PSC REF#:374901 Joint Application of Wisconsin Electric Power Company and Wisconsin Gas LLC, for Authority to Adjust Electric, Docket No. 5-UR-109 Natural Gas, and Steam Rates ______________________________________________________________________________ DIRECT TESTIMONY OF PAUL CHERNICK 1 I. Summary and Qualifications 2 Q: Mr. Chernick, please state your name, occupation, and business address. 3 A: My name is Paul L. Chernick. I am the president of Resource Insight, Incorporated, 5 Water Street, Arlington, Massachusetts. 4 5 Q: Summarize your professional education and experience. 6 A: I received a Bachelor of Science degree from the Massachusetts Institute of 7 Technology in June 1974 from the Civil Engineering Department, and a Master of 8 Science degree from the Massachusetts Institute of Technology in February 1978 in 9 technology and policy. 10 I was a utility analyst for the Massachusetts Attorney General for more than 11 three years, and was involved in numerous aspects of utility rate design, costing, 12 load forecasting, and the evaluation of power supply options. Since 1981, I have 13 been a consultant in utility regulation and planning, first as a research associate at 14 Analysis and Inference, after 1986 as president of PLC, Inc., and in my current 15 position at Resource Insight since 1990. In these capacities, I have advised a 16 variety of clients on utility matters. 17 My work has considered, among other things, the cost-effectiveness of 18 prospective new electric generation plants and transmission lines, retrospective Direct-Sierra Club-Chernick-p-1 Public Service Commission of Wisconsin RECEIVED: 08/28/2019 1:28:40 PM BEFORE THE PUBLIC SERVICE COMMISSION OF WISCONSIN 1 review of generation-planning decisions, ratemaking for plants under construction, 2 ratemaking for excess and/or uneconomical plants entering service, conservation 3 program design, cost recovery for utility efficiency programs, the valuation of 4 environmental externalities from energy production and use, allocation of costs of 5 service between rate classes and jurisdictions, design of retail and wholesale rates, 6 and performance-based ratemaking and cost recovery in restructured gas and 7 electric industries. My professional qualifications are further summarized in Ex.- 8 Sierra Club-Chernick-1. 9 Q: Have you testified previously in utility proceedings? 10 A: Yes. I have testified over three hundred times on utility issues before various 11 regulatory, legislative, and judicial bodies, including utility regulators in thirty- 12 seven states and six Canadian provinces, and three U.S. federal agencies. This 13 previous testimony has included many reviews of the economics of power plants, 14 utility planning, marginal costs, and related issues. 15 II. Introduction 16 Q: On whose behalf are you testifying? 17 A: I am testifying on behalf of Sierra Club. 18 Q: What is the scope of your testimony? 19 A: I review the economics of the coal plants owned by a Wisconsin electric-utility 20 subsidiary of WEC Energy, Wisconsin Electric Power Company (the Company, 21 WEPCo, or WEP), which is one of the applicants in the proceeding in which this 22 testimony is filed. My purpose is to determine whether WEPCo was prudent in 23 retiring the Pleasant Prairie Power Plant and the Presque Isle Power Plant, and 24 whether continued operation of WEPCo’s other coal plants would be prudent. I also Direct-Sierra Club-Chernick-p-2 1 question the inclusion of some dues and contributions in the WEPCo and 2 Wisconsin Gas expenditures. 3 My testimony relies on numerous WEPCo documents and discovery 4 responses (some of which are confidential), including the testimony of WEPCo 5 witness Richard Stasik, as well as publicly available documents from Wisconsin 6 Power and Light (WPL), Madison Gas and Electric (MGE), the Energy Information 7 Administration (EIA), the Mid-Continent Independent System Operator (MISO), 8 the Federal Energy Regulatory Commission (FERC), and the Environmental 9 Protection Agency (EPA). 10 Q: Why focus your testimony on the Company’s coal units? 11 A: Keeping the existing coal units in service is expensive, compared to the costs of the 12 gas-fired units. Economic operation of coal units is heavily dependent on having a 13 large number of hours in which market prices are higher than the costs of fuel and 14 other operating costs for starting the units and generating electricity. Since each 15 coal unit is much less nimble than most gas-fired or hydro plants, those profitable 16 hours also need to be predictable days in advance and must occur in clusters long 17 enough to pay for the costs of cycling the unit up and down. The addition of large 18 amounts of wind regionally has reduced the profitability of coal plants more than 19 for most other types of generation. In order to be cost-effective, coal plants must 20 operate in most hours of the year; low off-peak prices are more problematic for coal 21 plants than for gas combined-cycle units, for example. Due to their limited cycling 22 ability, coal units are frequently required to operate at a loss in low-priced hours, in 23 order to be available in high-priced hours, while most other plants would either 24 earn a little margin even at low price (e.g., run-of-river hydro) or shut down for the 25 low-priced hours (e.g., gas combined-cycle). Direct-Sierra Club-Chernick-p-3 Q: 1 What information did the WEPCo provide in its Application relevant to determining whether its existing generation remains used and useful? 2 A: 3 For the most part, WEPCo did not provide information in its Application relevant to 4 determining whether its existing generation remains used and useful and continued 5 investment in them is prudent. While WEPCo claimed that it “continuously reviews 6 the performance of all the plants in its generating fleet in making decisions 7 concerning their operations,” 1 it failed to provide projected retirement dates for 8 those plants when asked and simultaneously claimed that “[o]utside of annual Fuel 9 Plans, no analyses [of the economics of continued operation of one or more of 10 WEPCo’s coal plants that have been conducted by or for WEPCo since January 11 2014] exist for plants other than Pleasant Prairie and Presque Isle.” 2 12 Q: Which coal capacity does WEPCo own? 13 A: WEPCo owns all or parts of thirteen coal units, of which two units were retired in 14 2018 (Pleasant Prairie 1 and 2) and five units were retired in 2019 (Presque Isle 5- 15 9), as summarized in Table 1. 16 Table 1: Operating and Recently Retired WEPCo Coal Plants Plant Elm Road Oak Creek Pleasant Prairie Presque Isle Unit(s) Year Installeda 1-2 5-8 1-2 5-9 2010 1967 1985 1979 Retirement Yearb Summer Capacity (MW)c Operator 2018 2019 1,268 995 1,188 359 WEPCo WEPCo WEPCo WEPCo Data sources: a,b 2017 FERC Form 1, p. 402 c 2017 EIA 860 d 2017 EIA 860, Owner file e Percent times Capacity 2018 WEPCo Share 1 WEPCo Resp. to KHM 11(PSC REF# 366603) 2 WEPCo Resp. to Sierra Club 1.20 and 1.21 (PSC REF# 370971 and 370448) Direct-Sierra Club-Chernick-p-4 Percentd MWe 83.34% 100.00% 100.0% 100.0% 1,056.8 995 1,188 359 1 Q: Who owns the remainder of Elm Road? 2 A: Table 2 summarizes the ownership shares. Table 2: Co-owners of Elm Road Plant Unit(s) WEPCo WPPI Elm Road 1-2 83.34% 8.33% 3 MGE 8.33% 4 Q: How are the WEPCo units dispatched? 5 A: The WEPCo units sell all their output to the MISO market and WEPCo purchases 6 all energy required for load from MISO. Thus, the value of the power plants and 7 the costs of serving customers are distinct. 8 The operation of the WEPCo units should be determined by the hourly 9 market prices of energy. As I discuss in Sections IV.A and V, WEPCo requires that 10 MISO commit the Elm Road and Oak Creek units every day, to run at their 11 minimum load, with market prices determining only whether they operate above 12 those levels. 13 Q: is beneficial to ratepayers? 