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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 and Bluewater, which owns underground natural gas storage facilities in Michigan.
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. We expect to retire approximately 1,800 MW of coal generation by 2020, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. See Note 5, Property, Plant, and Equipment, for information related to the planned retirements of certain of our coal-fueled power plants.
Reliability
We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility in the United States in 2017 and, for the seventh year in a row, as the most reliable utility in the Midwest.
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 in 2019 and provide the region with affordable, reliable electricity that generates less emissions than the Presque Isle Power Plant (PIPP). This should allow for the retirement of PIPP no later than 2020. We began site preparation work for this new generation in October 2017. For more information, see Note 23, Regulatory Environment. |
| • | 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. |
| • | Wisconsin Public Service Corporation (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, Wisconsin Electric Power Company and Wisconsin Gas LLC also continue to upgrade their electric and natural gas distribution systems to enhance reliability. |
| 2017 Form 10-K | 43 | WEC Energy Group, Inc. |
Operating Efficiency
We continually look for ways to optimize the operating efficiency of our company. For example, we made further investments at the Elm Road Generating Station in 2017 to enable the facility to burn coal from the Powder River Basin located in the western United States. The plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibility and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.
We also made 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 a portion of a wind energy generation facility in Wisconsin. |
| • | See Note 3, Dispositions, for information on the sale of Integrys Transportation Fuels, LLC, the Milwaukee County Power Plant, certain assets of Wisvest LLC, and Bostco LLC's real estate holdings. |
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 billion from 2018 to 2022. Specific projects are discussed in more detail below under Liquidity and Capital Resources.
From 2018 to 2022, we expect capital contributions to ATC and ATC Holdco to be approximately $280 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 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 $1.3 billion inside the traditional ATC footprint and $300 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
| 2017 Form 10-K | 44 | WEC Energy Group, Inc. |
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) | 2017 | 2016 | 2015 | |||||||||
| Wisconsin | $ | 1,065.9 | $ | 1,027.0 | $ | 884.2 | ||||||
| Illinois | 273.0 | 239.6 | 78.1 | |||||||||
| Other states | 54.2 | 49.9 | 6.0 | |||||||||
| Non-utility energy infrastructure | 400.5 | 375.6 | 373.4 | |||||||||
| Corporate and other | (8.4 | ) | (10.0 | ) | (91.2 | ) | ||||||
| Total operating income | 1,785.2 | 1,682.1 | 1,250.5 | |||||||||
| Equity in earnings of transmission affiliates | 154.3 | 146.5 | 96.1 | |||||||||
| Other income, net | 64.6 | 80.8 | 58.9 | |||||||||
| Interest expense | 415.7 | 402.7 | 331.4 | |||||||||
| Income before income taxes | 1,588.4 | 1,506.7 | 1,074.1 | |||||||||
| Income tax expense | 383.5 | 566.5 | 433.8 | |||||||||
| Preferred stock dividends of subsidiary | 1.2 | 1.2 | 1.8 | |||||||||
| Net income attributed to common shareholders | $ | 1,203.7 | $ | 939.0 | $ | 638.5 | ||||||
| Diluted earnings per share | $ | 3.79 | $ | 2.96 | $ | 2.34 |
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 $38.9 million pre-tax ($23.3 million after 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 $33.4 million pre-tax ($20.0 million after 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. |
| • | A $24.9 million pre-tax ($14.9 million after 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. |
These increases in earnings were partially offset by a $16.2 million pre-tax ($9.7 million after-tax) decrease in other income, net. The decrease was primarily driven by the year-over-year impact of the gains recognized in 2016 related to the repurchase of a portion of Integrys's 2006 Junior Notes and the sale of certain assets of Wisvest. See Note 3, Dispositions, for information on the Wisvest sale.
2016 Compared with 2015
Earnings increased $300.5 million in 2016, driven by a $201.7 million increase in earnings due to the inclusion of a full year of Integrys's results for 2016, compared to six months of Integrys's results for 2015. Integrys was acquired on June 29, 2015. See Note 2, Acquisitions, for more information.
| 2017 Form 10-K | 45 | WEC Energy Group, Inc. |
The most significant factor driving the remaining $98.8 million increase in earnings was a $104.1 million pre-tax ($80.1 million after tax) decrease in acquisition costs in 2016.
Non-GAAP Financial Measure
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 more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our 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.
