November 7, 2018 Ms. Kavita Kale Michigan Public Service Commission 7109 W. Saginaw Hwy. P. O. Box 30221 Lansing, MI 48909 RE: Via E-Filing MPSC Case No. U-20162 Dear Ms. Kale: The following is attached for paperless electronic filing: Direct Testimony of Karl R. Rábago on behalf of Michigan Environmental Council, Natural Resources Defense Council, and Sierra Club Exhibits MEC-13 through MEC-31, MEC-21 is Reserved Proof of Service Sincerely, Digitally signed by Christopher M. Bzdok DN: cn=Christopher M. Bzdok, o=Olson Bzdok & Howard, P.C., ou, email=chris@envlaw.com, c=US Date: 2018.11.07 16:46:16 -05'00' Christopher M. Bzdok Chris@envlaw.com xc: Parties to Case No. U-20162 James Clift, MEC David Bender, Earthjustice STATE OF MICHIGAN MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of DTE ELECTRIC COMPANY for authority to increase its rates, amend its rate schedules and rules governing the distribution and supply of electric energy, and for miscellaneous accounting authority. ) ) ) ) ) ) Case No. U-20162 ALJ Sally L. Wallace DIRECT TESTIMONY OF KARL R. RÁBAGO ON BEHALF OF NATURAL RESOURCES DEFENSE COUNCIL, MICHIGAN ENVIRONMENTAL COUNCIL, AND SIERRA CLUB November 7, 2018 Table of Contents I. INTRODUCTION ................................................................................................................... 1 II. THE COMPANY’S PROPOSAL TO INCREASE FIXED CUSTOMER CHARGES FOR RESIDENTIAL RATE D1 AND SMALL COMMERCIAL RATE D3 CUSTOMERS AND TO RECOVER DEMAND-RELATED COSTS THROUGH THE FIXED CUSTOMER CHARGE ................................................................................................................................. 6 III. THE COMPANY’S PROPOSAL FOR A NEW DISTRIBUTED GENERATION RIDER 18 AND AN INFLOW/OUTFLOW DISTRIBUTED GENERATION TARIFF ...................... 22 IV. CHARGING CUSTOMERS FOR EDISON ELECTRIC INSTITUTE ACTIVITIES ........ 55 V. CONCLUSIONS AND RECOMMENDATIONS ................................................................ 61 i DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 I. INTRODUCTION 2 Q. Please state your name, business name and address, and role with the Natural 3 4 Resources Defense Council, Michigan Environmental Council and Sierra Club. A. My name is Karl R. Rábago. I am the principal of Rábago Energy LLC, a New York limited 5 liability company, located at 62 Prospect Street, White Plains, New York. I appear here in 6 my capacity as an expert witness on behalf of the Natural Resources Defense Council, 7 Michigan Environmental Council and Sierra Club. 8 Q. 9 10 Please summarize your experience and expertise in the field of electric utility regulation. A. I have worked for more than 28 years in the electricity industry and related fields. I am 11 actively involved in a wide range of electric utility issues across the United States, as an 12 expert witness, and in my capacity as executive Director of the Pace Energy and Climate 13 Center, as a party in New York rate cases and in Reforming the Energy Vision proceedings. 14 My previous employment experience includes Commissioner with the Public Utility 15 Commission of Texas, Deputy Assistant Secretary with the U.S. Department of Energy, 16 Vice President with Austin Energy, and Director with AES Corporation, among others. A 17 detailed resume is attached as Exhibit MEC-13. 18 Q. 19 20 Do you have a specific experience related to distributed energy resources, including distributed solar generation? A. Yes. I have extensive experience working in the field of distributed energy resources, a 21 category of energy resources that includes distributed generation, energy efficiency, energy 22 management, energy storage, and other technologies and related services. That experience 23 includes regulation of electric utilities in Texas, including review and approval of rates, 1 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 tariffs, plans, and programs proposed by electric utilities. I co-authored the seminal treatise 2 on distributed energy resource value, entitled “Small Is Profitable,” 1 when I was a 3 managing director at the Rocky Mountain Institute. I have also published several articles 4 and essays relating to the topic, as detailed in my resume. As a vice president for 5 Distributed Energy Services for Austin Energy, I had responsibility for all of the utility’s 6 customer-facing programs relating to distributed solar generation, energy efficiency, 7 demand management, low-income weatherization, energy storage, electric transportation, 8 building energy ratings and codes, and the utility’s electric vehicle initiatives. While with 9 Austin Energy, one of the largest municipal electric utilities in the nation, I developed and 10 implemented the nation’s first distributed solar tariff, based on objective and 11 comprehensive valuation of solar generation, often referred to as Austin Energy’s “Value 12 of Solar Tariff.” At the U.S. Department of Energy, I was the federal executive responsible 13 for the nation’s research, development, and deployment programs relating to renewable 14 energy, energy efficiency, energy storage, and other advanced energy technologies in the 15 Department’s Office of Utility Technologies. In my current position with the Pace Energy 16 and Climate Center, based at the Pace University Elisabeth Haub School of Law in White 17 Plains, New York, I lead a team that is actively engaged as a public interest intervenor in 18 the ground-breaking “Reforming the Energy Vision” process administered by the New 19 York Public Service Commission. The Pace Energy and Climate Center is committed to 20 growing self-sustaining markets for distributed energy resources in order to save money 21 for consumers and utilities, advance free market competition, and address environmental 22 challenges. I am a frequent speaker, commentator, and expert witness across the country 1 Amory B. Lovins, et al., Small is Profitable: The Hidden Economic Benefits of Making Electrical Resources the Right Size, Rocky Mountain Institute (2003). Witness Rábago was a co-author of the book. 2 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 on issues relating to electric utility regulation, distributed energy resource markets and 2 technologies, and electricity-sector market reform. 3 Q. 4 5 Have you ever testified before the Michigan Public Service Commission (“MPSC” or “Commission”) and other regulatory agencies? A. Yes. I provided testimony in MPSC Cases U-17302, U-17301, U-17767, U-18090, U- 6 18091, U-18089, U-18092, U-18093, U-18094, and U-20134. In the past six years, I 7 submitted testimony, comments, or presentations in proceedings in Arkansas, Arizona, 8 California, Colorado, Connecticut, Florida, Georgia, Guam, Hawaii, Indiana, Iowa, 9 Kansas, Kentucky, Louisiana, Massachusetts, Michigan, Minnesota, Missouri, New 10 Hampshire, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, Vermont, 11 Virginia, and Wisconsin, and before the U.S. Congress, the Federal Energy Regulatory 12 Commission, and the Federal Trade Commission. A listing of my recent previous 13 testimony, which includes testimony in a wide range of public service commission 14 proceedings relating to solar tariffs, distributed energy resources, grid modernization, 15 electric utility transformation, and utility planning and rate making, is attached as to my 16 resume. 17 Q. What materials did you review in preparing this testimony? 18 A. I reviewed applicable provisions of Michigan Compiled Laws, the application and 19 testimony of DTE Energy (“Company”) in this proceeding, Company and Commission 20 reports and websites, and Company and other party responses to requests for discovery 21 from other parties in this case. 22 Q. Do you have any business relationships with the Company? 3 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. I do not have any direct business relationships with the Company, its parent company, or 2 any affiliates. I sit as Chair of the Board of Directors for the Center for Resource Solutions 3 (“CRS”). CRS is a not-for-profit California corporation that offers certification services to 4 green pricing and green power products throughout the U.S., under the certification mark 5 called the “Green-e.” The Company’s GreenCurrentsSM green pricing service is currently 6 certified under the Green-e Energy program and pays a fee to the Center for Resource 7 Solutions for use of the certification mark. I have no direct involvement with the 8 certification of programs under the Green-e Energy program and I will not be involved 9 with matters directly relating to the Company’s certification. Consistent with the conflict 10 of interest policy adopted by the CRS Board, I have notified my fellow board members of 11 my participation in this proceeding as an expert witness. 12 Q. Are you sponsoring any exhibits? 13 A. Yes. I am sponsoring 19 exhibits: 14 MEC-13 Resume of Karl Rabago 15 MEC-14 MECNRDCSCDE-8.18 16 MEC-15 MECNRDCSCDE-8.19 17 MEC-16 MECNRDCSCDE-1.18d 18 MEC-17 MECNRDCSCDE-1.23 responses with Attachment c 19 MEC-18 MECNRDCSCDE-2.11 20 MEC-19 U-18255 MECNRDCSCDE-1.19 21 MEC-20 MECNRDCSCDE-8.20 22 MEC-21 Reserved 23 MEC-22 ELPCDE-2.84 with Attachment 4 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 MEC-23 ELPCDE-1.24a-g 2 MEC-24 MECNRDCSCDE-1.17d 3 MEC-25 MECNRDCSCDE-3.4a 4 MEC-26 MECNRDCSCDE-3.9 5 MEC-27 MECNRDCSCDE-1.10a 6 MEC-28 MECNRDCSCDE-1.2 Revised 7 MEC-29 MECNRDCSCDE-1.11 8 MEC-30 MECNRDCSCDE-3.6a 9 MEC-31 MECNRDCSCDE-3.16b 10 Q. What is the purpose of this testimony? 11 A. In this testimony, I address and recommend that the Commission deny the Company’s 12 proposals (1) for increased fixed customer charges for residential and small commercial 13 customers based on the collection of demand-related costs through the customer charge, 14 (2) for distributed generation Rider 18, comprised of a System Access Contribution 15 (“SAC”) charge and an outflow credit as a replacement for net metering, among other 16 things, and (3) for rate recovery of dues paid to Edison Electric Institute. 17 Q. How is this testimony organized? 18 A. My testimony is organized as follows: 19 • Introduction (see above) 20 • The Company’s Proposal to Increase Fixed Customer Charges for Residential Rate D1 21 and Small Commercial Rate D3 Customers and Recover Demand-Related Costs 22 through the Fixed Customer Charge 5 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB • 1 2 The Company’s Proposal for a New Distributed Generation Rider 18 and an Inflow/Outflow Distributed Generation Tariff 3 • The Company’s Proposal to Charge Customers for Edison Electric Institute Dues 4 • Recommendations to the Commission 5 II. THE COMPANY’S PROPOSAL TO INCREASE FIXED CUSTOMER CHARGES 6 FOR RESIDENTIAL RATE D1 AND SMALL COMMERCIAL RATE D3 7 CUSTOMERS AND TO RECOVER DEMAND-RELATED COSTS THROUGH 8 THE FIXED CUSTOMER CHARGE 9 Q. 10 11 Please describe the Company’s proposal to increase the residential fixed customer charge. A. The Company proposes, primarily through the testimony of Company witnesses Lacey and 12 Dennis, to increase in the fixed residential (rate D1) customer charge from $7.50 to $9.00 13 per customer per month, and from $11.25 to $15.00 per customer per month for general 14 service customers on rate D3. 15 Q. 16 17 What is the basis for the Company’s proposal to increase fixed customer charges for residential and commercial secondary customers? A. The Company takes the position that all of what it classifies as “non-variable demand 18 costs” should be recovered through a demand charge. In lieu of a demand charge for small 19 customers—because the Company is not prepared to implement a residential demand 20 charge—the Company proposes that it is most appropriate to recover demand-related costs 21 through a fixed customer charge. For residential customers, the Company classifies about 22 $1.092 billion in costs as eligible for recovery through the fixed customer charge. 2 Based 2 Company Exh. A-16, Sched. F1.4. 6 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 on about 2 million customers, the Company takes the position that the monthly customer 2 charge for residential customers should be $45.53 per customer per month. 3 For 3 commercial secondary customers, the Company classifies about $444 million in costs as 4 eligible for recovery through the fixed customer charge. 4 Based on about 207,000 of these 5 customers, the Company takes the position that the monthly customer charge for 6 commercial secondary customers should be $178.88 per customer per month. 5 The 7 Company’s proposal to increase the fixed customer charges for residential and commercial 8 secondary customers in this case is a proposed first step in the Company’s overall attempt 9 to incrementally raise the fixed customer charge or other non-volumetric charges until it 10 recovers $45.53 and $178.88 or more per customer per month, respectively, in revenues 11 that do not vary with the level of customer energy use. 6 12 Q. 13 14 Has the Company tried increasing fixed customer charges in previously filed rate applications? A. As in prior cases, the Company seeks a rate design for residential and small commercial 15 customers (1) that improperly shifts recovery demand-related costs from a volumetric 16 charge to the fixed customer charge; (2) that is economically regressive and shifts recovery 17 of these costs from high users and cost-causers to low users; (3) that weakens price signals 18 for economically efficient use of energy and investment in energy resources; and (4) that 19 weakens incentives to the Company to improve load forecasting and to seek out and make 20 the most economic choices in distributed resource investments. 21 Q. How has the Commission responded to these efforts in the past? 3 Id. Id. 5 Id. 6 Id. 4 7 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. The Company has been clear and unequivocal that fixed customer charges should be 2 reserved for the recovery of the marginal costs of connecting customers to the electric 3 system. 7 4 Q. 5 6 Why does the Company assert it is appropriate to recover demand-related revenues through a fixed customer charge? A. The Company asserts that “[c]ost causation should match cost recovery as much as 7 possible; therefore, all distribution costs, demand and customer related, should be collected 8 through the customer charge.” 8 9 Q. Is the Company justification a valid statement of sound regulatory policy? 10 A. No. It is true that rates should be assigned to cost causers in order to advance fairness and 11 economic efficiency. But the Company implies that the form of costs should be replicated 12 in the form of the rate design. There is no authority in economic or regulatory literature 13 that supports a principal that fixed costs should be recovered in fixed costs simply because 14 they are designated as fixed, or in the words of the Company, “non-variable.” There is no 15 evidence that this approach maximizes or even increases economic efficiency, for 16 monopoly utilities or for competitive businesses. Finally, there is no principle of rate 17 making that holds that the label assigned to a cost should dictate rate design structure. 18 Q. Is the Company proposal supported by facts in record? 19 A. No. The Company offers no evidence, and provided none through discovery, to support 20 any contention that demand charges or fixed charges are better correlated with cost of 7 MPSC Order, Case No. U-18255 (Apr. 18, 2018) at p. 65. See also MPSC Order, Case No. U-18014 (Jan. 31, 2017 at p. 107; MPSC Order, Case No. U-17767 (Dec. 11, 2015) at p. 119. 8 Lacey direct testimony at p. 20:1-3. See also Company responses to Exhibit MEC-14 discovery responses MECNRDCSCDE-8.18 and Exhibit MEC-15 discovery response MECNRDCSCDE-8.19 which confirm that the Company’s position is not supported by any arguments or evidence relating to economic efficiency, but only to the unsupported assertion that fixed charge recovery of demand charges “best matches cost causation to cost recovery.” 8 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 service than customers’ kWh consumption.9 In other words, the Company’s proposal to 2 collect more costs through a higher fixed charge is unnecessary to secure just and 3 reasonable cost recovery. 4 Q. 5 6 What costs does the Company include in the classification of non-variable demand costs? A. The Company classifies all demand infrastructure capital investment costs as non-variable. 7 The Company also classifies all demand-associated operations and maintenance (“O&M”) 8 costs to the non-variable category. 9 Q. 10 A. Do you agree with the Company’s classification? No. First, as noted above, the variable/non-variable designation is irrelevant for connecting 11 those costs to appropriate rate components. Second, demand and O&M costs are not non- 12 variable. 13 Q. What costs should the Company recover through the fixed customer charge? 14 A. The fixed customer charge should be reserved for the recovery of costs that vary 15 exclusively with the number of customers and the cost to connect those customers to the 16 grid. This is the Commission’s standard, as previously explained. It is also consistent with 17 sound rate making principles, which state that the customer function and, indirectly, the 18 customer charge, should reflect the costs incurred by the utility to connect the average 19 customer to the electric system for service. In 1961, James C. Bonbright defined the fixed 20 customer charge as follows: 21 22 23 [The customer costs] are those operating and capital costs found to vary with the number of customers regardless, or almost regardless, of power consumption. Included as a minimum are costs of metering and billing 9 Exhibit MEC-16 discovery responses to MECNRDCSCDE-1-18d. and Exhibit MEC-17 discovery response MECNRDCSCDE-1.23c. 9 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 2 along with whatever other expenses the company must incur in taking on another consumer. 10 3 Simply stated, Bonbright’s definition, like the Commission’s prior orders, ensures that the 4 customer charge is limited to the marginal cost of connecting the customer to the grid, and 5 should include only costs that vary directly with the number of customers. 11 6 Q. 7 8 What is the monthly bill impact of the proposed increase in fixed residential customer charges? A. The Company seeks a 9.1% increase in residential revenues. 12 The proposed fixed charge 9 increase is 20%. 13 This disproportionate increase to the fixed charge raises overall rates 10 more for customers who use the least amount of electricity and provides a price signal to 11 increase, rather than decrease, usage. The Company’s bill impact estimates reveal that the 12 greatest impact of the proposed fixed charge increases falls on the lowest users of 13 electricity. 14 For example, for rate D1 customers who use 140 kWh per month, the bill for 14 all charges would increase by 11.12%, while the percentage increase for customers that use 15 ten times as much electricity, or 1,400 kWh per month, the bill would increase by 8.77%. 16 In effect, the higher fixed customer charges for both residential and commercial secondary 17 customers operate and communicate price signals like a declining block rate, a rate making 18 approach that is inconsistent with efficient electricity operations and markets. 19 Q. 20 Why is the fact that the proposed rate changes impose a greater burden on low energy residential users important, in addition to the price signal related to energy use? 10 Bonbright at 347. See also, Jim Lazar & Wilson Gonzalez, “Smart Rate Design for a Smart Future at 36 (2015), http://www.raponline.org/wp-content/uploads/2016/05/rap-lazar-gonzalez-smart-rate-design-july2015.pdf 12 Exh. A-16, F2, at p. 2. 13 Calculated as ($9.00 - $7.50) / $7.50 = 20%. 14 Exh. A-16, F4, at p. 2. 11 10 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. Low energy residential users are often low-income customers, fixed-income customers, 2 and the elderly, whether or not they are enrolled in a discount rate. Customers who make 3 significant investments in energy efficiency and self-generation fall into this category as 4 well. For these residential customers, proposed rate changes like those proposed by the 5 Company are economically regressive. 6 Q. 7 8 What data are available about residential energy usage levels and income in Michigan? A. The Company did not address the relationship between energy usage levels and income in 9 its rate application. However, in discovery the Company cited low-income customer 10 population numbers in the hundreds of thousands. 15 While the Company has a Residential 11 Income Assistance program that provides a credit equal to the fixed charge, and a 12 Residential Service Special Low Income Pilot program that provides a larger credit, the 13 total number of credits available under these programs is much lower than DTE’s total 14 number of low income customers—leaving tens of thousands of lower income customers, 15 or more, impacted by the higher fixed charge. Data obtained from the U.S. Energy 16 Information Administration’s Residential Energy Consumption Survey for 2009, the most 17 recent data available, and published by the National Consumer Law Center (“NCLC”), 18 which show that energy usage is closely correlated with household income in Michigan. 16 15 Exhibit MEC-18, discovery response MECNRDCSCDE-2.11, Exhibit MEC-19 discovery response U-18255 MECNRDCSCDE-1.19 and attachment. 16 “Utility Rate Design: How Mandatory Monthly Customer Fees Cause Disproportionate Harm," available at: http://www.nclc.org/images/pdf/energy_utility_telecom/rate_design/MI-FINAL2.pdf. 11 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Figure 1: U.S. EIA Residential Energy Consumption Survey Data - Michigan 2009 2 3 In addition, according to the U.S. EIA data, median electricity usage is also lower for 4 households with residents older than 65 years, and for the homes of racial minorities. 5 Figure 2: U.S. EIA Residential Energy Consumption Survey Data - Michigan 2009 6 7 Q. 8 9 10 Does the Company need to increase fixed customer charges to avoid a financial integrity risk associated with volumetric rates? A. No. In fact, the Company does not assert that increased fixed customer charges are necessary to address or avoid any financial integrity risk associated with revenue recovery. 12 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 First, the actual ratemaking principle is that rates should reflect costs, and not that labels 2 applied in cost allocation should align with labels applied to monthly bill components. 3 There is no statistical likelihood of any real risk to the Company’s financial integrity due 4 to overall residential and small commercial customer usage level variability in the interval 5 between rate cases. The adverse impacts of high fixed charges on low use, low-income, 6 and fixed income elderly customers, as well as upon the economics of efficient use of 7 energy, discussed later in my testimony, outweighs any hypothetical risk to the Company’s 8 earnings. It should also be noted that if inter-rate case revenue variances were an actual 9 concern, they could more reasonably be addressed through better forecasting and the use 10 11 of future test year methods. Q. 12 13 Why is it appropriate to continue recovering so-called “fixed” costs through volumetric rates? A. It is appropriate because of the price signal function of properly designed rates. Properly 14 designed rates reflect properly allocated costs and send signals for efficient consumption 15 in the future. 16 Q. 17 18 Is recovery of fixed costs through volumetric charges consistent with principles of ratemaking and the economic efficiency of rates? A. Yes. Sound ratemaking is based on ensuring that costs are properly allocated to customer 19 classes based on cost causation. I know of no ratemaking or economic principle that finds 20 that cost structure must be replicated in rate design, especially when significant negative 21 policy impacts are attendant to that approach. Traditional rate making limits residential and 22 small commercial customer charges to certain basic customer connection costs—the 23 consumption measurement function of the meter, billing services associated with account 13 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 set up and disconnection, and other similar general and administrative costs that vary with 2 customer count and with the cost to connect a customer to electric service. As the 3 Commission has ordered on several prior occasions, this limited range of fixed costs should 4 form the basis and ceiling for fixed customer charges. 5 Q. 6 7 When costs associated with distribution systems are classified as fixed, should they be collected through the fixed customer charge? A. Not necessarily, and not if the result is that low usage customers are disproportionately 8 impacted, or adverse impacts on energy efficiency, conservation, and renewables result, as 9 discussed later in my testimony. First, such a policy would depend on proper classification 10 of fixed versus variable costs. Very few costs are actually fixed over the mid to longer 11 term. Second, I am not aware of any evidence or analysis, and see none in this record, that 12 increasing fixed customer charges improves system-wide economic efficiency or the 13 efficiency of customer decisions. 17 Absent evidence of system-wide or customer efficiency 14 benefits, fixed customer charges should not be increased, and demand-related costs should 15 instead be allocated to volumetric charges. Again, there is no agreement on proper 16 classification of costs as fixed or variable (including the time period for making that 17 determination) and, even if there was, the differences in costs that lead to labeling them as 18 fixed or variable do not, standing alone, tell us anything about the rate design that should 19 be used to recover them. 20 Q. What is the key difference between fixed and variable costs? 17 The Company confirms that it has no such authority for such a proposition and is able to cite only a single advocacy piece supporting the use of customer charges to collect demand-related costs. See Company response to MECNRDCSCDE-8.20 Exhibit MEC-20. 