14 15 Does it appear that continued operation of the WEPCo coal capacity A: No. The costs of fuel, operating and maintenance (O&M), overheads, and ongoing 16 capital additions for both of the two remaining Oak Creek units appear to 17 substantially exceed the market value of their output. The Elm Road units also may 18 be operating at a loss. The decision to keep a unit online for one or more years 19 constitutes a commitment to pay the fixed O&M, overheads, and capital additions 20 needed to keep it running. Thus, whatever profit the utility makes in the high-priced 21 hours, minus losses from unavoidable operation in the low-priced hours, plus small 22 value streams from capacity and miscellaneous revenues, must cover all the fixed 23 annual costs. For Oak Creek, and possibly Elm Road, that is no longer the case. Direct-Sierra Club-Chernick-p-5 1 Replacement resources, especially wind, are less expensive energy sources 2 than continued operation of the coal plants. To the extent that WEPCo requires 3 additional capacity to meet its MISO obligations, beyond what is provided by 4 replacement wind energy, it can purchase capacity credits (which are very 5 inexpensive), and build or purchase solar and/or storage resources. 6 Q: investment in those resources? 7 8 A: going-forward costs. 10 Q: Do your conclusions rely on any specific assumptions about the recovery of the unamortized capital cost of the retired plants? 12 13 No. I compare the going-forward costs of the plants with the costs of replacing their energy and capacity. The total costs of the coal units is higher than those 9 11 Do your estimates of the costs the coal units include recovery of the previous A: No. I do not include any sunk capital costs in my analysis. My conclusion is that 14 ratepayers are losing money on the continued operation of the plants. Customers 15 would be better off with retirement of the plants, even if they continue to pay for 16 depreciation and return on the sunk costs, just as if the plants were in service. 17 WEPCo can be made whole, and ratepayer costs can be reduced even further, if the 18 unamortized investment can be securitized and refinanced at a lower cost of capital. 19 Q: its fossil plants? 20 21 How does WEPCo take economics into account in deciding whether to retire A: As stated earlier, WEPCo claims that it has not conducted any analysis of the 22 economics of continued operation of its coal units other than ones it has already 23 retired. Further, when asked to provide estimated retirement dates for its plants 24 WEPCo failed to provide an answer, only stating that, “continuously reviews the Direct-Sierra Club-Chernick-p-6 1 performance of all the plants in its generating fleet in making decisions concerning 2 their operations.” 3 3 Q: How should the Commission deal with WEPCo’s coal plants? 4 A: None of WEPCo’s remaining coal plants appears to be profitable, and there is little 5 chance that they will become profitable over their remaining life. Ratepayers 6 should not be charged for the costs of keeping the plants operating unprofitably. 7 Thus, the Commission should disallow some combination of (1) depreciation and 8 return on the capital additions for the coal units since the last rate proceeding, (2) 9 future O&M for plants that should not be running and losing money for ratepayers, 10 and (3) fuel costs for the times when the plants are operating uneconomically. Since 11 fuel costs are recovered in other proceedings, I do not consider that option here. As 12 shown in Table 22, the losses from Elm Road and Oak Creek have averaged around 13 $98 million annually. 4 Excluding $98 million from WEPCo’s annual revenue 14 requirements would relieve ratepayers of that burden going forward. 5 15 Q: What other steps should the Commission take with respect to these units? 16 A: The Commission should warn WEPCo that cost recovery for these units in any 17 future rate case will be contingent on a showing that incremental investments and 18 operating costs are justified by the continued operation of the resources. The 19 Commission should also require that WEPCo demonstrate that it is taking measures 3 WEPCo Resp. to KHM 11(PSC REF# 366603) 4 See Table 26 for a refinement, using confidential information. 5 If WEPCo can demonstrate that some of the losses I estimate below would have occurred, even had WEPCo prudently reviewed the economics of continued operation of Elm Road and Oak Creek and taken prudent steps to reduce its expenditures for units that should be retired in the near term, the disallowance can be reduced accordingly. Direct-Sierra Club-Chernick-p-7 1 that may be required to retire uneconomic plants, including transmission studies 2 and procurement of resources. 3 III. Public Data on Performance and Costs of WEPCo Coal Units 4 Q: What performance and cost components of the coal units have you reviewed? 5 A: I have compiled performance data on unit capacity factor, forced outage rate, 6 availability, and heat rate. I have also assembled cost data for fuel, variable O&M, 7 fixed O&M, overheads, and capital additions. 8 A. Performance Measures 9 Q: Which performance measures have you compiled for the WEPCo coal units? 10 A: Table 3 shows data on each coal unit’s 2018 capacity factor, 2018 heat rate, and the 11 average forced outage rate that MISO reports for coal units of the size of each of 12 the WEPCo units. 13 Table 3: Coal Plant Technical Performance Plant Oak Creek Elm Road Pleasant Prairie Presque Isle a b Unit 2018 Capacity Factora 2018 Heat Rate (Btu/kWh) MISO Average Forced Outage Ratec 1-2 66% 10,427 9.28% b 4 67% 10,562 9.82% 7-8 33% 11,629 4.60% 3 42% 10,600 9.82% from EIA 860 and 923. 2018 EIA Form 923. c “Planning Year 2019–2020 Loss of Load Expectation Study Report,” Loss of Load Expectation Working Group, October 17, 2018, Table 4-1. Direct-Sierra Club-Chernick-p-8 1 Q: How has coal utilization changed? 2 A: Figure 1 depicts annual capacity factors by unit for the last nine years, from EIA 3 forms 860 and 923. The solid lines represent operating plants while the dashed 4 lines represent retired plants. 5 Figure 1: Annual Capacity Factors of WEPCo Coal Plants 80% 70% Capacity Factor 60% 50% 40% 30% Elm Road 20% Oak Creek Presque Isle 10% Pleasant Prairie 0% 2010 2011 2012 2013 2014 2015 2016 2017 2018 6 Most strikingly, Oak Creek has consistently run less than the retiring plants. It 7 only outperformed Pleasant Prairie in one of the nine last years, and outperformed 8 Presque Isle in three. Elm Road Units 1 and 2 were only installed in 2010 and 2011, 9 respectively, which accounts for its low capacity factors at the start of this analysis 10 period. However, after 2014, it consistently out-performed the retiring plants and 11 Oak Creek. 12 B. Fuel and O&M 13 Q: What public information do you have on the fuel and O&M costs of WEPCo’s coal units? 14 15 A: I have the following data on O&M: Direct-Sierra Club-Chernick-p-9 • 1 the fuel and O&M cost data that WEPCo and Madison Gas and Electric file in the 2012–2018 FERC Form 1 reports for each unit, 2 • 3 variable O&M by unit from the Bloomberg New Energy Finance study. 4 Table 4 provides data on the fuel and total nonfuel O&M costs for each of the 5 coal units, in dollars per megawatt-hour, from the WEPCo FERC Form 1 reports 6 for those years, pages 402 and 403. Table 4: Fuel and Non-Fuel O&M Costs by Coal Plant ($/MWh) 7 2012 Total Elm Road Fuel O&M Total Oak Creek Fuel O&M Pleasant Prairie Total Fuel O&M Total Presque Isle Fuel O&M 2013 2014 2015 2016 2017 2018 $65.05 $41.65 $23.40 $45.13 $32.38 $12.75 $33.38 $28.41 $4.97 $31.86 $24.46 $7.40 $29.39 $22.47 $6.93 $28.23 $21.49 $6.74 $26.89 $21.00 $5.90 $38.81 $26.05 $12.76 $35.58 $24.18 $11.41 $35.15 $23.59 $11.56 $33.07 $23.44 $9.62 $35.55 $22.31 $13.25 $32.09 $22.61 $9.48 $32.28 $21.91 $10.37 $35.68 $26.48 $9.21 $31.09 $25.12 $5.97 $31.40 $24.25 $7.15 $28.39 $21.62 $6.77 $27.99 $20.41 $7.58 $33.76 $21.14 $12.62 $23.15 $20.60 $2.56 $47.09 $33.23 $13.86 $47.80 $33.64 $14.16 $49.86 $34.33 $15.53 $52.28 $35.87 $16.42 $52.46 $30.92 $21.54 $49.08 $28.40 $20.68 $46.73 $33.20 $13.52 8 C. Capital Additions 9 Q: What information do you have regarding the ongoing capital costs for the WEPCo coal plants? 