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 and WG for all periods, operations for WPS beginning July 1, 2015, due to the acquisition of Integrys and its subsidiaries, 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) | 2017 | 2016 | 2015 | |||||||||
| Electric revenues | $ | 4,559.0 | $ | 4,628.1 | $ | 4,068.5 | ||||||
| Fuel and purchased power | 1,467.0 | 1,473.1 | 1,369.3 | |||||||||
| Total electric margins | 3,092.0 | 3,155.0 | 2,699.2 | |||||||||
| Natural gas revenues | 1,270.2 | 1,177.6 | 1,122.6 | |||||||||
| Cost of natural gas sold | 701.8 | 621.2 | 640.5 | |||||||||
| Total natural gas margins | 568.4 | 556.4 | 482.1 | |||||||||
| Total electric and natural gas margins | 3,660.4 | 3,711.4 | 3,181.3 | |||||||||
| Other operation and maintenance | 1,912.5 | 2,025.4 | 1,741.0 | |||||||||
| Depreciation and amortization | 523.9 | 496.6 | 408.6 | |||||||||
| Property and revenue taxes | 158.1 | 162.4 | 147.5 | |||||||||
| Operating income | $ | 1,065.9 | $ | 1,027.0 | $ | 884.2 |
| 2017 Form 10-K | 46 | WEC Energy Group, Inc. |
The following table shows a breakdown of other operation and maintenance:
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Operation and maintenance not included in line items below | $ | 822.6 | $ | 881.9 | $ | 744.2 | ||||||
| We Power (1) | 513.0 | 513.2 | 510.7 | |||||||||
| Transmission (2) | 407.4 | 423.2 | 341.3 | |||||||||
| Regulatory amortizations and other pass through expenses (3) | 158.1 | 157.4 | 144.8 | |||||||||
| Earnings sharing mechanisms | 2.9 | 24.4 | — | |||||||||
| Other | 8.5 | 25.3 | — | |||||||||
| Total other operation and maintenance | $ | 1,912.5 | $ | 2,025.4 | $ | 1,741.0 |
| (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 2017, 2016, and 2015, $535.1 million, $528.4 million, and $483.4 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 2017, 2016, and 2015, $451.4 million, $486.0 million, and $388.6 million, respectively, of costs were billed by transmission providers to our electric utilities. |
| (3) | Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income. |
The following tables provide information on delivered volumes by customer class and weather statistics:
| Year Ended December 31 | |||||||||
| MWh (in thousands) | |||||||||
| Electric Sales Volumes | 2017 | 2016 | 2015 | ||||||
| Customer class | |||||||||
| Residential | 10,636.3 | 10,998.9 | 9,218.9 | ||||||
| Small commercial and industrial * | 12,932.1 | 13,113.1 | 10,889.2 | ||||||
| Large commercial and industrial * | 12,822.0 | 13,418.6 | 11,545.8 | ||||||
| Other | 175.6 | 172.2 | 162.6 | ||||||
| Total retail * | 36,566.0 | 37,702.8 | 31,816.5 | ||||||
| Wholesale | 3,768.0 | 3,704.6 | 2,588.1 | ||||||
| Resale | 9,000.3 | 8,761.6 | 9,077.1 | ||||||
| Total sales in MWh * | 49,334.3 | 50,169.0 | 43,481.7 |
| * | 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 | 2017 | 2016 | 2015 | ||||||
| Customer class | |||||||||
| Residential | 1,039.4 | 1,014.9 | 859.4 | ||||||
| Commercial and industrial | 643.6 | 610.5 | 527.4 | ||||||
| Total retail | 1,683.0 | 1,625.4 | 1,386.8 | ||||||
| Transport | 1,316.4 | 1,270.6 | 994.2 | ||||||
| Total sales in therms | 2,999.4 | 2,896.0 | 2,381.0 |
| 2017 Form 10-K | 47 | WEC Energy Group, Inc. |
| Year Ended December 31 | |||||||||
| Degree Days | |||||||||
| Weather | 2017 | 2016 | 2015 | ||||||
| WE and WG (1) | |||||||||
| Heating (6,574 normal) | 5,908 | 6,068 | 6,468 | ||||||
| Cooling (714 normal) | 772 | 991 | 622 | ||||||
| WPS (2) | |||||||||
| Heating (7,377 normal) | 6,942 | 6,715 | 2,215 | ||||||
| Cooling (499 normal) | 450 | 572 | 396 | ||||||
| UMERC (3) | |||||||||
| Heating (8,368 normal) | 8,145 | N/A | N/A | ||||||
| Cooling (324 normal) | 235 | N/A | 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. Degree days for 2015 have been included for the period from July 1, 2015, through December 31, 2015. |
| (3) | Normal degree days are based on a 20-year moving average of monthly temperatures from the Iron Mountain, Michigan weather station. |
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, as well as 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 the same period in 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 23, 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 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 margins were partially offset by an additional day of sales during 2016 due to leap year.
| 2017 Form 10-K | 48 | WEC Energy Group, Inc. |
Operating Income
Operating income at the Wisconsin segment increased $38.9 million during 2017, compared with 2016. This increase was driven by $89.9 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 the PSCW conditions of approval related to the Integrys acquisition in Note 2, Acquisitions, 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 to reduce SSR costs related to PIPP, 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 is 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 plant retirement. See Note 5, Property, Plant, and Equipment, for more information on the plants to be retired. |
| • | 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. See Note 3, Dispositions, for more information on the sale of the MCPP. |
2016 Compared with 2015
Electric Utility Margins
Electric utility margins at the Wisconsin segment increased $455.8 million during 2016, compared with 2015. The increase was primarily driven by a $386.4 million margin contribution from WPS during the first six months of 2016, compared with no margin contribution from WPS for the first six months of 2015.
| 2017 Form 10-K | 49 | WEC Energy Group, Inc. |
The significant factors impacting the remaining $69.4 million increase in electric utility margins at the Wisconsin segment were:
| • | A $50.4 million increase related to higher retail sales volumes during 2016, primarily driven by warmer summer weather. As measured by cooling degree days, 2016 was 59.3% warmer than 2015 in the Milwaukee area. |
| • | The expiration of $12.5 million of bill credits refunded to customers in 2015 related to the Treasury Grant WE received in connection with its biomass facility. |
| • | An $11.3 million increase in the last six months of 2016 as a result of WPS's PSCW rate order, effective January 1, 2016. See Note 23, Regulatory Environment, for more information. |
These increases were partially offset by a $12.9 million decrease in wholesale margins driven by a reduction in capacity sales year-over-year at WE in addition to a reduction in sales volumes at WPS for the second half of 2016, compared with the same period in 2015. Certain wholesale customers have provisions in their contracts, which allowed them to reduce the amount of energy we provided to them.
Natural Gas Utility Margins
Natural gas utility margins at the Wisconsin segment increased $74.3 million during 2016, compared with 2015. The increase in natural gas utility margins was driven by a $63.6 million margin contribution from WPS during the first six months of 2016, compared with no margin contribution from WPS for the first six months of 2015.
The most significant factor impacting the remaining $10.7 million increase in natural gas utility margins at the Wisconsin segment was an $18.1 million net increase from both WG's rate order effective January 1, 2016, and a partially offsetting negative impact from WPS's rate order during the last six months of 2016. See Note 23, Regulatory Environment, for more information. This net increase was partially offset by a $3.2 million decrease related to lower sales volumes during 2016, primarily driven by warmer winter weather. As measured by heating degree days, 2016 was 6.2% warmer than 2015 in the Milwaukee area.
