STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

Transcription

1 STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of DTE ELECTRIC COMPANY Case No. U for authority to increase its rates, amend (e-file paperless) its rate schedules and rules governing the distribution and supply of electric energy, for miscellaneous accounting authority / MICHIGAN PUBLIC SERVICE COMMISSION STAFF S REPLY BRIEF MICHIGAN PUBLIC SERVICE COMMISSION STAFF Amit T. Singh (P75492) Spencer A. Sattler (P70524) Daniel E. Sonneveldt (P58222) Assistant Attorneys General Public Service Division 7109 W. Saginaw Hwy., 3rd Floor Lansing, MI Telephone: (517) DATED: February 1, 2019

2 Table of Contents Page No. I. Introduction... 1 II. Revenue deficiency... 1 III. Capital Structure and Return on Equity... 3 a. DTE Electric s ECAPM analysis... 3 b. Summary of Staff s ROE Recommendation... 4 IV. Net Operating Income... 5 a. Tree trimming O&M expense... 5 i. The Company is proposing a second alternative if the Commission does not approve the Company s Tree Trimming Surge or revises the net present value of the surge, thereby leaving DTE unable to obtain all the resources for the surge V. Distributed Generation Tariff... 7 a. Response to MEC... 7 VI. Cost of Service and Rate Design a. MEC/NRDC/SCs (MEC) arguments are misleading and fail to reach actionable proposals b. The Commission should not approve DTE Electric s proposed DG Rider 18 language providing for forfeiture of outflow credits but should approve one element of DTE Electric s revised position provided in its initial brief c. The Commission should clarify that an existing net metering customer who expands their project prior to the effective date of Public Act 342 may begin a new 10-year period beginning with the date of enrollment of the new project d. DTE Electric is incorrect in using volumetric rates to justify the System Access Contribution (SAC) i

3 e. MEIBC/IEI s accusations of DG rate shock are blatant mischaracterizations f. ELPC s recommendation of a market transition adder should be rejected g. ELPC s recommendation of compensation for full generation should be rejected h. GLREA s recommendation of a SAC credit should be denied i. GLREA s recommendation to remove or eliminate the DG caps should be denied j. GLREA s assertions regarding Power Supply Cost Recovery (PSCR) double counting are confusing, vague, lacking in evidentiary support and should be rejected k. GLREA s suggestion that delivery costs should be included in outflow should be rejected l. GLREA s concerns about appropriate solar and storage price signals are unfounded m. GLREA s recommendation of phase-in period for Rider 18 should be rejected n. Soulardarity s recommendation of compensating DG for externalities should be rejected o. MEIBC/IEI s and the ELPC s arguments in favor of caps on EV demand charges should be rejected p. The MEIBC/IEI and the ELPC s arguments in support of limiting a DCFC charge to the price of gasoline should be rejected q. The ALJ and Commission should exercise caution in considering the ELPC s recommendation of pass through of TOU rates to level 2 stations r. MEIBC/IEI s recommendation of a workplace charging tariff should be rejected s. Residential and Commercial Secondary Customer Charges ii

4 i. The Company s Assertion that distribution system design cost is caused by the number of customers is unsupported and should be rejected ii. The Company s statement that demand-related costs are fixed costs is false iii. Residential Income Assistance t. The Company s proposed energy and demand voltage level discounts are not appropriate u. RCG s assertions and conclusions related to summer on-peak rates are inaccurate and should be rejected v. The MEC/NRDC/SC s argument relating to the legal requirements for cost of service-based rates is inaccurate and should be rejected VII. Conclusion iii

