reduction in the base ROE used by MISO transmission owners, including ATC, to 8.67%, with a refund effective date retroactive to February 12, 2015. In June 2016, the ALJ issued an initial decision recommending that ATC and all other MISO transmission owners be authorized to collect a base ROE of 9.7%, as well as the 0.5% incentive adder approved for MISO transmission owners. The ALJ's initial decision is not binding on the FERC and applies to revenues collected from February 12, 2015, through May 11, 2016. We are uncertain when a FERC order related to this matter will be issued.
The MISO transmission owners have filed various appeals related to several of the FERC orders with the D.C. Circuit Court of Appeals as well as requests for rehearing.
In November 2018, the FERC issued an order directing MISO transmission owners, including ATC, to submit briefs on a proposed change to the methodology used to calculate their base ROE. If the proposed methodology is approved, ATC’s base ROE for the period from November 12, 2013 through February 11, 2015 would be 10.28% instead of the 10.32% approved by the FERC in September 2016. The proposed methodology would also impact the second complaint filed in February 2015 and ATC’s base ROE going forward. We are uncertain when a final FERC order related to the proposed methodology will be issued.
| 2018 Form 10-K | 69 | WEC Energy Group, Inc. |
Bonus Depreciation Provisions
Bonus depreciation is an additional amount of first-year tax deductible depreciation that is awarded above what would normally be available. The bonus depreciation deduction available for public utility property subject to rate-making by a government entity or public utility commission was modified by the Tax Legislation signed into law on December 22, 2017. Based on the provisions of the Tax Legislation, bonus depreciation can no longer be deducted for public utility property acquired and placed in service after December 31, 2017. The provisions of the Tax Legislation regarding the repeal of bonus depreciation do not apply to some of our non-utility investments.
Critical Accounting Policies and Estimates
Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgments.
Goodwill
We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2018. No impairments were recorded as a result of these tests. For all of our reporting units, the fair values calculated in step one of the test were greater than their carrying values. The fair values for the reporting units were calculated using a combination of the income approach and the market approach.
For the income approach, we used internal forecasts to project cash flows. Any forecast contains a degree of uncertainty, and changes in these cash flows could significantly increase or decrease the calculated fair value of a reporting unit. Since all of our reporting units containing goodwill are regulated, a fair recovery of and return on costs prudently incurred to serve customers is assumed. An unfavorable outcome in a rate case could cause the fair values of our reporting units to decrease.
Key assumptions used in the income approach include ROEs, long-term growth rates used to determine terminal values at the end of the discrete forecast period, and discount rates. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The discount rate is based on the weighted-average cost of capital for each reporting unit, taking into account both the after-tax cost of debt and cost of equity. The terminal year ROE for each utility is driven by its current allowed ROE. The terminal growth rate is based primarily on a combination of historical and forecasted statistics for real gross domestic product and personal income for each utility service area.
For the market approach, we used an equal weighting of the guideline public company method and the guideline merged and acquired company method. The guideline public company method uses financial metrics from similar publicly traded companies to determine fair value. The guideline merged and acquired company method calculates fair value by analyzing the actual prices paid for recent mergers and acquisitions in the industry. We applied multiples derived from these two methods to the appropriate operating metrics for our reporting units to determine fair value.
The underlying assumptions and estimates used in the impairment tests were made as of a point in time. Subsequent changes in these assumptions and estimates could change the results of the tests.
For all of our reporting units, fair value exceeded carrying value by over 50%. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.
| 2018 Form 10-K | 70 | WEC Energy Group, Inc. |
Our reporting units had the following goodwill balances at July 1, 2018:
| (in millions, except percentages) | Goodwill | Percentage of Total Goodwill | |||||
| Wisconsin | $ | 2,104.3 | 68.9 | % | |||
| Illinois | 758.7 | 24.9 | % | ||||
| Other states | 183.2 | 6.0 | % | ||||
| Bluewater | 6.6 | 0.2 | % | ||||
| Total goodwill | $ | 3,052.8 | 100.0 | % |
See Note 9, Goodwill, for more information.