Operating Income
Operating income at the Wisconsin segment increased $142.8 million during 2016, compared with 2015. The increase was driven by the $530.1 million increase in margins discussed above, partially offset by $387.3 million of higher operating expenses. Higher operating expenses were driven by $321.6 million of operating expenses from WPS during the first six months of 2016, compared with no operating expenses from WPS for the first six months of 2015.
The significant factors impacting the remaining $65.7 million increase in operating expenses during 2016, compared with 2015, at the Wisconsin segment were:
| • | A $27.0 million increase in depreciation and amortization, driven by an overall increase in utility plant in service. In November 2015, WG completed the Western Gas lateral project, and WE completed the conversion of the fuel source for VAPP from coal to natural gas. |
| • | A $25.3 million increase in expenses related to charitable projects supporting our customers and the communities within our service territories. |
| • | A $24.4 million expense related to the earnings sharing mechanisms in place at WE and WG, effective January 1, 2016. |
These increases in operating expenses were partially offset by a $16.4 million positive impact at WE from the sale of the MCPP in April 2016, including a gain on sale and lower operating costs in 2016.
| 2017 Form 10-K | 50 | WEC Energy Group, Inc. |
Illinois Segment Contribution to Operating Income
We did not have any operations in Illinois until our acquisition of Integrys on June 29, 2015. Since the majority of PGL and NSG customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Natural gas revenues | $ | 1,355.5 | $ | 1,242.2 | $ | 503.4 | ||||||
| Cost of natural gas sold | 438.9 | 365.2 | 133.2 | |||||||||
| Total natural gas margins | 916.6 | 877.0 | 370.2 | |||||||||
| Other operation and maintenance | 471.1 | 485.1 | 219.6 | |||||||||
| Depreciation and amortization | 152.6 | 134.0 | 63.3 | |||||||||
| Property and revenue taxes | 19.9 | 18.3 | 9.2 | |||||||||
| Operating income | $ | 273.0 | $ | 239.6 | $ | 78.1 |
The following table shows a breakdown of other operation and maintenance:
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Operation and maintenance not included in the line items below | $ | 368.4 | $ | 385.3 | $ | 196.0 | ||||||
| Riders * | 98.1 | 82.3 | 20.2 | |||||||||
| Regulatory amortizations * | 1.0 | 2.7 | 1.3 | |||||||||
| Other | 3.6 | 14.8 | 2.1 | |||||||||
| Total other operation and maintenance | $ | 471.1 | $ | 485.1 | $ | 219.6 |
| * | 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 | 2017 | 2016 | 2015 | ||||||
| Customer Class | |||||||||
| Residential | 886.2 | 905.6 | 300.7 | ||||||
| Commercial and industrial | 183.6 | 187.6 | 63.2 | ||||||
| Total retail | 1,069.8 | 1,093.2 | 363.9 | ||||||
| Transport | 858.8 | 855.3 | 328.4 | ||||||
| Total sales in therms | 1,928.6 | 1,948.5 | 692.3 |
| Degree Days | |||||||||
| Weather * | 2017 | 2016 | 2015 | ||||||
| Heating (6,110 normal) | 5,470 | 5,713 | 1,813 |
| * | Normal heating degree days are based on a 12-year moving average of monthly temperatures from Chicago's O'Hare Airport. |
2017 Compared with 2016
Natural Gas Utility Margins
Natural gas utility margins, 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. 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.
| 2017 Form 10-K | 51 | WEC Energy Group, Inc. |
Operating Income
Operating income at the Illinois segment increased $33.4 million during 2017, compared with 2016. This increase was due to the $23.8 million net increase in margins discussed above and a $9.6 million decrease in 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 decrease in operating expenses were:
| • | A $21.1 million decrease in benefit related expenses driven by lower pension costs. |
| • | A $9.8 million decrease in expenses related to charitable projects supporting our customers and the communities within our service territories. |
| • | A $6.0 million decrease in expenses related to an information technology project created to improve the billing, call center, and credit collection functions of certain WEC Energy Group subsidiaries. Lower expenses were primarily due 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. Lower expenses related to the transfer are offset through higher depreciation and amortization, discussed below. |
These decreases were partially offset by:
| • | 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 the information technology project to PGL and NSG in 2017. |
| • | A $3.4 million increase in natural gas distribution expenses, driven by increased repair activity in 2017. |
2016 Compared with 2015
Natural Gas Utility Margins
Natural gas utility margins at the Illinois segment increased $506.8 million during 2016, compared with 2015. The increase was primarily driven by a $467.8 million margin contribution from the Illinois segment during the first six months of 2016, compared to no margin contribution from this segment for the first six months of 2015.
The significant factors impacting the remaining $39.0 million increase in natural gas utility margins at the Illinois segment were:
| • | A $26.3 million increase in margins related to the riders referenced in the table above during the last six months of 2016, compared with the last six months of 2015. |
| • | A $10.8 million increase in revenue at PGL due to continued capital investment in projects under its QIP rider. |
Operating Income
Operating income at the Illinois segment increased $161.5 million during 2016, compared with 2015. The increase was primarily driven by the $506.8 million increase in margin discussed above, partially offset by:
| • | Operating expenses of $308.2 million during the first six months of 2016, compared with no operating expenses during the first six months of 2015. |
| • | A $26.3 million increase in other operation and maintenance expenses related to the riders referenced in the table above during the last six months of 2016, compared with the last six months of 2015. |
| • | A $9.7 million increase in other operation and maintenance expenses during the last six months of 2016 compared with the last six months of 2015, due to an increase in expenses related to charitable projects supporting our customers and the communities within our service territories. |
| 2017 Form 10-K | 52 | WEC Energy Group, Inc. |
Other States Segment Contribution to Operating Income
We did not have any operations in this segment until our acquisition of Integrys on June 29, 2015. Since the majority of MERC and MGU customers use natural gas for heating, operating income is sensitive to weather and is generally higher during the winter months.