5 I. Introduction In accordance with the schedule established for this case, Staff files the following reply brief. Staff maintains its overarching position that its proposed rate base, return on equity, and operating expenses strike the right balance between investors and ratepayers interests. While Staff reasserts the correctness of each of its positions taken in its initial brief, supported by its testimony and exhibits, Staff selectively responds in this reply brief to arguments made by other parties that require additional emphasis and explanation. Neither the ALJ, nor the Commission, should consider Staff s failure to address any argument made by another party as an agreement with that party s position. II. Revenue deficiency In its initial filing, DTE calculated a revenue deficiency of $ million. Subsequently, DTE adjusted its case, making several adjustments in its Initial Brief, which resulted in a revised revenue deficiency of $ million. Staff continues to support a revenue deficiency of $ million. (Appendix A). Additionally, the U Tax Cuts and Jobs Act Credit A case will cease effective with new approved rates in the instant case, which increase rates an additional $ million. (Appendix A). Therefore, the total rate impact of the Staff s proposed rate increase is a $ million ($ million base rates plus $ million Credit ceasing). Staff s proposed revenue deficiency is $ million less than the Company s as detailed in Appendix F. Staff has prepared Appendices A through E which calculate the Staff revenue deficiency. Appendix F 1

6 reconciles the revenue deficiency in the Company s initial filing to the Company s initial brief position, and the Company s initial brief position to the Staff s reply brief position. In preparing the reconciliation, Staff found several discrepancies in the Company s calculations that are identified below: 1. The Company adopted the Staff s deferred federal income tax (DFIT) amortization expense adjustment of $411,000 but did not gross-up the amount for taxes. The Company s amount is shown on Appendix F, line 6, and the difference related to the gross-up is shown on Appendix F, line 16. Additionally, the $411,000 reduction in FIT is shown as an increase in the Company s filing, which can be seen on Staff Appendix C, line 6. To correct for this, Staff made a correcting adjustment, which can be found on Appendix C, line The Company adopted Staff s Headquarters (HQ) Energy Center adjustment, but the related depreciation expense adjustment was omitted in the Company s calculations. On Appendix F, it is included as a correcting adjustment on line 13. Additionally, there is a minor discrepancy between Staff and the Company s amounts for depreciation expense and accumulated depreciation related to this line item. Staff updated the depreciation rate for this line item with the newly approved rate in MPSC Case No. U The Company relied upon the old rate for its calculation. Therefore, where Staff has a depreciation expense adjustment of $240,000, the Company has a depreciation adjustment of $151,000. Staff s accumulated depreciation adjustment is $181,000 versus $114,000 for DTE. Staff supports its adjustments as filed and has included the delta in its depreciation 2

7 expense adjustment and accumulated depreciation adjustment, as detailed on Appendix E, line 2. III. Capital Structure and Return on Equity In its initial brief, the Company reiterated its request for a 51% equity layer in the Company s ratemaking capital structure. (DTE Electric s initial brief, p 47.) Staff agrees with the Company s capital structure. The Company also reiterated its request for a 10.50% ROE, the upper end of its 9.75% % ROE range and recapped its various objections to Staff s 9.80% recommendation. (Id. at 50, 52.) Staff stands behind its 9.80% ROE recommendation and will not reiterate the reasons stated in its initial brief explaining why its recommendation is more reasonable than the Company s proposal. However, Staff will address a specific argument made by the Company in its initial brief below. a. DTE Electric s ECAPM analysis On page 53 of DTE Electric s brief, the Company remarked that empirical research has long shown that the CAPM tends to overstate the actual sensitivity of the cost of capital to beta. Low-beta stocks tend to have higher risk premiums than predicted by the CAPM, and high-beta stocks tend to have lower risk premiums than predicted. The Company concludes that based on this observation the ECAPM is warranted. However, Staff noted its disagreement with the ECAPM approach and points out that the explanation provided by the Company regarding the ECAPM is misleading. The ECAPM purports to show that from an empirical 3

8 observation, low-beta stocks tend to have higher returns than what the CAPM predicts and high-beta stocks have lower returns than predicted. This means that low-beta stocks tend to earn more and thus have higher earned returns than what the CAPM predicts. There is ongoing debate as to why this is occurring; however, this does not mean that low-beta stocks have higher risk premiums as the Company suggests. A higher risk premium implies higher risk and the Company is inferring that since low-beta stocks have a higher risk premium, they are supposedly riskier than high-beta stocks. This is an erroneous and misleading conclusion. Utility companies, such as the ones in Staff s proxy group, are low-beta companies and thus have lower risk than the market in general. The Company s conclusion that lowbeta companies equate to higher risk premiums is a misleading characterization of the empirical data and should be rejected by the Commission. b. Summary of Staff s ROE Recommendation Staff emphasizes that its 9.80% ROE recommendation is not only reasonable, but favorable based on the Company s stable business outlook as reflected in its credit ratings, its equity positive capital structure that Staff agrees with, and solid realized rate of return over the past few years, as well as DTE Electric s request for a substantial risk-mitigating IRM. DTE Electric s solid credit rating from S&P and Moody s suggests that the Company will not have a problem accessing capital markets on a reasonable, if not preferable, basis to finance its future infrastructure and capital investment programs. Thus, the Company s argument that an ROE in line with Staff s 9.80% ROE recommendation and below the Company s 10.50% 4