10 A: 11 I have compiled the historical additions to capital plant in service from the WEPCo 12 Form 1 reports for 2012–2018. The capital additions by plant are computed from 13 the change in capital cost reported in the annual FERC Form 1 reports. 6 These are 14 net additions, representing the investment at the plant in the particular year, minus 6 I eliminated the line for “Asset Retirement Costs,” which are accounting allowances for future removal costs. Direct-Sierra Club-Chernick-p-10 1 the cost of equipment at that plant retired. The interim accounting retirements do 2 not generally reduce revenue requirements, since an equal amount of accumulated 3 depreciation is removed, leaving net plant in service unchanged, so the net 4 additions understate the costs imposed on ratepayers. 5 Q: What have been the historical net capital additions for the WEPCo units? 6 A: Table 5 lists the net annual capital additions by unit. Where the capital cost 7 declined from year to year, I left the line blank. The value in italics is an outlier, 8 due to major retrofits that occur rarely. 9 Table 5: WEPCo Net Capital Additions ($ millions) Elm Road Oak Creek Pleasant Prairie Presque Isle 2013 $0.7 $33.6 $9.8 $12.4 2014 $2.8 $52.7 $34.0 $2.2 2015 $1.0 $17.8 $5.9 $1.7 2016 $1.6 $25.7 $8.9 $9.7 2017 $1.2 $32.4 $6.4 $0.2 10 In Table 6, I convert those capital additions to $/kW by dividing by WEPCo’s 11 ownership share of the unit, as well as the average capital additions over the last six 12 years. Since these values are net of retirements, they understate the actual costs to 13 ratepayers. 14 Table 6: WEPCo Net Capital Additions ($/kW-year) 15 Elm Road Oak Creek Pleasant Prairie Presque Isle 16 2013 $0.6 $30.6 $8.2 $34.5 2014 $2.2 $48.0 $28.6 $6.0 2015 $0.8 $16.2 $5.0 $4.6 2016 $1.3 $23.4 $7.5 $27.0 2017 $1.0 $29.5 $5.4 $0.6 Average $1.2 $29.5 $10.9 $14.6 Table 7 below presents the same data, in dollars per megawatt hour. Direct-Sierra Club-Chernick-p-11 Table 7: WEPCo Net Capital Additions ($/MWh) 1 Elm Road Oak Creek Pleasant Prairie Presque Isle 2 Q: 2013 $0.3 $7.0 $1.3 $6.6 2014 $0.5 $12.2 $5.5 $1.1 2015 $0.2 $3.4 $0.9 $1.0 2016 $0.2 $6.7 $1.5 $5.3 2017 $0.2 $6.9 $1.2 $0.1 Average $0.3 $7.2 $2.1 $2.8 Has WEPCo provided any other public data on historical capital additions for its coal units? 3 4 A: Yes, WEPCo provided gross capital additions by plant, as shown in Table 8 below, 5 converted to $/MWh. 7 These values are less than the net increase in the capital 6 costs reported in the FERC Form reports for some years, which is difficult to 7 understand, since the gross increase always be higher than the net increase. Since I 8 have not had the opportunity to further pursue an explanation for this discrepancy, I 9 have not used the WEPCo-provided capital additions in my later analyses. Table 8: WEPCo-Reported Historical Coal Capital Additions ($/MWh) 10 Plant Elm Road Oak Creek Pleasant Prairie Presque Isle 2016 $11.69 $4.38 $0.46 $0.01 2017 $4.86 $5.36 $0.18 $ - 2018 $3.03 $9.46 $0.09 $ - In the sections that follow, I used the annual net capital additions by coal 11 plant from Table 7. 12 13 D. Overheads 14 Q: What other costs are associated with continuing operation of the marginal coal units? 15 16 A: In addition to the O&M costs reported in the FERC Form 1 (e.g., page 402) for 17 each plant, running the coal units incurs other costs that are recorded in other 18 accounts, including: 7 WEPCo Resp. to Sierra Club 1.3i (PSC REF# 371001) Direct-Sierra Club-Chernick-p-12 • 1 Labor-related overheads, such as social security, unemployment taxes, pensions, and benefits (e.g., health and life insurance, education assistance). 2 3 • Property insurance. 4 • Property taxes. 5 • Administrative costs, such as legal, human resources, supervision, regulatory and public affairs. 6 7 • Office expenses related to administration. 8 • Maintenance of the step-up transformers and other dedicated transmission equipment. 9 10 Q: How large are these indirect costs? 11 A: One way to address that question is to examine the extent to which the lead owner 12 of each WPS or WEPCo plant marks up O&M charges to other owners, passing 13 through these other costs. In general, the lead owner of a jointly owned plant 14 carries various costs in non-generation accounts on its own books and charges the 15 point owners for their share of those costs, which are usually recorded in the plant 16 O&M of the non-operating owner. As shown in Table 2, WPL is the lead owner of 17 Columbia and Edgewater and can charge overheads to WPS and (in the case of 18 Columbia) MGE. 8 As the lead owner of Weston 4, WPS charges overhead cost to 19 Dairyland Power Cooperative. WEPCo is the lead owner of Elm Road, and charges 20 overhead cost to MGE. Table 9 provides non-fuel O&M per kWh from the 2013 to 21 2018 FERC Form 1 filings for the various investor-owned units and the RUS Form 22 12 for Dairyland. 9 The adder non-fuel O&M per kWh charged to the joint owner 23 has a wide range, from 1% in Edgewater 4 to 258% in Weston 4. 8 The lead owner for each resource is shown in bold. 9 Dairyland files its RUS reports with the Minnesota PUC, which posts those reports to its web site. I have not found any similar cost report for the other publically-owned joint owners of coal plants in Wisconsin. Direct-Sierra Club-Chernick-p-13 1 Table 9: Implied Overheads for Jointly-Owned Plants, Non-Fuel O&M Columbia 2018 2017 2016 2015 2014 2013 Average $/kWh Markup WPS MGE WPL WPS MGE 0.0055 0.0072 0.0045 1.21 1.60 0.0050 0.0070 0.0042 1.20 1.66 0.0061 0.0097 0.0056 1.08 1.72 0.0045 0.0093 0.0047 0.97 2.00 0.0062 0.0090 0.0054 1.15 1.67 0.0034 0.0057 0.0032 1.07 1.80 1.11 1.74 Edgewater 4 2018 2017 2016 2015 2014 2013 $/kWh WPS WPL 0.0041 0.0046 0.0094 0.0046 0.0054 0.0048 Markup WPS 1.08 0.88 1.46 0.76 1.02 0.84 1.01 0.0038 0.0052 0.0065 0.0060 0.0053 0.0057 Average Weston 4 WPS 2018 2017 2016 2015 2014 2013 $/kWh Dairyland N/A 0.0021 0.0040 0.0064 0.0042 0.0020 Markup Dairyland 0.0079 0.0117 0.0182 0.0144 0.0095 Average Elm Road $/kWh 2018 2017 2016 2015 2014 2013 WEPCo 0.0059 0.0067 0.0069 0.0074 0.0050 0.0127 MGE 0.0087 0.0101 0.0093 0.0093 0.0095 0.0114 Average 3.82 2.95 2.86 3.40 4.86 3.58 Markup MGE 1.48 1.50 1.35 1.26 1.91 0.89 1.40 2 The Dairyland markups on Weston 4 seem to be too large to be just the overhead 3 charges from WPS. The other overhead adders average 1.316. I use Elm Road’s average Direct-Sierra Club-Chernick-p-14 1 overhead adder of 39.83% for its analysis, and the average value of 31.64% of non-fuel 2 O&M for WEPCo’s other coal plants. A similar analysis of fuel costs across the joint owners does not show any 3 4 significant overheads excluded from the lead owners’ reported fuel costs. 5 E. Cost Summary 6 Q: How do the cost components (fuel, O&M, overheads and capital expenditures) add up to a cost per megawatt-hour for continued operation? 7 8 A: I computed the total costs of keeping each operational coal unit using the public 9 data from the tables above. Since the WEPCo FERC report did not have updated 10 capital costs for 2018, I assumed that capital additions in 2018 would equal the 11 average of the prior years. Direct-Sierra Club-Chernick-p-15 Table 10: Historical Costs of Running WEPCo Coal Units ($/MWh) 1 OH Adder Elm Road Oak Creek Pleasant Prairie Presque Isle Fuel O&M Capital Adds Overheads Total Cost Fuel O&M Capital Adds Overheads Total Cost Fuel O&M Capital Adds Overheads Total Cost Fuel O&M Capital Adds Overheads Total Cost 39.8% 31.6% 31.6% 31.6% 2013 $32.38 $12.75 $0.25 $5.07 $50.45 $24.18 $11.41 $7.04 $3.60 $46.23 $25.12 $5.97 $1.25 $1.89 $34.24 $33.64 $14.16 $6.57 $4.47 $58.84 2014 $28.41 $4.97 $0.49 $1.98 $35.84 $23.59 $11.56 $12.19 $3.65 $50.99 $24.25 $7.15 $5.46 $2.26 $39.12 $34.33 $15.53 $1.14 $4.91 $55.91 2015 $24.46 $7.40 $0.17 $2.94 $34.98 $23.44 $9.62 $3.41 $3.04 $39.52 $21.62 $6.77 $0.89 $2.14 $31.42 $35.87 $16.42 $0.96 $5.19 $58.43 2016 $22.47 $6.93 $0.25 $2.76 $32.40 $22.31 $13.25 $6.68 $4.19 $46.42 $20.41 $7.58 $1.47 $2.40 $31.85 $30.92 $21.54 $5.32 $6.81 $64.58 2017 $21.49 $6.74 $0.19 $2.68 $31.10 $22.61 $9.48 $6.87 $3.00 $41.96 $21.14 $12.62 $1.21 $3.99 $38.96 $28.40 $20.68 $0.15 $6.54 $55.76 2018 $21.00 $5.90 $0.27 $2.35 $29.51 $21.91 $10.37 $7.24 $3.28 $42.79 $20.60 $2.56 $2.06 $0.81 $26.02 $33.20 $13.52 $2.83 $4.27 $53.83 2 The all-in cost of keeping Pleasant Prairie in service was between $26 and 3 $39/MWh, and the cost of keeping Presque Isle operating was between $54 and 4 $65/MWh. Oak Creek fell in between those costs, ranging from $40 to $51/MWh. 5 Excluding Elm Road’s higher costs from 2013, it was similar to Pleasant Prairie 6 with costs ranging from $29/MWh to $36/MWh. 7 IV. Market Prices for WEPCo’s Coal-Unit Output 8 A. Recent Energy Prices for WEPCo Coal-Unit Output 9 Q: What MISO market energy prices have the WEPCo coal units faced? 