14 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. The key discriminator for labeling a cost as fixed or variable is the element of time. It is 2 important to remember that over the long term, all costs are variable; just as over the very 3 short term, one could argue all costs are fixed. For example, distribution transformers are 4 typically treated as a fixed cost because of their relatively long life. Loading on a 5 transformer, especially during periods of high demand, will impact its useful life. As a 6 result, demand reductions can extend the useful life of transformers. In order to send a price 7 signal that will encourage the reductions in demand that could extend useful life and reduce 8 revenue requirements in the future, a volumetric rate should be used. Demand charges for 9 these costs may be appropriate for much larger customers whose individual demands have 10 greater impact on the cumulative loads on the equipment and where customers have greater 11 experience with and control over their usage levels and patterns. 12 Q. 13 14 How do residential and small general service customers exercise control over their variable and fixed costs? A. With volumetric rates to recover fixed and variable demand and energy costs, residential 15 and small commercial customers have meaningful, practical, and realistic opportunities to 16 exercise control over their energy bills and costs. As discussed below, reductions in use— 17 through efficiency, conservation, or self-generation—all contribute to reductions in 18 variable energy costs. Moreover, these behaviors also reduce high peak demand, and by 19 doing so customers directly contribute to reduced fixed costs going forward. Efficiency, 20 demand response, solar, storage, and other options allow customers to contribute to fixed 21 cost reduction. All of these options are frustrated by shifting cost recovery for demand- 22 related costs from volumetric to fixed monthly charges, as proposed by the Company. The 23 overwhelming experience in the United States is that a utility can recover the exact same 15 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 amount of authorized revenue requirement through a volumetric charge and avoid such 2 unwelcome consequences. 3 Q. 4 5 Do fixed charges for demand-related costs send a meaningful price signal to customers? A. No. There is no meaningful price signal in charging a rate that small customers cannot 6 effectively respond to through modification in usage behavior. Recovering demand-related 7 costs in fixed per-customer charges means customers are burdened with those charges 8 regardless of the level of their use, and regardless of the time that they use electricity. The 9 demand charges that the Company aspires to also collect from residential and small 10 commercial customers in the future—charges based on sunk fixed costs—are also deeply 11 flawed because most such customers lack meaningful tools for responding to them. This is 12 one reason why there is no widely accepted regulatory principle that merely labeling a cost 13 as “fixed” compels its recovery through a fixed customer charge or an effectively fixed 14 demand charge. Indeed, if fixed charges for demand-related costs send any price signals at 15 all, it is the perverse price signal that changes in usage, regardless of time of use, have no 16 effect on bills—encouraging electricity waste. 17 To the extent that there are three theoretical options—demand charges, volumetric 18 charges, or fixed charges—fixed charges are the worst for purposes of sending price 19 signals. Demand charges are second worst, and for customer who have no affordable 20 meaningful way to reduce demand, demand charges operate as fixed charges. Residential 21 and small commercial customers have only limited options for changing their demand 22 independently of their energy use, and this is especially true of renters. A customer’s 23 demand, especially for low-income and low use customers, is a function of the energy 16 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 performance of their home or business facility, which is often rented; their major 2 appliances or equipment, which are often expensive to replace or upgrade; and the weather. 3 These customers do have increasing options for reducing energy use, so allocating and 4 recovering demand-related costs on the basis of volumetric energy consumption is the best 5 rate design option for sending price signals for both energy and demand cost causation on 6 a going-forward basis. A fixed charge for demand-related costs eliminates any potential 7 price signal. Imposing higher demand-based fixed charges on these customers takes bread 8 from the tables of these customers by increasing their energy bills while removing any 9 tools to mitigate that burden and is the rate design equivalent of telling these customers to 10 just “eat cake.” 11 Q. How should the Company recover prudently-incurred demand-related fixed costs? 12 A. There is no reason to change the Commission’s established approach on this issue. The 13 prudently incurred demand-related costs (above those strictly associated with the cost of 14 connecting the customer to the grid) that the Company proposes to allocate to fixed 15 customer charges should be allocated to the volumetric rate. The Company has not 16 demonstrated the reasonableness of its proposed rate design, especially in light of the 17 potential adverse impacts discussed below and considering the relative impacts of 18 alternative rate designs. 19 Q. Do the Company’s proposals to increase the fixed customer charges, and potentially 20 impose residential and small commercial demand charges in the future, help to 21 stabilize the Company’s revenues? 22 23 A. Maybe but not necessarily. Moreover, while it is understandable that the Company would try to fix a larger portion of its revenues collected from customers, it is not reasonable that 17 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 they should be allowed to do so. Fixed charges for demand-related investments send a price 2 signal to utilities that recovery of their demand-related spending is not subject to variability 3 in the level of customer demand and, therefore, there is no value to correctly predicting 4 loads. If a utility company incorrectly forecasts greater demand than it ends up 5 experiencing, it will have an overbuilt system and should experience a situation where sunk 6 fixed costs are potentially unrecovered under current rates. Imposing on utilities the 7 potential financial responsibility for unjustified overbuilding provides an efficient price 8 signal to the utility to correctly predict loads by improving forecasting. It should also 9 inspire investment in a smarter grid that leverages the potential benefits of all manner of 10 flexible distributed energy resources as cost-effective alternatives to large, expensive, and 11 inflexible resources. Shielding the utility from the consequences of unjustified 12 overbuilding or of uneconomic resource decisions through fixed charge recovery of costs 13 actually creates a perverse incentive in favor of economic waste. As explained later in the 14 section discussing impacts on energy efficiency and distributed generation, the Company’s 15 proposal to increase fixed charges for residential and general service customers not only 16 constitutes the bad choice, it frustrates the good ones. 17 Q. 18 19 Can you provide an example of the price signal to the utility when demand costs are recovered through volumetric rates instead of fixed charges? A. One example is that if the utility forecasts that demand on a particular feeder will be heavy, 20 it may install a larger, more expensive transformer. The money spent on that transformer 21 will be sunk. If load and sales do not grow as expected, the utility risks under-recovering 22 the cost of the transformer. That provides a signal to the utility to make its forecasts as 23 accurate as possible by putting risk of inaccurate forecasts on the utility, and to consider 18 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 alternatives, such as demand reductions, to the traditional transformer solution. In contrast, 2 if the utility is guaranteed recovery of the over-sized transformer through fixed charges, it 3 shifts risk of inaccurate forecasts to customers and discourages the search for more flexible 4 alternative investments or spending. 5 Importantly, volumetric rates also simultaneously provide a price signal to 6 customers to reduce their loading, which reduces the size of the next transformer and 7 associated cost in the future. Energy efficiency, demand response, and other factors can 8 reduce the fixed cost requirements in the future, and perhaps even allow for the installation 9 of smaller replacement equipment. These measures can also extend the useful life of the 10 installed fixed cost assets. Moving demand cost to the fixed charge, instead of the 11 consumption based charge, provides no price signal to reduce consumption— 12 simultaneously providing inefficient price signals to both utility and customers. The 13 expected result is higher costs in the long term. 14 It is widely accepted—and a strong justification for grid modernization 15 investments—that customers can reduce the requirement for expensive infrastructure 16 investments by reducing their usage, especially during particular times of the day. These 17 reductions arise because of reductions in system loading, which in turn reduces the need 18 for costly system upgrades, reduces wear and tear (e.g., temperature-related degradation), 19 and results in capital cost deferrals related to replacement. Higher volumetric charges for 20 on-peak usage can further support demand response programs and energy storage 21 deployment with similar results. 22 23 Q. Did the Company evaluate how customer demand would or might change in response to changes in rates? 19 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. No. The Company does not address the issue of price elasticity of demand. The Company 2 did not produce customer usage information by household for residential customers or 3 business income for commercial secondary customers. In order to support its application, 4 the Company must produce competent evidence that its rates are at least likely to produce 5 changes in consumption behavior that would track with economically efficient outcomes. 6 In the absence of any evidence of elasticity coefficients for residential and small 7 commercial customers under both existing and proposed rates, the Company cannot 8 support a showing that its proposed rates are likely to be effective in this regard. The 9 Company’s application lacks a foundation on which to assert that its proposed rate design 10 11 is just and reasonable. Q. 12 13 energy efficiency and conservation? A. 14 15 Increases in fixed customer charges create powerful price signals against investment in energy efficiency, conservation, and renewables. Q. 16 17 How do increased fixed customer charges specifically impact customer investment in Did the Company consider the impact of its proposed increase in the fixed customer charge on energy efficiency, conservation, and renewables? A. The Company provided no evidence that it considered the impacts of its fixed charge 18 proposals, or its future demand charge proposals, on energy efficiency, conservation, or 19 renewables. 20 Q. 21 22 23 Why should the Commission be concerned about approving a rate design that is detrimental to energy efficiency, conservation, and renewables? A. Energy efficiency, conservation, and renewables offer many benefits to the people and State of Michigan. These benefits include resource diversification, grid resiliency, future 20 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 cost reductions associated with increased volume of deployment (economies of scale), job 2 creation, system-wide cost reductions, and leveraging of non-utility investment dollars, 3 among others. 4 Q. 5 6 What result would you expect from allowing a monopoly electric utility to use fixed charges to recover fixed cost investments? A. In a competitive market, a service provider would meet customer efforts to reduce and 7 increase control over service bills with service innovations, operational efficiency, and 8 price reductions. The logical result of using rate design to insulate a monopoly from market 9 forces that would otherwise drive such benefits is that the monopoly will resist innovation 10 and increase prices. In conclusion, the proposed increase in the fixed monthly charges for 11 residential and small commercial customers are inimical to Michigan policy and utility 12 sector transformation objectives. 13 Q. 14 15 What action should the Commission take on the Company’s fixed customer charge proposals for residential and small commercial customers? A. I recommend that the Commission deny the Company proposals to increase the monthly 16 customer charges. Consistent with its prior Orders, the Commission should direct the 17 Company to remove demand-related investment costs beyond the cost to connect small 18 customers and recalculate the monthly customer charge without those costs. 19 Q. 20 21 In summary, does the Company’s proposal to disproportionately increase fixed customer charges constitute sound economics, regulation, and policy? A. No. Peter Kind, known as the author of the Edison Electric Institute’s “Disruptive 22 Challenges” paper, recognized in a paper published in November of 2015 that “many 23 utilities have been seeking to increase fixed charges, while customers and policymakers 21 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 are vehemently opposed to such action. An evolved approach would focus on common 2 ground with win4 (i.e. beneficial to customers, policy, competitive providers, and utilities) 3 perspective.” 18 As Kind further explained: 4 5 6 7 8 Adopting meaningful monthly fixed or demand charges system-wide will reduce financial risk for utility revenue collections for the immediate future, but this approach has several flaws that need to be considered when assessing alternatives through a win4 lens, by which all principal stakeholders benefit. Fixed charges: 9 10 • do not promote efficiency of energy resource demand and capital investment; 11 • reduce customer control over energy costs; 12 • have a negative impact on low- or fixed-income customers; and 13 14 15 • impact all customers when select customers adopt [distributed energy resources] and potentially exit the system altogether, if high fixed charges are approved and the utility’s cost of service increases. 19 16 The Company’s proposed monthly charge proposals for residential and small commercial 17 customers is bad for customers, policy, competitive providers, and even itself. It puts the 18 Company’s revenue recovery strategies in opposition to the best interests of its customers, 19 which should be an unsustainable posture in an increasingly competitive sector. In my 20 opinion, fixed charge proposals like those put forth by the Company in this case harm 21 customers in several ways, violate fundamental principles of rate design, are unsupported 22 by sound argument, and are inconsistent with regulatory trends around the country. 23 III. THE COMPANY’S PROPOSAL FOR A NEW DISTRIBUTED GENERATION 24 RIDER 18 AND AN INFLOW/OUTFLOW DISTRIBUTED GENERATION 25 TARIFF 18 19 Peter Kind, “Pathway to a 21st Century Utility,” CERES (Nov. 9, 2015), at p. 12. Id. at 30. 22 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Overview of the Company’s Rider 18 Proposal 2 Q. Please summarize the Company’s Rider 18 proposal. 3 A. The Company proposes Rider 18 as a replacement tariff for net metering or distributed 4 generation (“DG”) customers, purportedly under the provisions of 6 PA 341 § 6a.(14).20 5 The Company proposal has three major components. First, the Company proposes to 6 charge DG customers for energy consumed as recorded on the consumption channel of the 7 meter (“inflow”) according to the customer’s otherwise-applicable retail service rate. 8 Second, the Company proposes a lost sales charge that it calls a System Access 9 Contribution ("SAC") charge for distributed generation customers whose underlying rate 10 does not include a demand charge, collected based on the customer’s installed distributed 11 generation capacity. The proposed SAC charge is $2.31 per kW per month of installed 12 generation capacity for residential customers, and $2.28 per kW per month of installed 13 capacity for small commercial customers. 21 Third, the Company proposes to provide 14 credits to customers for metered generation outflow at the local node monthly average 15 locational marginal price (“LMP”). The tariff provides for no monthly netting of 16 consumption and generation as contemplated for distributed generation programs under 17 Act 342 Part 5. 22 18 Q. Under what authority does the Company propose its new tariff for DG customers? 19 A. The Company asserts that its proposal complies with provisions of Act 342, 23 and with the Commission’s April 18, 2018 order in Case No. U-18383. 24 20 20 See Dennis at p. 19, et seq. Exh. A-16, Sched. F9. 22 2016 PA 342, MCL 460.1173-1185. 23 See Serna direct testimony at p. 66:1-10. 24 In re Commission’s own motion, to implement the provisions of Sections 73 and 183(1) of 2016 PA 342 and Section 6a(14) of 2016 PA 341, Case No. U-18383, Order (April 18, 2018). 21 23 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Q. What did the Commission’s April 18, 2018 order in Case No. U-18383 require? 2 A. On April 18, 2018, in Case No. U-18383, the Commission that, “in any rate case filed after 3 June 1, 2018, the rate-regulated utility must file the Inflow/Outflow tariff, attached to this 4 order as Exhibit A. The rate-regulated utility may also file its own distributed generation 5 tariff, if desired.” 25 6 Q. What does Michigan law require regarding the Company’s proposed tariff for 7 distributed generation interconnected to the grid and operated by residential and 8 small commercial customers? 9 A. Michigan law on distributed generation is complex. Table KRR-1 below summarizes the 10 different structural, credit, and charges under True Net Metering, Modified Net Metering, 11 and the Inflow / Outflow tariff models. As a matter of foundational principle, MCL § 12 460.6a. requires tariffs adopted under that statute be based on “equitable cost of service for 13 utility revenue requirements for customers who participate in a net metering program or 14 distributed generation program.” 26 That is, it provides for a charge specifically for 15 customers taking service under the net metering and distributed generation programs, not 16 an alternative to such programs. 17 The distributed generation program was adopted through Act 342, which replaced 18 the prior net metering program but contains many similar provisions. Act 342 states that 19 its purpose is “to promote the development and use of clean and renewable energy 20 resources,” and “to diversify the resources used to reliably meet the energy needs of 21 consumers,” and to “[e]ncourage private investment in renewable energy.” 27 Company 25 Id. at p. 18. MCL 460.6a.(14). 27 MCL 460.1001(2). 26 24 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 witness Serna also offers some non-legal interpretations of the requirements of Act 342 in 2 his testimony28 that I will address in greater detail later in this testimony. 28 Serna direct at p. 49:19-24; p. 65:3-20. 25 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Table 1 – Comparison of DG Tariff Structures 2 26 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Q. 2 3 What is your overall assessment of the Company’s proposed DG tariff as it impacts residential and small commercial customers? A. The Company’s proposal fails to meet the requirements of Michigan law because it is not 4 based on equitable cost of service and because it is discriminatory and unreasonable in its 5 treatment of DG customers. 6 Q. 7 8 Are you offering an opinion about the legality of the Commission’s order in Case No. U-18383 adopting the Inflow/Outflow structure in place of netting? A. No. I understand that there are disagreements about the relationship between the MCL 9 460.6a tariff and the distributed generation tariffs under Part 5 of Public Act 342. I also 10 understand that there is no final decision in the U-18383 docket, and therefore there has 11 been no opportunity for court review, because of a pending petition request for 12 reconsideration. I am not providing an opinion about those legal issues. 13 Q. 14 15 Does the Company’s proposal meet the Commission’s requirements as set out in its April 18, 2018 order in Case No. U-18383? A. The Company’s DG tariff proposal complies with the procedural requirement set out in the 16 Commission’s April 18, 2018 Order in Case No. U-18383 to the extent that it filed a DG 17 tariff structured around the so-called “Inflow/Outflow” approach recommended by Staff 18 and endorsed by the Commission in Case No. U-18383. However, the Company also filed 19 and prefers an alternative proposal in Rider 18 that diverges from the Inflow/Outflow 20 approach contemplated by the Staff’s proposal in Case No. U-18383 and contains 21 fundamental substantive flaws that should preclude it from being approved. 22 23 Q. What is the economic effect of the proposed tariff on residential and small commercial DG customers? 27 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. The Company did not prepare a bill impact analysis for proposed Rider 18. However, in 2 response to a discovery request, the Company did provide sample data for five DG 3 customers, with an average of 4.7 kW of installed DG. 29 Those sample data are provided 4 in Table 2, below, which shows the dramatic increase in charges and reduction in savings 5 that these DG customer experience on average. For these customers, on average, the 6 Company proposal represents a more than 100% increase in charges levied on DG 7 customers and reduces monthly savings by about $44 dollars per month. While impacts 8 ultimately depend on customer energy use and DG production, over a 25-year estimated 9 life for a solar customer, this difference amounts to a reduction in savings of more than 10 $13,000. For a customer with a 4.7 kilowatt generation system, the Company’s proposed 11 SAC charge adds $3,216 in charges over the 25 years, or $10.72 per month, for the DG 12 customer. Assuming an after-tax cost of going solar in 2018 of around $2.77, 30 the savings 13 reductions and additional SAC charges proposed by the Company more than double a 14 customer’s cost for going solar. 31 The Company’s proposed SAC charge in particular is 15 devoid of any reasonable connection to the cost of service. The Company’s inflow charge 16 and outflow credit proposals are also flawed and unreasonable. Overall, I view the 17 Company’s proposal as confiscatory. 18 Q. Why do you use the word “confiscatory?” 19 A. While the impacts of the Company proposals will vary with customer levels of usage and 20 DG generation, and with prices, the pattern revealed in the Company’s own data from five 21 sample customers, and summarized in Table 2, is that the proposed Rider 18 terms will 29 Exhibit MEC-22, discovery response ELPCDE 2-84. https://news.energysage.com/how-much-does-the-average-solar-panel-installation-cost-in-the-u-s/ 31 Calculated as ($13,000 + $3,216) / 4.7 kW = $3.450 per watt. 30 28 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 reduce the benefits of self-generation by more than 60%. 32 For the reasons set out in this 2 testimony, this level of tax on private customer investments in DG is excessive and 3 unreasonable, and therefore, if approved would be confiscatory. 4 Table 2: Impact of Company Rider 18 Proposal on Sample Residential Customers 5 6 Q. 7 8 What are the major drivers in reduction of value and increase of costs for DG customers under the Company’s proposed Rider 18? A. As Table KRR-2 makes clear, the Inflow / Outflow method is itself the major driver of 9 value reduction when outflow is set at the monthly average LMP value, accounting for 10 nearly three quarters (74%) of the reduced value. 33 The SAC reduces the value of DG by 11 adding the remaining 26% of lost value in the form of a charge under the Company’s 12 proposal. 13 Q. 14 15 What are your primary concerns with the Company’s justification for the Rate Rider 18 provisions? A. Witness Serna’s testimony on the solar rate design reads like anti-solar advocacy, rather 16 than substantive evidence. It is short on facts, long on unsubstantiated assertions, and 17 unsupported by primary data. The most serious flaws in the Company’s Rider 18 proposal 18 are the way the Company unreasonably and selectively seeks interprets the provisions of 32 33 Calculated as $44.09 / $71.24 = 62%. Calculated as $9,810 / $13,228 = 74.2%. 29 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Public Acts 341 and 342 to propose the elimination of true net metering and modified net 2 metering in favor of an Inflow / Outflow tariff that: (1) fails to provide a cost of service 3 justification for the proposed inflow charge, (2) proposes a charge that resembles a stand- 4 by, back-up, or supplementary power service charge without a reasonable relationship to 5 the costs to serve DG customers; (3) includes an outflow credit value that fails to reflect 6 the full avoided costs and benefits of exported DG electricity; and (4) adds a forfeiture 7 provision that confiscates earned DG customer outflow credit value when a customer 8 terminates participation in the DG program. This testimony addresses these issues serially, 9 and in the same order that they are proposed in Company testimony. 10 The Company’s Proposed Inflow Rate Based on Underlying Class Rates 11 Q. What is the Company’s inflow charge proposal under its Rider 18 proposal? 12 A. The Company proposes to charge small DG customers for their inflow usage at the level 13 of their standard retail rate for consumption. The Company also proposes to impose a 14 System Access Contribution (“SAC”) charge, discussed in the following section of this 15 testimony. 16 Q. (“Staff Report”) proposing the use of the Inflow / Outflow tariff model? 34 17 18 Is the Company proposal the same as that by the Staff in its February 21, 2018 report A. Because of differences in terminology, it is not entirely clear whether the Company 19 proposal is congruent with the Staff Report. The Staff Report speaks in terms of cost of 20 service allocators and billing determinants, and states that “separate and distinct rate- 21 schedules for DG customers are not needed,” 35 implying that all rates used in rate schedules 34 MPSC Staff, “Report on the MPSC Staff Study to Develop a Cost of Service-Based Distribution Generation Program Tariff,” MPSC Case No. U-18383 (Feb. 21, 2018), at p. 12. 35 Id. 30 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 for customers without DG would be used to calculate the inflow charge under the Staff 2 proposal. The formula used in the Staff Report identifies both energy (kWh) and demand 3 (kW) “Distribution & Power Supply” elements of the inflow charge. The Company 4 proposes a charge “equivalent to the standard, full service retail rates for the underlying 5 rate schedule.” 