9 would not be reasonable due to the Company s higher than average risk is meritless. The Commission should reject the arguments DTE Electric offered for a higher ROE and adopt Staff s reasonable 9.80% recommendation. IV. Net Operating Income a. Tree trimming O&M expense i. The Company is proposing a second alternative if the Commission does not approve the Company s Tree Trimming Surge or revises the net present value of the surge, thereby leaving DTE unable to obtain all the resources for the surge. In its Initial Brief, the Company requests that the Commission provide additional O&M funding if the Company s Tree Trimming Surge is not approved. The Company requests $137.5 million for tree trimming for the May 1, 2019 April 30, 2020 test year, which would allow DTE Electric to recover $119.6 million for the 2019 calendar year. The Company believes this would be a reasonable compromise between the Staff s funding proposal and the Company s Surge proposal. (DTE Electric Initial Brief, p. 77.) Staff does not support this proposal, for reasons stated in its Initial Brief. (Staff Initial Brief, p. 76.) Also, in its Initial Brief, the Company is proposing another alternative: Approve regulatory asset treatment for the surge costs in the instant case and clarify that the Commission will address the appropriate amortization period in a future rate case. [DTE Electric Initial Brief, p. 77.] 5

10 Staff disagrees with this proposal as well because it asks for regulatory asset treatment of the surge costs, which Staff opposed in the direct testimony of Nicholas M. Evans (8 TR ) and in its Initial Brief. (Staff Initial Brief, pp ) In its original filing, the Company stated the net present value (NPV) of the tree trim surge to be $46.1 million. The Company then revised the NPV upward to $66.6 million. (Exhibit A-22, Schedule L1 Revised.) In its Initial Brief, Staff stated that the NPV of the surge without regulatory asset treatment was $55.4 million compared to the $46.1 million that was originally provided by the Company. (Staff Initial Brief, p. 72.) Calculating the $55.4 million was done by clearing the contents of a critical line item in the unrevised, originally-filed Exhibit A-22, Schedule L1. (8 TR 4128.) While the Staff has not calculated a new NPV of the surge without regulatory asset treatment using Exhibit A-22, Schedule L1 Revised (which produced the updated $66.6 million NPV), Staff is confident such an NPV would be greater than $66.6 million. This means that ratepayers would still be better off paying the full O&M costs every year instead of deferring them. Finally, the Commission should pay careful attention to what Company witness Heather D. Rivard stated in her rebuttal testimony: [T]he Company is unable to fully predict the tree trim labor market. The proposed Surge spend profile assumes that the Company is going to be able to attract a significant volume of tree trimmers to our service territory in the short term and grow the tree trimmer work force locally in the long term. If the Company is unable to fully ramp up additional tree trimmers due to events outside of its control (for example, recent California wildfires have caused utilities in that state to significantly increase tree trim budgets resulting in 6

11 unprecedented demand for tree trimmers in an already constrained national labor market), it may need to shift some of the Surge spend from the early years to years 4-7. (emphasis added.) [3 TR ] Ms. Rivard said later in cross-examination that the Company believes it is going to be able to secure the necessary resources to complete the surge plan. (3 TR 260.) However, the Commission should consider the possibility that the Company may not be able to secure enough tree trimmers over the next couple years to execute its surge plan as proposed. The Company is proposing to go from recovering $ million annually in tree trimming expense to spending $137.5 million annually, a 64.2% increase. (Staff Initial Brief, p. 76.) Staff s proposal forecasts a more modest and realistic ramp-up of tree trimming work, and the Commission should support it. V. Distributed Generation Tariff a. Response to MEC Staff s proposed Inflow/Outflow tariff properly comports with the applicable statutory provision in MCL 460.6a(14) and with the distributed generation program, MCL The Michigan Environmental Council, National Resources Defense Council, and the Sierra Club s (collectively MEC ) erroneous assertion that Staff s proposed Inflow/Outflow tariff fails to comply with Michigan law is baseless and should be rejected by the ALJ and the Commission. 7