10 A: Table 11 contains the average locational marginal price (LMP) at the MISO market 11 node for each of WEPCo’s currently operating units from 2013 to 2018, weighted 12 by the hourly load and Table 12 provides the distribution of the LMPs for 2018. Direct-Sierra Club-Chernick-p-16 Table 11: Average LMP ($/MWh) by Unit 1 2013 2014 2015 2016 2017 2018 Elm Road 29.19 35.35 25.14 24.88 26.43 28.05 Oak Creek 29.19 35.35 25.09 24.92 26.56 28.13 Table 12: Hourly Energy Prices ($/MWh) by Unit (2018) 2 Elm Road Oak Creek 28.05 -36.39 21.38 24.56 30.76 513.45 28.13 -35.88 21.41 24.58 30.80 512.39 Mean Minimum 25th Percentile 50th Percentile 75th Percentile Maximum 3 Q: energy prices from these units? 4 5 How do these energy prices compare to the short-run costs of producing A: Table 13 summarizes that comparison for a counterfactual situation in which the 6 plants are always available and able to dispatch in the profitable hours, but not at 7 any other time. I started by estimating the short-run cost for each unit as the sum of 8 fuel costs from Table 4 and an estimate of variable O&M from the Bloomberg New 9 Energy Finance (BNEF) analysis of the U.S. coal fleet. 10 I then counted the 10 number of hours in which the market energy price exceeded the short-run cost. The 11 market energy price exceeded the estimated short-run cost for 2,236 hours for Elm 12 Road and 2,848 hours for Oak Creek. I also computed the average LMP in the 13 hours when it exceeded the short-run cost. The LMP in those profitable hours 14 varies inversely with the number of profitable hours. 11 10 Ex.-Sierra Club-Chernick-2. 11 In this section, I consider whether the units are profitable to run in a particular hour, once WEC has committed to the capital additions and fixed O&M necessary to make the plant available. Elsewhere, I consider the annual profitability of the units, including the capital additions and fixed O&M. I do not reflect the sunk capital costs of the units in any of my analyses. Direct-Sierra Club-Chernick-p-17 Table 13: Energy Margin by Unit with Perfect Dispatch (2018) 1 Elm Road Fuel + VOM ($/MWh) Oak Creek 30.56 28.26 2,236 25.8% 45.07 2,848 32.9% 41.82 14.51 32.45 13.57 38.64 When LMP exceeds Fuel + VOM Number of Hours % of hours Average LMP ($/MWh) Energy Margin = LMP – (Fuel + VOM) $/MWh $/kW-year 2 In the last section of Table 13, I computed the average energy margin for each 3 unit in the profitable hours, in dollars per megawatt-hour (the difference between 4 average LMP and the variable running cost) and in $/kW-year (the $/MWh margin 5 times the number of profitable hours). 6 Q: factors? 7 8 9 10 How does the percentage of profitable hours compare to the units’ capacity A: Both Elm Road and Oak Creek produced more energy than if they had run in every profitable hour, and not in any unprofitable hour, as shown in Table 14. Table 14: Comparison of Profitable Hours to Capacity Factors, 2018 Elm Road Oak Creek Profitable Hours 25.8% 32.9% Capacity Factor (%) 71.3% 49.5% Difference 45.5% 16.7% 11 If the coal units were always available and able to ramp up immediately to full 12 power in the profitable hours and shut down immediately when LMP fell, the 13 capacity factor should be very close to the profitable hours. In reality, the capacity 14 factor for each unit is reduced by forced and maintenance outages. In addition, the 15 coal units cannot cycle up and down fast enough to run in all the profitable hours 16 without running in unprofitable hours. 17 18 Table 14 indicates that both currently operating WEPCo plants continued running during unprofitable hours. Direct-Sierra Club-Chernick-p-18 1 Q: Why might the units be running in hours in which they are not economic? 2 A: There are two ways in which WEPCo may have kept the plants running at 3 relatively high capacity factors. First, rather than bidding its coal units into the 4 market as resources to be dispatched economically, WEPCo designated Elm Road 5 and Oak Creek as “must-run” units, ensuring that MISO would dispatch them, 6 regardless of cost or price. 12 7 Second, when WEPCo bids the units into the MISO energy market (for the 8 Elm Road and Oak Creek capacity in excess of the must-run level), it may bid them 9 in at prices below their short-run marginal costs of fuel and variable O&M. 10 These mechanisms would allow WEPCo to force the coal units to run when 11 they are not economic sources of energy for the region. Merchant generation 12 owners usually do not engage in that behavior, since they would lose money on 13 every MWh sold. Vertically-integrated utilities, on the other hand, can often count 14 on recovering those losses from their retail (and in some cases, regulated 15 wholesale) customers. I do not fully understand WEPCo’s incentives to run the coal 16 plants uneconomically, but it may be motivated by an interest in avoiding scrutiny 17 of the coal plants’ economics until more of their costs have been depreciated. Since WEPCo is not subject to market discipline, as it would be if it were a 18 merchant generator, that role falls to the Commission. 13 19 20 Q: Does WEPCo explain why it designated some units as must-run? 21 A: Though WEPCo does not explain why some units are designated as must-run, it 22 does confirm that when forecasting the generation system for 2020 all of their coal 23 are dispatched as must-run for the entire year. 14 12 WEP Resp. to Sierra Club 1.28 (PSC REF# 370985). 13 See the testimony of Scott Hempling on behalf of Sierra Club in this docket. 14 WEPCo Resp. to Sierra Club 1.28 (PSC REF# 370985) Direct-Sierra Club-Chernick-p-19 1 Q: How were WEPCo’s coal units actually dispatched? 2 A: Table 15 shows the average energy margins for the remaining coal units in the 3 hours in which were actually dispatched. The percentage of hours in which each 4 plant operated was higher than its capacity factor, since each plant operated at 5 partial load in many hours. 6 Table 15: Energy Margin by Unit with Actual Dispatch (2018) Fuel + VOM ($/MWh) Elm Road Oak Creek 30.56 28.26 7551 86.2% 28.05 5980.5 68.3% 28.15 -2.51 -18.94 -0.11 -0.66 When Unit was Operating Number of Hours % of hours Average LMP ($/MWh) Energy Margin = LMP – (Fuel + VOM) $/MWh $/kW-year 7 Because both plants were dispatched in so many unprofitable hours, they 8 ended up having much lower energy margins than in the perfect conditions in Table 9 13. Elm Road and Oak Creek actually had negative energy margins in 2018, 10 meaning that the plants lost money even from a short term marginal cost 11 perspective, and certainly have not been earning enough revenue to also cover 12 capital additions, overhead and fixed O&M costs. 15 13 Table 16: Average Energy LMP as Operated 2018 2017 2016 2015 2014 Average Elm Road 28.05 26.36 24.76 25.13 35.57 27.97 Oak Creek 28.15 26.56 24.90 25.09 35.55 28.05 14 Table 17 shows the average energy margin by year for each of the remaining 15 units. Elm Road and Oak Creek appear to have lost money in the energy market in 15 I revisit energy revenues in Section V, using confidential data provided by the Company. Direct-Sierra Club-Chernick-p-20 1 each of the last four years, and the profits they made in 2014 were not enough for 2 them to have positive energy margins on average. 