36 Because the Company insists that its proposal is an “equivalent to,” rather 6 than simply applying, the full-service retail rate it is not clear that the Company is actually 7 proposing to apply the retail rate. 8 Q. 9 to the proposed inflow charge, are the otherwise applicable class rates for 10 11 Notwithstanding potential differences in the Staff and Company approaches relating consumption of energy and demand a reasonable basis for inflow charges? A. I cannot reach a conclusion as to the reasonableness of using the otherwise applicable class 12 rates as the inflow charge without more information, particularly about the usage patterns 13 of individual DG customers or even DG customers in aggregate. 14 Solar DG customers in particular have generation profiles that are very coincident 15 with utility system peaks and pre-peaks. These customers have their own non-coincident 16 peaks that provide diversification and asset utilization benefits to the system as a whole.37 17 And the excess energy exported from a DG facility immediately travels through a revenue 18 meter to serve load, generate utility billings, and avoid costs extending throughout the 19 utility system. 38 All these factors point to the potential for significantly lower costs to serve 20 DG customers than similar non-DG customers. It is likely a credit is in order for DG 21 customers that reflects this lower cost of service, and that an inflow rate based on the costs 36 Serna direct at p. 58:20-21. The Company has conducted no study of the benefits of DG to the system. See Company response to ELPC 1.24g Exhibit MEC-23. 38 See Company responses to ELPC 1.24b & 1.24c Exhibit MEC-23. 37 31 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 associated with serving non-DG customers would be too high. I understand that other 2 witnesses may be providing evidence related to the cost to serve DG customers. I reserve 3 the right to respond to that evidence. 4 Q. Did the Company provide any evidence to support a finding that the costs of serving 5 DG customers are equivalent to the costs of serving non-DG customers in the same 6 rate class? 7 A. The sole basis offered by the Company for setting the inflow charge based on the DG 8 customers’ underlying consumption rates is the somewhat ambiguous declaration that “the 9 volumetric retail rates in [the Company’s] residential, and some of the secondary 10 commercial rate schedules, captures the entire cost of service not supported by the 11 customer charge.” 39 For these reasons, further analysis is required before it can be 12 concluded that the Company’s proposed inflow charge in Rider 18 is just and reasonable. 13 The Company’s Proposed System Access Contribution (“SAC”) Charge 14 Q. What are your concerns with the Company’s proposed SAC charge in Rider 18? 15 A. There are two major flaws with the Company’s SAC charge proposal: How it works, and 16 how it was constructed. First, the SAC imposes a charge on customers for what is 17 essentially supplementary power service (and perhaps also back-up power service) that is 18 not cost-based. Second, the SAC charge is constructed to impose a charge on DG customers 19 for the energy not used by a hypothetical customer with a hypothetical DG facility and a 20 hypothetical pattern of electricity usage, which is then allocated based on system capacity 21 rather than energy usage (real or hypothetical). 40 As a result, the SAC charge is based on 39 Serna at p. 59:5-7. See Exhibit MEC-24, Company discovery response MECNRDCSCDE-1.17d. See also Exhibit MEC-25, Company response to MECNRDCSC-3.4a, “on an overall basis (using 2017 data as a proxy for future loads), the System Access 40 32 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 the flawed premises that non-use of grid-supplied energy creates a basis for a charge under 2 cost-based regulation, and that charges on self-generators should be based on sub-group 3 deviations from forecasted usage which are then imposed on nameplate capacity rather 4 than usage. 5 Q. 6 7 Please explain how cost of service rate making principles inform evaluation of the Company’s proposed SAC charge. A. A fundamental principle of cost of service regulation is that a utility must enjoy a 8 reasonable opportunity to recover the prudently incurred costs associated with the 9 provision of electric service. And because the monopoly utility stands in a position of 10 immense market power over small customers, the rates it charges must be based on the 11 costs associated with services used by customers. It is therefore also axiomatic that under 12 tariffed rates, a customer can only be required to pay for services that they actually use. In 13 seeking regulatory approval to charge and collect rates, utilities have the legal 14 responsibility of producing competent evidence of the costs incurred and of proving that 15 the rates charged are reasonable, just, and not unduly discriminatory. The Company has 16 not based the proposed SAC charge in Rider 18 on actual costs that is has incurred or will 17 incur in providing services specifically to distributed generation customers. 41 Therefore, 18 the Company fails in meeting its burdens under Michigan law. Contribution charge when combined with the inflow charge, is designed to recover the distribution revenue if no electricity was consumed with behind the meter generation, however, impacts on customers would vary.” 41 See Exhibit MEC-26, Company response to MECNRDCSCDE-3.9, “The Company did not undertake a review or study any connection and/or correlation between an individual distributed generation customer’s nameplate system capacity and his or her contribution to peak loads, energy, and customer counts.” 33 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Q. Are there statutory and regulatory provisions, in addition to general requirements 2 that rates be just and reasonable, that guide the review of the Company’s proposed 3 SAC charge? 4 A. Yes. MCL 460.6a. requires that a tariff related to a distributed generation program be based 5 on “equitable cost of service for utility revenue requirements for customers who participate 6 in a net metering program or distributed generation program.” 42 Act 342 states that its 7 purpose is “to promote the development and use of clean and renewable energy resources,” 8 and “to diversify the resources used to reliably meet the energy needs of consumers,” and 9 to “[e]ncourage private investment in renewable energy . . .” 43 Further, because small 10 distributed solar generation facilities are also qualifying facilities under federal and 11 Michigan law, additional state and federal laws apply. The federal Public Utility 12 Regulatory Policies Act 44 requires utilities to interconnect “small power production 13 facilities” as defined by FERC eligibility requirements for qualifying facilities (“QFs”). 45 14 QF status automatically applies to on-site solar generators up to 1 MW. 46 FERC’s 15 regulations implementing PURPA require that rates for electricity sales to QFs “shall be 16 just and reasonable and in the public interest” and “[s]hall not discriminate against any 17 qualifying facility in comparison to rates for sales to other customers served by the electric 18 utility.” 47 Under FERC’s regulations, rates for QFs that differ from the rates otherwise 19 applicable to non-QF customers are only considered to be non-discriminatory when they 20 are “based on accurate data and consistent system-wide costing principles” and only “to 42 MCL 460.6a.(14). MCL 460.1001(2). 44 16 USC Ch. 46. 45 18 C.F.R. § 292.303(c). 46 Facilities with net power production of less than 1 MW are exempt from the QF certification process. 18 C.F.R. § 292.203(d). 47 18 CFR § 292.305(a)(1)(ii). 43 34 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 the extent that such rates apply to the utility's other customers with similar load or other 2 cost-related characteristics.” 48 MCL 460.6v imposes nearly identical requirements on the 3 Company and Commission-approved rates relating to just and reasonable rates, non- 4 discrimination, and sales to qualifying facilities. 49 5 Q. 6 7 Does the proposed SAC charge comply with these statutory and regulatory requirements? A. No. The Company can only impose additive charges on any self-generating customer, 8 which must be based on actual costs of providing service as determined through 9 methodologies applied to all customers regardless of whether they self-generate. The SAC 10 fails under those standards. 11 The Company states that DG customers seek service “to meet their energy needs 12 when the generation is not operating at full output or when there are additional demand 13 that solar cannot meet.” 50 The Company is describing supplementary power service and 14 perhaps, back-up power service. A charge for supplementary service is appropriate for 15 service above and beyond what the DG customer provides for themselves with their own 16 equipment in order to meet their needs. 51 The Company has not created a cost-based rate 17 for supplementary service with its class-based rate, and has not demonstrated in this case 18 that the Company has incurred any costs relating to the provision of such service that are 19 additional to those reflected in class rates. 52 As shown in witness Serna’s testimony at 48 18 CFR § 292.305(a)(2). See MCL 460.6v.(4). 50 Serna direct at p. 51:8-13 51 MCL 460.6v.(6)(f): "Supplementary power" means electric energy or capacity supplied by an electric utility, regularly used by a qualifying facility in addition to the electric energy or capacity that the qualifying facility generates. 52 See Company response to ELPC 1.23 Exhibit MEC-17, stating that the Company has not conducted a cost of service study unique to DG customers. In Company Response to ELPC 1.24a, Exhibit MEC-23, the Company states that it “has not developed or reviewed documentation of the impacts of distributed generation customers on the Company’s system.” 49 35 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Figure 1 53 the pattern of solar DG customer production and load shows a dramatic 2 reduction in net load during the hours leading up to and including a typical summer peak, 3 implying cost savings result from DG operations. The Company confirm this effect.54 4 Whether through net metering or an Inflow / Outflow method, the Company must also 5 account for the full range of benefits and avoided costs created by exported distributed 6 generation, and for the fact that exported energy physically serves and is fully metered at 7 the nearest unserved electric load, in order to establish a just and reasonable rate for 8 supplementary service. 9 A lawful charge for back-up power service must be based on costs the Company 10 incurs when the solar customer’s generation is not operating as it ordinarily would. 55 A 11 back-up power service charge should, therefore, be based on demonstrated incremental 12 costs incurred and directly associated with provision of service during actual or statistically 13 demonstrated periods of unscheduled outages at the DG facility. In this regard, it is 14 essential that the Company not confuse variability with intermittence. Variability in output 15 due to changes in solar insolation is predictable, and solar modeling tools account for the 16 resulting variability in solar output well. Intermittence relates to unexpected reductions in 17 availability; solar generation has availability factors in the range of 95% and greater. Due 18 to the size of rooftop solar generation and the fact that it is disbursed across the Company’s 19 system, the 5% of unavailability of solar is not perceptible in the diversity of all other loads. 53 Serna at p. 52. Company Response to MECNRDCSCDE-1.10a, Exhibit MEC-27, confirming that DG customers have lower average contribution to class demands during the class NCP hours used to allocate distribution system capacity costs than non-DG customers in the same class. See also, Company Response to MECNRDCSCDE-3.6a, Exhibit MEC-30 “The Company does not “contend that installing distributed generation reduces a customer’s contribution to 4CP, 12CP, and NCP class loads by a smaller amount than the distributed generation reduces kWh inflows.” 55 MCL 460.6v.(6)(b): "Backup power" means electric energy or capacity supplied by an electric utility to replace electric energy ordinarily generated by a qualifying facility's own electric generation equipment during an unscheduled outage of the qualifying facility. 54 36 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A calculation of cost to provide standby service to rooftop solar would therefore result in 2 a value of zero or near zero. However, the Company did not do a cost-based calculation for 3 standby service. Instead of relying on cost-based data, the Company built its proposed 4 Rider 18 rates to be a revenue recovery mechanism based on the hypothetical bills that the 5 customers with generation would have paid if they had never invested in solar generation. 6 That is, the proposed charge is based on the reduction in revenue that results from 7 customers’ reduced demand for services, not on additional services required after solar 8 generation is installed. Therefore, it is not cost based. The SAC charge is unjust, 9 unreasonable, contrary to Michigan law, and contrary to federal law as well. 10 Q. Doesn’t Company witness Serna offer evidence that distributed generation customers 11 have a summer net peak demand nearly half a kW greater than traditional residential 12 Rate D1 customers? 56 13 A. Company witness Serna’s assertion about the respective summer net peak demand of DG 14 customers as compared to non-DG customers is a deceptive half-truth. Mr. Serna’s 15 comment and the associated data that he cites 57 purport to shows that for some undefined 16 sets of DG and non-DG customers, there is an average value for “Maximum Hourly 17 Average Peak” that is about 0.5 kW higher for the net metered customers. What Mr. Serna 18 omits in his testimony—and does not offer in support of the Company’s rate proposal—is 19 the DG customers’ share of cumulative demand on the system, at the substation level, or 20 at the feeder level, during peak hours that drive costs. The data do not tell us whether the 21 DG summer peak demand is coincident with system peak demand, or whether it shifts DG 22 customers’ maximum demands to off-peak hours, providing peak load reduction, load 56 57 Serna direct at 53:1-3. See Exh. A-16, Sch. F11. 37 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 diversification, and asset utilization benefits. The data Mr. Serna relies on, therefore, say 2 nothing about the relative cost to serve. Nor do the data tell us whether purported difference 3 in individual customer peak load has anything to do with the fact that the customer has 4 distributed generation or whether it is due to independent and unrelated factors. The data 5 may simply be an artifact of the fact that larger, higher-use, and higher-earning customers 6 were the first investors in DG, especially in very small markets like the one that exists in 7 the Company’s service territory. In sum, the data Mr. Serna presents tell us nothing about 8 cost to serve DG customers that are different than costs to serve customers without 9 generation. The statement from witness Serna has no probative value in supporting the 10 11 Company proposal. Q. Doesn’t Company witness Serna also assert that DG customers place a demand on 12 the Company for several kinds of additional services simply as a result of the 13 installation and operation of distributed generation? 14 A. In general, witness Serna makes the assertion that the “bidirectional relationship between 15 the distribution system and distributed generation customers is a key and fundamental 16 distinction of these customers from traditional customers.” 58 That is, at most, 59 a tautology. 17 It is not a difference based on cost, which is what the applicable statutes and regulations 18 require to support a different treatment of customer-generators. Mr. Serna provides no cost- 19 based difference between self-generating and non-generating customers. 20 Mr. Serna also asserts that the Company provides DG customers with a “range of 21 additional grid services from the electric system that are unique to their choice to utilize 58 Serna direct at p. 52:8-11. Not all customers who self-generate export electricity. Therefore, it is not even true that distributed generation customers necessarily have “a bidirectional relationship with the distribution grid.” 59 38 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 distributed generation,” 60 and incurs costs resulting from “operational and technical 2 impacts of distributed generation” 61 relating to system protective equipment impacts or 3 reverse power flows that are not already addressed through compliance with existing safety 4 and interconnection standards. However, these assertions are false and unsubstantiated.62 5 First, the services that Mr. Serna identifies—capacity to meet demand, balancing services 6 and inrush current to start large appliances 63—are services that are provided as part of the 7 bundled service received by all customers. They are not “additional grid services” to only 8 distributed generation customers. Second, despite claiming additional costs from 9 distributed generation customers’ “unique electric system dynamics,” the Company admits 10 that it has no evidence of any actual impacts much less costs. 64 Thus, here again, the 11 Company provides no cost-based evidence to support a charge for these “services” or for 12 the “impacts” that DG might cause. 13 Q. Do you agree with Witness Serna’s assertions that system costs are stable and 14 predictable except for distributed generation 65 and that DG customers enjoy “system 15 use optionality” but are “not supporting the costs of the infrastructure required for 16 their service?” 66 17 A. These arguments by Mr. Serna are also misleading, incomplete, and unsubstantiated. First, 18 the Company makes no evidentiary showing that system costs are stable and predictable 19 without distributed generation, and that these costs are being made unstable and 60 Serna direct at p. 51:6-8. Id at p. 53:5-20. 62 Witness Serna asserts at p. 53:13, that distributed generation “may cause the circuit to trip offline,” but confirms in Company Response to MECNRDCSCDE-1.2 (Revised) Exhibit MEC-28 that there is no evidence of any instance of this happening. 63 Serna at 51:8-13. 64 DTE Response to MECNRDCSC-1.2 (Revised), Exhibit MEC-28. 65 Serna direct at p. 60:5-14. 66 Id. 61 39 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 unpredictable as a result of distributed generation. An honest analysis of distribution 2 system investment requirements shows that grid modernization, weather, maintenance, and 3 other factors have a much more significant and variable impact on distribution system costs 4 than distributed generation. Hundreds of DG systems are operating in an interconnected 5 manner on the Company’s grid today, and the Company has not pointed to any instability- 6 or unpredictability-induced impacts, trends, data, or costs. 67 7 Second, witness Serna’s implication that DG customers enjoy a special or unique 8 kind of “optionality” with regard to their use of the grid is baseless. Optionality is a 9 bargained-for contractual right by all residential and general service customers that can be 10 volitionally exercised by any of them at any time. DG customers enjoy no such rights that 11 are materially different from those that any other customer enjoys. Just like the customer 12 that invests in a high-efficiency heating and cooling system, the DG customer has taken 13 private action to reduce use. Moreover, the customer with 5 kW of rooftop solar who may 14 take (and pay for) 5 kW of service from the Company should the rooftop solar trip offline 15 is exercising the same “optionality” of service as the customer with an electric vehicle who 16 may, at any time, plug that vehicle in to charge at 5 kW. This optionality is not a different 17 service that could justify discriminatory treatment or charges not related meaningfully to 18 increased costs. 19 Furthermore, characterization of electric service as an “option” is inconsistent with 20 the understood meaning of that term. DG customers do take service under net metering 21 tariffs, but are not equivalent to the typically understood meaning of an “option.” DG 22 customers with solar do not arbitrage against market prices or distribution system costs. 67 See Company response to MECNRDCSCDE-1.2 Revised, Exhibit MEC-28. 40 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 And DG customers are not able to reasonably negotiate an option with a monopoly actor 2 like DTE. 3 Finally, Mr. Serna’s assertion that DG customers are not supporting the 4 infrastructure costs required to serve them is an objectively provable assertion. However, 5 Mr. Serna offers no proof for the assertion. Nor does the Company offer any evidence that 6 DG customers fail to pay costs they cause in a manner different than any other customer 7 who reduces their load through technology or behavior. Due to solar’s production 8 coincident with many of the hours used to allocate costs in the cost of service studies the 9 utility conducted, I would expect a cost of service study conducted for solar DG customers 10 to show a much lower cost to serve those customers. Given witness Serna’s broadside 11 assertions about DG customers, the fact that the Company elected not to attempt to show 12 that DG customers under-collect their cost of service with data is telling. Moreover, the 13 fact that the Company choose to construct its SAC charge based on lost sales, rather than 14 costs of service, is also telling. There is no evidence that DG customers under collect their 15 costs. 16 Q. Witness Serna asserts that the SAC charge is specifically designed to recover two 17 kinds of electric system costs related to (1) DG intermittence and variability, and (2) 18 the requirement for “in rush” power service. Are these services properly costed in the 19 SAC charge? 68 20 A. No. The costs that witness Serna alleges are related to intermittence and variability, and in- 21 rush power, cannot be reflected directly or accurately in the SAC charge because these 22 costs, even if they existed, are unrelated to the calculations used to develop the SAC 68 Serna at p. 61:1 through p. 62:2. 41 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 charge. 69 As noted above, the SAC is designed to recover lost revenue from services not 2 provided to DG customers, not based on the intermittence and variability or in-rush current 3 of service actually provided. Moreover, there is no evidence that DG customers show 4 significantly different levels of variability or demand for in-rush service as compared to 5 the universe of Rate D1 and Rate D3 customers. Given the very high rates of availability 6 for DG facilities, the very small number of DG customers on the Company system, and the 7 fact that net meted customers pay the fully-loaded retail rate when their facilities fail to 8 operate as forecasted, it is not likely that the Company could show material costs related 9 to DG intermittence, even if they had tried. The SAC charge is therefore specifically 10 unjustified by the costs that witness Serna asserts as the justification for the charge. 11 Even if Mr. Serna is attempting to assert that the SAC recovers the cost of DG 12 customers’ variability and inrush current because it recovers amounts based on the 13 distribution rate for D1 and D3 customers—which includes costs associated with 14 addressing variations in demand and to meet demand for in-rush service—he is incorrect. 15 DG customers already pay the fully bundled distribution rate for inflows and, therefore, 16 recover whatever costs for variability in demand and inrush current are bundled into that 17 rate. The SAC charges the fully bundled rate for service the utility does not provide. 18 Q. 19 20 Please explain why you say the SAC is based on the bill a hypothetical customer would have paid and why this is a problem. A. Company Exhibit A-16, Schedule F9, sponsored by Company witness Dennis under the 21 direction of Company witness Serna, shows how the Company built its proposed SAC 22 charge. The Company first averages all the inflow, outflow, and generation for distributed 69 See Company response to MECNRDCSCDE-1.11 Exhibit MEC-29 (Company has no data relating to the costs of providing in-rush current.). 42 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 generation customers during the year 2017. From those data, the Company calculates the 2 average total on-site usage for these customers. The Company then multiplies these values 3 times the per-kWh revenue requirement for all DG and non-DG customers in rate classes 4 D1 and D3. It is important to note that the Company does not have or rely upon cost-of- 5 service values specific to DG customers within those classes. The Company then calculates 6 the amount of revenues it would not recover from the average DG customer due to the 7 average amount of reduced sales to those customers, calling this a “revenue deficiency.” 8 Finally, the Company assumes that the average customer has an average-sized solar system 9 with a capacity of 6.7 kW and divides the hypothetical “revenue deficiency” into this 10 hypothetical system size to arrive at a value of $2.31 and $2.28 per kW that it wants to 11 charge DG customers in rate classes D1 and D3 respectively. 12 There are three important points to note from this calculation. First, it is not based 13 on a cost of service specific to DG customers and their loads. Instead, it uses the revenue 14 requirement for the broad class of primarily non-DG customers. Second, it calculates the 15 amount of revenue it is not receiving because of reduced units of fully-bundled distribution 16 service no longer required by the customer who is serving her load from behind the meter 17 generation. Third, it redistributes that lost revenue to individual customers based on each 18 customer’s nameplate capacity of generation regardless of that customer’s usage. Each of 19 these points, alone, would make the SAC not cost based. 20 Q. 21 22 23 Does the Company offer any explanation or justification for its reliance on average data for DG customers as a basis for building the SAC charge? A. Company witness Serna asserts that the SAC charge “assigns a cost per kW AC of nameplate system capacity based on the system-cost responsibility of distributed 43 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 generation customers.” 