12 MEC errs in asserting that any distributed generation program provided by the Company must include monthly netting. (MEC s initial brief, p 127.) MEC bases this belief on its idea that Michigan statutes require the Company to provide a distributed generation program that offsets monthly inflows with outflows and credits the excess outflows for the month. Id. at 123. In this way, MEC improperly conflates distributed generation with net metering. The MEC is wrong. The MEC presents the following statutory analysis in support of its position: 1. Because MCL 460.6a(14) states that it applies to customers participating in the present tense in net metering programs pursuant to MCL the intent is for net metering programs under MCL to continue to apply to customers taking service under a Section 6(a)(14) tariff; 2. The fact that Section 177(5) states that no charge pursuant to a Section 6a(14) tariff shall be reduced by any credit related to Section 177 means that the Legislature intended to continue the distributed generation program in MCL for new customers even after a tariff under Section 6a(14) applies because it implies that the same customer is subject to both Sections 6a(14) and 177; and 3. Because the statute includes a termination point for the distributed generation program when participation reaches 1%, no other termination point for the distributed generation program under MCL was contemplated, meaning that the establishment of a DG tariff under 460.6a(14) does not implicitly mean that the distributed generation program including net metering was intended to be terminated. 8

13 On the basis of these three points, MEC concludes that the Company must offer a DG tariff for new customers that offsets power inflows with outflows during the monthly billing period and offer true net metering for customers with systems capable of generating 20 kilowatts or less and modified net metering for customers with systems capable of generating more than 20 kilowatts. Staff rejects net metering as an appropriate tariff for achieving an equitable cost of service and maintains that its proposed inflow/outflow tariff is the most reasonable proposal and comports with all applicable statutory provisions. Staff agrees that each of MEC s points is taken from a statutory provision. However, Staff strongly disagrees with MEC s interpretation and resulting conclusion that, taken together, these three points restrict the Commission to approving only a net metering tariff for the Distributed Generation Program established pursuant to MCL (1). Staff counters that MCL 460.6a(14) is permissive and not restrictive. If the Legislature had assurance that a net-metering tariff was the correct approach to realizing an equitable cost of service, it would have plainly stated so. Rather, the statute acknowledges the Commission s expertise in the rate-setting process for utilities. Thus, the statute delegates to the Commission the determination of an appropriate tariff through a year-long study mandated by the statute. It should be noted that MCL 460.6a(14) clearly places responsibility on the Commission for the final determination of what constitutes: an appropriate tariff reflecting equitable cost of service. It does not prejudge or limit the Commission s discretion 9

14 in this matter, else the statute would have logically stated: a net metering tariff reflecting equitable cost of service. The fact that Part 5 of PA 342 was retitled Distributed Generation Program, from the formerly restrictive Net Metering Program strongly supports the interpretation of MCL 460.6a(14) that the form of tariff deemed appropriate by the Commission is not limited to net metering, but inclusive, and not exclusive of alternative billing methods. [emphasis added.] Regarding the idea of net metering as a potential, but not exclusive form of billing customers under the new distributed generation program, the Legislature, at the time it mandated the Commission to undertake a study, could not have known with certainty whether or not such study would be successful in developing a new tariff for customer-sited distributed generation. It is apparent that the Legislature prudently created a fallback-option allowing the Commission to continue net metering on a permanent basis for the new Distributed Generation program - but with an added grid charge to align the tariff with the cost of service. Thus, for example, PA 342 Section 177(4), in delineating the crediting process for the modified net-metering billing method necessarily references a charge set pursuant to PA 341 Section 6a(14). The Commission Staff, in its Report on the MPSC Staff Study to Develop a Cost of Service-Based Distributed Generation Program Tariff (Exhibit MEC-162), did evaluate the option of adding a charge to net metering and rejected it as inferior to the new Inflow/Outflow tariff. This conclusion was reached, in part, due to the fact that the Inflow/Outflow tariff can intrinsically realize an equitable cost-of-service and unlike net metering, which requires an added charge 10