3 Table 17: Annual Energy Margins by Unit ($/MWh) 2018 2017 2016 2015 2014 Average Elm Road -2.51 -4.20 -5.80 -5.43 5.01 -2.58 Oak Creek -0.11 -1.69 -3.35 -3.17 7.30 -0.21 4 B. Future Energy Prices 5 Q: Are market prices for electric energy in Wisconsin likely to increase dramatically over the next several years? 6 7 A: No. While price may spike occasionally, indications are that electric market prices 8 will rise slowly, and even fall in the next few years. Table 18 shows the simple 9 average of the ICE forward prices for MISO’s Minnesota hub from July 19, 2019, 10 for as far out as those products are traded. 16 The prices mostly fall from the second 11 half of 2019, through 2023. 12 Table 18: MISO Minnesota Forward Prices ($/MWh) Period ICE code 2H19 2020 2021 2022 2023 13 Q: 16 Off MDO $18.91 $18.75 $18.09 $18.08 $18.66 Is there any public information on likely future electric energy prices beyond 2023? 14 15 On MDP $25.76 $26.88 $25.98 $25.45 $24.76 A: Not directly. However, one major driver of electric energy prices is the cost of natural gas. Table 19 shows Henry Hub gas prices for the NYMEX forwards (the 16 https://www.theice.com/marketdata/reports/142 Direct-Sierra Club-Chernick-p-21 1 HH contract) and from the EIA’s 2019 Annual Energy Outlook reference case. The 2 2019 price in the NYMEX column is the average of monthly actual spot price to 3 mid-July and forwards thereafter. The EIA’s projection looks to be somewhat 4 bullish in the short term. Interestingly, the forwards for MISO energy prices fall 5 from 2019 through 2023, even though gas-price futures and forecasts are rising. 6 That downward trend is probably the result of increasing penetration of renewables. 7 Table 19: Henry Hub Gas Price Projections ($/MMBtu) 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 NYMEX $2.54 $2.49 $2.55 $2.60 $2.67 $2.76 $2.90 $3.02 $3.17 $3.29 $3.41 $3.54 $3.65 EIA $3.02 $2.99 $3.10 $3.25 $3.24 $3.33 $3.56 $3.84 $4.20 $4.39 $4.52 $4.72 $4.84 $5.00 $5.09 8 C. Capacity Prices 9 Q: Is capacity very valuable or expensive in the MISO market? 10 A: No. Table 20 shows the clearing prices in Zone 2 (which includes eastern 11 Wisconsin and upper Michigan) for each of the Planning Reserve Auctions (PRAs) 12 that MISO has conducted. 17 17 From “MISO Planning Resource Auction (PRA) for Planning Year 2019-2020 Results Posting,” MISO, April 12, 2019, p. 8. Direct-Sierra Club-Chernick-p-22 Table 20: MISO Zone 2 Capacity Prices 1 Planning Year 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 Average Per unit of UCAP $/MW-day $/kW-year $16.75 $6.11 $3.48 $1.27 $72.00 $26.28 $1.50 $0.55 $10.00 $3.65 $2.99 $1.09 $17.79 $6.49 $/MWh at capacity factor of 40% 50% 60% $1.74 $1.40 $1.16 $0.36 $0.29 $0.24 $7.50 $6.00 $5.00 $0.16 $0.13 $0.10 $1.04 $0.83 $0.69 $0.31 $0.25 $0.21 $1.85 $1.48 $1.23 2 Zone 2 has always cleared at the same price as Zones 3, 5, 6, and 7, and 3 usually with other zones, as well. In three of the six PRAs (those with Zone 2 4 prices over $4/MW-day), Zone 1, western Wisconsin and Minnesota, cleared at 5 much lower prices than Zone 2. If transmission capacity out of Zone 1 increases (to 6 allow wind exports, or better integrate the MISO system), the capacity surplus in 7 Zone 1 is likely to reduce prices in Zone 2. There is no clear trend in the capacity prices over the five capacity auctions, 8 despite the large amount of coal capacity retired in this period. 9 10 Q: What are the capacity prices in other regions? 11 A: Only four ISOs operate capacity markets: MISO, PJM, NYISO and ISO-NE. The 12 SPP has an administrative penalty for capacity deficiencies, ERCOT has only an 13 energy market, and the CA ISO requires that each participant contribute to resource 14 adequacy and collects data on bilateral transactions to meet that standard. 18 15 The capacity prices in the Midwestern portion of PJM, the ISO area most 16 similar to MISO, have averaged about $36/kW-year since its first capacity auction 17 for 2007/08, through the 2021/22 capacity period, for which PJM acquired 18 resources in May 2018. 19 Recent prices are for capacity contracts with high 18 The average price reported in for 2017 contract, for 2017 through 2021, averaged $21/kW-year for the unconstrained portions of the system. 19 The 2019 auction for 2022/23 has been delayed while FERC considers potential changes in market rules. Direct-Sierra Club-Chernick-p-23 1 penalties for non-performance. 20 Prices comparable to the MISO capacity product 2 (which does not have performance penalties for conventional generation) would be 3 several percent lower. 4 The prices for Upstate New York are more difficult to summarize, because 5 NYISO conducts three types of capacity auctions (a seasonal strip auction every six 6 months, a monthly auction every month for each of the remaining months of the 7 season, and a spot price for each month). The average strip price for the latest sixty 8 months for which the prices have been set (through October 2019) is under 9 $23/kW-year, while the average spot price for the latest sixty months for which the 10 prices have been set (through July 2019) is under $26/kW-year. 11 Capacity prices are higher in places where building capacity is difficult, land 12 is scarce, labor is expensive, and transmission is constrained (e.g., New York City, 13 New Jersey), but those conditions are not typical of Wisconsin and neighboring 14 parts of MISO. 21 15 Both the PJM and NYISO capacity markets are dominated by non-utility 16 generators who face greater risks building for a competitive market than do the 17 vertically-integrated utilities that dominate the MISO market, both in total and in 18 Zone 2. 20 In the earlier years in which the PJM capacity market accepted both standard and high-performance capacity bids, I used the price for standard capacity, which is most comparable to the MISO capacity product. 21 In New England, which largely meets the high-cost criteria, the ISO-NE has run forward capacity auctions since the 2010/11 delivery year, but most of those auctions have settled at administrative floors or ceilings. In the last five auctions, following the largely unanticipated retirement of capacity equivalent to over 10% of peak load, the capacity price has fallen from over $100/kW-year to $46/kW-year. Direct-Sierra Club-Chernick-p-24 1 D. Other Revenues 2 Q: What other revenues did WEPCo report? 3 A: WEPCo provided historic revenues from fly ash or gypsum sales, UP rail refunds, 4 and refined coal construction management fees (RCCF) at the plant level from 5 2014–2018, as well as forecasts for 2019 and 2020. 22 These are provided in Table 6 21 for the operating units. Table 21: Other Revenues from Operating WEPCo Coal Plants ($ million) 7 Plant Elm Road Elm Road Elm Road Elm Road Oak Creek Item Fly Ash UP Rail RCCF Total Fly Ash 2014 2015 2016 2017 2018 2019 2020 Average $0.07 $0.15 $0.31 $1.65 $5.60 $2.63 $1.49 $0.58 $1.08 $1.60 $0.00 $0.07 $0.19 $1.00 $3.18 $4.33 $0.70 $0.89 $0.86 $2.73 $0.90 $7.20 $3.75 $2.63 $0.92 $0.61 $0.45 $2.55 $1.12 $0.52 8 E. Long-Run Economics of WEPCo’s Coal Plants from Public Data 9 Q: How do the market revenues for the units compare to the long-run plant costs that you estimated in Table 10? 10 11 A: The discussion in Section IV.A was limited to a comparison between the short-run 12 costs of operating the coal plants versus their market energy revenues. This 13 comparison does not account for the long-run costs required to make the coal plants 22 WEPCo Resp. to Sierra Club 1.3d and 1.3e (PSC REF# 371001). It is not clear who pays for the RCCF from Elm Road, or whether those revenues are already netted from the costs reported in the FERC reports. Nor is it clear whether the fuel costs that WEP reports for Elm Road are already net of the rail refunds. To be conservatively optimistic about the economics of Elm Road, I include all these revenues as benefits of operating the plant. Direct-Sierra Club-Chernick-p-25 1 available, provided in Table 10, above. Table 22 shows the total costs, energy 2 revenues and the capacity prices converted to millions of dollars for 2018. 