70 Company witness Dennis appears to try to justify the use of 2 averaged data when he states that “the Company in this case (and in past cases) is moving 3 toward universal consumption based (kWh) distribution charges for all residential 4 secondary customers, and for all commercial secondary customers with a per kWh 5 distribution charge.” 71 6 Q. 7 8 Do average-based calculations accurately capture system-cost responsibility of individual distribution generation customers? A. No. Witness Serna’s statement is misleading and incomplete when he asserts that the SAC 9 charge is based on “system-cost responsibility of distributed generation customers.” The 10 statement is not true when applied to the costs created by DG customers as a whole or 11 individual DG customers specifically. As demonstrated above, the SAC charge is not based 12 on costs incurred to serve DG customers as a subclass. Even if it was, the charge is still not 13 cost-based because it is unrelated to usage or generation of individual customers. A 5-kW 14 DG customer that is a high-volume, on-peak, no-export user of electricity would be 15 required to pay exactly the same SAC charge as a 5-kW DG customer with low usage, and 16 minimal use and high exports during the system peak. This outcome is not cost-based and 17 not based on the use of the electric grid. 72 18 Q. 19 20 Is a “universal distribution charge” approach a reasonable justification for the approach used by the Company in building its proposed SAC charge? A. 21 Absolutely not. As already explained, the SAC charge can only be justified by a demonstration of incremental costs incurred by the Company to provide incremental 70 Serna direct at p. 59:24-25. Dennis direct at p. 20:21-24. 72 MCL 460.11(1). 71 44 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 services, like supplementary power or back-up power service, that are not covered by 2 charges incurred when a DG customer is a net consumer of energy from the grid and pays 3 applicable cost-based class rates under Rates D1 and D3. 4 Q. Is the SAC charge deficient in other ways? 5 A. To the extent that the Company is proposing the SAC charge as a kind of charge for back- 6 up power service, it violates established federal regulations that state that “the rate for sales 7 of back-up power . . . shall not be based on an assumption (unless supported by factual 8 data) that forced outages or other reductions in electric output by all qualifying facilities 9 on an electric utility’s system will occur simultaneously, or during the system peak, or both 10 . . .” 73 The lost-sales approach used by the Company calculates the SAC charge based on 11 the assumption that all DG facilities, regardless of actual and individual performance 12 reduce utility sales by the full amount of DG load reduction. It further assumes that all of 13 this loss of sales must be recovered from all DG customers as if they were all calling on 14 the Company for back-up or supplementary service at the same time and potentially during 15 system or class peaks. 16 Q. 17 18 Why do you cite federal regulations in your review of a proposed tariff for DG customers? A. The federal Public Utility Regulatory Policies Act 74 requires utilities to interconnect “small 19 power production facilities” as defined by FERC eligibility requirements for qualifying 20 facilities (“QFs”). 75 QF status automatically applies to on-site solar generators up to 1 73 18 CFR § 292.305. 16 USC Ch. 46. 75 18 C.F.R. § 292.303(c). 74 45 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 MW. 76 FERC’s regulations implementing PURPA require that rates for electricity sales to 2 QFs “shall be just and reasonable and in the public interest” and “[s]hall not discriminate 3 against any qualifying facility in comparison to rates for sales to other customers served by 4 the electric utility.” 77 Under FERC’s regulations, rates for QFs that differ from the rates 5 otherwise applicable to non-QF customers are only considered non-discriminatory when 6 they are “based on accurate data and consistent system-wide costing principles” and only 7 “to the extent that such rates apply to the utility's other customers with similar load or other 8 cost-related characteristics.” 78 9 10 The Company’s Proposed Outflow Rate based on the Monthly Average LMP Q. 11 12 How does the Company attempt to justify its proposal to compensate outflow energy at a rate equal to the monthly average LMP? A. The Company makes the flawed assertion that energy exported from a DG facility “offsets 13 only the fuel and purchased power component of the energy cost classification,” and that 14 exported energy “does not reduce the cost of the Company’s distribution infrastructure [or 15 of] the Company’s generation capacity required to serve customer load when their 16 generator is not producing,” because these costs do not vary with volumetric energy 17 consumption. 79 18 Q. 19 What is your evaluation of these assertions by the Company regarding the value and effect of exported energy from DG facilities. 76 Facilities with net power production of less than 1 MW are exempt from the QF certification process. 18 C.F.R. § 292.203(d). 77 18 CFR § 292.305(a)(1)(ii). 78 18 CFR § 292.305(a)(2). 79 Serna direct at p. 62:12-17. 46 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. The Company’s approach to outflow credit is factually incorrect. Electricity produced by 2 distributed generation is injected into the distribution grid at the distribution level, 3 offsetting electricity that would have otherwise flowed across all upstream equipment 4 (production, transmission, and most of the primary distribution system). That is, the exports 5 appear as negative load upstream of the nearest unserved load and offset all costs driven 6 by loads on all upstream equipment. Wholesale energy prices do not reflect the full range 7 of costs avoided by that electricity exported to the secondary distribution grid. 8 Unlike wholesale energy, distributed generation exports do not require transmission 9 services or suffer transmission losses. As a matter of physics, the excess energy serves the 10 nearest unserved load and passes through a revenue meter from which the Company 11 generates a bill at the full applicable retail rates. The full range of costs avoided by DG 12 generation is the appropriate place to start in setting a fair compensation rate for excess DG 13 generation. It is also consistent with how the Company views cost –causation for purposes 14 of cost-allocation in the cost of service study. The Company’s proposal to value exports at 15 only wholesale energy is both illogical and wrong in its excessively narrow approach to 16 valuing exported energy from DG facilities, is confiscatory, is discriminatory compared to 17 how the Company views cost causation for its own purposes and is inconsistent with 18 Michigan and federal law. 19 Q. 20 21 Did the Company consider using an avoided cost method for setting the outflow credit rate under its proposed Rider 18? A. The Company rejected an avoided cost basis for setting the outflow rate because future avoided costs were theoretical and based on costs that would be avoided in the future. 80 22 80 Serna direct at p. 64:11-14. 47 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 This approach stands in stark contrast to the Company’s willingness to propose a SAC 2 charge for all small DG customers based on the theoretical revenue differences of a single 3 hypothetical DG and non-DG customer. The Company assertions about avoiding system 4 costs also confuse sunk costs with fixed costs. A solar DG facility will generate at a very 5 high availability factor and on a very predictable basis for decades—providing real 6 capacity value and other resource values. The Company’s primary problem seems to be 7 that the benefits of DG facilities occur in the future and are measured by investments that 8 the Company can avoid; and after the Company has already sunk excessive investments 9 into fixed distribution facilities costs made less necessary as a result of DG facility 10 11 generation. Q. 12 13 Does the Company have any special concerns about reflecting the capacity value of DG generation in its proposed outflow rate? A. Yes. The Company offers the faulty proposition that a capacity credit is inappropriate 14 because DG customers do not have a “temporal production contract” with the Company, 15 and because the primary purpose of DG is the production of electricity for self- 16 consumption. 81 First, a tariff is a contract, providing the precise terms under which credit 17 will be awarded for energy, capacity, or any other value that accompanies excess DG 18 production. Tariffs are different from the private contracts that the Company might 19 otherwise seek to negotiate with DG customers, because they are subject to Commission 20 oversight and therefore reduce the risk of discriminatory exercise of negotiating power by 21 any one party. No additional contract is required with DG customers, nor would a contract 22 change the fact of the generation profile of distributed generation. The Company’s 81 See Serna direct at p. 64:15-22. 48 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 assertion that a temporal production contract is a necessary precondition to recognizing the 2 capacity value of DG unreasonably promotes form over substance. Second, the purposes 3 for which DG customers install DG systems is absolutely irrelevant to whether the 4 Company avoids having to procure and provide capacity services to that customer at a 5 reduced level due to the DG generation. Moreover, the DG customer’s motivations have 6 nothing to do with the capacity value of exports. The Company’s assertions that these 7 customers “cannot be counted on to generate when needed” speaks to dispatchability, but 8 not capacity. It is also not correct. Solar generation has high availability that can be 9 predicted. While it will not be the nameplate capacity of the generating systems in each 10 hour of the year, there will be a predictable generation value that can “be counted on to 11 generate when needed” 12 Q. What is your opinion on the Company’s assertion that excess DG generation does not 13 reduce the costs of “the Company’s generation capacity required to serve customer 14 load when their generator is not producing.”82 15 A. The Company position that the value of DG outflows should be limited to the LMP rate 16 because those outflows do not have capacity value when they do not occur makes no logical 17 sense. The outflow credit should reflect the value of excess DG generation, not non- 18 production. The relevant question is how much solar will generate during the peak periods 19 that drive capacity needs. Just like fossil generation experiences outages and derates and is 20 not available at its nameplate capacity during all hours does not mean that it receives no 21 capacity value; it receives capacity value based on the projected availability during peak 22 hours. The outflow credit for DG solar should likewise reflect the extent to which the DG 82 Serna direct at p. 62:15-16. 49 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 generation outflows reduce Company generation capacity costs when the DG generator is 2 producing, and the fact that DG generation does not provide capacity value when that DG 3 generation is not operating is not a justification for limiting the outflow credit to the LMP 4 rate. 5 Q. The Company also asserts that DG electricity exports cannot reduce or offset costs 6 associated with utility distribution or capacity costs because “these costs do not vary 7 with volumetric energy consumption.” 83 Is this a reasonable position? 8 A. The Company’s ultimate position that distribution or capacity costs do not vary with 9 volumetric energy consumption further reflects the Company’s flawed confusion of sunk 10 and fixed costs and ignores the reality of electricity system operations. Future distribution 11 investments, the life of existing investments, the adequacy of existing capacity, and the 12 need for future capacity, are driven by the level of both energy and demand. If enough 13 customers use sufficient additional energy during relatively coincident times, the Company 14 will see existing infrastructure wear out more quickly or become simply inadequate to serve 15 demand. It therefore follows that reductions in volumetric consumption, whether due to 16 conservation, more efficient use, self-generation, or the injection of electricity at the 17 distribution level, can prolong the useful life of fixed cost investments, defer or avoid the 18 need for future investments, and reduce capacity costs at the distribution, transmission, and 19 generation level. The Company’s assertion is also internally inconsistent. The Company 20 allocates costs to the residential and small commercial classes based on demand during 21 peak hours, and purports that such allocation follows cost-causation factors; it cannot 83 Serna direct at p. 62:12-17. 50 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 simultaneously contend that negative load during those same peak hours has no negative 2 cost impact. 3 Q. 4 5 Is the Company proposal to compensate exported DG energy at the LMP rate consistent with the Inflow / Outflow tariff structure? A. No. The market price for energy embodied in the LMP is an artifact of market operations, 6 the bidding strategies of numerous market participants, the influence of tax incentives, and 7 a structure designed to address very short-term congestion price conditions. The full cost 8 of a utility resource, and hence, the full avoided cost that should be reflected in outflow 9 rates—just like in PURPA rates—includes capital investment costs, portfolio 10 requirements, long-run resource costs—all the costs associated with the purchase from the 11 qualifying facility, but for that purchase, the utility would incur. Spot energy markets 12 reflected in the LMP are not designed to reveal these costs. Full avoided cost does not 13 equate to the price that the utility might pay to buy one kilowatt of energy in the market; it 14 reflects the full panoply of costs that the utility avoided by not having to generate, transmit, 15 and deliver that kilowatt itself. 16 Q. 17 18 What kind of costs can be considered in establishing just and reasonable outflow and PURPA rates for sales to a utility? A. The PURPA regulations lay out several factors that “shall, to the extent practicable, be 19 taken into account” when state commissions are determining avoided costs. 84 The legal 20 mandate that state commissions consider these factors underscores the fact that avoided 21 costs are not simply marginal prices. That is, avoided costs must include all of the costs 22 that the utility does not incur as a result of the purchase from the qualifying facility. Full 84 18 CFR § 292.101(e) 51 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 and fair consideration of these factors is essential to ensure that rates for DG customers are 2 not unduly discriminatory, a principle embedded in both Michigan and federal law. 85 These 3 factors include: 4 • 5 Energy and capacity cost data provided pursuant to FERC regulations, including state review of any such data; • 6 7 Availability of capacity or energy from qualifying facilities during system daily and seasonal peak periods; 8 • Dispatchability and reliability; 9 • Duration and terms of contract; 10 • Usefulness of energy and capacity during system emergencies; 11 • Individual and aggregate value of energy and capacity; 12 • Smaller capacity increments and shorter lead times for additional capacity from 13 qualifying facilities; • 14 Relationship of availability of energy and capacity from the qualifying facility to the 15 ability of the utility to avoid costs, including deferral of capacity additions and 16 reduction in fossil fuel use; and • 17 Costs or savings resulting from variations in line losses from those that would have existed in the absence of purchases from a qualifying facility. 86 18 • 19 State commissions may also account for the environmental compliance and resource 20 portfolio compliance costs “of all fuel sources” in determining avoided cost rates, as 21 long as they are “real costs that would be incurred by utilities.” 87 In other words, 85 See 18 CFR.304(a)(1) (rates for purchases); MCL § 460.6v. 18 CFR § 292.304(e)(4). 87 71 FERC 61,269, 62,080 (June 2, 1995) (citing 70 FERC 61,290, 61,676, reconsideration denied, 71 FERC 61,232 (1995)). 86 52 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 commissions may account for environmental costs that are part of the utility’s cost of 2 doing business to the extent those costs would be avoided by the purchase from the 3 qualifying facility. 4 Q. 5 6 Did the Commission Staff take a position on the proper valuation of outflows in its proposal that the Commission adopt the Inflow / Outflow model? A. Yes. In its report to the Commission, the Staff stated that “[a] fair valuation method for DG 7 resources injected into the grid by DG customers consists of two parts: (1) an avoided 8 capital and energy cost; and (2) all other avoided cost or benefit elements such as avoided 9 distribution line losses, transmission and distribution costs, avoided air emission and 10 environmental costs, the solar-fuel price hedge, and reactive supply and voltage control.” 88 11 In my opinion, and without expressing an opinion on the merits or legality of the Inflow / 12 Outflow method in general, the Staff position on setting the outflow credit rates is a good 13 place to start. 14 Q. The Company suggests that the LMP rate for outflow credits under the Inflow / 15 Outflow tariff method is required by Act 342, particularly by section 177 of the Act. 89 16 Do you agree? 17 A. As an attorney with nearly 35 years of experience in law, including 28 years in utility 18 regulatory law, I offer my personal opinion—but not a formal legal opinion—that the 19 Company is cherry-picking language from the statute in order to support its position. First, 20 I would note that the Commission addressed this very issue in its Order of April 18, 2018, 21 in Case No. U-18383, when it concluded that section 177 of Act 342 does not apply to the 88 MPSC Staff, “Report on the MPSC Staff Study to Develop a Cost of Service-Based Distribution Generation Program Tariff,” MPSC Case No. U-18383 (Feb. 21, 2018), at p. 15. 89 Serna at p. 65:1-20. 53 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 charge rate or credit value established under a cost of service based tariff established under 2 Act 341, section 6a.(14). In this case, unless and until a court intervenes, or the Commission 3 revises its order in U-18383, the Company’s obligation was to propose a just and 4 reasonable tariff for DG customers based on the Commission’s decision that section 177 5 does not apply and, therefore, cannot limit the outflow credit. Second, the Company’s view 6 that a portion of section 177(4) applies to limit the credit for exports conveniently ignores 7 the fact that the rest of section 177, as well as the rest of Act 342 Part 5 it was adopted as 8 part of, also retain true net metering for DG customers with systems 20 kilowatts or smaller 9 in size. Therefore, in order to be consistent with itself, in addition to proposing to limit 10 exports based on the second half of section 177(4) the Company should have also proposed 11 to retain netting within the billing period as required by section 177 and Act 342 Part 5. 12 The Company attempts to strip the second portion of 177(4) of its context and insists that 13 it applies, while simultaneously insisting that the rest of the distributed generation program 14 do not apply. That interpretation is untenable. 15 The Company’s Proposed Confiscation of Credit Balances from Customers 16 Q. 17 18 What is the Company’s Rider 18 proposal regarding excess credits when a customer terminates participation in the program? A. The Company proposes that a customer forfeits all unused credits when a customer terminates participation in the DG program. 90 19 20 Q. Is this approach reasonable? 21 A. No. The Company proposal to confiscate all unused credits when a customer terminates 22 participation in the DG program ignores the fact that customers earn those credits during 90 Company proposed Rider 18, at D-116.00, Exhibit A-16, Sched. F10. 54 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 the period of their participation in the program, and that the credits represent excess energy 2 that the Company used in providing electric service to customers. 3 Q. 4 5 What do you recommend that the Commission require of the Company regarding unused credits when a customer terminates participation in the DG program? A. Customers who terminate participation in the DG program should receive the full value of 6 their remaining credits as a credit on their final bill. To the extent overpayments are 7 refunded to other customers when they terminate service, the same should be true of DG 8 customers who have overpayments because of export credits. 9 IV. CHARGING CUSTOMERS FOR EDISON ELECTRIC INSTITUTE ACTIVITIES 10 Q. Is the Company a member of any trade associations? 11 A. Yes, the Company is a member of several trade associations, including, in particular, the Edison Electric Institute (“EEI”). 91 12 13 Q. 14 15 Please describe the issue of the Company seeking cost recovery from customers for EEI activities. A. The Company seeks to recover EEI dues as an “above-the-line” expense from ratepayers. 16 Unbeknownst to most customers, these payments may be used to fund advocacy with 17 which customers may disagree and that is contrary to their interests. The Company reports 18 that it paid a total of $1,269,000 in dues to EEI. 92 Groups such as EEI receive a majority 19 of their revenue from utility membership dues, 93 are highly political in nature, and promote 20 policies that are not always in the best interests of ratepayers. 91 Exh. A-3, Sched. C14, line 4. Id. 93 U.S. Dep’t of Treasury, IRS, Form 990, Part VIII Statement of Revenue (Edison Electric Institute, 2015), https://projects.propublica.org/nonprofits/organizations/130659550. 92 55 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 The Company also indicates in this filing that it reduced the total amount of all 2 corporate memberships charged to customers by $554,000 for “disallowed expense,” 94 and 3 that some of the dues to EEI are “below the line,” recorded in account 426.4 (relating to 4 Political and Civil Activities) and are not charged to ratepayers. 95 5 Q. 6 7 How does the Company determine the amount of EEI dues that are not charged to ratepayers as Political and Civil Activities? A. The Company takes EEI’s word for it. The Company states that EEI identifies the portion 8 of dues that relate to influencing legislation on the invoice that the association submits to 9 the Company. 96 The Company provides no information to support the reasonableness of 10 cost recovery for the “above the line” dues or to ensure the accuracy of the assertions by 11 EEI as to the extent to which dues are used to support lobbying and advocacy positions. 12 Q. 13 14 What do you conclude therefore about the Company’s effort to have customers pay for EEI dues? A. The Company has failed to demonstrate that the costs associated with EEI membership 15 dues are limited to activities that benefit ratepayers and therefore are just and reasonable. 16 The Company has failed to demonstrate that it has removed all payments for lobbying and 17 other inappropriate activities from the costs it seeks to recover from customers. The 18 Company produced no evidence that it verified the assertions from EEI. 19 Q. What do you recommend that the Commission do based on your findings? 94 Exh. A-3, Sched. C14, line 14. Exhibit MEC-31 Company response to MECNRDCSCDE-3-16b. 96 Id. 95 56 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. Based on this failure to justify and substantiate the reasonableness of cost recovery for the 2 dues paid to EEI, I recommend that the Commission deny recovery of these expenses and 3 order the Company to adjust its revenue requirement downward accordingly. 4 Q. What is EEI, and what services does the trade association provide to its members? 5 A. EEI is a trade association with a large operating budget ($96.5 million in 2016) that 6 represents U.S. investor-owned electric companies in all 50 states. 97 EEI describes its 7 mission as providing public policy leadership, industry data, business intelligence, 8 conferences and forums, and products and services to the utility industry. 98 EEI also 9 provides a Mutual Assistance Program in which member utilities can access assistance 10 during storms to restore power to affected customers. 99 Most of EEI’s work involves 11 promoting its utility members’ policy agenda and bottom-line through political action and 12 advocacy. 13 Q. 14 15 What portion of EEI’s budget is spent on lobbying activity as compared with other activities? A. It is unknown what portion of EEI’s budget is allocated towards lobbying activity because, 16 to my knowledge, the most recently available NARUC audit of EEI data is from 2005. The 17 Company has not submitted a more recent audit of any kind in this proceeding. 18 Q. Why is it important to know how EEI treats its expenditures? 19 A. Reliable data on EEI spending activity is necessary for reasonable allocations of expenses 20 between lobbying and non-lobbying activity. Absence of that data presents a significant 97 Budget data based on EEI IRS Form 990 for 2016 obtained from Guidestar, available at https://www.guidestar.org/FinDocuments/2016/130/659/2016-130659550-0eb71f32-9O.pdf. 98 See EEI, About EEI, http://www.eei.org/about/Pages/default.aspx (last visited May 24, 2018). 99 See EEI, Mutual Assistance, http://www.eei.org/issuesandpolicy/electricreliability/ mutual assistance/ (last visited May 24, 2018). 57 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 challenge for stakeholders, ratepayers, and regulatory authorities who seek to protect 2 ratepayers from funding lobbying and any non-lobbying advocacy that may not be in their 3 best interest. 4 Q. What dues-funded EEI activities are in the interest of Michigan ratepayers? 5 A. Examples of association activities clearly in the interests of ratepayers include: EEI 6 sponsored workforce education and training modules, knowledge campaigns centered 7 around electrical and gas safety, and EEI’s Mutual Assistance Program that combines 8 utility resources during extreme weather to restore power to customers. 