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Natural gas revenues | $ | 411.2 | $ | 376.5 | $ | 149.3 | ||||||
| Cost of natural gas sold | 215.3 | 182.3 | 76.9 | |||||||||
| Total natural gas margins | 195.9 | 194.2 | 72.4 | |||||||||
| Other operation and maintenance | 101.3 | 110.1 | 50.0 | |||||||||
| Depreciation and amortization | 24.8 | 21.1 | 10.0 | |||||||||
| Property and revenue taxes | 15.6 | 13.1 | 6.4 | |||||||||
| Operating income | $ | 54.2 | $ | 49.9 | $ | 6.0 |
The following table shows a breakdown of other operation and maintenance:
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Operation and maintenance not included in line items below | $ | 78.3 | $ | 86.4 | $ | 43.2 | ||||||
| Regulatory amortizations and other pass through expenses * | 23.0 | 23.6 | 6.7 | |||||||||
| Other | — | 0.1 | 0.1 | |||||||||
| Total other operation and maintenance | $ | 101.3 | $ | 110.1 | $ | 50.0 |
| * | 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 | 2017 | 2016 | 2015 | ||||||
| Customer Class | |||||||||
| Residential | 285.6 | 278.5 | 84.7 | ||||||
| Commercial and industrial | 199.4 | 178.2 | 60.9 | ||||||
| Total retail | 485.0 | 456.7 | 145.6 | ||||||
| Transport | 693.3 | 696.2 | 279.6 | ||||||
| Total sales in therms | 1,178.3 | 1,152.9 | 425.2 |
| Degree Days | |||||||||
| Weather * | 2017 | 2016 | 2015 | ||||||
| MERC | |||||||||
| Heating (7,907 normal) | 7,625 | 7,188 | 2,563 | ||||||
| MGU | |||||||||
| Heating (6,244 normal) | 5,707 | 5,712 | 1,822 |
| * | 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. |
| 2017 Form 10-K | 53 | WEC Energy Group, Inc. |
2017 Compared with 2016
Operating Income
Operating income at the other states segment increased $4.3 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.
2016 Compared with 2015
Natural Gas Utility Margins
Natural gas utility margins at the other states segment increased $121.8 million during 2016, compared with 2015. The increase was primarily driven by a $110.4 million margin contribution from the other states segment during the first six months of 2016, compared to no margin contribution from this segment for the first six months of 2015.
The significant factors impacting the remaining $11.4 million increase in natural gas utility margins at the other states segment were:
| • | A $3.9 million increase in the last six months of 2016 as a result of various rate orders. An interim rate order for MERC was effective January 1, 2016, and accounted for $2.5 million of the rate increase. The MGU rate order was also effective January 1, 2016, and accounted for $1.4 million of the rate increase. See Note 23, Regulatory Environment, for more information. |
| • | A $3.0 million increase related to higher sales volumes during the last six months of 2016, driven by colder weather. As measured by heating degree days, the last six months of 2016 were 11.5% colder than the last six months of 2015 at MGU and 5.7% colder than the last six months of 2015 at MERC. |
| • | A $1.6 million increase related to the MERC conservation improvement program financial incentive as a result of exceeding certain energy savings goals. |
Operating Income
Operating income at the other states segment increased $43.9 million during 2016, compared with 2015. The increase was driven by the $121.8 million increase in margins discussed above, partially offset by $77.9 million of higher operating expenses. Higher operating expenses were driven primarily by $76.3 million of operating expenses from the other states segment during the first six months of 2016, compared with no operating expenses during the first six months of 2015.
Non-Utility Energy Infrastructure Segment Contribution to Operating Income
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Operating income | $ | 400.5 | $ | 375.6 | $ | 373.4 |
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. See Note 2, Acquisitions, for more information on the acquisition of Bluewater and Note 19, Segment Information, for information on the change in segment name.
2016 Compared with 2015
Operating income at the non-utility energy infrastructure segment increased $2.2 million during 2016, compared with 2015. This increase was primarily related to higher revenues in connection with capital additions to the plants We Power owns and leases to WE.
| 2017 Form 10-K | 54 | WEC Energy Group, Inc. |
Corporate and Other Segment Contribution to Operating Income
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Operating loss | $ | (8.4 | ) | $ | (10.0 | ) | $ | (91.2 | ) |
2017 Compared with 2016
The operating loss at the corporate and other segment decreased $1.6 million during 2017, compared with 2016, driven by $3.5 million of costs incurred in 2016 related to the acquisition of Integrys. See Note 2, Acquisitions, for more information regarding costs associated with the acquisition.
2016 Compared with 2015
The operating loss at the corporate and other segment decreased $81.2 million during 2016, compared with 2015, driven by a reduction in costs related to the acquisition of Integrys.
Electric Transmission Segment Operations
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Equity in earnings of transmission affiliates | $ | 154.3 | $ | 146.5 | $ | 96.1 |
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.
2016 Compared with 2015
Earnings from our ownership interests in transmission affiliates increased $50.4 million during 2016, compared with 2015, primarily due to the increase in our ownership interest from 26.2% to approximately 60% as a result of the acquisition of Integrys on June 29, 2015. In addition, the lower earnings during 2015 were also driven by an ALJ initial decision issued in December 2015 related to the ATC ROE complaints, which was later affirmed by a FERC order in 2016.