23 3 Table 22: Summary of WEPCo Average Coal Plant Costs and Revenues a b c d e f g h I j Cost 2014–2018 ($/MWh) Energy Revenue 2014–2018 ($/MWh) 2018 GWh Margin with Energy ($M) WEPCo Capacity Share 2018 Capacity Revenue ($M) Other Revenue Net profit ($M) Net Profit ($/MWh) Net profit ($/kW-year) Notes: a From Table 10 b From Table 17 c From FERC Form 1 d = (b - a) × c ÷ 1,000 e From Table 1 f = e × $1.09 ÷ 1,000 g From Table 21 h =d+f+g I = h ÷ c × 1,000 j = h ÷ e × 1,000 Elm Road $32.8 $28.0 7,063 -$33.9 1,056.8 $1.2 $2.3 -$30.5 -$4.3 -$28.8 Oak Creek $44.3 $28.1 4,767 -$77.6 995.0 $1.1 $1.1 -$75.4 -$15.8 -$75.8 4 As shown in Table 22, both of WEPCo’s remaining coal plants have been 5 costing customers more money than they earned. These public data suggest that 6 Elm Road cost customers about $29 million more annually than the value of its 7 output. Since Elm Road’s costs have fallen somewhat in recent years, it has 8 been edging closer to break even. Oak Creek costs customers about $75 9 million more annually. 10 Q: customers in the future? 11 12 13 Is there any reason to expect that these units would have positive benefits for A: I see no reason to expect that outcome. Most industry forecasters expect costs of renewables and storage to continue to fall, and penetration of renewable energy in 23 The capacity revenues should be reduced about 5% to reflect the difference between rated and accredited capacity; that difference is inconsequential in this comparison. Direct-Sierra Club-Chernick-p-26 1 the Midwest MISO market will continue to rise, pushing down market energy 2 prices and reducing the value of the coal plants’ output. Any environmental retrofits 3 (such as those required to comply with the Clean Water Act) and any future limits 4 on carbon emissions will also tend to make coal plants less economic. 5 Q: obligations, would that be expensive? 6 7 If WEPCo needed to purchase additional capacity to meet its MISO A: Not at the historical average market capacity prices. As shown in Table 20, the cost 8 of capacity to replace generation with the range of capacity factors that the WEPCo 9 coal units are likely to achieve is only about one or two dollars per MWh. If the 10 coal energy were instead replaced by wind or solar, those resources would not only 11 provide energy at lower cost than the coal plants, but also provide some capacity 12 value. For solar, with a capacity factor of about 20% and a UCAP capacity credit 13 of 50% of nameplate, the capacity credit is about 2.5 times the average hourly 14 output, while for a power plant with a 60% capacity factor and a capacity credit of 15 90% of nameplate, the ratio is 1.5. Wind provides less capacity value per MWh 16 than solar or even the coal plants, since a wind farm with a 30% capacity factor 17 would get a capacity credit of about 16%, for a ratio about 0.5. 24 So cost- 18 competitive energy from renewables would also contribute to satisfying WEPCo’s 19 capacity requirements. 24 See Section VI for a discussion of MISO capacity credit for renewables. Direct-Sierra Club-Chernick-p-27 IQ V. Additional Analyses from Con?dential Data Q: What forced outage and deration data did provide? A: While provided forecast (only for the year 2020)25 and historical26 forced outage and deration rates for its Elm Road and Oak Creek luiits. it did not provide the historical data for its retired Pleasant Prairie and Presque Isle units. Table 23 provides annual forced outage rates. which demonstrate the annual variability in plant performance. - Elm Road is the average that MISO repo?s for plants of its size as outlined in Table 3, Oak Creek is- Table 23: Con?dential Historical and Forecast Forced Outage Rates Average (2014? Plant Unit 2014 2015 2016 2017 2018 2018 2020 Q: What capacity factor data did provide? A: provided data on 2020 forecast capacity factors for its operating coal luiits.27 Table 24 contains these numbers. and Figure 2 plots them alongside the historical capacity factors from Figlu?e 1. 35 Resp. to Sierra Club 1.5p (PSC 370998) 36 Resp. to PSCW DM-5 362818) 37 Resp. to Sierra Club 1.50 (PSC 370998) Direct-Sierra lub-C hemick-p-28 Wk) 'Jl Table 24: Con?dential 2020 Forecast Capacity Factors 2020 Forecasted Plant Capacity Factor Elm Road - - Oak Creek 4 Figure 2: Con?dential Historical and Forecast Capacity Factors of Coal Plants 100% 90% 80% 70% 60% 50% 40% Capacity Factor 30% 20% Elm Road 10% Oak Creek 0% 2010 2012 2014 2016 2018 2020 - projects that the capacity factor for Oak Creek will- it I mm Road capacity factor to- in 2020. Q: What energy revenues did report? A: Table 25 contains the yearly energy revenues that reported for each of its plants28. divided by the share of generation for those plants in order to provide a revenue value. Table 26 compares these values to those that I estimated using the average LMPS in Table 16. 28 Resp. to Sierra Club 1.3a (PSC 371000) Dil?ect-Sien?a lub-C hemick-p-29 1 Table 25: Con?dential Reported Energy Revenue by Unit Plant Unit 2015 2016 2017 2018 Average Elm Road 1-2 Oak Creek 5-8 Pleasant Prairie 1-2 Presque Isle 5-9 2 Table 26: Con?dential Comparison of Public Estimate of Energy Revenues to 3 Con?dential Information Elm Road Oak Creek Average LMP 2014-18 $27.97 $28.05 Reported Revenue 2015-18 Difference 4 repo?ed energy revenues_ are- than my estimates 5 from the public data. for which I had only gross output. Adding the differences in 6 Table 26 to my estimate of operating losses in Table 22 OO 10 Q: Have you updated your Table 22 using the energy revenues from Table 25? 11 A: Yes, Table 27 provides that update. Dil?ect-Sien?a lub-C hemick-p-3O luv?i OO 10 11 13 14 Table 27: Con?dential Summary of Average Coal Plant Costs and Revenues Elm Road Oak Creek Cost 2014?2018 $32.8 $44.3 Energy Revenue 2014?2018 2018 7,063 4,767 Margin with Energy (SM) ?$2.95 ?$82.08 Capacity Share 1,056.8 995.0 2018 Capacity Revenue (SM) $1.2 $1.1 Other Revenue 2.3 1.1 Net profit (SM) Profit per Net profit (SM) Notes: From Table 10 From Table 25 From FERC Form 1 From Table 1 $1.09 1,000 From Table 21 1,000 1,000 How much extra would customers pay annually in order to keep uneconomic coal plants operating at the profit levels in Table 27? k: - Creek kee keen - Q: To what extent can the coal units vary their output in response to changes in load or market energy price? A: In general, large coal 1mits are veiy slow to respond to changing conditions. Table 28 elaborates on the limited load-following abilities of each of the WEPCO coal 1mits.39 The various Imits have a minimum up time of - The full plant ramp rate for the imits ranges from?, equivalent to to get from fn?st generation to full power. 39 Resp. to Sierra Club 1.8 370993) Dil?ect-Sien?a lub-C hemick-p-3 1 Table 28: Confidential WEPCo Coal Unit Load-Following Parameters 1 Unit Plant Elm Road Elm Road Oak Creek Oak Creek Oak Creek Oak Creek Pleasant Prairie Pleasant Prairie Presque Isle Presque Isle Presque Isle Presque Isle Presque Isle 2 Q: Minimum Down Time (Hrs) Unit Ramp Rate (MW/min) up and down Did WEPCo provide any confidential data on its dispatch strategy for its coal units? 3 4 1 2 5 6 7 8 1 2 5 6 7 8 9 Minimum Up Time (Hrs) A: As stated earlier in this testimony, WEPCo publicly revealed that it forecasts all of 5 its coal units as must-run all year round. It also provided data on how the plants 6 were dispatched between 2017 and 2018. 30 This information is summarized in 7 Table 29. 