9 Q. So, what is the problem with above-the-line trade association dues? 10 A. The problem is that the EEI acts as advocacy organizations in supporting a policy agenda 11 contrary to many ratepayers’ interests or personal beliefs, and contrary to the policies of 12 the State of Michigan. 13 Q. Are you recommending that the Company not be allowed to indirectly fund ALEC or 14 other anti-renewable energy advocacy organizations through its contributions to EEI 15 member dues? 16 A. No. I accept that the Company may decide that it is in the best interests of shareholders to 17 join in these agendas. My testimony is that ratepayers should not be required to support 18 these organizations, directly or indirectly, through EEI dues, and that the Company must 19 produce sufficient and competent evidence to the Commission that any dues payments that 20 it seeks to recover from ratepayers through the revenue requirement do not fund these 21 activities. 22 Q. Do any third-party regulatory organizations conduct oversight of utility EEI dues? 58 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. No, there is no regulatory oversight of the allocation of trade association membership dues 2 today. From the 1980s to the early 2000s, NARUC conducted annual audits of trade 3 association financial records through the Committee on Utility Oversight. 100 The audits 4 persuaded NARUC regulators to direct utilities to collect a smaller portion of their EEI 5 dues from ratepayers. 101 The Committee on Utility Oversight, which audited expenditure 6 data, disbanded in the year 2000. Recently, utilities have been seeking lower than usual 7 amounts from shareholders, and correspondingly higher shares from customers—though 8 there is no evidence of a major shift in program efforts at EEI. For example, Georgia Power 9 proposed 29% of EEI dues as below-the-line expenses in a 2016 filing, 102 NV Energy 10 proposed 16% in a 2015 filing, 103 and Oklahoma Gas & Electric proposed 0% in a 2016 11 filing. 104 Without transparency of spending data, it is difficult to fully understand how EEI 12 spends ratepayer funds. The Commission is the best institution to re-address this issue in 13 the absence of a coordinated multi-state audit like the audit NARUC conducted. 14 Q. Have other public utility commissions addressed this issue? 15 A. While I have not conducted a comprehensive survey of all states, commissions in 16 California and Missouri have addressed the issue in recent rate cases. In 2013, the 17 California Public Utilities Commission (“CPUC”) decided to decrease the recoverable 18 portion of EEI dues by changing the below-the-line amount of dues from the 25% proposed 100 See NARUC Bd. of Directors, Resolution Regarding Discontinuation of the Committee on Utility Oversight (adopted Mar. 8, 2000), http://pubs.naruc.org/pub/5398B543-2354-D714-51D3-90ACAB1DA952. 101 See EPI, Paying for Utility Politics, at 6. 102 See id. at 20. 103 See id. at 24. 104 See id. at 20–21 & tbl.1; Responsive Testimony of Sharhonda Dodoo at 5:17–6:2 & tbl.1, In re Okla. Gas & Elec. Co., No. PUD 201500273 (Corp. Comm’n Okla. Mar. 21, 2016), https://www.documentcloud.org/documents/3111578-Sharhonda-Dodoo-PUD-Testimony-OGEDues.html#document/p6/a318911. 59 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 by PG&E to 43.3%. 105 2 similarly disallowed EEI dues when the utility failed to “develop some method of 3 allocating expenses between its shareholders and the ratepayers once the benefits and 4 activities leading thereto have been adequately quantified.” 106 5 Q. 6 7 The Missouri Public Service Commission (“MO-PSC”) has What do you propose to ensure that ratepayers are not required to fund activities from which they receive no benefit or by which they risk being harmed? A. The Company must provide sufficiently detailed information regarding the membership 8 dues cost allocation as an incident to its burden of producing sufficient evidence that its 9 requested rates are just and reasonable. This evidence must demonstrate that above-the- 10 line dues to EEI: (1) directly benefit ratepayers and (2) do not work contrary to ratepayer 11 interests. In the absence of a third-party audit in the record, it is not reasonable to rely 12 merely upon the assertions by EEI. The data submitted by the Company therefore is 13 inadequate to carry the Company’s burden of demonstrating that its rates are just and 14 reasonable or to confirm that ratepayers are not being asked to pay for lobbying or political 15 advocacy activities carried out by the EEI. 16 Q. What do you recommend that the Commission do in the face of this lack of evidence? 17 A. Because the Company has not provided sufficient and competent evidence to support a 18 finding that the dues it is asking ratepayers to pay are a just and reasonable expense, I 105 Application of Pac. Gas & Elec. Co. for Auth., Among Other Things, to Increase Rates & Charges for Elec. & Gas Serv. Effective on Jan. 1, 2014 (U39m). & Related Matter., 12-11-009, 2014 WL 4248558, at *142 (Aug. 14, 2014); see also Application of S. California Edison Co. (U338e) for Auth. to, Among Other Things, Increase Its Authorized Revenues for Elec. Serv. in 2015, & to Reflect That Increase in Rates., 13-11-003, 2015 WL 7351928, at *200 (Nov. 5, 2015) (reducing recoverable EEI dues from $1.9M to $1M because “SCE has not shown that it has removed all political or lobbying costs from its forecast.”) 106 In re Kansas City Power & Light Co., 48 P.U.R.4th 598 (July 14, 1982) 60 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 recommend that the total amount of requested revenue requirement related to membership 2 dues in EEI be disallowed. 3 V. CONCLUSIONS AND RECOMMENDATIONS 4 Q. Based on your testimony and review of the Company’s proposal to increase fixed 5 customer charges for residential and small commercial customers, what conclusions 6 do you reach? 7 A. The Company’s proposal to increase fixed customer charges for residential and commercial 8 secondary customers is based on a flawed regulatory foundation. The major flaws are two: 9 First, the Company provides no reasonable or logical support for its assertion that demand- 10 related costs allocated to small customers should be recovered through a demand charge. 11 Second, the Company provides no reasonable or logical support for its assertion that in the 12 absence of a capability to assess a small customer demand charge, it should be allowed to 13 increase the Rate D1 and D3 fixed customer charges in order to recover demand-related 14 capital and operating costs. 15 Q. Based on your conclusion, what action do you recommend that the Commission take 16 regarding the Company proposal to increase fixed customer charges for residential 17 and small commercial customers? 18 A. I recommend that the Commission deny the Company proposal to deny the Company’s 19 proposal to increase the fixed customer charges for customers taking service under Rates 20 D1 and D3. Further, the Commission should direct the Company to calculate the costs 21 classified as customer costs including only the costs of connecting customers to the grid 22 and reserve any fixed customer charge solely for recovery of those customer costs. 107 107 Because it takes the position that all customer- and demand-related costs should be recovered through the fixed customer charge, the Company did not classify costs as either customer or demand. As a result, the Company has not 61 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 Q. 2 3 Based on your testimony and review of the Company’s proposed Rate Rider 18 for distributed generation customers, what conclusions do you reach? A. The Company’s proposal for a new Rate Rider 18 is unjust, unreasonable, unduly 4 discriminatory, and inconsistent with Michigan law and the Commission’s regulation and 5 directives. 6 Q. Based on your conclusions regarding the Company’s proposed Rate Rider 18 for 7 distributed generation customers, what action do you recommend that the 8 Commission take? 9 A. The Commission should deny the Company’s proposed Rider 18 in its entirety. The 10 Commission should further direct the Company: (1) to perform an objective and 11 comprehensive assessment of the costs and benefits of serving residential and small 12 commercial DG customers, and to use the results of that assessment in developing a new 13 proposal for inflow charges for DG customer consumption; (2) eliminate its proposal for a 14 SAC charge as not cost-based for services specific to DG customers ; and (3) implement 15 an outflow credit for excess DG production that puts DG customers on an even economic 16 footing with current net metering rates until and unless the Company demonstrates, with 17 competent and objective evidence, that a different outflow credit would be just and 18 reasonable and non-discriminatory. 19 20 Q. Based on your testimony and review of the Company’s proposal to charge customers for EEI trade association dues, what do you conclude? provided a record upon which to base any change in the fixed customer charges for residential and small commercial customers. 62 DIRECT TESTIMONY OF KARL RABAGO ON BEHALF OF MEC-NRDC and SIERRA CLUB 1 A. The Company has failed to produce evidence and prove that the amount of EEI dues it 2 seeks to recover from customers is just and reasonable. The evidence provided based on 3 the unverified assertion of EEI is inadequate to support recovery of the EEI dues expense. 4 Q. 5 6 What action do you recommend that the Commission take regarding the Company’s proposal for rate recovery of EEI dues? A. 7 I recommend that the Company disallow the recovery of the entire amount of EEI dues and reduce the Company’s revenue requirement accordingly. 8 Q. Does this conclude your testimony? 9 A. Yes. 63 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 1 of 13 Karl R. Rábago Rábago Energy LLC 62 Prospect Street, White Plains, New York 10606 c: +1.512.968.7543 e: rabago@me.com Nationally recognized leader and innovator in electricity and energy law, policy, and regulation. Experienced as a research and development manager, utility executive, business builder, sustainability leader, senior government official, consultant, and advocate. Highly proficient in advising, managing, and interacting with government agencies and committees, the media, citizen groups, and business associations. Successful track record of working with U.S. Congress, state legislatures, governors, regulators, city councils, business leaders, researchers, academia, and community groups. National and international contacts through experience with Pace Energy and Climate Center, Austin Energy, AES Corporation, US Department of Energy, Texas Public Utility Commission, Jicarilla Apache Tribal Utility Authority, Cargill Dow LLC (now NatureWorks, LLC), Rocky Mountain Institute, CH2M HILL, Houston Advanced Research Center, Environmental Defense Fund, and others. Skilled attorney, negotiator, and advisor with more than twenty-five years of experience working with diverse stakeholder communities in electricity policy and regulation, emerging energy markets development, clean energy technology development, electric utility restructuring, smart grid development, and the implementation of sustainability principles. Extensive regulatory practice experience. Nationally recognized speaker on energy, environment, and sustainable development matters. Managed staff as large as 250; responsible for operations of research facilities with staff in excess of 600. Developed and managed budgets in excess of $300 million. Law teaching experience at Pace University Elisabeth Haub School of Law, University of Houston Law Center, and U.S. Military Academy at West Point. Post-doctorate degrees in environmental and military law. Military veteran. Employment RÁBAGO ENERGY LLC Principal: July 2012—Present. Consulting practice dedicated to providing expert witness and policy formulation advice and services to organizations in the clean and advanced energy sectors. Prepared and submitted testimony in more than 20 states and 60 electricity regulatory proceedings. Recognized national leader in development and implementation of award-winning “Value of Solar” alternative to traditional net metering. Additional information at www.rabagoenergy.com. PACE ENERGY AND CLIMATE CENTER, PACE UNIVERSITY ELISABETH HAUB SCHOOL OF LAW Executive Director: May 2014—Present. Leader of a team of professional and technical experts and law students in energy and climate law, policy, and regulation. Secure funding for and manage execution of research, market development support, and advisory services for a wide range of funders, clients, and stakeholders with the overall goal of advancing clean energy deployment, climate responsibility, and market efficiency. Provide learning and development opportunities for law students. Additional activities: • Chairman of the Board, Center for Resource Solutions (1997-present). CRS is a not-for-profit organization based at the Presidio in California. CRS developed and manages the Green-e Renewable Electricity Brand, a nationally and internationally recognized branding program for green power and green pricing products and programs. Past chair of the Green-e Governance Board. • Director, Interstate Renewable Energy Council (IREC) (2012-present). IREC focuses on issues impacting expanded renewable energy use such as rules that support renewable energy Page 1 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 2 of 13 Karl R. Rábago and distributed resources in a restructured market, connecting small-scale renewables to the utility grid, developing quality credentials that indicate a level of knowledge and skills competency for renewable energy professionals. • Co-Director and Principal Investigator, Northeast Solar Energy Market Coalition (20152017). The NESEMC was a US Department of Energy’s SunShot Initiative Solar Market Pathways project. Funded under a cooperative agreement between the US DOE and Pace University, the NESEMC worked to harmonize solar market policy and advance supportive policy and regulatory practices in the northeast United States. • Director, Alliance for Clean Energy – New York (2018-present). AUSTIN ENERGY – THE CITY OF AUSTIN, TEXAS Vice President, Distributed Energy Services: April 2009—June 2012. Executive in 8th largest public power electric utility serving more than one million people in central Texas. Responsible for management and oversight of energy efficiency, demand response, and conservation programs; low-income weatherization; distributed solar and other renewable energy technologies; green buildings program; key accounts relationships; electric vehicle infrastructure; and market research and product development. Executive sponsor of Austin Energy’s participation in an innovative federally-funded smart grid demonstration project led by the Pecan Street Project. Led teams that successfully secured over $39 million in federal stimulus funds for energy efficiency, smart grid, and advanced electric transportation initiatives. Additional activities included: • Director, Renewable Energy Markets Association. REMA is a trade association dedicated to maintaining and strengthening renewable energy markets in the United States. • Membership on Pedernales Electric Cooperative Member Advisory Board. Invited by the Board of Directors to sit on first-ever board to provide formal input and guidance on energy efficiency and renewable energy issues for the nation’s largest electric cooperative. THE AES CORPORATION Director, Government & Regulatory Affairs: June 2006—December 2008. Government and regulatory affairs manager for AES Wind Generation, one of the largest wind companies in the country. Manage a portfolio of regulatory and legislative initiatives to support wind energy market development in Texas, across the United States, and in many international markets. Active in national policy and the wind industry through work with the American Wind Energy Association as a participant on the organization’s leadership council. Also served as Managing Director, Standards and Practices, for Greenhouse Gas Services, LLC, a GE and AES venture committed to generating and marketing greenhouse gas credits to the U.S. voluntary market. Authored and implemented a standard of practice based on ISO 14064 and industry best practices. Commissioned the development of a suite of methodologies and tools for various greenhouse gas credit-producing technologies. Also served as Director, Global Regulatory Affairs, providing regulatory support and group management to AES’s international electric utility operations on five continents. JICARILLA APACHE NATION UTILITY AUTHORITY Director: 1998—2008. Located in New Mexico, the JANUA was an independent utility developing profitable and autonomous utility services that provide natural gas, water utility services, low income housing, and energy planning for the Nation. Authored “First Steps” renewable energy and energy efficiency strategic plan with support from U.S. Department of Energy. Page 2 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 3 of 13 Karl R. Rábago HOUSTON ADVANCED RESEARCH CENTER Group Director, Energy and Buildings Solutions: December 2003—May 2006. Leader of energy and building science staff at a mission-driven not-for-profit contract research organization based in The Woodlands, Texas. Responsible for developing, maintaining and expanding upon technology development, application, and commercialization support programmatic activities, including the Center for Fuel Cell Research and Applications, an industry-driven testing and evaluation center for near-commercial fuel cell generators; the Gulf Coast Combined Heat and Power Application Center, a state and federally funded initiative; and the High Performance Green Buildings Practice, a consulting and outreach initiative. Secured funding for major new initiative in carbon nanotechnology applications in the energy sector. Developed and launched new and integrated program activities relating to hydrogen energy technologies, combined heat and power, distributed energy resources, renewable energy, energy efficiency, green buildings, and regional clean energy development. Active participant in policy development and regulatory implementation in Texas, the Southwest, and national venues. Frequently engaged with policy, regulatory, and market leaders in the region and internationally. Additional activities: • President, Texas Renewable Energy Industries Association. As elected president of the statewide business association, leader and manager of successful efforts to secure and implement significant expansion of the state’s renewable portfolio standard as well as other policy, regulatory, and market development activities. • Director, Southwest Biofuels Initiative. Established the Initiative acts as an umbrella structure for a number of biofuels related projects, including emissions evaluation for a stationary biodiesel pilot project, feedstock development, and others. • Member, Committee to Study the Environmental Impacts of Windpower, National Academies of Science National Research Council. The Committee was chartered by Congress and the Council on Environmental Quality to assess the impacts of wind power on the environment. • Advisory Board Member, Environmental & Energy Law & Policy Journal, University of Houston Law Center. CARGILL DOW LLC (NOW NATUREWORKS, LLC) Sustainability Alliances Leader: April 2002—December 2003. Integrated sustainability principles into all aspects of a ground-breaking biobased polymer manufacturing venture. Responsible for maintaining, enhancing and building relationships with stakeholders in the worldwide sustainability community, as well as managing corporate and external sustainability initiatives. NatureWorks is the first company to offer its customers a family of polymers (polylactide – “PLA”) derived entirely from annually renewable resources with the cost and performance necessary to compete with packaging materials and traditional fibers; now marketed under the brand name “Ingeo.” • Successfully completed Minnesota Management Institute at University of Minnesota Carlson School of Management, an alternative to an executive MBA program that surveyed fundamentals and new developments in finance, accounting, operations management, strategic planning, and human resource management. ROCKY MOUNTAIN INSTITUTE Managing Director/Principal: October 1999–April 2002. In two years, co-led the team and grew annual revenues from approximately $300,000 to more than $2 million in annual grant and consulting income. Co-authored “Small Is Profitable,” a comprehensive analysis of the benefits of distributed energy resources. Worked to increase market opportunities for clean and distributed Page 3 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 4 of 13 Karl R. Rábago energy resources through consulting, research, and publication activities. Provided consulting and advisory services to help business and government clients achieve sustainability through application and incorporation of Natural Capitalism principles. Frequent appearance in media at international, national, regional and local levels. • President of the Board, Texas Ratepayers Organization to Save Energy. Texas R.O.S.E. is a non-profit organization advocating low-income consumer issues and energy efficiency programs. • Co-Founder and Chair of the Advisory Board, Renewable Energy Policy Project-Center for Renewable Energy and Sustainable Technology. REPP-CREST was a national non-profit research and internet services organization. CH2M HILL Vice President, Energy, Environment and Systems Group: July 1998–August 1999. Responsible for providing consulting services to a wide range of energy-related businesses and organizations, and for creating new business opportunities in the energy industry for an established engineering and consulting firm. Completed comprehensive electric utility restructuring studies for the states of Colorado and Alaska. PLANERGY Vice President, New Energy Markets: January 1998–July 1998. Responsible for developing and managing new business opportunities for the energy services market. Provided consulting and advisory services to utility and energy service companies. ENVIRONMENTAL DEFENSE FUND Energy Program Manager: March 1996–January 1998. Managed renewable energy, energy efficiency, and electric utility restructuring programs for a not-for-profit environmental group with a staff of 160 and over 300,000 members. Led regulatory intervention activities in Texas and California. In Texas, played a key role in crafting Deliberative Polling processes. Initiated and managed nationwide collaborative activities aimed at increasing use of renewable energy and energy efficiency technologies in the electric utility industry, including the Green-e Certification Program, Power Scorecard, and others. Participated in national environmental and energy advocacy networks, including the Energy Advocates Network, the National Wind Coordinating Committee, the NCSL Advisory Committee on Energy, and the PV-COMPACT Coordinating Council. Frequently appeared before the Texas Legislature, Austin City Council, and regulatory commissions on electric restructuring issues. UNITED STATES DEPARTMENT OF ENERGY Deputy Assistant Secretary, Utility Technologies: January 1995–March 1996. Manager of the Department’s programs in renewable energy technologies and systems, electric energy systems, energy efficiency, and integrated resource planning. Supervised technology research, development and deployment activities in photovoltaics, wind energy, geothermal energy, solar thermal energy, biomass energy, high-temperature superconductivity, transmission and distribution, hydrogen, and electric and magnetic fields. Developed, coordinated, and advised on legislation, policy, and renewable energy technology development within the Department, among other agencies, and with Congress. Managed, coordinated, and developed international agreements for cooperative activities in renewable energy and utility sector policy, regulation, and market development between the Department and counterpart foreign national entities. Established and enhanced partnerships with stakeholder groups, including technology firms, electric utility companies, state and local governments, and associations. Supervised development Page 4 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 5 of 13 Karl R. Rábago and deployment support activities at national laboratories. Developed, advocated and managed a Congressional budget appropriation of approximately $300 million. STATE OF TEXAS Commissioner, Public Utility Commission of Texas. May 1992–December 1994. Appointed by Governor Ann W. Richards. Regulated electric and telephone utilities in Texas. Laid the groundwork for legislative and regulatory adoption of integrated resource planning, electric utility restructuring, and significantly increased use of renewable energy and energy efficiency resources. Co-chair and organizer of the Texas Sustainable Energy Development Council. ViceChair of the National Association of Regulatory Utility Commissioners (NARUC) Committee on Energy Conservation. Member and co-creator of the Photovoltaic Collaborative Market Project to Accelerate Commercial Technology (PV-COMPACT). Member, Southern States Energy Board Integrated Resource Planning Task Force. Member of the University of Houston Environmental Institute Board of Advisors. LAW TEACHING Professor for a Designated Service: Pace University Elisabeth Haub School of Law, 2014present. Non-tenured member of faculty. Courses taught: Energy Law. Supervise a student intern practice program that engages in a wide range of advocacy, analysis, and research activities in support of the mission of the Pace Energy and Climate Center. Associate Professor of Law: University of Houston Law Center, 1990–1992. Full time, tenure track member of faculty. Courses taught: Criminal Law, Environmental Law, Criminal Procedure, Environmental Crimes Seminar, Wildlife Protection Law. Provided pro bono legal services in administrative proceedings and filings at the Texas Public Utility Commission. Assistant Professor: United States Military Academy, West Point, New York, 1988–1990. Member of the faculty in the Department of Law. Honorably discharged in August 1990, as Major in the Regular Army. Courses taught: Constitutional Law, Military Law, and Environmental Law Seminar. Greatly expanded the environmental law curriculum and laid foundation for the concentration program in law. While carrying a full time teaching load, earned an LL.M. in Environmental Law. Established a program for subsequent environmental law professors