Consolidated Other Income, Net
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| AFUDC – Equity | $ | 11.4 | $ | 25.1 | $ | 20.1 | ||||||
| Gain on repurchase of notes | — | 23.6 | — | |||||||||
| Gain on asset sales | 1.9 | 19.6 | 22.9 | |||||||||
| Other, net | 51.3 | 12.5 | 15.9 | |||||||||
| Other income, net | $ | 64.6 | $ | 80.8 | $ | 58.9 |
2017 Compared with 2016
Other income, net decreased $16.2 million during 2017, compared with 2016. This decrease was primarily driven by the $23.6 million gain recorded in February 2016 on the repurchase of a portion of Integrys's 2006 Junior Notes at a discount, the $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, and lower AFUDC in 2017 largely due to the ReACTTM emission control technology project at Weston Unit 3 going into service during the fourth quarter of 2016. Partially offsetting these decreases were higher gains on investments held in our rabbi trust during 2017, compared
| 2017 Form 10-K | 55 | WEC Energy Group, Inc. |
with 2016. See Note 12, Long-Term Debt and Capital Lease Obligations, for more information on the note repurchase and Note 3, Dispositions, for information on our asset sales.
2016 Compared with 2015
Other income, net increased $21.9 million during 2016, compared with 2015. This increase was primarily driven by the repurchase of a portion of Integrys's 2006 Junior Notes at a discount in February 2016, as well as higher AFUDC in 2016 due to the inclusion of AFUDC from the Integrys companies post acquisition. Partially offsetting these increases was a $19.6 million gain recorded in April 2016 from the sale of the chilled water generation and distribution assets of Wisvest, compared with a $20.8 million gain from the sale of Minergy LLC and its remaining financial assets in June 2015, as well as excise tax credits recognized by ITF in 2015. ITF was sold in the first quarter of 2016.
Consolidated Interest Expense
| Year Ended December 31 | ||||||||||||
| (in millions) | 2017 | 2016 | 2015 | |||||||||
| Interest expense | $ | 415.7 | $ | 402.7 | $ | 331.4 |
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.
2016 Compared with 2015
Interest expense increased $71.3 million during 2016, compared with 2015. The increase was primarily driven by $68.5 million of interest expense from Integrys and its subsidiaries during the first six months of 2016, compared to no interest expense from these companies during the same period in 2015. Additionally, we issued $1.2 billion of long-term debt in June 2015 to finance a portion of the cash consideration for the acquisition of Integrys. This was offset, in part, by the repurchase of a portion of the 2006 Junior Notes in February 2016. These notes were replaced with lower-interest rate short-term debt.
Consolidated Income Tax Expense
| Year Ended December 31 | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Effective tax rate | 24.1 | % | 37.6 | % | 40.4 | % |
2017 Compared with 2016
Our effective tax rate was 24.1% in 2017 compared to 37.6% in 2016. This decrease 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%. Preliminarily, we expect our 2018 annual effective tax rate to be between 15% and 16%, which includes an estimated 7% effective tax rate benefit due to the flow through of tax repairs in connection with the Wisconsin settlement. See Note 23, Regulatory Environment, for more information on the Wisconsin settlement. Excluding the impact of the tax repairs, the 2018 range would be between 22% and 23%. See Note 13, Income Taxes, for more information.
2016 Compared with 2015
Our effective tax rate was 37.6% in 2016 compared to 40.4% in 2015. This decrease was primarily related to a charge in 2015 to remeasure our state deferred income taxes as a result of the acquisition of Integrys.
| 2017 Form 10-K | 56 | 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) | 2017 | 2016 | 2015 | Change in 2017 Over 2016 | Change in 2016 Over 2015 | |||||||||||||||
| Cash provided by (used in): | ||||||||||||||||||||
| Operating activities | $ | 2,079.6 | $ | 2,103.5 | $ | 1,293.6 | $ | (23.9 | ) | $ | 809.9 | |||||||||
| Investing activities | (2,239.6 | ) | (1,270.1 | ) | (2,517.5 | ) | (969.5 | ) | 1,247.4 | |||||||||||
| Financing activities | 161.4 | (845.7 | ) | 1,211.8 | 1,007.1 | (2,057.5 | ) |
Operating Activities
2017 Compared with 2016
Net cash provided by operating activities decreased $23.9 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 15, 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 costs. 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. |
| • | A $49.6 million increase in cash distributions provided by ATC during 2017, compared with 2016. |
2016 Compared with 2015
Net cash provided by operating activities increased $809.9 million during 2016, compared with 2015. This increase was driven by $466.6 million of net cash flows from the operating activities of Integrys during the first six months of 2016 since Integrys was acquired on June 29, 2015. See Note 2, Acquisitions, for more information.
The remaining $343.3 million increase in net cash provided by operating activities was driven by:
| • | A $377.9 million increase in cash resulting from lower payments for natural gas and fuel and purchased power in 2016, due to lower commodity prices and warmer weather during the 2016 heating season. The average per-unit cost of natural gas sold decreased 18.5% during 2016. |
| • | A $94.2 million decrease in contributions and payments to our pension and OPEB plans during 2016, compared with 2015. |
| 2017 Form 10-K | 57 | WEC Energy Group, Inc. |
| • | A $44.1 million increase in cash due to lower collateral requirements during 2016, compared with 2015, driven by an increase in the fair value of our derivative instruments. |
| • | A $29.2 million increase in cash received from income taxes, primarily due to a Wisconsin state income tax refund received in the fourth quarter of 2016. |
These increases in net cash provided by operating activities were partially offset by a $210.8 million decrease in cash related to lower overall collections from customers. Collections from customers decreased primarily because of lower commodity prices and warmer weather during the 2016 heating season.