30 WEPCo Resp. to Sierra Club 1.3v (PSC REF# 371000) Direct-Sierra Club-Chernick-p-32 Plant Table 29: Con?dential Annual Unit Operating Status 2017 2018 Must Run Must Run Econ- omic Econ- Emerg- ency Emerg- ency Unit Outage Outage omic Elm Road Elm Road Oak Creek Oak Creek Oak Creek Oak Creek Pleasant Prairie Pleasant Prairie Presque Isle Presque Isle Presque Isle Presque Isle Presque Isle 2 3 The con?dential historical data c111rent dispatch snarezgy Please summarize the effect of confidential data on your conclusions in section IV. The con?dential data from has continued my conclusions based on public data. Costs of Renewables Has provided you with any information on wind claims it does not estimate its own levelized costs of Wind31 and also declined to provide any infonnation 011 the price of energy from Wind faims it does not own. 33 31 Resp. to Sieira Club 1.9 (PSC 370973) 33 Resp. to Sien?a Club 1.10 (PSC 370208) Direct-Sien?a lub-C hemick-p?33 1 Q: What wind PPA prices are reported by public sources? 2 A: Table 30 shows levelized PPA prices compiled by LevelTen Energy for the period 3 from October 2018 to June 2019 for wind PPA offers in its northernmost MISO 4 region, covering North Dakota, Minnesota, Wisconsin and Upper Michigan. 33 5 Table 30 also shows the levelized prices for utility-scale solar projects. The PPA 6 prices in the table refer to the most competitive 25th percentile offer prices 7 associated with projects with contract tenors of 10 to 25 years. LevelTen does not 8 publish all combinations of locations and contract start dates. 9 Table 30: LevelTen Energy Levelized North-MISO P25 PPA Prices ($/MWh) Q3 2018 Q4 2018 Q1 2019 Q2 2019 10 11 Wind PPA Price $17.4 $20.0 $20.7 $15.7 Solar PPA Price NA $34.2 $34.6 $34.2 These prices are consistent with prices reported elsewhere, with the solar prices reflecting the higher latitude of Wisconsin, compared to Colorado or Texas. 12 Figure 3 below shows the levelized MISO solar and wind PPA price 13 trajectories by ISO over the past few quarters. LevelTen describes these data as 14 price indices; the prices are higher than the P25 values, and may represent median 15 prices. 33 https://leveltenenergy.com/. Direct-Sierra Club-Chernick-p-34 Figure 3: LevelTen Solar Wind PPA Indices 1 3 Q: How much capacity credit does MISO give for solar and wind resources? 4 A: For MISO’s most recent planning year, 2019/2020, the capacity credit for wind 5 generation was set at 15.7%, which translated to 2,855 MW out of 18,210 MW of 6 unforced wind capacity potentially qualifying under Module E-1 of MISO’s tariff. 7 The 2019-2020 wind capacity credit is 0.5 percent points higher than the 2018- 8 2019 credit. While MISO consistently assumes that wind’s capacity credit will 9 decline as penetration rises, its estimate of the capacity contribution has increased 10 over 20% since 2011, even as wind penetration has nearly doubled. 34 The default 11 solar capacity credit for the 2019-2020 planning year remains at 50%. 12 Since MISO credits wind with less capacity per MWh than a baseload power 13 plant, replacement of coal units with mostly wind energy would require some short- 14 or long-term market capacity purchases, addition of solar and/or storage resources, 15 and/or addition of demand response. 34 MISO Planning Year 2019-2020 Wind & Solar Capacity Credit, December 2018, p. 9. Direct-Sierra Club-Chernick-p-35 these costs of renewables compare to the costs of continuing to operate coal resources? Figure 4 compares the costs of continuing to run the coal resources with the costs of recent renewable PPAs. For each coal resource, I present the lowest annual cost, the average cost, and the maximum cost for 2013 2018 from Table 10. For renewables, I present the minimum, average, and maximum costs of the MISO North PPAs for the past four quarters from Table 30. Figure 4: Costs of Renewable PPAs and Coal Plant Operation $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 Elm Road Oak Creek Recent Wind P25 Recent Solar P25 I Min Average Max As Figure 4 shows, the entire range of wind prices from low to high are lower than the low cost for both coal units. The average and high prices of solar are cheaper than the average and high prices of both coal units as well. Only Elm Road outperforms solar in a low cost year. Notably, even its cheapest year Oak Creek is more expensive than the high cost estimates of wind and solar. Since a solar plant provides more energy in the high-value on-peak period, and provides an unusually large amount of capacity per unit of energy, it may be cost-effective even if its energy price were somewhat higher than the cost per of a coal plant. Direct-Sierra Club-Chernick-p-36 1 Q: energy? 2 3 How much could ratepayers save if the coal units were replaced with wind A: Just comparing the costs of energy, customers would save over $220 million 4 annually replacing $39/MWh coal with $19/MWh wind energy over the 11,830 5 GWh reported for WEPCo’s share of Elm Road and Oak Creek in WEPCo’s 2018 6 FERC Form 1. Since this change in resources would change the dispatch of 7 WEPCo’s system into the MISO market, the overall effect of the transition would 8 be somewhat different from this top-level estimate. 9 10 VII. Other Studies of Coal-Plant Economics Q: operation? 11 12 Have other recent studies reviewed the prospects for economic coal plant A: Yes. Bloomberg New Energy Finance (BNEF), the Brattle Group and the Coal 13 Tracker Initiative released conducted separate analyses of coal-plant cost- 14 effectiveness in 2018. 15 A. The BNEF Study 16 Q: What did the BNEF study examine? 17 A: The Bloomberg study, attached as Ex.-Sierra Club-Chernick-2, covered the six-year 18 period of 2012 through 2017, for 903 units totaling 280 MW of nameplate capacity, 19 excluding combined heat and power units. 35 The authors compared energy, 20 capacity and byproduct revenues by unit to the fuel, variable O&M and emissions 21 charges, to compute what they call the “short-run margin.” Adding fixed O&M to 35 Half of U.S. Coal Fleet on Shaky Economic Footing: Coal Plant Operating Margins Nationwide, William Nelson and Sophia Liu, March 26, 2018. Direct-Sierra Club-Chernick-p-37 1 the costs produces the “long-run margin.” The study reports environmental capital 2 additions, but does not include any capacity additions in the profitability analysis. 3 Q: What did the BNEF study conclude? 4 A: The study’s conclusions included the following: 5 6 By our estimates, 48% of the coal fleet (135 of 280 GW) posted negative margins from 2012-17… 7 8 9 10 11 We find ourselves awestruck by the resilience of U.S. coal. Plants persist even when they cost more to run than replace. As we hunt for coal closures, beware of the sometimes tenuous link between ‘economics’ and ’retirement decisions’. The link is especially weak in regulated regions, where high-cost coal runs regularly out of merit. … 12 13 14 The majority of ‘uneconomic’ units (130GW of 135GW) are regulated. They are kept online by virtue of cost-plus pacts that partially insulate owners from shifting economics. … (p. 1) 15 16 17 18 19 20 21 Coal plants were originally designed to run baseload – to sell large volumes of electricity with healthy short-run operating margins (i.e. dark spreads). This was necessary to cover relatively high fixed costs. Since the shale boom, collapsing dark spreads and dwindling capacity factors have cut deeply into coal’s energy revenues – so much so that plants sometimes fail to cover fixed operating costs. Ongoing operating losses can drive plants to retire. 22 23 24 Simply boosting output is not an option. Plants have reduced their capacity factors precisely because in many hours, fuel prices are higher than power prices. Running more would mean running at a loss. (p. 8) 25 Q: What does BNEF conclude about WEPCo’s coal plants? 