to obtain an LL.M. prior to joining the faculty. LITIGATION Trial Defense Attorney and Prosecutor, U.S. Army Judge Advocate General’s Corps, Fort Polk, Louisiana, January 1985–July 1987. Assigned to Trial Defense Service and Office of the Staff Judge Advocate. Prosecuted and defended more than 150 felony-level courts-martial. As prosecutor, served as legal officer for two brigade-sized units (approximately 5,000 soldiers), advising commanders on appropriate judicial, non-judicial, separation, and other actions. Pioneered use of some forms of psychiatric and scientific testimony in administrative and judicial proceedings. NON-LEGAL MILITARY SERVICE Armored Cavalry Officer, 2d Squadron 9th Armored Cavalry, Fort Stewart, Georgia, May 1978– August 1981. Served as Logistics Staff Officer (S-4). Managed budget, supplies, fuel, ammunition, and other support for an Armored Cavalry Squadron. Served as Support Platoon Leader for the Squadron (logistical support), and as line Platoon Leader in an Armored Cavalry Troop. Graduate of Airborne and Ranger Schools. Special training in Air Mobilization Planning and Nuclear, Biological and Chemical Warfare. Page 5 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 6 of 13 Karl R. Rábago Formal Education LL.M., Environmental Law, Pace University School of Law, 1990: Curriculum designed to provide breadth and depth in study of theoretical and practical aspects of environmental law. Courses included: International and Comparative Environmental Law, Conservation Law, Land Use Law, Seminar in Electric Utility Regulation, Scientific and Technical Issues Affecting Environmental Law, Environmental Regulation of Real Estate, Hazardous Wastes Law. Individual research with Hudson Riverkeeper Fund, Garrison, New York. LL.M., Military Law, U.S. Army Judge Advocate General’s School, 1988: Curriculum designed to prepare Judge Advocates for senior level staff service. Courses included: Administrative Law, Defensive Federal Litigation, Government Information Practices, Advanced Federal Litigation, Federal Tort Claims Act Seminar, Legal Writing and Communications, Comparative International Law. J.D. with Honors, University of Texas School of Law, 1984: Attended law school under the U.S. Army Funded Legal Education Program, a fully funded scholarship awarded to 25 or fewer officers each year. Served as Editor-in-Chief (1983–84); Articles Editor (1982–83); Member (1982) of the Review of Litigation. Moot Court, Mock Trial, Board of Advocates. Summer internship at Staff Judge Advocate’s offices. Prosecuted first cases prior to entering law school. B.B.A., Business Management, Texas A&M University, 1977: ROTC Scholarship (3–yr). Member: Corps of Cadets, Parson’s Mounted Cavalry, Wings & Sabers Scholarship Society, Rudder’s Rangers, Town Hall Society, Freshman Honor Society, Alpha Phi Omega service fraternity. Page 6 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 7 of 13 Karl R. Rábago Selected Publications “Achieving very high PV penetration – The need for an effective electricity remuneration framework and a central role for grid operators,” Richard Perez (corresponding author), Energy Policy, Vol. 96, pp. 27-35 (2016). “The Net Metering Riddle,” Electricity Policy.com, April 2016. “The Clean Power Plan,” Power Engineering Magazine (invited editorial), Vol. 119, Issue 12 (Dec. 2, 2015) “The ‘Sharing Utility:’ Enabling & Rewarding Utility Performance, Service & Value in a Distributed Energy Age,” co-author, 51st State Initiative, Solar Electric Power Association (Feb. 27, 2015) “Rethinking the Grid: Encouraging Distributed Generation,” Building Energy Magazine, Vol. 33, No. 1 Northeast Sustainable Energy Association (Spring 2015) “The Value of Solar Tariff: Net Metering 2.0,” The ICER Chronicle, Ed. 1, p. 46 [International Confederation of Energy Regulators] (December 2013) “A Regulator’s Guidebook: Calculating the Benefits and Costs of Distributed Solar Generation,” coauthor, Interstate Renewable Energy Council (October 2013) “The ‘Value of Solar’ Rate: Designing an Improved Residential Solar Tariff,” Solar Industry, Vol. 6, No. 1 (Feb. 2013) “A Review of Barriers to Biofuels Market Development in the United States,” 2 Environmental & Energy Law & Policy Journal 179 (2008) “A Strategy for Developing Stationary Biodiesel Generation,” Cumberland Law Review, Vol. 36, p.461 (2006) “Evaluating Fuel Cell Performance through Industry Collaboration,” co-author, Fuel Cell Magazine (2005) “Applications of Life Cycle Assessment to NatureWorks™ Polylactide (PLA) Production,” co-author, Polymer Degradation and Stability 80, 403-19 (2003) “An Energy Resource Investment Strategy for the City of San Francisco: Scenario Analysis of Alternative Electric Resource Options,” contributing author, Prepared for the San Francisco Public Utilities Commission, Rocky Mountain Institute (2002) “Small Is Profitable: The Hidden Economic Benefits of Making Electrical Resources the Right Size,” coauthor, Rocky Mountain Institute (2002) “Socio-Economic and Legal Issues Related to an Evaluation of the Regulatory Structure of the Retail Electric Industry in the State of Colorado,” with Thomas E. Feiler, Colorado Public Utilities Commission and Colorado Electricity Advisory Panel (April 1, 1999) “Study of Electric Utility Restructuring in Alaska,” with Thomas E. Feiler, Legislative Joint Committee on electric Restructuring and the Alaska Public Utilities Commission (April 1, 1999) “New Markets and New Opportunities: Competition in the Electric Industry Opens the Way for Renewables and Empowers Customers,” EEBA Excellence (Journal of the Energy Efficient Building Association) (Summer 1998) “Building a Better Future: Why Public Support for Renewable Energy Makes Sense,” Spectrum: The Journal of State Government (Spring 1998) “The Green-e Program: An Opportunity for Customers,” with Ryan Wiser and Jan Hamrin, Electricity Journal, Vol. 11, No. 1 (January/February 1998) Page 7 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 8 of 13 Karl R. Rábago “Being Virtual: Beyond Restructuring and How We Get There,” Proceedings of the First Symposium on the Virtual Utility, Klewer Press (1997) “Information Technology,” Public Utilities Fortnightly (March 15, 1996) “Better Decisions with Better Information: The Promise of GIS,” with James P. Spiers, Public Utilities Fortnightly (November 1, 1993) “The Regulatory Environment for Utility Energy Efficiency Programs,” Proceedings of the Meeting on the Efficient Use of Electric Energy, Inter-American Development Bank (May 1993) “An Alternative Framework for Low-Income Electric Ratepayer Services,” with Danielle Jaussaud and Stephen Benenson, Proceedings of the Fourth National Conference on Integrated Resource Planning, National Association of Regulatory Utility Commissioners (September 1992) “What Comes Out Must Go In: The Federal Non-Regulation of Cooling Water Intakes Under Section 316 of the Clean Water Act,” Harvard Environmental Law Review, Vol. 16, p. 429 (1992) “Least Cost Electricity for Texas,” State Bar of Texas Environmental Law Journal, Vol. 22, p. 93 (1992) “Environmental Costs of Electricity,” Pace University School of Law, Contributor–Impingement and Entrainment Impacts, Oceana Publications, Inc. (1990) Page 8 of 8 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 9 of 13 Date Proceeding Case/Docket # On Behalf Of: Dec. 21, 2012 VA Electric & Power Special Solar Power Tariff Virginia SCC Case # PUE2012-00064 Southern Environmental Law Center May 10, 2013 Georgia Power Company 2013 IRP Georgia PSC Docket # 36498 Georgia Solar Energy Industries Association Jun. 23, 1203 Louisiana Public Service Commission Re-examination of Net Metering Rules Louisiana PSC Docket # R31417 Gulf States Solar Energy Industries Association Aug. 29, 2013 DTE (Detroit Edison) 2013 Renewable Energy Plan Review (Michigan) Michigan PUC Case # U17302 Environmental Law and Policy Center Sep. 5, 2013 CE (Consumers Energy) 2013 Renewable Energy Plan Review (Michigan) Michigan PUC Case # U17301 Environmental Law and Policy Center Sep. 27, 2013 North Carolina Utilities Commission 2012 Avoided Cost Case North Carolina Utilities Commission Docket # E100, Sub. 136 North Carolina Sustainable Energy Association Oct. 18, 2013 Georgia Power Company 2013 Rate Case Georgia PSC Docket # 36989 Georgia Solar Energy Industries Association Nov. 4, 2013 PEPCO Rate Case (District of Columbia) District of Columbia PSC Formal Case # 1103 Grid 2.0 Working Group & Sierra Club of Washington, D.C. Apr. 24, 2014 Dominion Virginia Electric Power 2013 IRP Virginia SCC Case # PUE2013-00088 Environmental Respondents May 7, 2014 Arizona Corporation Commission Investigation on the Value and Cost of Distributed Generation Arizona Corporation Commission Docket # E00000J-14-0023 Rábago Energy LLC (invited presentation and workshop participation) Jul. 10, 2014 North Carolina Utilities Commission 2014 Avoided Cost Case North Carolina Utilities Commission Docket # E100, Sub. 140 Southern Alliance for Clean Energy Jul. 23, 2014 Florida Energy Efficiency and Conservation Act, Goal Setting – FPL, Duke, TECO, Gulf Florida PSC Docket # 130199-EI, 130200-EI, 130201-EI, 130202-EI Southern Alliance for Clean Energy Sep. 19, 2014 Ameren Missouri’s Application for Authorization to Suspend Payment of Solar Rebates Missouri PSC File No. ET2014-0350, Tariff # YE2014-0494 Missouri Solar Energy Industries Association Aug. 6, 2014 Appalachian Power Company 2014 Biennial Rate Review Virginia SCC Case # PUE2014-00026 Southern Environmental Law Center (Environmental Respondents) U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 10 of 13 Aug. 13, 2014 Wisconsin Public Service Corp. 2014 Rate Application Wisconsin PSC Docket # 6690-UR-123 RENEW Wisconsin and Environmental Law & Policy Center Aug. 28, 2014 WE Energies 2014 Rate Application Wisconsin PSC Docket # 05-UR-107 RENEW Wisconsin and Environmental Law & Policy Center Sep. 18, 2014 Madison Gas & Electric Company 2014 Rate Application Wisconsin PSC Docket # 3720-UR-120 RENEW Wisconsin and Environmental Law & Policy Center Sep. 29, 2014 SOLAR, LLC v. Missouri Public Service Commission Missouri District Court Case # 14AC-CC00316 SOLAR, LLC Jan. 28, 2016 (date of CPUC order) Order Instituting Rulemaking to Develop a Successor to Existing Net Energy Metering Tariffs, etc. California PUC Rulemaking 14-07-002 The Utility Reform Network (TURN) Mar. 20, 2015 Orange and Rockland Utilities 2015 Rate Application New York PSC Case # 14-E0493 Pace Energy and Climate Center May 22, 2015 DTE Electric Company Rate Application Michigan PSC Case # U17767 Michigan Environmental Council, NRDC, Sierra Club, and ELPC Jul. 20, 2015 Hawaiian Electric Company and NextEra Application for Change of Control Hawai’i PUC Docket # 2015-0022 Hawai’i Department of Business, Economic Development, and Tourism Sep. 2, 2015 Wisc. PSCo Rate Application Wisconsin PSC Case # 6690-UR-124 ELPC Sep. 15, 2015 Dominion Virginia Electric Power 2015 IRP VA SCC Case # PUE-201500035 Environmental Respondents Sep. 16, 2015 NYSEG & RGE Rate Cases New York PSC Cases 15-E0283, -0285 Pace Energy and Climate Center Oct. 14, 2015 Florida Power & Light Application for CCPN for Lake Okeechobee Plant Appalachian Power Company 2015 IRP Florida PSC Case 150196-EI Environmental Confederation of Southwest Florida VA SCC Case # PUE-201500036 Environmental Respondents Narragansett Electric Power/National Grid Rate Design Application State of West Virginia, et al., v. U.S. EPA, et al. Rhode Island PUC Docket No. 4568 Wind Energy Development, LLC U.S. Court of Appeals for the District of Columbia Circuit Case No. 15-1363 and Consolidated Cases Declaration in Support of Environmental and Public Health Intervenors in Support of Movant Respondent-Intervenors’ Responses in Opposition to Motions for Stay Oct. 27, 2015 Nov. 23, 2015 Dec. 8, 2015 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 11 of 13 Dec. 28, 2015 Ohio Power/AEP Affiliate PPA Application PUC of Ohio Case No. 141693-EL-RDR Environmental Law and Policy Center Jan. 19, 2016 Ohio Edison Company, Cleveland Electric Illuminating Company, and Toledo Edison Company Application for Electric Security Plan (FirstEnergy Affiliate PPA) PUC of Ohio Case No. 141297-EL-SSO Environmental Law and Policy Center Jan. 22, 2016 Northern Indiana Public Service Company (NIPSCO) Rate Case Indiana Utility Regulatory Commission Cause No. 44688 Citizens Action Coalition and Environmental Law and Policy Center Mar. 18, 2016 Northern Indiana Public Service Company (NIPSCO) Rate Case – Settlement Testimony Indiana Utility Regulatory Commission Cause No. 44688 Joint Intervenors - Citizens Action Coalition and Environmental Law and Policy Center Mar. 18, 2016 Comments on Pilot Rate Proposals by MidAmerican and Alliant Consolidated Edison of New York Rate Case Iowa Utility Board NOI2014-0001 Environmental Law and Policy Center New York PSC Case No. 16E-0060 Pace Energy and Climate Center Invited workshop presentation Pace Energy and Climate Center Aug. 17, 2016 Federal Trade Commission: Workshop on Competition and Consumer Protection Issues in Solar Energy Dominion Virginia Electric Power 2016 IRP VA SCC Case # PUE-201600049 Environmental Respondents Sep. 13, 2016 Appalachian Power Company 2016 IRP VA SCC Case # PUE-201600050 Environmental Respondents Oct. 27, 2016 Consumers Energy PURPA Compliance Filing Michigan PSC Case No. U18090 Environmental Law & Policy Center, “Joint Intervenors” Oct. 28, 2016 Maryland PSC Case PC 44 Public Interest Advocates Dec. 1, 2016 Delmarva, PEPCO (PHI) Utility Transformation Filing – Review of Filing & Utilities of the Future Whitepaper DTE Electric Company PURPA Compliance Filing Michigan PSC Case No. U18091 Environmental Law & Policy Center, “Joint Intervenors” Dec. 16, 2016 Rebuttal of Unitil Testimony in Net Energy Metering Docket New Hampshire Docket No. DE 16-576 New Hampshire Sustainable Energy Association (“NHSEA”) Jan. 13, 2017 Gulf Power Company Rate Case Florida Docket No. 160186-EI Earthjustice, Southern Alliance for Clean Energy, League of Women Voters-Florida May 27, 2016 June 21, 2016 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 12 of 13 Jan. 13, 2017 Alpena Power Company PURPA Compliance Filing Michigan PSC Case No. U18089 Environmental Law & Policy Center, “Joint Intervenors” Jan. 13, 2017 Michigan PSC Case No. U18092 Environmental Law & Policy Center, “Joint Intervenors” Michigan PSC Case No. U18093 Environmental Law & Policy Center, “Joint Intervenors” Michigan PSC Case No. U18094 Environmental Law & Policy Center, “Joint Intervenors” Mar. 10, 2017 Indiana Michigan Power Company PURPA Compliance Filing Northern States Power Company PURPA Compliance Filing Upper Peninsula Power Company PURPA Compliance Filing Eversource Energy Grid Modernization Plan Massachusetts DPU Case No. 15-122/15-123 Cape Light Compact Apr. 27, 2017 Eversource Rate Case & Grid Modernization Investments Massachusetts DPU Case No. 17-05 Cape Light Compact May 2, 2017 AEP Ohio Power Electric Security Plan PUC of Ohio Case No. 161852-EL-SSO Environmental Law & Policy Center Jun. 2, 2017 Vectren Energy TDSIC Plan Indiana URC Cause No. 44910 Citizens Action Coalition & Valley Watch Jul. 28, 2017 Vectren Energy 2016-2017 Energy Efficiency Plan Indiana URC Cause No. 44645 Citizens Action Coalition Jul. 28, 2017 Vectren Energy 2018-2020 Energy Efficiency Plan Indiana URC Cause No. 44927 Citizens Action Coalition Aug. 11, 2017 Dominion Virginia Electric Power 2017 IRP VA SCC Case # PUR-201700051 Environmental Respondents Aug. 18, 2017 Appalachian Power Company 2017 IRP VA SCC Case # PUR-201700045 Environmental Respondents Aug. 25, 2017 Niagara Mohawk Power Co. d/b/a National Grid Rate Case NY PSC Case # 17-E-0238, 17-G-0239 Pace Energy and Climate Center Sep. 15, 2017 Niagara Mohawk Power Co. d/b/a National Grid Rate Case NY PSC Case # 17-E-0238, 17-G-0239 Pace Energy and Climate Center Oct. 20, 2017 Missouri PSC Working Case to Explore Emerging Issues in Utility Regulation Central Hudson Gas & Electric Co. Electric and Gas Rates Cases MO PSC File No. EW-20170245 Renew Missouri NY PSC Case # 17-E-0459, 0460 Pace Energy and Climate Center Jan. 13, 2017 Jan. 13, 2017 Nov. 21, 2017 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-13; Source: Resume of K. Rabago Page 13 of 13 Jan. 16, 2018 Great Plains Energy, Inc. Merger with Westar Energy, Inc. U.S. House of Representatives, Energy and Commerce Committee Missouri PSC Case # EM2018-0012 Renew Missouri Advocates Hearing on “The PURPA Modernization Act of 2017,” H.R. 4476 Rábago Energy LLC Joint Petition of Electric Distribution Companies for Approval of a Model SMART Tariff Mass. D.P.U. Case No. 17140 Boston Community Capital Solar Energy Advantage Inc. Joint Petition of Electric Distribution Companies for Approval of a Model SMART Tariff Mass. D.P.U. Case No. 17140 - Surrebuttal Apr. 6, 2018 Narragansett Electric Co., d/b/a National Grid Rate Case Filing RI PUC Docket No. 4770 New Energy Rhode Island (“NERI”) Apr. 25, 2018 Narragansett Electric Co., d/b/a National Grid Power Sector Transformation Plan U.S. EPA Proposed Repeal of Carbon Pollution Emission Guidelines for Existing Stationary Stories: Electric Utility Generating Units, 82 Fed. Reg. 48,035 (Oct. 16, 2017) – “Clean Power Plan” Rhode Island PUC Docket No. 4780 New Energy Rhode Island (“NERI”) U.S. EPA Docket No. EPAHQ-OAR-2016-0592 Karl R. Rábago May 25, 2018 Orange & Rockland Utilities, Inc. Rate Case Filing NY PSC Case Nos. 18-E0067, 18-G-0068 Pace Energy and Climate Center Jun. 15, 2018 Orange & Rockland Utilities, Inc. Rate Case Filing NY PSC Case Nos. 18-E0067, 18-G-0068 – Rebuttal Testimony Pace Energy and Climate Center Aug. 10, 2018 Dominion Virginia Electric Power 2018 IRP VA SCC Case # PUR-201800065 Environmental Respondents Sep. 20, 2018 Consumers Energy Company Rate Case Michigan PSC Case No. U20134 Environmental Law & Policy Center Jan. 19, 2018 Jan. 29, 2018 Feb. 21, 2018 Apr. 26, 2018 (Jointly authored with Sheryl Musgrove) Boston Community Capital Solar Energy Advantage Inc. (Jointly authored with Sheryl Musgrove) U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-14; Source: MECNRDCSCDE-8.18 Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: U-20162 MECNRDCSC MECNRDCSCDE-8.18 Legal/T. W. Lacey 1 of 1 Question: Please explain the Company position that demand related costs should be recovered through fixed or per-customer charges in order to advance economic efficiency. If this is not the Company position, please explain. Answer: DTE objects to the request for the reason that the request is vague, unclear, and incapable of answer in its current form since the Company is unclear on what is meant by “economic efficiency.” Subject to this objection, and without waiving this objection, DTE Electric would answer as follows: The Company believes that costs that do not vary based on energy (i.e. fixed costs) should be recovered through charges that do not vary based on energy, as it best matches cost causation to cost recovery. Also, please see my testimony at pages TWL-18 to 24. Attachments: N/A U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-15; Source: MECNRDCSCDE-8.19 Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: U-20162 MECNRDCSC MECNRDCSCDE-8.19 Legal/T. W. Lacey 1 of 1 Question: Please explain whether the Company position is that all demand related costs should be recovered through fixed charges in order to advance economic efficiency. If this is not the Company position, please explain which demand related costs the Company believes should be recovered through fixed or per-customer charges. Please detail the Company’s method for distinguishing between demand related costs that it asserts should be recovered through fixed or per-customer charges. Please detail how that method is reflected in the application in this proceeding, including references to specific numbers in exhibits attached to this application. Answer: DTE objects to the request for the reason that the request is vague, unclear, and incapable of answer in its current form since the Company is unclear on what is meant by “economic efficiency.” Subject to this objection, and without waiving this objection, DTE Electric would answer as follows: The Company believes all demand costs should be recovered through fixed charges, as it best matches cost causation to cost recovery. Please see response to MECNRDCSCDE-8.16. The specific numbers identified for actual or potential recovery through fixed charges are reflected Exhibit No. A-16, Schedules F1.1, F1.2, F1.4 and F1.5. Please see my testimony at pages TWL-6 to 24 for the detailed explanation. Attachments: N/A U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-16; Source: MECNRDCSCDE-1.18d Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSCDE MECNRDCSCDE-1.18d T. W.Lacey/ K.O. Farrell 1 of 1 Please reference Dennis Direct at 21:17-20. d. Please state whether you contend that there is greater correlation between each individual customer’s maximum monthly demand and that customer’s individual contribution to class NCP used to allocate demand costs in the cost of service study, than between each customer’s individual kWh consumption and that customer’s individual contribution to class NCP used to allocate demand costs in the cost of service study. Answer: The Company does not allocate distribution costs based on individual customer’s maximum monthly demands. See response to MECNRDCSCDE-1.23c, which subject to objection states as follows: None of the amounts used in the U-20162 Cost of Service study reflect individual customer’s detail, however if I use total voltage class amounts and assuming: (1) I use allocation schedule 300 reflected on page 13 of Exhibit A-17, Schedule G1.2, which reflects annual maximum demands, (2) “customer’s contribution to class NCP” means allocation schedule no. 202c per page 7 of Exhibit A-17, Schedule G1.2, and (3) a “customer’s kWh imports” means the projected energy sales as reflected on Exhibit A-17, Schedule G1.1. I would answer as follows: I can not determine the level of stastically significant correlation, but I can state for the forecasted values reflected in this case the former shows more variation than the latter for residential and less variation for commercial secondary. (See attached file “U-20162 MECNRDSCDE-1.23” for the calculation.) U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-17; Source: MECNRDCSCDE-1.23c w attachment Page 1 of 2 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSCDE MECNRDCSCDE-1.23c T. W. Lacey/Legal 1 of 1 Please reference Lacey Direct at 18:24-20:19. c. Do you contend that there is a more significant correlation between an individual customer’s contribution to class NCP and that customer’s individual monthly maximum demand, than between an individual customer’s contribution to class NCP and the customer’s kWh imports? Answer: DTE Electric objects because the request is unclear and unduly vague and incapable of answer in its present form since the Company is unclear regarding the comparison requested using the terms stated in the question. Subject to this objection, and without waiving this objection, the Company would answer as follows: None of the amounts used in the U-20162 Cost of Service study reflect individual customer’s detail, however if I use total voltage class amounts and assuming: (1) I use allocation schedule 300 reflected on page 13 of Exhibit A-17, Schedule G1.2, which reflects annual maximum demands, (2) “customer’s contribution to class NCP” means allocation schedule no. 202c per page 7 of Exhibit A-17, Schedule G1.2, and (3) a “customer’s kWh imports” means the projected energy sales as reflected on Exhibit A-17, Schedule G1.1. I would answer as follows: I can not determine the level of stastically significant correlation, but I can state for the forecasted values reflected in this case the former shows more variation than the latter. for residential and less variation for commercial secondary. (See attached file “U-20162 MECNRDSCDE-1.23” for the calculation.) U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-17; Source: MECNRDCSCDE-1.23c w attachment Page 2 of 2 Michigan Public Service Commission DTE Electric Company Support for Discovery Response MECNRDCSCDE-1.23c 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Res Com sec Max Demand Sch 300 %/Ratio Source 70.36% 29.26% Exh A-17, sch G1.2 Page 17 Line 1 col. (C) Exh A-17, sch G1.2 Page 17 Line 7 col. (C) 48.69% 26.74% Exh A-17, sch G1.2 Page 7 Line 2 col. (C) Exh A-17, sch G1.2 Page 7 Line 7 col. (C) Sch 202c NCP Res Com sec Ratio Res Com sec Res Com sec Total Res Com sec 1.45 1.09 Energy Sales 16,335,533 10,563,282 36.56% 23.64% Line 1/Line 9 Line 2/Line 10 Exh A-17, sch G1.1 Lines 2-4 col. (B) Exh A-17, sch G1.1 Lines 9-11 col. (B) 44,685,656 Ratio 1.33 1.13 Line 9/Line 18 Line 10/Line 19 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-18; Source: MECNRDCSCDE-2.11 Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: U-20162 MECNRDCSCDE MECNRDCSCDE-2.11 T. D. Johnson 1 of 1 Question: Refer to Tamara Johnson direct testimony concerning low income programs. Produce any and all data in the possession or control of DTE regarding poverty rates in the Company’s service territory, and any and all data regarding the numbers of DTE customers the Company would consider to be low income. Answer: The low income data as of August 2018 is as follows: Num of BPs 164,475 Num of CAs 175,136 Num of Contracts 300,791 Num of Premise 174,035 Customers identified as low income are at or below 200% of the Federal Poverty Level. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-19; U-18255 MECNRDCSCDE-1.19 w attachment Page 1 of 2 MPSC Case No.: Respondent: Requestor: Question No.: Page: U-18255 M. C. Johnson MECNRDCSC-1 MECNRDCSCDE-1.19 1 of 1 Question: Refer to direct testimony of Mark Johnson, page 22, lines 21-24. Produce any and all data in DTE’s possession or control regarding poverty rates (and rates of increase in same) in the Company’s service territory. Answer: Please see the Demographics”. attachment, “U-18255 MECNRDCSCDE-1.19 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-19; U-18255 MECNRDCSCDE-1.19 w attachment Page 2 of 2 https://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ACS_15_1YR_S1701&prodType=table MICHIGAN 2005 2006 2007 2008 2009 2010 Population for whom poverty status is determined 9,830,885 9,852,543 9,832,533 9,769,537 9,735,741 9,656,449 Below poverty level 1,299,688 1,331,833 1,376,658 1,410,276 1,576,704 1,618,257 13.2% 13.5% 14.0% 14.4% 16.2% 16.8% 150 percent of poverty level 2,055,201 2,115,954 2,193,987 2,224,040 2,459,508 2,536,075 20.9% 21.5% 22.3% 22.8% 25.3% 26.3% 200 percent of poverty level 2,873,439 2,961,488 3,026,225 3,103,459 3,374,521 3,444,954 29.2% 30.1% 30.8% 31.8% 34.7% 35.7% DETROIT 2005 2006 2007 2008 2009 2010 832,680 817,638 796,076 766,714 897,869 702,010 Population for whom poverty status is determined Below poverty level 261,497 265,600 269,011 255,559 326,764 263,864 31.4% 32.5% 33.8% 33.3% 36.4% 37.6% 150 percent of poverty level 360,486 379,988 366,277 367,258 445,357 363,720 43.3% 46.5% 46.0% 47.9% 49.6% 51.8% 200 percent of poverty level 452,787 462,911 448,722 452,914 555,363 444,839 54.4% 56.6% 56.4% 59.1% 61.9% 63.4% 2011 9,656,260 1,693,294 17.5% 2,608,572 27.0% 3,488,897 36.1% 2011 695,930 284,421 40.9% 373,936 53.7% 452,118 65.0% 2012 9,663,760 1,685,178 17.4% 2,588,971 26.8% 3,488,070 36.1% 2012 691,284 292,391 42.3% 382,506 55.3% 451,207 65.3% 2013 9,669,513 1,648,436 17.0% 2,518,135 26.0% 3,446,237 35.6% 2013 678,700 276,186 40.7% 368,458 54.3% 434,515 64.0% 2014 9,686,787 1,568,844 16.2% 2,493,432 25.7% 3,359,370 34.7% 2014 669,071 262,767 39.3% 361,175 54.0% 435,180 65.0% 2015 9,698,396 1,529,645 15.8% 2,394,986 24.7% 3,279,049 33.8% 2015 665,640 265,097 39.8% 363,142 54.6% 437,067 65.7% Chart Title 45% 40% 35% 40.9% 42.3% 40.7% 39.3% 39.8% 25% 20% 13.5% 14.0% 14.4% 15% 13.2% 16.2% 16.8% 17.5% 17.4% 17.0% 16.2% 15.8% 10% 5% 0% 2005 2006 2007 2008 2009 2010 MICHIGAN 2011 2012 2013 2014 2015 DETROIT Chart Title 60% DETROIT All families Percent below poverty level Below poverty level 2005 189,728 27.0% 51,227 2006 180,216 27.0% 48,658 2007 165,521 28.2% 46,677 2008 158,012 30.3% 47,878 2009 188,297 31.3% 58,937 2010 148,316 32.3% 47,906 2011 145,224 35.5% 51,555 2012 145,294 37.7% 54,776 2013 144,476 35.4% 51,145 2014 141,250 33.8% 47,743 2015 141,284 35.5% 50,156 20% MICHIGAN 50 percent of poverty level 125 percent of poverty level 150 percent of poverty level 185 percent of poverty level 200 percent of poverty level 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 111,906 360,566 451,807 594,331 652,713 DETROIT 50 percent of poverty level 125 percent of poverty level 150 percent of poverty level 185 percent of poverty level 200 percent of poverty level 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 22,337 61,017 69,790 81,780 85,841 8 ‐ MECNRDCSCDE‐1.19.xlsx 36.4% 37.6% 30% https://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ACS_15_1YR_S1702&prodType=table MICHIGAN 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2,594,228 2,579,201 2,560,681 2,525,388 2,523,758 2,508,780 2,472,884 2,482,612 2,484,558 2,485,159 2,479,724 All families Percent below poverty level 9.9% 9.6% 10.1% 10.5% 11.6% 12.1% 12.5% 12.6% 12.3% 11.4% 11.1% Below poverty level 256,829 247,603 258,629 265,166 292,756 303,562 309,111 312,809 305,601 283,308 275,249 https://factfinder.census.gov/faces/tableservices/jsf/pages/productview.xhtml?pid=ACS_15_1YR_DP03&prodType=table 33.8% 33.3% 31.4% 32.5% 50% 43.3% 55.3% 54.3% 54.0% 54.6% 51.8% 53.7% 49.6% 46.5% 46.0% 47.9% 40% 30% 20.9% 21.5% 22.3% 22.8% 25.3% 26.3% 27.0% 26.8% 26.0% 25.7% 24.7% 10% 0% 2005 2006 2007 2008 2009 2010 MICHIGAN 2011 DETROIT 2012 2013 2014 2015 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-20; Source: MECNRDCSCDE-8.20 Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: U-20162 MECNRDCSC MECNRDCSCDE-8.20 T. W. Lacey 1 of 1 Question: Please provide citations, including references to specific language, for all treatises, scholarly articles, texts, commission decisions, statutes, or any other references relied upon by the Company that assert or support the proposition that economic efficiency, fairness, and/or reasonableness are advanced when fixed costs of any type are recovered through fixed charges of any type. Answer: I have no citation that explicitly states “economic efficiency, fairness, and/or reasonableness are advanced when fixed costs of any type are recovered through fixed charges of any type.” However, the Blank and Gegax article in the April 2016 issue of The Electricity Journal, Volume 29, Issue 3, pages 42-47 entitled An Enhanced Two-Part Tariff Methodology When Demand Charges Are Not Used,” supports the argument that demand costs should be collected through a customer charge when a demand charge is not an option. Attachments: N/A U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-22; Source: ELPCDE-2.84 w attachment Page 1 of 7 MPSC Case No.: Requestor: Question No.: Respondent: Page: U-20162 ELPC ELPCDE-2.84 P. W. Dennis 1 of 1 Question: Provide all bill impact analyses that have been conducted on the effect of the proposed DG tariff changes (including the SAC) compared to customers without DG and customers currently taking service under Rider 16. Data should be provided in its native format with formulas intact. If any workpaper has an external link to another workpaper, provide the supplemental workpaper. If any workpaper has hardcoded figures derived from another workpaper, provide the supplemental workpapers. Answer: The Company has not completed a bill impact analyses comparing the effect of the proposed rates and DG tariff changes (including the SAC) compared to customers without DG, and customers currently taking service under Rider 16. However, the Company did complete a bill impact analysis on earlier iterations of a similar concept. Note, this bill impact analysis does not reflect the rates proposed in this case. See also the response to ELPCDE-2.61. Attachments: U-20162 ELPCDE-2.84 analysis.xls U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-22; Source: ELPCDE-2.84 w attachment Page 2 of 7 Customer 1 Inputs Month 1 2 3 4 5 6 7 8 9 10 11 12 D1 ‐ no net meter Month 1 2 3 4 5 6 7 8 9 10 11 12 Gen 44.62 140.08 405.77 617.28 672.72 661.45 657.06 616.61 489.14 321.40 201.83 172.06 5000 Days 31 28 31 30 31 30 31 31 30 31 30 31 In 401 474 569 536 406 381 360 408 440 605 809 869 6258 Total Use 424 522 725 677 589 563 522 571 588 726 919 978 Out 22 92 249 476 490 480 495 454 341 201 92 63 D1 Rate First Block Second Block PSCR In + Gen ‐ Out 424 522 725 677 589 563 522 571 588 726 919 978 3454 7803 First Block kWh 424 476 527 510 527 510 522 527 510 527 510 527 First Block $34.05 $38.25 $42.34 $40.98 $42.34 $40.98 $41.91 $42.34 $40.98 $42.34 $40.98 $42.34 Second Block kWh 0 46 198 167 62 53 0 44 78 199 409 451 Second Block Bill 0 4.44 19 16.06 5.93 5.04 0 4.22 7.53 19.09 39.28 43.27 PSCR Bill ‐0.37 ‐0.45 ‐0.63 ‐0.59 ‐0.51 ‐0.49 ‐0.45 ‐0.5 ‐0.51 ‐0.63 ‐0.8 ‐0.85 ANNUAL D1 ‐ Category 1 Net Metering Month Days 1 31 2 28 3 31 4 30 5 31 6 30 7 31 8 31 9 30 10 31 11 30 12 31 $0.08035 $0.09599 ‐$0.000870 Service Charge Distribution Rate (k Nuclear EO LIEAF $7.50 $0.05529 0.000728 $0.003396 $0.93 Total Fix Total Dist Surchagr $8.43 $0.00412 PS Total $33.68 $42.24 $60.71 $56.45 $47.76 $45.53 $41.46 $46.06 $48.00 $60.80 $79.46 $84.76 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Outflow Credit L Distribution Bill $23.43 $28.87 $40.08 $37.45 $32.55 $31.10 $28.84 $31.57 $32.54 $40.14 $50.82 $54.06 Dist Surch Bill $1.75 $2.15 $2.99 $2.79 $2.43 $2.32 $2.15 $2.35 $2.43 $2.99 $3.79 $4.03 ($0.035) Dist subtotal $33.61 $39.45 $51.50 $48.67 $43.41 $41.85 $39.42 $42.35 $43.40 $51.56 $63.04 $66.52 $646.91 Net Inflow First Block kWh 379 379 382 382 319 319 60 60 0 0 0 0 0 0 0 0 99 99 405 405 717 510 806 527 First Block $30.46 $30.71 $25.64 $4.83 $0.00 $0.00 $0.00 $0.00 $7.98 $32.50 $40.98 $42.34 Excess Gen Cred ‐$7.98 ‐$21.27 Second Block kWh 0 0 0 0 0 0 0 0 0 0 207 279 Second Block Bill 0 0 0 0 0 0 0 0 0 0 19.91 26.75 Excess Gen Cred $564.78 PSCR Bill ‐0.33 ‐0.33 ‐0.28 ‐0.05 0 0 0 0 ‐0.09 ‐0.35 ‐0.62 ‐0.7 Excess Gen Credit 0.09 $0.23 ANNUAL D1 ‐ Inflow/outflow method at LMP Outflow Credit Month Days Total Inflow First Block kWh 1 31 401 401 2 28 474 474 3 31 569 527 4 30 536 510 5 31 406 406 6 30 381 381 7 31 360 360 8 31 408 408 9 30 440 440 10 31 605 527 11 30 809 510 12 31 869 527 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Total Bill Bank Value Remaining $1,212 N/A $500 $0 $862 $0 Total Bill $67.29 $81.69 $112.21 $105.12 $91.17 $87.38 $80.88 $88.41 $91.40 $112.36 $142.50 $151.28 $1,211.69 Distribution Bill $20.96 $21.13 $17.65 $3.32 $0.00 $0.00 $0.00 $0.00 $5.49 $22.37 $39.66 $44.55 Excess Gen Cred ‐$5.49 ‐$14.63 Dist Surch Bill $1.56 $1.58 $1.32 $0.25 $0.00 $0.00 $0.00 $0.00 $0.41 $1.67 $2.96 $3.32 Dist subtotal $30.95 $31.14 $27.40 $12.00 $8.43 $8.43 $8.43 $8.43 $8.84 $17.84 $51.05 $56.30 $230.42 First Block $32.25 $38.07 $42.34 $40.98 $32.60 $30.63 $28.89 $32.77 $35.39 $42.34 $40.98 $42.34 Second Block kWh 0 0 42 26 0 0 0 0 0 78 299 342 Second Block Bill 0 0 4 2.47 0 0 0 0 0 7.53 28.72 32.8 PSCR Bill ‐0.35 ‐0.41 ‐0.49 ‐0.47 ‐0.35 ‐0.33 ‐0.31 ‐0.35 ‐0.38 ‐0.53 ‐0.7 ‐0.76 ANNUAL D1 ‐ Inflow/outflow method, grid charge, and LMP outflow Month Days Total Inflow First Block kWh 1 31 401 401 2 28 474 474 3 31 569 527 4 30 536 510 5 31 406 406 6 30 381 381 7 31 360 360 8 31 408 408 9 30 440 440 10 31 605 527 11 30 809 510 12 31 869 527 PS Total $30.13 $30.38 $25.36 $4.78 $0.00 $0.00 $0.00 $0.00 $0.00 $11.11 $60.27 $68.39 Annual Summary No gen Cat 1 NM In/Out  ‐ LMP Outflow PS Total $31.90 $37.66 $45.85 $42.98 $32.25 $30.30 $28.58 $32.42 $35.01 $49.34 $69.00 $74.38 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $22.19 $26.19 $31.44 $29.62 $22.44 $21.08 $19.88 $22.55 $24.35 $33.48 $44.74 $48.03 Dist Surch Bill $1.66 $1.95 $2.35 $2.21 $1.67 $1.57 $1.48 $1.68 $1.82 $2.50 $3.34 $3.58 $269.24 Dist subtotal $32.28 $36.57 $42.22 $40.26 $32.54 $31.08 $29.79 $32.66 $34.60 $44.41 $56.51 $60.04 $509.67 First Block $32.25 $38.07 $42.34 $40.98 $32.60 $30.63 $28.89 $32.77 $35.39 $42.34 $40.98 $42.34 Second Block kWh 0 0 42 26 0 0 0 0 0 78 299 342 Second Block Bill 0 0 4 2.47 0 0 0 0 0 7.53 28.72 32.8 PSCR Bill ‐0.35 ‐0.41 ‐0.49 ‐0.47 ‐0.35 ‐0.33 ‐0.31 ‐0.35 ‐0.38 ‐0.53 ‐0.7 ‐0.76 PS Total $31.90 $37.66 $45.85 $42.98 $32.25 $30.30 $28.58 $32.42 $35.01 $49.34 $69.00 $74.38 Outflow kWh 22 92 249 476 490 480 495 454 341 201 92 63 LMP Outflow Cred ‐$0.78 ‐$3.21 ‐$8.73 ‐$16.65 ‐$17.14 ‐$16.80 ‐$17.33 ‐$15.87 ‐$11.94 ‐$7.03 ‐$3.21 ‐$2.21 $472.96 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $22.19 $26.19 $31.44 $29.62 $22.44 $21.08 $19.88 $22.55 $24.35 $33.48 $44.74 $48.03 Dist Surch Bill $1.66 $1.95 $2.35 $2.21 $1.67 $1.57 $1.48 $1.68 $1.82 $2.50 $3.34 $3.58 Total Bill $61.08 $61.52 $52.76 $16.78 $8.43 $8.43 $8.43 $8.43 $8.84 $28.95 $111.32 $124.69 Dist subtotal $32.28 $36.57 $42.22 $40.26 $32.54 $31.08 $29.79 $32.66 $34.60 $44.41 $56.51 $60.04 $509.67 $472.96 10 ‐ ELPCDE‐2.84 analysis.xlsx Total Bill $63.40 $71.02 $79.34 $66.59 $47.65 $44.58 $41.04 $49.21 $57.67 $86.72 $122.30 $132.21 Bank Start Bank Change Bank End 0 0 0 0 0 0 0 0 0 0 0 0 0 84 84 84 99 183 183 136 318 318 46 364 364 ‐99 265 265 ‐265 0 0 0 0 0 0 0 $499.66 Bank Start no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess 0 Bank ChangeBank End 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $861.73 Grid Charge $10.25 $10.25 $10.25 $10.25 $10.25 $10.25 $10.25 $10.25 $10.25 $10.25 $10.25 $10.25 $122.98 Outflow kWh 22 92 249 476 490 480 495 454 341 201 92 63 Outflow Cred ‐$0.78 ‐$3.21 ‐$8.73 ‐$16.65 ‐$17.14 ‐$16.80 ‐$17.33 ‐$15.87 ‐$11.94 ‐$7.03 ‐$3.21 ‐$2.21 ‐$120.90 Total Bill $73.65 $81.27 $89.59 $76.84 $57.90 $54.82 $51.29 $59.46 $67.92 $96.96 $132.55 $142.46 no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess $984.71 Bank StartBank Change Bank End 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $0.13 $0.00 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-22; Source: ELPCDE-2.84 w attachment Page 3 of 7 Customer 1 Inputs Month 1 2 3 4 5 6 7 8 9 10 11 12 D1 ‐ no net meter Month 1 2 3 4 5 6 7 8 9 10 11 12 Gen 13.93 67.11 103.8 149.6 139.1 131.4 141.8 131.5 112.9 72.09 42.78 34.41 Days 31 28 31 30 31 30 31 31 30 31 30 31 In 304.826 377.045 397.648 305.947 382.455 448.05 457.178 448.952 334.073 290.486 359.68 410.186 Out 2.103 12.254 31.733 65.245 47.315 30.525 31.911 32.982 44.935 27.451 10.206 4.18 Total Use First Block kWh 317 317 432 432 470 470 390 390 474 474 549 510 567 527 547 527 402 402 335 335 392 392 440 440 D1 Rate First Block Second Block PSCR In + Gen ‐ Out 317 432 470 390 474 549 567 547 402 335 392 440 5316 First Block $25.44 $34.70 $37.74 $31.36 $38.10 $40.98 $42.34 $42.34 $32.31 $26.93 $31.52 $35.39 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 39 3.74 40 3.85 20 1.96 0 0 0 0 0 0 0 0 PSCR Bill ‐0.28 ‐0.38 ‐0.41 ‐0.34 ‐0.41 ‐0.48 ‐0.49 ‐0.48 ‐0.35 ‐0.29 ‐0.34 ‐0.38 ANNUAL D1 ‐ Category 1 Net Metering Month Days Net Inflow First Block kWh 1 31 303 303 2 28 365 365 3 31 366 366 4 30 241 241 5 31 335 335 6 30 418 418 7 31 425 425 8 31 416 416 9 30 289 289 10 31 263 263 11 30 349 349 12 31 406 406 $0.08035 $0.09599 ‐$0.000870 Service Charge Distribution Rate  Nuclear EO LIEAF $7.50 $0.05529 0.000728 $0.003396 $0.93 Total Fix Total Dist Surchag $8.43 $0.00412 PS Total $25.16 $34.32 $37.33 $31.02 $37.69 $44.24 $45.70 $43.82 $31.96 $26.64 $31.18 $35.01 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Outflow Credit Distribution Bill $17.51 $23.88 $25.97 $21.58 $26.22 $30.35 $31.35 $30.27 $22.23 $18.53 $21.69 $24.35 $424.07 First Block $24.32 $29.31 $29.40 $19.34 $26.93 $33.55 $34.17 $33.42 $23.23 $21.13 $28.08 $32.62 Excess Gen Cred Second Block kWh Second Block Bill Excess Gen Cred 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Dist subtotal $27.25 $34.09 $36.34 $31.62 $36.61 $41.04 $42.12 $40.96 $32.32 $28.34 $31.74 $34.60 $417.03 PSCR Bill ‐0.26 ‐0.32 ‐0.32 ‐0.21 ‐0.29 ‐0.36 ‐0.37 ‐0.36 ‐0.25 ‐0.23 ‐0.3 ‐0.35 Excess Gen Credit ANNUAL D1 ‐ Inflow/outflow method at LMP Outflow Credit Month Days Total Inflow First Block kWh 1 31 305 305 2 28 377 377 3 31 398 398 4 30 306 306 5 31 382 382 6 30 448 448 7 31 457 457 8 31 449 449 9 30 334 334 10 31 290 290 11 30 360 360 12 31 410 410 Dist Surch Bill $1.31 $1.78 $1.94 $1.61 $1.96 $2.26 $2.34 $2.26 $1.66 $1.38 $1.62 $1.82 ($0.035) PS Total $24.06 $28.99 $29.08 $19.13 $26.64 $33.19 $33.80 $33.06 $22.98 $20.90 $27.78 $32.27 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Annual Summary No gen Cat 1 NM In/Out  ‐ LMP Outflow Total Bill $841 $681 $717 Bank Value Remaining N/A $0.00 0 Total Bill $52.41 $68.41 $73.67 $62.64 $74.30 $85.28 $87.82 $84.78 $64.28 $54.98 $62.92 $69.61 $841.10 Distribution Bill $16.74 $20.17 $20.23 $13.31 $18.53 $23.08 $23.51 $23.00 $15.99 $14.54 $19.32 $22.45 Excess Gen Cred Dist Surch Bill $1.25 $1.50 $1.51 $0.99 $1.38 $1.72 $1.75 $1.72 $1.19 $1.08 $1.44 $1.67 Dist subtotal $26.42 $30.10 $30.17 $22.73 $28.34 $33.23 $33.69 $33.15 $25.61 $24.05 $29.19 $32.55 $331.88 First Block $24.49 $30.30 $31.95 $24.58 $30.73 $36.00 $36.73 $36.07 $26.84 $23.34 $28.90 $32.96 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 PSCR Bill ‐0.27 ‐0.33 ‐0.35 ‐0.27 ‐0.33 ‐0.39 ‐0.4 ‐0.39 ‐0.29 ‐0.25 ‐0.31 ‐0.36 ANNUAL D1 ‐ Inflow/outflow method, grid charge, and LMP outflow Month Days Total Inflow First Block kWh First Block 1 31 305 305 $24.49 2 28 377 377 $30.30 3 31 398 398 $31.95 4 30 306 306 $24.58 5 31 382 382 $30.73 6 30 448 448 $36.00 7 31 457 457 $36.73 8 31 449 449 $36.07 9 30 334 334 $26.84 10 31 290 290 $23.34 11 30 360 360 $28.90 12 31 410 410 $32.96 PS Total $24.22 $29.97 $31.60 $24.31 $30.40 $35.61 $36.33 $35.68 $26.55 $23.09 $28.59 $32.60 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $16.85 $20.85 $21.99 $16.92 $21.15 $24.77 $25.28 $24.82 $18.47 $16.06 $19.89 $22.68 Dist Surch Bill $1.26 $1.55 $1.64 $1.26 $1.58 $1.85 $1.89 $1.85 $1.38 $1.20 $1.48 $1.69 $358.95 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 PSCR Bill ‐0.27 ‐0.33 ‐0.35 ‐0.27 ‐0.33 ‐0.39 ‐0.4 ‐0.39 ‐0.29 ‐0.25 ‐0.31 ‐0.36 PS Total $24.22 $29.97 $31.60 $24.31 $30.40 $35.61 $36.33 $35.68 $26.55 $23.09 $28.59 $32.60 $358.95 $349.23 Dist subtotal $26.54 $30.83 $32.06 $26.61 $31.16 $35.05 $35.60 $35.10 $28.28 $25.69 $29.80 $32.80 Outflow kWh 2 12 32 65 47 31 32 33 45 27 10 4 LMP Outflow Cred ‐$0.07 ‐$0.43 ‐$1.11 ‐$2.28 ‐$1.66 ‐$1.07 ‐$1.12 ‐$1.15 ‐$1.57 ‐$0.96 ‐$0.36 ‐$0.15 $369.52 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $16.85 $20.85 $21.99 $16.92 $21.15 $24.77 $25.28 $24.82 $18.47 $16.06 $19.89 $22.68 Dist Surch Bill $1.26 $1.55 $1.64 $1.26 $1.58 $1.85 $1.89 $1.85 $1.38 $1.20 $1.48 $1.69 Total Bill $50.48 $59.09 $59.25 $41.86 $54.98 $66.42 $67.49 $66.21 $48.59 $44.95 $56.97 $64.82 Dist subtotal $26.54 $30.83 $32.06 $26.61 $31.16 $35.05 $35.60 $35.10 $28.28 $25.69 $29.80 $32.80 $369.52 Total Bill $50.69 $60.37 $62.55 $48.64 $59.90 $69.59 $70.81 $69.63 $53.26 $47.82 $58.03 $65.25 Bank Start Bank Change Bank End 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $681.11 Bank Start no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess 0 0 0 0 0 0 0 0 0 0 0 0 0 ank Chang Bank End 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $716.54 Grid Charge $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $29.28 10 ‐ ELPCDE‐2.84 analysis.xlsx Outflow kWh 2 12 32 65 47 31 32 33 45 27 10 4 Outflow Cred ‐$0.07 ‐$0.43 ‐$1.11 ‐$2.28 ‐$1.66 ‐$1.07 ‐$1.12 ‐$1.15 ‐$1.57 ‐$0.96 ‐$0.36 ‐$0.15 ‐$11.93 Total Bill $53.13 $62.81 $64.99 $51.08 $62.34 $72.03 $73.25 $72.07 $55.70 $50.26 $60.47 $67.69 $745.82 no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess Bank Startank Chang 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Bank End 0 0 0 0 0 0 0 0 0 0 0 0 $0.13 $0.00 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-22; Source: ELPCDE-2.84 w attachment Page 4 of 7 Customer 1 Inputs Month 1 2 3 4 5 6 7 8 9 10 11 12 D1 ‐ no net meter Month 1 2 3 4 5 6 7 8 9 10 11 12 Gen 202.3 494.1 647.9 752.9 779.1 707.3 795 742.2 653.2 478.5 317.4 239.4 Days 31 28 31 30 31 30 31 31 30 31 30 31 In 416.823 447.381 484.546 493.15 457.565 511.19 500.73 560.062 564.034 499.762 666.864 812.83 D1 Rate First Block Second Block PSCR Out In + Gen ‐ Out 101.517 518 297.102 644 388.815 744 460.075 786 480.164 756 386.632 832 449.857 846 420.065 882 363.397 854 291.653 687 159.549 825 91.592 961 9334 Total Use First Block kWh 518 518 644 476 744 527 786 510 756 527 832 510 846 527 882 527 854 510 687 527 825 510 961 527 First Block $41.59 $38.25 $42.34 $40.98 $42.34 $40.98 $42.34 $42.34 $40.98 $42.34 $40.98 $42.34 Second Block kWh Second Block Bill 0 0 168 16.16 217 20.8 276 26.49 229 22.03 322 30.89 319 30.61 355 34.1 344 33.01 160 15.32 315 30.21 434 41.63 PSCR Bill ‐0.45 ‐0.56 ‐0.65 ‐0.68 ‐0.66 ‐0.72 ‐0.74 ‐0.77 ‐0.74 ‐0.6 ‐0.72 ‐0.84 ANNUAL D1 ‐ Category 1 Net Metering Month Days Net Inflow First Block kWh 1 31 315 315 2 28 150 150 3 31 96 96 4 30 33 33 5 31 0 0 6 30 125 125 7 31 51 51 8 31 140 140 9 30 201 201 10 31 208 208 11 30 507 507 12 31 721 527 $0.08035 $0.09599 ‐$0.000870 Service Charge Distribution Rate  Nuclear EO LIEAF $7.50 $0.05529 0.000728 $0.003396 $0.93 Total Fix Total Dist Surchag $8.43 $0.00412 PS Total $41.14 $53.85 $62.49 $66.79 $63.71 $71.15 $72.21 $75.67 $73.25 $57.06 $70.47 $83.13 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Outflow Credit Distribution Bill $28.62 $35.63 $41.12 $43.46 $41.83 $45.99 $46.77 $48.78 $47.21 $37.96 $45.60 $53.12 $790.92 First Block $25.33 $12.07 $7.69 $2.66 $0.00 $10.01 $4.09 $11.25 $16.12 $16.72 $40.76 $42.34 Excess Gen Cred ‐$1.82 Second Block kWh Second Block Bill Excess Gen Cred 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 194 18.64 Dist subtotal $39.18 $46.72 $52.62 $55.13 $53.38 $57.85 $58.69 $60.85 $59.16 $49.22 $57.43 $65.51 $655.74 PSCR Bill ‐0.27 ‐0.13 ‐0.08 ‐0.03 0 ‐0.11 ‐0.04 ‐0.12 ‐0.17 ‐0.18 ‐0.44 ‐0.63 Excess Gen Credit $0.02 ANNUAL D1 ‐ Inflow/outflow method at LMP Outflow Credit Month Days Total Inflow First Block kWh 1 31 417 417 2 28 447 447 3 31 485 485 4 30 493 493 5 31 458 458 6 30 511 510 7 31 501 501 8 31 560 527 9 30 564 510 10 31 500 500 11 30 667 510 12 31 813 527 Dist Surch Bill $2.13 $2.66 $3.07 $3.24 $3.12 $3.43 $3.49 $3.64 $3.52 $2.83 $3.40 $3.96 ($0.035) PS Total $25.06 $11.94 $7.61 $2.63 $0.00 $8.10 $4.05 $11.13 $15.95 $16.54 $40.32 $60.35 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Annual Summary No gen Cat 1 NM In/Out  ‐ LMP Outflow Total Bill Bank Value Remaining $1,447 N/A $455 $0 $864 $0 Total Bill $80.32 $100.57 $115.11 $121.92 $117.09 $129.00 $130.90 $136.52 $132.41 $106.28 $127.90 $148.64 $1,446.66 Distribution Bill $17.43 $8.31 $5.29 $1.83 $0.00 $6.89 $2.81 $7.74 $11.09 $11.51 $28.05 $39.88 Excess Gen Cred ‐$1.25 Dist Surch Bill $1.30 $0.62 $0.39 $0.14 $0.00 $0.51 $0.21 $0.58 $0.83 $0.86 $2.09 $2.97 Dist subtotal $27.16 $17.36 $14.11 $10.40 $8.43 $14.58 $11.45 $16.75 $20.35 $20.80 $38.57 $51.28 $203.68 First Block $33.49 $35.95 $38.93 $39.62 $36.77 $40.98 $40.23 $42.34 $40.98 $40.16 $40.98 $42.34 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 1 0.11 0 0 33 3.17 54 5.19 0 0 157 15.06 286 27.44 PSCR Bill ‐0.36 ‐0.39 ‐0.42 ‐0.43 ‐0.4 ‐0.44 ‐0.44 ‐0.49 ‐0.49 ‐0.43 ‐0.58 ‐0.71 ANNUAL D1 ‐ Inflow/outflow method, grid charge, and LMP outflow Month Days Total Inflow First Block kWh First Block 1 31 417 417 $33.49 2 28 447 447 $35.95 3 31 485 485 $38.93 4 30 493 493 $39.62 5 31 458 458 $36.77 6 30 511 510 $40.98 7 31 501 501 $40.23 8 31 560 527 $42.34 9 30 564 510 $40.98 10 31 500 500 $40.16 11 30 667 510 $40.98 12 31 813 527 $42.34 PS Total $33.13 $35.56 $38.51 $39.19 $36.37 $40.65 $39.79 $45.02 $45.68 $39.73 $55.46 $69.07 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $23.05 $24.74 $26.79 $27.27 $25.30 $28.26 $27.69 $30.97 $31.19 $27.63 $36.87 $44.94 Dist Surch Bill $1.72 $1.84 $2.00 $2.03 $1.89 $2.11 $2.07 $2.31 $2.33 $2.06 $2.75 $3.35 $518.16 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 1 0.11 0 0 33 3.17 54 5.19 0 0 157 15.06 286 27.44 PSCR Bill ‐0.36 ‐0.39 ‐0.42 ‐0.43 ‐0.4 ‐0.44 ‐0.44 ‐0.49 ‐0.49 ‐0.43 ‐0.58 ‐0.71 PS Total $33.13 $35.56 $38.51 $39.19 $36.37 $40.65 $39.79 $45.02 $45.68 $39.73 $55.46 $69.07 $518.16 $251.24 Dist subtotal $33.20 $35.01 $37.22 $37.73 $35.62 $38.80 $38.19 $41.71 $41.95 $38.12 $48.05 $56.72 Outflow kWh 102 297 389 460 480 387 450 420 363 292 160 92 LMP Outflow Cred ‐$3.55 ‐$10.40 ‐$13.61 ‐$16.10 ‐$16.81 ‐$13.53 ‐$15.74 ‐$14.70 ‐$12.72 ‐$10.21 ‐$5.58 ‐$3.21 $482.32 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $23.05 $24.74 $26.79 $27.27 $25.30 $28.26 $27.69 $30.97 $31.19 $27.63 $36.87 $44.94 Dist Surch Bill $1.72 $1.84 $2.00 $2.03 $1.89 $2.11 $2.07 $2.31 $2.33 $2.06 $2.75 $3.35 Total Bill $52.22 $29.30 $21.72 $13.03 $8.43 $22.68 $15.50 $27.88 $36.30 $37.34 $78.89 $111.63 Dist subtotal $33.20 $35.01 $37.22 $37.73 $35.62 $38.80 $38.19 $41.71 $41.95 $38.12 $48.05 $56.72 $482.32 Total Bill $62.78 $60.17 $62.12 $60.82 $55.18 $65.92 $62.24 $72.03 $74.91 $67.64 $97.93 $122.58 Bank Start Bank Change Bank End 0 0 0 0 0 0 0 0 0 0 0 0 0 23 23 23 ‐23 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $454.92 Bank Start no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess 0 0 0 0 0 0 0 0 0 0 0 0 0 ank Chang Bank End 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $864.32 Grid Charge $11.59 $11.59 $11.59 $11.59 $11.59 $11.59 $11.59 $11.59 $11.59 $11.59 $11.59 $11.59 $139.08 10 ‐ ELPCDE‐2.84 analysis.xlsx Outflow kWh 102 297 389 460 480 387 450 420 363 292 160 92 Outflow Cred ‐$3.55 ‐$10.40 ‐$13.61 ‐$16.10 ‐$16.81 ‐$13.53 ‐$15.74 ‐$14.70 ‐$12.72 ‐$10.21 ‐$5.58 ‐$3.21 ‐$136.16 Total Bill $74.37 $71.76 $73.71 $72.41 $66.77 $77.51 $73.83 $83.62 $86.50 $79.23 $109.52 $134.17 $1,003.40 no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess Bank Startank Chang 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Bank End 0 0 0 0 0 0 0 0 0 0 0 0 $0.13 $0.00 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-22; Source: ELPCDE-2.84 w attachment Page 5 of 7 Customer 1 Inputs Month 1 2 3 4 5 6 7 8 9 10 11 12 D1 ‐ no net meter Month 1 2 3 4 5 6 7 8 9 10 11 12 Gen 38.01 150.5 401.4 675.7 750.1 730.8 762.7 687.4 486.2 251.6 137.4 134.7 Days 31 28 31 30 31 30 31 31 30 31 30 31 In 339.165 345.449 365.403 335.652 347.502 303.246 310.506 347.136 344.369 397.399 571.55 490.716 D1 Rate First Block Second Block PSCR Out In + Gen ‐ Out 15.007 362 92.793 403 304.503 462 515.642 496 581.889 516 530.504 504 555.758 517 513.97 521 329.455 501 124.075 525 56.103 653 59.75 566 6025 Total Use First Block kWh 362 362 403 403 462 462 496 496 516 516 504 504 517 517 521 521 501 501 525 525 653 510 566 527 First Block $29.10 $32.40 $37.14 $39.83 $41.44 $40.46 $41.58 $41.82 $40.27 $42.18 $40.98 $42.34 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 143 13.71 39 3.71 PSCR Bill ‐0.32 ‐0.35 ‐0.4 ‐0.43 ‐0.45 ‐0.44 ‐0.45 ‐0.45 ‐0.44 ‐0.46 ‐0.57 ‐0.49 ANNUAL D1 ‐ Category 1 Net Metering Month Days Net Inflow First Block kWh 1 31 324 324 2 28 253 253 3 31 61 61 4 30 0 0 5 31 0 0 6 30 0 0 7 31 0 0 8 31 0 0 9 30 15 15 10 31 273 273 11 30 515 510 12 31 431 431 $0.08035 $0.09599 ‐$0.000870 Service Charge Distribution Rate  Nuclear EO LIEAF $7.50 $0.05529 0.000728 $0.003396 $0.93 Total Fix Total Dist Surchag $8.43 $0.00412 PS Total $28.78 $32.05 $36.74 $39.40 $40.99 $40.02 $41.13 $41.37 $39.83 $41.72 $54.12 $45.56 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Outflow Credit Distribution Bill $20.02 $22.29 $25.56 $27.41 $28.51 $27.84 $28.61 $28.78 $27.71 $29.02 $36.10 $31.27 $481.71 First Block $26.05 $20.30 $4.89 $0.00 $0.00 $0.00 $0.00 $0.00 $1.20 $21.96 $40.98 $34.63 Excess Gen Cred ‐$1.20 ‐$21.96 ‐$40.98 ‐$20.09 Second Block kWh Second Block Bill Excess Gen Cred 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5 0.52 0 0 Dist subtotal $29.94 $32.38 $35.90 $37.88 $39.07 $38.35 $39.17 $39.36 $38.21 $39.61 $47.22 $42.03 $459.12 PSCR Bill ‐0.28 ‐0.22 ‐0.05 0 0 0 0 0 ‐0.01 ‐0.24 ‐0.45 ‐0.37 Excess Gen Credit 0.01 0.24 0.45 $0.22 ANNUAL D1 ‐ Inflow/outflow method at LMP Outflow Credit Month Days Total Inflow First Block kWh 1 31 339 339 2 28 345 345 3 31 365 365 4 30 336 336 5 31 348 348 6 30 303 303 7 31 311 311 8 31 347 347 9 30 344 344 10 31 397 397 11 30 572 510 12 31 491 491 Dist Surch Bill $1.49 $1.66 $1.91 $2.04 $2.13 $2.08 $2.13 $2.15 $2.07 $2.16 $2.69 $2.33 ($0.035) PS Total $25.77 $20.08 $4.84 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.52 $14.39 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Annual Summary No gen Cat 1 NM In/Out  ‐ LMP Outflow Total Bill $941 $220 $598 Bank Value Remaining N/A $0 $0 Total Bill $58.72 $64.43 $72.64 $77.28 $80.06 $78.37 $80.30 $80.73 $78.04 $81.33 $101.34 $87.59 $940.83 Distribution Bill $17.92 $13.97 $3.37 $0.00 $0.00 $0.00 $0.00 $0.00 $0.82 $15.11 $28.50 $23.83 Excess Gen Cred ‐$0.82 ‐$15.11 ‐$28.50 ‐$13.82 Dist Surch Bill $1.34 $1.04 $0.25 $0.00 $0.00 $0.00 $0.00 $0.00 $0.06 $1.13 $2.13 $1.78 Dist subtotal $27.69 $23.44 $12.05 $8.43 $8.43 $8.43 $8.43 $8.43 $8.49 $9.56 $10.56 $20.22 $65.60 First Block $27.25 $27.76 $29.36 $26.97 $27.92 $24.37 $24.95 $27.89 $27.67 $31.93 $40.98 $39.43 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 62 5.91 0 0 PSCR Bill ‐0.3 ‐0.3 ‐0.32 ‐0.29 ‐0.3 ‐0.26 ‐0.27 ‐0.3 ‐0.3 ‐0.35 ‐0.5 ‐0.43 ANNUAL D1 ‐ Inflow/outflow method, grid charge, and LMP outflow Month