Investing Activities
2017 Compared with 2016
Net cash used in investing activities increased $969.5 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. During the fourth quarter of 2017, ATC Holdco purchased ATC's ownership interest in DATC, which resulted in an increase in our capital contributions. 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. 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. |
2016 Compared with 2015
Net cash used in investing activities decreased $1,247.4 million during 2016, compared with 2015, driven by:
| • | An investment of $1,329.9 million in June 2015 related to the acquisition of Integrys, which is net of cash acquired of $156.3 million. See Note 2, Acquisitions, for more information. |
| • | A $137.4 million increase in the proceeds received from the sale of assets and businesses during 2016, compared with 2015. |
These decreases in net cash used in investing activities were partially offset by:
| • | A $157.5 million increase in cash paid for capital expenditures during 2016, compared with 2015, which is discussed in more detail below. |
| • | A $33.6 million increase in our capital contributions to ATC during 2016, compared with 2015, driven by both the continued investment in equipment and facilities by ATC to improve reliability and the increase in our ATC ownership interest as a result of the June 2015 Integrys acquisition. |
| 2017 Form 10-K | 58 | WEC Energy Group, Inc. |
Capital Expenditures
Capital expenditures by segment for the years ended December 31 were as follows:
| Reportable Segment (in millions) | 2017 | 2016 | 2015 | Change in 2017 Over 2016 | Change in 2016 Over 2015 | |||||||||||||||
| Wisconsin | $ | 1,152.3 | $ | 910.9 | $ | 950.3 | $ | 241.4 | $ | (39.4 | ) | |||||||||
| Illinois | 545.2 | 293.2 | 194.4 | 252.0 | 98.8 | |||||||||||||||
| Other states | 74.5 | 59.5 | 34.7 | 15.0 | 24.8 | |||||||||||||||
| Non-utility energy infrastructure | 35.4 | 62.3 | 53.4 | (26.9 | ) | 8.9 | ||||||||||||||
| Corporate and other | 152.1 | 97.8 | 33.4 | 54.3 | 64.4 | |||||||||||||||
| Total capital expenditures | $ | 1,959.5 | $ | 1,423.7 | $ | 1,266.2 | $ | 535.8 | $ | 157.5 |
2017 Compared with 2016
The increase in cash paid for capital expenditures at the Wisconsin segment during 2017, compared with 2016, was 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 driven by increased construction activity related to PGL's SMP and natural gas storage field as well as 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 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 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 driven by a project to implement a new enterprise resource planning system and various other software projects.
See Capital Resources and Requirements – Capital Requirements – Capital Expenditures and Significant Capital Projects below for more information.
2016 Compared with 2015
The decrease in cash paid for capital expenditures at the Wisconsin segment during 2016, compared with 2015, was driven by the November 2015 completion of both WG's Western Gas Lateral project, which improved the reliability of WG's natural gas distribution network in the western part of Wisconsin, and WE's coal to natural gas conversion project at VAPP. Also contributing to the decrease were lower payments at WE for environmental compliance projects and electric distribution upgrades. The inclusion of WPS for all of 2016, as compared with only the last six months of 2015, substantially offset these lower capital expenditures. WPS's capital expenditures of $154.1 million during the first six months of 2016 related to the ReACTTM emission control technology project at Weston Unit 3, the combustion turbine project at the Fox Energy Center, and the SMRP.
The increase in cash paid for capital expenditures at the Illinois segment during 2016, compared with 2015, was due to the inclusion of PGL and NSG for all of 2016, compared with only the last six months of 2015. Capital expenditures at the Illinois segment were driven primarily by the SMP at PGL.
The increase in cash paid for capital expenditures at the other states segment during 2016, compared with 2015, was due to the inclusion of MERC and MGU for all of 2016, compared with only the last six months of 2015. MERC's and MGU's capital expenditures of $22.7 million during the first six months of 2016 primarily related to natural gas distribution systems and mains.
| 2017 Form 10-K | 59 | WEC Energy Group, Inc. |
The increase in cash paid for capital expenditures at the corporate and other segment during 2016, compared with 2015, was driven by a project to implement a new enterprise resource planning system and an information technology project created to improve the billing, call center, and credit collection functions of the Integrys subsidiaries.
Financing Activities
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 long-term debt repayments 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 increase in 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.
2016 Compared with 2015
Net cash related to financing activities decreased $2,057.5 million during 2016, compared with 2015, driven by:
| • | A $1,526.4 million net decrease in cash due to a $1,750.0 million decrease in the issuance of long-term debt during 2016, partially offset by $223.6 million of lower repayments of long-term debt during 2016. We issued $1,200.0 million of long-term debt during 2015 in connection with the acquisition of Integrys. |
| • | A $397.8 million net decrease in cash due to $234.8 million of net repayments of commercial paper during 2016, compared with $163.0 million of net borrowings of commercial paper during 2015. |
| • | A $169.5 million increase in dividends paid on common stock during 2016, compared with 2015, due to the issuance of 90.2 million shares of our common stock in June 2015 as a result of the Integrys acquisition and increases to our quarterly dividend rate. See Note 2, Acquisitions, for more information. |
| • | A $33.3 million decrease in cash due to more shares of our common stock purchased during 2016, compared with 2015, to satisfy requirements of our stock-based compensation plans. |
These decreases in net cash related to financing activities were partially offset by a $52.7 million increase in cash due to the redemption of all of WPS's preferred stock during 2015.
Significant Financing Activities
For more information on our financing activities, see Note 11, Short-Term Debt and Lines of Credit, and Note 12, Long-Term Debt and Capital Lease Obligations.
| 2017 Form 10-K | 60 | WEC Energy Group, Inc. |
Capital Resources and Requirements
Capital Resources
Liquidity
We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors.
We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets, and internally generated cash.
WEC Energy Group, 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 11, 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, 2017 and 2016, 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:
| 2017 | 2016 | |||||||||||||||
| (in millions) | Actual | Adjusted | Actual | Adjusted | ||||||||||||
| Common equity | $ | 9,461.4 | $ | 9,711.4 | $ | 8,929.8 | $ | 9,179.8 | ||||||||
| Preferred stock of subsidiary | 30.4 | 30.4 | 30.4 | 30.4 | ||||||||||||
| Long-term debt (including current portion) | 9,588.7 | 9,338.7 | 9,315.4 | 9,065.4 | ||||||||||||
| Short-term debt | 1,444.6 | 1,444.6 | 860.2 | 860.2 | ||||||||||||
| Total capitalization | $ | 20,525.1 | $ | 20,525.1 | $ | 19,135.8 | $ | 19,135.8 | ||||||||
| Total debt | $ | 11,033.3 | $ | 10,783.3 | $ | 10,175.6 | $ | 9,925.6 | ||||||||
| Ratio of debt to total capitalization | 53.8 | % | 52.5 | % | 53.2 | % | 51.9 | % |
Included in long-term debt on our balance sheets as of December 31, 2017 and 2016, 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 the rating agency 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 9, 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, 2017, 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 11, Short-Term Debt and Lines of Credit, for more information about our credit facilities and other short-term credit agreements. See Note 12, Long-Term Debt and Capital Lease Obligations, for more information about our long-term debt.
| 2017 Form 10-K | 61 | WEC Energy Group, Inc. |
Working Capital
As of December 31, 2017, our current liabilities exceeded our current assets by $1,655.8 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.