26 A: Table 31 provides BNEF’s results for each of the WEPCo plants, for each year and 27 cumulative for the period. Overall, both plants lost money overall, and especially in 28 the past three years. Direct-Sierra Club-Chernick-p-38 Table 31: BNEF Estimates of WEPCo Unit Operating Profit ($/kW) 1 2012 Elm Road Oak Creek 2013 2014 2015 2016 -$70.2 -$57.0 $9.9 -$57.9 -$13.9 -$65.3 -$35.9 $11.5 -$47.0 -$36.7 2017 Total -$28.0 -$217.3 -$42.9 -$216.2 2 Figure 5: Annual Unit Operating Profit, per BNEF 3 4 $20.0 5 $10.0 6 $0.0 -$10.0 7 2012 2013 2014 2015 2016 2017 -$20.0 8 -$30.0 9 -$40.0 10 -$50.0 Elm Road Oak Creek -$60.0 11 -$70.0 12 -$80.0 13 14 Since these are the annual profits without capital additions or overheads, 15 these results understate the losses that WEPCo’s customers have experienced from 16 both the Elm Road and Oak Creek units. Including capital additions and overheads, 17 the losses on those units would be even larger. 18 B. The Brattle Study 19 Q: What were the results of the Brattle study? 20 A: The Brattle Group study, attached as Ex.-Sierra Club-Chernick-3, used ABB’s 21 Velocity Suite data (the default data for PROMOD) to estimate the 2017 net margin Direct-Sierra Club-Chernick-p-39 1 for each domestic coal plant (as well as each nuclear plant). 36 Brattle does not 2 identify the results for specific units, but does provide aggregate results, as 3 summarized in Table 32. 4 Table 32: Brattle Results for Coal Plant Economics, 2017 RTO Non‐RTO Total Total Capacity (GW) 160.1 75.7 235.8 Capacity with Revenue Shortfall Percentage of Gigawatts Total LowHighLowHighCost Cost Cost Cost Case Case Case Case 120.1 154.2 75% 96% 65.3 69.5 86% 92% 185.4 223.7 79% 95% Brattle also plotted the distribution of plant profitability, as shown in Figure 5 6 6. 7 Figure 6: Brattle Summary of Power Plant Cost-Effectiveness, 2017 8 36 The Cost of Preventing Baseload Retirements: A Preliminary Examination of the DOE Memorandum, Metin Celebi, et al, July 2018. Brattle reports that it excluded another 11.7 GW of coal units (averaging 37 MW per unit) were listed as having no generation and in most cases no cost data. Direct-Sierra Club-Chernick-p-40 The dark data points, representing the coal plants, are sometimes obscured by 1 the large light data points that Brattle used for the nuclear units. 2 3 Q: of the WEPCo coal units? 4 5 How do the costs of the coal units in the Brattle analysis compare to the costs A: The average costs of the coal units in the Brattle analysis are listed in Table 33. 6 Brattle used unit-specific fuel and VOM costs from the ABB database, generic 7 FOM values from EPA and capital additions (CapEx) costs from EIA. 8 Table 33: Brattle Average Coal Forward Costs ($/MWh) Fuel Costs VOM FOM Ongoing CapEx Total Low-Cost Case $22.30 $1.56 $7.14 $4.97 $35.97 High-Cost Case $22.30 $4.91 $8.51 $4.97 $40.69 9 Brattle’s fuel costs are similar to those I calculated for WEPCo’s coal units, 10 summarized in Table 10. Elm Road and Pleasant Prairie had lower O&M costs than 11 Brattle’s estimates and Presque Isle and Oak Creek had higher O&M costs. I also 12 calculated lower capital addition costs for most of the coal units, with the exception 13 of Oak Creek again being more expensive than the Brattle estimate. 14 VIII. Dues and Contributions 15 Q: Which association dues and contributions that Wisconsin Gas and WEPCo 16 have proposed to include in the test year revenue requirement would you like 17 to call to the Commission’s attention? 18 19 A: The Companies have provided lists of dues and contributions included in the test year revenue requirement. 37 37 WEPCo Resp. to Sierra Club 3.3 (PSC REF# 372987). Direct-Sierra Club-Chernick-p-41 1 Some of the dues strike me as being non-controversial, based on their 2 organizational designations (and my understanding of what those organizations 3 do), such as the National Association of Corporate Directors, the American 4 Association of Blacks in Energy, Hispanic Professionals, Better Business Bureau of 5 Wisconsin and National Minority Supplier. But a number of the organizations 6 appear to be heavily involved in lobbying, policy advocacy, and public relations, 7 incurring costs that might not be recoverable in rates if they were incurred and 8 reported directly by the Companies, such as: 9 • American Gas Association (AGA), 10 • Edison Electric Institute (EEI), 11 • National Hydropower Association, 12 • Wisconsin Manufacturers and Commerce, 13 • Wisconsin Utilities Association, 14 • Wisconsin Utility Investors, and 15 • the Metropolitan Milwaukee Association of Commerce. These seven organizations account for over 90% of the Companies’ dues and 16 contributions. 17 18 I would expect that these organizations would spend significant sums on such 19 activities as funding policy and political advocacy and public relations efforts that 20 do not advance the interests of ratepayers as a whole. 21 Q: ratepayers? 22 23 24 What standards should the Commission apply to recovery of these costs from A: I am informed by counsel that Wisconsin law precludes the Companies from charging ratepayers for “advertising” costs (defined broadly to include advertising Direct-Sierra Club-Chernick-p-42 1 paid for through contributions to trade associations), unless the utility demonstrates 2 that the costs provide specific, defined value for ratepayers. 38 Aside from Wisconsin statutory requirements, the general rule for utility 3 regulation is that costs should be charged to customers only if the costs either: 4 5 1. are expected to benefit customers, or 6 2. are required by law or regulation. The Companies have not shown that these costs meet those or similar 7 standards. 8 9 Q: the organizations listed in WEPCO’s Response to Sierra Club 3.3? 10 11 Do you have any specific concerns about ratepayers paying for payments to A: Yes. While EEI and AGA sponsor studies and facilitate exchange of information 12 among utilities that just help them do their job better, they also sponsor reports, 13 lobby public officials and advertise to the public and decisionmakers to pursue the 14 interests of utility shareholders and managers. 15 Wisconsin Utility Investors sounds like the kind of organization that would 16 also be involved in lobbying and public relations on issues that do not particularly 17 align with the interest of ratepayers. Each utility’s revenue requirements already 18 include its costs to address issues in regulatory proceedings. It is not reasonable for 19 ratepayers to fund yet another surrogate to also represent the utility owners in 20 regulatory proceedings. Of course, the shareholders can spend their own money on 21 regulatory participation, to the extent permitted by the Commission. The issue here 22 is whether they can charge the ratepayers for that advocacy. 38 Wis. Stat. § 196.595(2), (2m) and Wis. Admin. Code ch. PSC 12; Wis. Stat. § 195.595(1)(b). Direct-Sierra Club-Chernick-p-43 1 Q: Do the Companies adequately identify the amount of each organization’s 2 budget go to lobbying, advertising, or other activities that should not be 3 charged to ratepayers? 4 A: No. WEPCo asserts that “$5,292 (21%) of dues represent estimated lobbying 5 expenses” for the National Hydropower Association. 39 WEPCo also claims that the 6 value it reports for its EEI expense is for the “amount unrelated to lobbying” and 7 both Companies similarly assert that the reported costs for AGA are for the 8 “amount unrelated to lobbying.” The Companies do not define “lobbying” as they 9 use that term, show that all lobbying expenses have been excluded, or demonstrate 10 that the remaining expenses are legally chargeable to customers. The Companies 11 have provided no evidence that the non-lobbying costs either are for activities other 12 than advertising, or are for advertising that provides specific, defined ratepayer 13 benefits. 14 Q: How should the Commission deal with these claimed expenses? 15 A: The Commission should not allow the Companies to recover any of the costs of the 16 seven organizations I have flagged, unless and until the Companies demonstrate 17 that the claimed expenses benefit ratepayers by improving utility operations or 18 cutting costs. 19 Q: Does this conclude your testimony? 20 A: Yes. 39 WEPCo Resp. to Sierra Club 3.3 (PSC REF# 372987). It does not appear that even that amount has been subtracted from the test year expenses, unlike some portion of the EEI and AGA dues. Direct-Sierra Club-Chernick-p-44