15 to neutralize the inherent subsidy, can do so while providing clear and transparent pricing signals to customers. The Commission acknowledged the superiority of the Inflow/Outflow billing method in its Order in U-18383, by adopting it as the basis for a cost-based Distributed Generation tariff. Additionally, in determining the Legislature s intent, is it constructive to analyze the terms tariff and charge which are core to this matter. The use of the word tariff in the statute is clearly tied to its meaning as used in the economic regulation of public utilities. From a regulatory standpoint, a tariff necessarily encompasses an underlying foundational pricing model (e.g. billing method), and associated rates, charges, terms and conditions of service. The law requires such a tariff to be approved in future Commission proceedings that are initiated by the filing of a general rate request by each regulated electric-utility subsequent to June 1, Staff s proposed Exhibit S-11.0 contains all such components, being a complete tariff. Given the broadly inclusive meaning of the term tariff, the only rational interpretation of subsection 6a(14) is that the conceptual basis of a cost-based DG billing mechanism, with its associated terms and conditions, emanate out of the Commission s prior study on an appropriate tariff reflecting equitable cost of service. Subsequently, given that a general rate proceeding is the forum in which a particular utility s revenue requirements and associated cost-of-service for each rate class are quantified, the actual charges under the new tariff would be 11

16 appropriately set in the context of a future (from the perspective of the Commission study) general rate proceeding; i.e. filed subsequent to June 1, There is a critical significance in the fact that the term tariff is used in MCL 460.6a(14). By using the term tariff, the Legislature was clearly providing the Commission the option to develop a cost-based billing mechanism to replace the existing net metering billing methods (true and modified net-metering). Had the Legislature intended to limit the new Distributed Generation program to netmetering billing methods with an added charge to make it cost-based, it would have used the term charge in MCL 460.6a(14) and not tariff. This would have obviated the need for a year-long study, enabling the Commission to move directly to general rate-case proceedings to quantify and implement such charges, as charges are readily established in a general rate case. The upshot is that the Commission was clearly granted explicit authority to approve new DG pricing models in which longstanding cost-of-service principles such as cost-causation would dictate the form of the rate structure (i.e. tariff) thus removing the subsidy inherent to net metering billing methods. (8 TR 3433.) Staff also points out that net energy metering persists because of the grandfathering provision in MCL (1). Reading MCL 460.6a(14) demonstrates that the tariff to be filed pursuant to that section is to address issues related to the equitable cost of service for net metering customers. Essentially then, the point of the tariff is to rectify, as much as possible, problems with the existing net metering paradigm going forward and, at the same time, allow for customers 12

17 already participating in a net metering program to continue for the remaining duration of their program. MEC s references to distributed generation in its brief seem to imply only true and modified net metering. However, the term distributed generation is a broad term that can encompass net energy metering and other costbased tariffs. As such, the Legislature, in MCL 460.6a(14), directed the Commission to explore and establish such a cost-based tariff to apply to net metering and distributed generation customers under Act 295. MEC also asserts that the Company must offer a DG tariff that nets power inflows against power outflows and provides for true net metering and modified net metering. MEC s initial brief, p 127. MEC is mistaken. MCL 460.6a(14) provides for the development of a tariff reflecting equitable cost of service applicable to DG and net metering customers operating under the previous paradigm. It does not require that the Company provide for modified and true net metering in its tariff. This is made clear by the very fact of the grandfathering provision in MCL , which allows for participating customers to continue receiving service under the old net metering paradigm for up to 10 years from the date of their enrollment in the program. And ultimately, it is illogical for the Legislature to have directed the Commission to establish a DG tariff if what it intended all along was the preservation of true and modified net metering, as the MEC contends. 13