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. We do not believe the change in rating outlook will have a material impact on our ability to access capital markets.
In July 2017, Moody's downgraded the ratings of WE (senior unsecured), WPS (senior unsecured), WG (senior unsecured), and ERGSS (senior secured) to A2 from A1. Moody's affirmed the commercial paper ratings of WE (P-1), WPS (P-1), and WG (P-1). Moody's also affirmed the ratings of WEC Energy Group (senior unsecured, A3), WECC (senior unsecured, A3), and Integrys (senior unsecured, A3), but changed the rating outlook for these companies to negative from stable. We do not believe the changes in ratings and rating outlook will have a material impact on our ability to access capital markets.
Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.
If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our or our subsidiaries’ credit ratings on negative outlook or downgrading 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, 2017:
| 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) | $ | 18,025.9 | $ | 1,238.0 | $ | 1,801.1 | $ | 1,070.5 | $ | 13,916.3 | ||||||||||
| Capital lease obligations (3) | 71.4 | 14.7 | 31.9 | 24.8 | — | |||||||||||||||
| Operating lease obligations (4) | 115.1 | 9.5 | 16.8 | 14.7 | 74.1 | |||||||||||||||
| Energy and transportation purchase obligations (5) | 11,640.9 | 1,084.2 | 1,691.4 | 1,369.7 | 7,495.6 | |||||||||||||||
| Purchase orders (6) | 1,168.6 | 851.3 | 137.7 | 77.7 | 101.9 | |||||||||||||||
| Pension and OPEB funding obligations (7) | 49.0 | 13.1 | 35.9 | — | — | |||||||||||||||
| Total contractual obligations | $ | 31,070.9 | $ | 3,210.8 | $ | 3,714.8 | $ | 2,557.4 | $ | 21,587.9 |
| 2017 Form 10-K | 62 | WEC Energy Group, Inc. |
| (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, 2017. |
| (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 power purchase commitments and rail car leases. |
| (5) | Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility operations. |
| (6) | Purchase obligations related to normal business operations, information technology, and other services. |
| (7) | Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2020. |
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 13, Income Taxes.
The table above also does not reflect estimated future payments related to the manufactured gas plant remediation liability of $617.2 million at December 31, 2017, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 21, Commitments and Contingencies, for more information about environmental liabilities.
AROs in the amount of $573.7 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years.
Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.
Capital Expenditures and Significant Capital Projects
We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures and acquisitions for the next three years are as follows:
| (in millions) | 2018 | 2019 | 2020 | |||||||||
| Wisconsin | $ | 1,430.1 | $ | 1,152.0 | $ | 1,850.2 | ||||||
| Illinois | 633.8 | 629.2 | 676.5 | |||||||||
| Other states | 99.6 | 116.1 | 110.6 | |||||||||
| Non-utility energy infrastructure | 280.8 | 60.5 | 51.9 | |||||||||
| Corporate and other | 20.7 | 13.2 | 0.8 | |||||||||
| Total | $ | 2,465.0 | $ | 1,971.0 | $ | 2,690.0 |
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 $250 million between 2018 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. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.
| 2017 Form 10-K | 63 | WEC Energy Group, Inc. |
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 in 2019. The estimated cost of this project is approximately $266 million ($277 million with AFUDC). See Note 23, Regulatory Environment, for more information about UMERC and this new generation.
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 rider, which is in effect through 2023. PGL's projected average annual investment through 2020 is between $280 million and $300 million. See Note 23, Regulatory Environment, for more information on the SMP.
We expect to provide capital contributions to ATC and ATC Holdco (not included in the above table) of approximately $200 million from 2018 through 2020.
Common Stock Matters
For information related to our common stock matters, see Note 9, Common Equity.
On January 18, 2018, our Board of Directors increased our quarterly dividend to $0.5525 per share effective with the first quarter of 2018 dividend payment, which equates to an annual dividend of $2.21 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 $3.8 billion as of December 31, 2017. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $120.5 million, $28.7 million, and $121.0 million to our pension and OPEB plans in 2017, 2016, and 2015, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 17, Employee Benefits.
Off-Balance Sheet Arrangements
We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit 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 11, Short-Term Debt and Lines of Credit, Note 16, Guarantees, and Note 20, 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 the 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 our 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
| 2017 Form 10-K | 64 | WEC Energy Group, Inc. |
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, 2017, our regulatory assets were $2,840.4 million, and our regulatory liabilities were $3,760.4 million.
Due to the Tax Legislation signed into law in December 2017, our regulated utilities remeasured their deferred taxes and recorded an estimated tax benefit of $2,450 million. This tax benefit will be returned to ratepayers through future refunds, bill credits, riders, or reductions to other regulatory assets. See Note 13, Income Taxes, and Note 23, 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, is currently estimated to be $342 million. In September 2017, the PSCW approved an extension of this deferral through 2019 as part of a settlement agreement. See Note 23, 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, 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, 2017, 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 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. In 2018, PGL agreed to a settlement of the 2014 reconciliation, which includes a rate base reduction of $5.4 million and a $4.7 million refund to ratepayers. As of December 31, 2017, 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 23, 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), Revenues and Customer Receivables, for more information on riders and other mechanisms that allow for cost recovery or refund of uncollectible expense.
| 2017 Form 10-K | 65 | WEC Energy Group, Inc. |
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 summary of actual weather information in our utilities' service territories during 2017, 2016, and 2015, 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, 2017, and December 31, 2016, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $20.6 million and $9.8 million in 2017 and 2016, 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, 2017 | Expected Return on Assets in 2018 | |||||
| Pension trust funds | $ | 2,966.8 | 7.12 | % | |||
| OPEB trust funds | $ | 841.5 | 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.
| 2017 Form 10-K | 66 | WEC Energy Group, Inc. |
Inflation
We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.