Days Total Inflow First Block kWh First Block 1 31 339 339 $27.25 2 28 345 345 $27.76 3 31 365 365 $29.36 4 30 336 336 $26.97 5 31 348 348 $27.92 6 30 303 303 $24.37 7 31 311 311 $24.95 8 31 347 347 $27.89 9 30 344 344 $27.67 10 31 397 397 $31.93 11 30 572 510 $40.98 12 31 491 491 $39.43 PS Total $26.95 $27.46 $29.04 $26.68 $27.62 $24.11 $24.68 $27.59 $27.37 $31.58 $46.39 $39.00 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $18.75 $19.10 $20.20 $18.56 $19.21 $16.77 $17.17 $19.19 $19.04 $21.97 $31.60 $27.13 Dist Surch Bill $1.40 $1.42 $1.51 $1.38 $1.43 $1.25 $1.28 $1.43 $1.42 $1.64 $2.36 $2.02 $358.47 Second Block kWh Second Block Bill 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 62 5.91 0 0 PSCR Bill ‐0.3 ‐0.3 ‐0.32 ‐0.29 ‐0.3 ‐0.26 ‐0.27 ‐0.3 ‐0.3 ‐0.35 ‐0.5 ‐0.43 PS Total $26.95 $27.46 $29.04 $26.68 $27.62 $24.11 $24.68 $27.59 $27.37 $31.58 $46.39 $39.00 $358.47 Dist subtotal $28.58 $28.95 $30.14 $28.37 $29.07 $26.45 $26.88 $29.05 $28.89 $32.04 $42.39 $37.58 Outflow kWh 15 93 305 516 582 531 556 514 329 124 56 60 Distribution Bill $18.75 $19.10 $20.20 $18.56 $19.21 $16.77 $17.17 $19.19 $19.04 $21.97 $31.60 $27.13 Dist Surch Bill $1.40 $1.42 $1.51 $1.38 $1.43 $1.25 $1.28 $1.43 $1.42 $1.64 $2.36 $2.02 Dist subtotal $28.58 $28.95 $30.14 $28.37 $29.07 $26.45 $26.88 $29.05 $28.89 $32.04 $42.39 $37.58 $368.39 Total Bill $55.00 $53.16 $48.52 $37.00 $36.32 $31.99 $32.11 $38.65 $44.73 $59.28 $86.82 $74.49 Bank Start Bank Change Bank End 0 0 0 0 0 0 0 0 0 0 180 179.99 180 234 414 414 227 642 642 245 887 887 167 1054 1054 ‐15 1039 1039 ‐273 765 765 ‐515 250 ‐250 0 250 $219.76 $154.16 LMP Outflow Cred ‐$0.53 ‐$3.25 ‐$10.66 ‐$18.05 ‐$20.37 ‐$18.57 ‐$19.45 ‐$17.99 ‐$11.53 ‐$4.34 ‐$1.96 ‐$2.09 $368.39 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Total Bill $53.46 $43.52 $16.89 $8.43 $8.43 $8.43 $8.43 $8.43 $8.49 $9.56 $11.08 $34.61 Bank Start no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess 0 0 0 0 0 0 0 0 0 0 0 0 0 ank Chang Bank End 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 $598.08 Grid Charge $12.20 $12.20 $12.20 $12.20 $12.20 $12.20 $12.20 $12.20 $12.20 $12.20 $12.20 $12.20 $146.41 10 ‐ ELPCDE‐2.84 analysis.xlsx Outflow kWh 15 93 305 516 582 531 556 514 329 124 56 60 Outflow Cred ‐$0.53 ‐$3.25 ‐$10.66 ‐$18.05 ‐$20.37 ‐$18.57 ‐$19.45 ‐$17.99 ‐$11.53 ‐$4.34 ‐$1.96 ‐$2.09 ‐$128.78 Total Bill $67.21 $65.36 $60.72 $49.20 $48.52 $44.19 $44.31 $50.85 $56.93 $71.48 $99.02 $86.69 $744.48 no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess Bank Startank Chang 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Bank End 0 0 0 0 0 0 0 0 0 0 0 0 $0.13 $0.00 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-22; Source: ELPCDE-2.84 w attachment Page 6 of 7 Customer 1 Inputs Month 1 2 3 4 5 6 7 8 9 10 11 12 D1 ‐ no net meter Month 1 2 3 4 5 6 7 8 9 10 11 12 D1 Rate Gen 79.41 103.66 916.79 1822.45 2045.13 2058.83 2127.52 1595.28 1590.01 1008.71 529.43 476.29 Days 31 28 31 30 31 30 31 31 30 31 30 31 In 1015.05 1373.16 1121.34 829.72 513.38 737.04 761.89 641.38 840.37 968.02 1080.81 1384.31 Out 30.16 38.14 776.75 1395.71 1727.77 1513.34 1600.13 1386.30 1188.64 724.37 325.16 208.90 Total Use First Block kWh 1064 527 1439 476 1261 527 1256 510 831 527 1283 510 1289 527 850 527 1242 510 1252 527 1285 510 1652 527 In + Gen ‐ Out 1064 1439 1261 1256 831 1283 1289 850 1242 1252 1285 1652 14705 First Block $42.34 $38.25 $42.34 $40.98 $42.34 $40.98 $42.34 $42.34 $40.98 $42.34 $40.98 $42.34 First Block Second Block PSCR Second Block kWh Second Block Bill 537 51.58 963 92.41 734 70.49 746 71.65 304 29.16 773 74.15 762 73.17 323 31.04 732 70.24 725 69.63 775 74.4 1125 107.96 PSCR Bill ‐0.93 ‐1.25 ‐1.1 ‐1.09 ‐0.72 ‐1.12 ‐1.12 ‐0.74 ‐1.08 ‐1.09 ‐1.12 ‐1.44 ANNUAL D1 ‐ Category 1 Net Metering Month Days 1 31 2 28 3 31 4 30 5 31 6 30 7 31 8 31 9 30 10 31 11 30 31 12 $0.08035 $0.09599 ‐$0.000870 Service Charge Distribution Rate  Nuclear EO LIEAF $7.50 $0.05529 0.000728 $0.003396 $0.93 Total Fix Total Dist Surchag $8.43 $0.00412 PS Total $92.99 $129.41 $111.73 $111.54 $70.78 $114.01 $114.39 $72.64 $110.14 $110.88 $114.26 $148.86 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Outflow Credit Distribution Bill $58.85 $79.54 $69.74 $69.47 $45.93 $70.91 $71.28 $47.02 $68.66 $69.24 $71.05 $91.32 Dist Surch Bill $4.39 $5.93 $5.20 $5.18 $3.43 $5.29 $5.32 $3.51 $5.12 $5.16 $5.30 $6.81 $1,301.63 Net Inflow First Block kWh 985 527 1335 476 345 345 0 0 0 0 0 0 0 0 0 0 0 0 244 244 756 510 1175 527 First Block $42.34 $38.25 $27.69 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $19.58 $40.98 $42.34 Excess Gen Cred ‐$19.58 ‐$40.98 ‐$42.34 Second Block kWh Second Block Bill Excess Gen Cred 458 43.95 859 82.46 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 246 23.58 648 62.24 PSCR Bill ‐0.86 ‐1.16 ‐0.3 0 0 0 0 0 0 ‐0.21 ‐0.66 ‐1.02 Excess Gen Credit 0.21 0.66 1.02 PS Total $85.43 $119.55 $27.39 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $23.58 $62.24 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Annual Summary No gen Cat 1 NM In/Out  ‐ LMP Outflow Total Bill Bank Value Remaining $2,276 N/A $587 $311.78 $1,363 0.00 Total Bill $164.66 $223.31 $195.10 $194.62 $128.57 $198.64 $199.42 $131.60 $192.35 $193.71 $199.04 $255.42 $2,276.44 Distribution Bill $54.45 $73.81 $19.05 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $13.47 $41.78 $64.99 Excess Gen Cred ‐$13.47 ‐$41.78 ‐$64.99 Dist Surch Bill $4.06 $5.51 $1.42 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $1.00 $3.12 $4.85 Dist subtotal $66.94 $87.75 $28.90 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $9.43 $11.55 $13.28 $318.19 First Block $42.34 $38.25 $42.34 $40.98 $41.25 $40.98 $42.34 $42.34 $40.98 $42.34 $40.98 $42.34 Second Block kWh Second Block Bill 488 46.85 897 86.12 594 57.05 320 30.69 0 0 227 21.79 235 22.55 114 10.98 330 31.71 441 42.33 571 54.79 857 82.29 PSCR Bill ‐0.88 ‐1.19 ‐0.98 ‐0.72 ‐0.45 ‐0.64 ‐0.66 ‐0.56 ‐0.73 ‐0.84 ‐0.94 ‐1.2 ANNUAL D1 ‐ Inflow/outflow method, grid charge, and LMP outflow Month Days Total Inflow First Block kWh 1 31 1015 527 2 28 1373 476 3 31 1121 527 4 30 830 510 5 31 513 513 6 30 737 510 7 31 762 527 8 31 641 527 9 30 840 510 10 31 968 527 11 30 1081 510 12 31 1384 527 Dist subtotal $71.67 $93.90 $83.37 $83.08 $57.79 $84.63 $85.03 $58.96 $82.21 $82.83 $84.78 $106.56 $974.81 ANNUAL D1 ‐ Inflow/outflow method at LMP Outflow Credit Days Total Inflow First Block kWh Month 1 31 1015 527 2 28 1373 476 3 31 1121 527 4 30 830 510 5 31 513 513 6 30 737 510 7 31 762 527 8 31 641 527 9 30 840 510 10 31 968 527 11 30 1081 510 12 31 1384 527 ($0.035) PS Total $88.31 $123.18 $98.41 $70.95 $40.80 $62.13 $64.23 $52.76 $71.96 $83.83 $94.83 $123.43 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $56.12 $75.92 $62.00 $45.88 $28.38 $40.75 $42.12 $35.46 $46.46 $53.52 $59.76 $76.54 Dist Surch Bill $4.19 $5.66 $4.62 $3.42 $2.12 $3.04 $3.14 $2.65 $3.47 $3.99 $4.46 $5.71 $974.82 First Block $42.34 $38.25 $42.34 $40.98 $41.25 $40.98 $42.34 $42.34 $40.98 $42.34 $40.98 $42.34 Second Block kWh Second Block Bill 488 46.85 897 86.12 594 57.05 320 30.69 0 0 227 21.79 235 22.55 114 10.98 330 31.71 441 42.33 571 54.79 857 82.29 PSCR Bill ‐0.88 ‐1.19 ‐0.98 ‐0.72 ‐0.45 ‐0.64 ‐0.66 ‐0.56 ‐0.73 ‐0.84 ‐0.94 ‐1.2 PS Total $88.31 $123.18 $98.41 $70.95 $40.80 $62.13 $64.23 $52.76 $71.96 $83.83 $94.83 $123.43 $974.82 $268.43 Dist subtotal $68.74 $90.01 $75.05 $57.73 $38.93 $52.22 $53.69 $46.54 $58.36 $65.94 $72.65 $90.68 Outflow kWh 30 38 777 1396 1728 1513 1600 1386 1189 724 325 209 LMP Outflow Cred ‐$1.06 ‐$1.33 ‐$27.19 ‐$48.85 ‐$60.47 ‐$52.97 ‐$56.00 ‐$48.52 ‐$41.60 ‐$25.35 ‐$11.38 ‐$7.31 $770.54 Fixed Charges $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 Distribution Bill $56.12 $75.92 $62.00 $45.88 $28.38 $40.75 $42.12 $35.46 $46.46 $53.52 $59.76 $76.54 Dist Surch Bill $4.19 $5.66 $4.62 $3.42 $2.12 $3.04 $3.14 $2.65 $3.47 $3.99 $4.46 $5.71 Total Bill $152.37 $207.30 $56.29 $8.43 $8.43 $8.43 $8.43 $8.43 $8.43 $9.43 $35.13 $75.52 Dist subtotal $68.74 $90.01 $75.05 $57.73 $38.93 $52.22 $53.69 $46.54 $58.36 $65.94 $72.65 $90.68 $770.54 Total Bill $155.99 $211.86 $146.27 $79.83 $19.26 $61.38 $61.92 $50.78 $88.72 $124.42 $156.10 $206.80 Bank Start Bank Change Bank End 0 0 0 0 0 0 0 0 0 0 566 566 566 1214 1780 1780 776 2557 2557 838 3395 3395 745 4140 4140 348 4488 4488 ‐244 4244 3489 4244 ‐756 3489 ‐1175 2313 $586.62 Bank Start no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2313 ank Chang Bank End 0 0.00 0 0.00 0 0.00 $0.00 0.00 $0.00 0.00 $0.00 0.00 $0.00 0.00 $0.00 0.00 $0.00 0.00 $0.00 0.00 $0.00 0.00 0.00 0.00 $1,363.32 653.82 Grid Charge $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 $20.50 $245.96 10 ‐ ELPCDE‐2.84 analysis.xlsx Outflow kWh 30 38 777 1396 1728 1513 1600 1386 1189 724 325 209 Outflow Cred ‐$1.06 ‐$1.33 ‐$27.19 ‐$48.85 ‐$60.47 ‐$52.97 ‐$56.00 ‐$48.52 ‐$41.60 ‐$25.35 ‐$11.38 ‐$7.31 ‐$382.04 Total Bill $176.49 $232.35 $166.77 $100.33 $39.75 $81.88 $82.41 $71.28 $109.21 $144.91 $176.60 $227.30 $1,609.28 no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess no excess Bank Startank Chang 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Bank End 0 0 0 0 0 0 0 0 0 0 0 0 $0.13 $311.78 U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-22; Source: ELPCDE-2.84 w attachment Page 7 of 7 DTEE Ranking using Annual Bill Yearly on‐site usage (kWh) Generator Size in kW  Cust 1 7,803 4.2 Cust 2 5,316 1.0 Cust 3 9,334 4.8 Cust 4 6,025 5.0 Cust 5 14,705 8.4 $941 $598 $744 $220 $2,276 $1,363 $1,609 $587 AVG 8,637 4.7 Incr. over NM No DG In/Out ‐ LMP Outflow @ 3.5 cents In/Out, grid charge, and LMP 3.5 Cat 1 ‐ Current Net Metering Program $1,212 $862 $985 $500 $841 $717 $746 $681 $1,447 $864 $1,003 $455 10 ‐ ELPCDE‐2.84 analysis.xlsx $1,343 $881 $1,018 $488 80% 108% 0% U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-23; Source: ELPC-1.24a-g Page 1 of 7 MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.24a Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where witness Serna states: “[D]istributed generation customers receive a range of additional grid services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).” a. Provide all documentation produced or reviewed by the Company which supports the assertion that DG customers “make more intensive demands of the infrastructure.” Answer: The Company has not developed or reviewed documentation of the impacts of distributed generation customers on the Company’s system. However, the topic of how distributed generation customers leverage the electric system is an important topic of research by the Electric Power Research Institute (EPRI) – an independent, non-profit research organization. The report titled “The Integrated Grid” provides information on the way distributed generation customers interact with the grid and the type of services provided by the grid to support these customers. Please see attachment “ELPCDE-1.24a The Integrated Grid.” U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-23; Source: ELPC-1.24a-g Page 2 of 7 MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.24b Respondent: C. Serna/Legal Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where witness Serna states: “[D]istributed generation customers receive a range of additional grid services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).” b. Please confirm or deny. The Company takes title to the outflow from DG customers when the power passes the DG customer’s meter and enters the utility-owned distribution system. [If the Company denies this assertion, please explain the reason for the denial.] Answer: DTE Electric objects to the request for the reason that the request is vague and incapable of answer in its current form, as the meaning of the term “takes title” is unclear. Subject to this objection, and without waiving this objection, DTE Electric would answer as follows: The Company confirms that outflow power from distributed generation customers ‘enters the utility-owned distribution system. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-23; Source: ELPC-1.24a-g Page 3 of 7 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 ELPC ELPCDE-1.24c C. Serna / R. Mueller 1 of 1 Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where witness Serna states: “[D]istributed generation customers receive a range of additional grid services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).” c. Please confirm or deny. The Company delivers the outflow from a DG customer to other customers on the Company’s system. [If the Company denies this assertion, please explain the reason for the denial.] Answer: The Company confirms that “the outflow power that enters the utility-owned distribution system” becomes part of the overall power flowing in the system. Power in the system can be, in general, ultimately delivered to individual customers at wholesale for resale as well as for end use consumption. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-23; Source: ELPC-1.24a-g Page 4 of 7 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 ELPC ELPCDE-1.24d C. Serna 1 of 1 Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where witness Serna states: “[D]istributed generation customers receive a range of additional grid services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).” d. Please confirm or deny. The customer who ultimately consumes the excess DG generation (“outflow”) exported to the Company’s system will pay the Company for the delivery of that power to their premises. [If the Company denies this assertion, please explain the reason for the denial.] Answer: The Company confirms that non-DG customers pay a delivery charge for the power delivered to their premises. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-23; Source: ELPC-1.24a-g Page 5 of 7 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 ELPC ELPCDE-1.24e T. W. Lacey 1 of 1 Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where witness Serna states: “[D]istributed generation customers receive a range of additional grid services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).” e. Provide all analyses produced by (or for) the Company that calculate the cost to serve net metering customers both independently and compared to traditional customers, including all cost of service studies specific to net metering customers. Answer: Please see the Company’s response to ELPCDE-1.23. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-23; Source: ELPC-1.24a-g Page 6 of 7 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 ELPC ELPCDE-1.24f C. Serna / R. Mueller 1 of 1 Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where witness Serna states: “[D]istributed generation customers receive a range of additional grid services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).” f. Please provide all analyses produced by (or for) the Company that demonstrates that outflow energy from current net metering customers is ever exported beyond the distribution substation level of the distribution system. Answer: The Company has not performed such analyses. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-23; Source: ELPC-1.24a-g Page 7 of 7 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 ELPC ELPCDE-1.24g C. Serna / R. Mueller 1 of 1 Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where witness Serna states: “[D]istributed generation customers receive a range of additional grid services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).” g. Please explain if the Company has studies or calculated the benefits provided by distributed generation customers to the distribution system. If it has, please provide that study or calculations. Answer: The Company has not performed such study or calculation. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-24; Source: MECNRDCSCDE-1.17d Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSCDE MECNRDCSCDE-1.17d P. W. Dennis 1 of 1 Please reference Dennis Direct at 20:15-21:13 and Exhibit A-16, Schedule F9. d. Please confirm that you designed the proposed SAC to recover the amount of distribution revenue that DG customers would have paid through kWh charges if they had not reduced purchases of grid-supplied electricity by self-generating. Answer: For individual customers this may not be true, however, on an overall basis, I confirm. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-25; Source: MECNRDCSCDE-3.4a Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSC MECNRDCSCDE-3.4a P. W. Dennis 1 of 1 Please reference DTE Response to MEC DR 1.7(a), 1.10(a) and 1.17(f). a) Please confirm that on an overall sub-class basis (i.e., all customers subject to the System Access Contribution), the System Access Contribution and inflow charges will recover the same level of distribution revenue from those customers than if those customers supplied none of their electricity consumption through behind the meter generation. Answer: As stated in the responses to MECNRDCSCDE1.17(d) and (f), on an overall basis (using 2017 data as a proxy for future loads), the System Access Contribution charge when combined with the inflow charge, is designed to recover the distribution revenue if no electricity was consumed with behind the meter generation, however, impacts on customers would vary. Attachments: n/a U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-26; Source: MECNRDCSCDE-3.9 Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: U-20162 MECNRDCSC MECNRDCSCDE-3.9 P. W. Dennis 1 of 1 Question: Please reference Serna Direct at CS-59:24-25. Please provide any connection and/or correlation between an individual distributed generation customer’s nameplate system capacity and his or her contribution to the peak loads, energy, and customer counts used in the unbundled cost of service study you conducted for this case. Answer: The Company did not undertake a review or study any connection and/or correlation between an individual distributed generation customer’s nameplate system capacity and his or her contribution to the peak loads, energy, and customer counts. Attachments: n/a U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-27; Source: MECNRDCSCDE-1.10a Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: U-20162 MECNRDCSCDE MECNRDCSCDE-1.10a C. Serna/K.O. Farrell/T. W. Lacey Page: 1 of 1 Question: Please reference Serna Direct at 61:1-18. a. Please confirm that DG customers have lower average contribution to class demands during the class NCP hours used to allocate distribution system capacity costs than non-DG customers in the same class. Answer: Confirmed. However, class NCP hours is only one of the components of allocating distribution costs. A list of all distribution allocators is included on Workpaper WPA16F1 Support Schedule 2. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-28; Source: MECNRDCSCDE-1.2 Revised Page 1 of 3 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSCDE MECNRDCSCDE-1.2a Revised_ C. Serna / R. J. Mueller 1 of 1 Please reference Serna Direct at 53:9-20. a. Please identify each instance when a residential or secondary commercial customer with distributed generation (“DG”) experienced an inverter tripping offline that caused DTE Electric Company (“DTE”) protective equipment to trip the circuit offline. Answer: The Company does not have a record that this has occurred due to a residential or secondary commercial customer with distributed generation (“DG”) on the Company’s system to date. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-28; Source: MECNRDCSCDE-1.2 Revised Page 2 of 3 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSCDE MECNRDCSCDE-1.2b Revised C. Serna / R. J. Mueller 1 of 1 Please reference Serna Direct at 53:9-20. b. Please identify each instance when a residential or secondary commercial customer with DG experienced rapid cloud cover change that caused DTE protective equipment to trip the circuit offline. Answer: The Company does not have a record that this has occurred due to a residential or secondary commercial customer with DG on the Company’s system to date. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-28; Source: MECNRDCSCDE-1.2 Revised Page 3 of 3 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSCDE MECNRDCSCDE-1.2c Revised C. Serna / R. J. Mueller 1 of 1 Please reference Serna Direct at 53:9-20. c. Please identify each instance when a residential or secondary commercial customer with DG caused reverse power flow that required equipment to be reconfigured or replaced, the cost of that reconfiguration or replacement, and whether the DG customer was charged for such reconfiguration or replacement through the applicable interconnection process. Answer: The Company does not have any specific records of upgrades due to DGdriven reverse power flow for residential or secondary commercial customers with DG. There have been instances of regulator, relay and recloser settings changes, service line upgrades and transformer replacement to support interconnection. However, the Company notes that current cost of service regulations do not support the individual assignment of the costs for secondary circuit level upgrades. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-29; Source: MECNRDCSCDE-1.11 Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: U-20162 MECNRDCSCDE MECNRDCSCDE-1.11 T. W. Lacey 1 of 1 Question: Please reference Serna Direct at 61:19-62:2. Have you quantified the cost of providing inrush current as an unbundled service? If so, please provide the cost and produce all data, calculations, and workpapers used to quantify the cost. Answer: I have not been asked to perform, nor am I aware of any studies quantifying the cost of providing inrush current as an unbundled service. U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-30; Source: MECNRDCSCDE-3.6a Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSC MECNRDCSCDE-3.6a C. Serna/K. O. Farrell 1 of 1 Please reference Serna Direct at CS-54:20-22. a) State whether you contend that installing distributed generation reduces a customer’s contribution to 4CP, 12CP, and NCP class loads by a smaller amount than the distributed generation reduces kWh inflows? If so, identify the percentage reduction in distributed generation customer’s contribution 4CP, 12CP, and NCP class loads and the percentage reduction in kWh inflows. Answer: The Company does not “contend that installing distributed generation reduces a customer’s contribution to 4CP, 12CP, and NCP class loads by a smaller amount than the distributed generation reduces kWh inflows”. The referenced text describes the current cost recovery paradigm in Michigan and makes no specific claim of 4CP, 12CP, and NCP behaviors. Attachments: n/a U-20162 - November 7, 2018 Direct Testimony of K. Rabago on behalf of MEC-NRDC-SC Exhibit: MEC-31; Source: MECNRDCSCDE-3.16 Page 1 of 1 MPSC Case No.: Requestor: Question No.: Respondent: Page: Question: U-20162 MECNRDCSC MECNRDCSCDE-3.16b T. M. Uzenski 1 of 1 Please reference DTE Response to MEC 1.24(c) and (g). b) How does DTE determine the portion of dues paid to EEI “below the line in account, 426.4, Political and Civil Activities” that are not charged to ratepayers? Answer: Edison Electric Institute (EEI) identifies the portion of dues that relate to influencing legislation on the invoice. STATE OF MICHIGAN MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the Application of DTE ELECTRIC COMPANY for authority to increase its rates, amend its rate schedules and rules governing the distribution and supply of electric energy, and for miscellaneous accounting authority. Case No. U-20162 ALJ Sally L. Wallace PROOF OF SERVICE On the date below, an electronic copy of Direct Testimony of Karl R. Rábago on behalf of MEC-NRDC-SC, EIBC, and IEI and Exhibits MEC-13 through MEC-31 with MEC-21 being Reserved were served on the following: Name/Party Administrative Law Judge Sally L. Wallace E-mail Address Wallaces2@michigan.gov mpscfilings@dteenergy.com andrea.hayden@dteenergy.com jon.christinidis@dteenergy.com lauren.donofrio@dteenergy.com megan.irving@dteenergy.com Counsel for DTE Electric Co. Andrea E. Hayden Jon P. Christinidis Lauren D. Donofrio Megan E. Irving Counsel for Attorney General Joel King Sebastian Coppola Counsel for MPSC Staff Daniel E. Sonneveldt Amit T. Singh Spencer A. Sattler Counsel for ABATE Bryan A. Brandenburg Robert A. W. Strong Michael J. Pattwell Sean P. Gallagher James R. Dauphinais Brian Andrews Counsel for Michigan Cable Telecommunications Association Michael S. Ashton Anita G. Fox Counsel for Energy Michigan, Inc. Laura A. Chappelle Timothy J. Lundgren Counsel for Kroger Co. Kurt J. Boehm Ag-enra-spec-lit@michigan.gov KingJ38@michigan.gov sebcoppola@corplytics.com sonneveldtd@michigan.gov singha9@michigan.gov sattlers@michigan.gov bbrandenburg@clarkhill.com rstrong@clarkhill.com mpattwell@clarkhill.com sgallagher@clarkhill.com jdauphinais@consultbai.com bandrews@consultbai.com mashton@fraserlawfirm.com afox@fraserlawfirm.com lachappelle@varnumlaw.com tjlundgren@varnumlaw.com kboehm@BKLlawfirm.com 1 Jody Kyler Cohn Kevin Higgins Counsel for Walmart Inc. Melissa M. Horne Counsel for Great Lakes Renewable Energy Association and Residential Customer Group Don L. Keskey Brian W. Coyer Counsel for Environmental Law & Policy Center Margrethe Kearney Jean-Luc Kreitner Counsel for Utility Workers Union of America Local 223 Benjamin L. King John R. Canzano Counsel for ChargePoint Timothy Lundgren Justin Ooms Michigan Energy Innovation Business Council and the Institute for Energy Innovation Laura A. Chappelle Toni N. Newell Counsel for Soulardarity Mark N. Templeton Robert A. Weinstock Counsel for Soulardarity Lydia Barbash-Riley Breanna Thomas Kimberly Flynn Mark Templeton Robert Weinstock Rebecca Boyd JKylerCohn@BKLlawfirm.com khiggins@energystrat.com mhorne@hcc-law.com donkeskey@publiclawresourcecenter.com bwcoyer@publiclawresourcecenter.com mkearney@elpc.org jkreitner@elpc.org bking@michworkerlaw.com jcanzano@michworkerlaw.com tjlundgren@varnumlaw.com jkooms@varnumlaw.com lachappelle@varnumlaw.com tlnewell@varnumlaw.com templeton@uchicago.edu rweinstock@uchicago.edu lydia@envlaw.com breanna@envlaw.com kimberly@envlaw.com templeton@uchicago.edu rweinstock@uchicago.edu rebecca.j.boyd@gmail.com The statements above are true to the best of my knowledge, information and belief. OLSON, BZDOK & HOWARD, P.C. Counsel for MEC-NRDC-SC Date: Digitally signed by Kimberly Flynn DN: cn=Kimberly Flynn, o=Olson Bzdok & Howard, P.C., ou, email=kimberly@envlaw.com, c=US Date: 2018.11.07 16:45:56 -05'00' November 7, 2018 By: ________________________________________ Karla Gerds, Legal Assistant Kimberly Flynn, Legal Assistant Breanna Thomas, Legal Assistant Email: karla@envlaw.com kimberly@envlaw.com and breanna@envlaw.com 2