Long-Lived Assets
In accordance with ASC 360, Property, Plant, and Equipment, we periodically assess the recoverability of certain long-lived assets when events or changes in circumstances indicate that the carrying amount of those long-lived assets may not be recoverable. Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, and assets within nonregulated operations that are proposed to be sold or are currently generating operating losses.
We have evaluated future plans for our older and less efficient fossil fuel generating units and have either retired or announced the retirement of certain generating units. In accordance with ASC 980-360, Regulated Operations – Property, Plant, and Equipment, when it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. As a result, the remaining net book value of these assets can be significant. If a generating unit meets applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining carrying value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining carrying value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers.
Pleasant Prairie power plant, Pulliam Units 7 and 8, and the jointly-owned Edgewater 4 generating unit were retired during 2018. PIPP continued to meet the criteria to be considered probable of abandonment as of December 31, 2018. We plan to ask for full cost recovery of and a full return on the remaining book value of these generating units and have concluded that no impairment was required related to these assets as of December 31, 2018. See Note 6, Property, Plant, and Equipment, for more information on our retired generating units, including various approvals we have received from the FERC.
Pension and Other Postretirement Employee Benefits
The costs of providing non-contributory defined pension benefits and OPEB, described in Note 18, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.
Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded at our utilities through the rate-making process.
| 2018 Form 10-K | 71 | WEC Energy Group, Inc. |
The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
| Actuarial Assumption (in millions, except percentages) | Percentage-Point Change in Assumption | Impact on Projected Benefit Obligation | Impact on 2018 Pension Cost | |||||||
| Discount rate | (0.5) | $ | 178.3 | $ | 19.9 | |||||
| Discount rate | 0.5 | (159.8 | ) | (13.6 | ) | |||||
| Rate of return on plan assets | (0.5) | N/A | 13.6 | |||||||
| Rate of return on plan assets | 0.5 | N/A | (13.6 | ) |
The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
| Actuarial Assumption (in millions, except percentages) | Percentage-Point Change in Assumption | Impact on Postretirement Benefit Obligation | Impact on 2018 Postretirement Benefit Cost | |||||||
| Discount rate | (0.5) | $ | 36.6 | $ | 2.8 | |||||
| Discount rate | 0.5 | (33.0 | ) | (1.1 | ) | |||||
| Health care cost trend rate | (0.5) | (18.9 | ) | (3.9 | ) | |||||
| Health care cost trend rate | 0.5 | 21.7 | 4.5 | |||||||
| Rate of return on plan assets | (0.5) | N/A | 4.1 | |||||||
| Rate of return on plan assets | 0.5 | N/A | (4.1 | ) |
The discount rates are selected based on hypothetical bond portfolios consisting of noncallable (or callable with make-whole provisions), noncollateralized, high-quality corporate bonds across the full maturity spectrum. The bonds are generally rated "Aa" with a minimum amount outstanding of $50.0 million. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.
We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.12%, 7.11%, and 7.12%, in 2018, 2017, and 2016, respectively. The actual rate of return on pension plan assets, net of fees, was (4.30)%, 13.74%, and 7.75%, in 2018, 2017, and 2016, respectively.
In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 18, Employee Benefits.
Regulatory Accounting
Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC. Our financial statements reflect the effects of the rate-making principles followed by the various jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators.
Future recovery of regulatory assets is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, and the status of any pending or potential deregulation legislation.
The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2018, we had
| 2018 Form 10-K | 72 | WEC Energy Group, Inc. |
$3,855.8 million in regulatory assets and $4,288.4 million in regulatory liabilities. See Note 5, Regulatory Assets and Liabilities, for more information.
Unbilled Revenues
We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2018 of approximately $7.6 billion included accrued utility revenues of $497.7 million as of December 31, 2018.
Income Tax Expense
We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to income tax expense in our income statements.
Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.
Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(m), Income Taxes, and Note 14, Income Taxes, for a discussion of accounting for income taxes.
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