For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.
Industry Restructuring
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.
Restructuring in 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.
Restructuring in 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, 2017, 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.
Restructuring in Wisconsin
The PSCW previously instituted generic proceedings to consider how its regulation of natural gas distribution utilities should change to reflect a competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to provide customer classes with competitive market choices 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. Currently, we are unable to predict the impact of potential future industry restructuring on our results of operations or financial position.
| 2017 Form 10-K | 67 | WEC Energy Group, Inc. |
Restructuring in 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.
Restructuring in 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.
Restructuring in 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 21, 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
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 a final 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 refunds 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. See Note 18, Investment in Transmission Affiliates, for more information.
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.
The decrease in ATC's ROE resulting from the FERC's final order issued in September 2016 will continue to have a negative impact on our equity earnings and distributions from ATC.
| 2017 Form 10-K | 68 | WEC Energy Group, Inc. |
Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Legislation was signed into law. See Note 13, Income Taxes, and Note 23, Regulatory Environment, for more information regarding its impact on us.
Bonus Depreciation Provisions
Bonus depreciation is an additional amount of first-year tax deductible depreciation that is awarded above what would normally be available. Based on the Protecting Americans from Tax Hikes Act of 2015, a 50% bonus depreciation deduction was available for assets placed in service during 2017. The increase in our federal tax depreciation from this deduction significantly reduced our 2017 federal income tax payment.
On December 22, 2017, the Tax Legislation was signed into law. This legislation modified the bonus depreciation deduction available for public utility property subject to rate-making by a government entity or public utility commission. See Note 13, Income Taxes, for more information.
Critical Accounting Policies and Estimates
Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective, or complex judgments.
Goodwill Impairment
We completed our annual goodwill impairment tests for all of our reporting units that carried a goodwill balance as of July 1, 2017. No impairments were recorded as a result of these tests. For our Bluewater reporting unit, we assumed fair value equaled carrying value since Bluewater was acquired on June 30, 2017. For all of our other reporting units that carried a goodwill balance, the fair values calculated in step one of the test were greater than their carrying values. The fair values for these 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 fair value of a reporting unit. Since all of our reporting units 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 included 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.
| 2017 Form 10-K | 69 | WEC Energy Group, Inc. |
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 other than Bluewater, fair value exceeded carrying value by over 50%. For Bluewater, we assumed fair value equaled carrying value since we acquired Bluewater on June 30, 2017. Based on these results, our reporting units are not at risk of failing step one of the goodwill impairment test.
Our reporting units had the following goodwill balances at July 1, 2017:
| (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 | 7.3 | 0.2 | % | ||||
| Total goodwill | $ | 3,053.5 | 100.0 | % |
See Note 8, Goodwill, for more information.
Long-Lived Assets
We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to 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 fossil fuel generating units and have announced our plans for the retirement of certain older and less-efficient generating units. 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, 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 the abandoned generating unit, an impairment charge may be required. An impairment charge would be recorded if the remaining carrying value of the abandoned generating unit is greater than the present value of the amount expected to be recovered from ratepayers.
We concluded that the Pleasant Prairie power plant, PIPP, the Pulliam power plant, and the jointly-owned Edgewater 4 generating unit meet the criteria to be considered probable of abandonment as of December 31, 2017. We plan to ask for full cost recovery of and a full return on the remaining book value of the generating units and have concluded that no impairment was required related to these assets as of December 31, 2017.
See Note 5, Property, Plant, and Equipment, for more information on the units to be retired.
Pension and Other Postretirement Employee Benefits
The costs of providing non-contributory defined pension benefits and OPEB, described in Note 17, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.
| 2017 Form 10-K | 70 | WEC Energy Group, Inc. |
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.
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 2017 Pension Cost | |||||||
| Discount rate | (0.5) | $ | 211.3 | $ | 18.3 | |||||
| Discount rate | 0.5 | (183.6 | ) | (10.3 | ) | |||||
| 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 2017 Postretirement Benefit Cost | |||||||
| Discount rate | (0.5) | $ | 56.2 | $ | 2.6 | |||||
| Discount rate | 0.5 | (49.3 | ) | (1.3 | ) | |||||
| Health care cost trend rate | (0.5) | (31.9 | ) | (3.3 | ) | |||||
| Health care cost trend rate | 0.5 | 37.1 | 3.8 | |||||||
| Rate of return on plan assets | (0.5) | N/A | 3.8 | |||||||
| Rate of return on plan assets | 0.5 | N/A | (3.8 | ) |
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 7.11%, 7.12%, and 7.37%, in 2017, 2016, and 2015, respectively. The actual rate of return on pension plan assets, net of fees, was 13.74%, 7.75%, and (3.85)%, in 2017, 2016, and 2015, respectively.
In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 17, Employee Benefits.
Regulatory Accounting
Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC. Our financial statements reflect the effects of the 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.
| 2017 Form 10-K | 71 | WEC Energy Group, Inc. |
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, 2017, we had $2,840.4 million in regulatory assets and $3,760.4 million in regulatory liabilities. See Note 4, 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 2017 of approximately $7.6 billion included accrued utility revenues of $538.1 million as of December 31, 2017.
Income Tax Expense
We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to the provision for income taxes in the income statements.
Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.
Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(o), Income Taxes, and Note 13, Income Taxes, for a discussion of accounting for income taxes.
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