18 VI. Cost of Service and Rate Design a. MEC/NRDC/SCs (MEC) arguments are misleading and fail to reach actionable proposals. MEC states that DG rate designs must recognize generation, transmission, and distribution value from DG customers. (MEC initial brief, pp ) MEC goes on to discuss how DG customers contribute less to class cost of service because they have lower loads during the hours used to allocate generation, transmission and distribution demand (capacity) costs to the class. This is an example of the types of arguments that are misleading. Staff agrees in its report that solar DG contributes to offsetting generation allocation and that DG customers cost less to serve, for generation. (Exhibit MEC-162, p 26.) To the contrary, Staff s report shows that DG customers cost more to serve from a distribution perspective. Id. Also, MEC fails to acknowledge that discussions in Staff s report were based on breaking DG customers into a separate rate class from non-dg customers, and in the end, Staff recommended not treating DG customers as a separate rate class, as further discussed in Staff s initial brief. Id at Under Staff s proposed tariff, DG customers will be able to reduce the amount they pay for generation and distribution based on the amount that they are able to reduce their inflow. (8 TR ) Furthermore, additional benefits beyond those for reducing inflow have not been demonstrated in the record of the instant case. (8 TR ) Staff has also pointed out that if all benefits are paid to the DG customer then there are not any benefits for non-dg ratepayers. (8 TR ) MEC seems to support compensating DG customers for savings that they 14

19 anecdotally claim to exist but have not demonstrated to exist or even quantified their existence. MEC argues that reducing the 12CP peaks will reduce DTE s transmission costs, and thus those cost savings should be reflected in DG tariffs. (MEC initial brief, p 136.) The problem, once again, is that MEC has failed to provide more than anecdotal evidence that customer-owned DG will actually reduce the 12CP. MEC once again misleads, it is true that reducing the 12CP will reduce DTE s transmission costs, but it is not true that MEC has demonstrated that this is actually taking place, or will, in the projected test year. MEC also argues that DG should include compensation for reduced distribution loads, stating DG generation is delivered close to load, which displaces electricity that would have otherwise flowed from the transmission transformer all of the way to the ultimate served load. (MEC initial brief, p 137.) This statement is also misleading. Outflow will reduce electricity distributed upstream of the customer, because the additional DG generation will offset some of the previous generation upstream of the customer. However, other customers on the same circuit have not reduced their use of the distribution system. For higher levels of the distribution system, MEC failed to prove that current distribution allocators will be lowered due to DG. MEC goes on to state distribution value of DG should be calculated based on the coincidence of distributed generation output during class NCP. Staff has 15

20 already pointed out that the residential distribution peak is later than the system peak, and that solar does a much poorer job of offsetting this peak. (8 TR 4235.) Staff added in rebuttal that it is possible that DG will hardly drop the residential peak at all. (8 TR 4229.) With regard to the above statement, MEC has failed to recommend an actionable proposal. It rightly says that coincidence with NCP is what currently determines cost-causation for distribution, but there are only two logical outcomes from this assertion. One is that DG and non-dg customers should be broken into two cost of service classes and then contribution to NCP should be used to allocate distribution costs between the two classes. Staff, as mentioned previously, is already on record as saying this is not a preferred outcome. The second method would be to use an NCP demand charge in rate design to determine the appropriate use of the distribution system by every customer. Staff is on record for suggesting that this is a better alternative to the Company s proposed SAC. (8 TR 4240.) MEC failed to suggest any method to accomplish their proposed cost allocation. Due to all the reasons listed above, MECs assertions have failed to reach any actionable proposals and should be disregarded. b. The Commission should not approve DTE Electric s proposed DG Rider 18 language providing for forfeiture of outflow credits but should approve one element of DTE Electric s revised position provided in its initial brief. The Company s proposed DG Rider 18 includes a provision specifying that any remaining Outflow Credit in a customer s account must be forfeited upon 16

21 termination from the DG Program. The Company explained to Staff in an audit response, admitted as Exhibit S-11.1, that the basis for the provision is the Company s interpretation of Section 177(4) of 2016 Public Act 342 that Outflow Credits cannot be applied against distribution and transmission charges. In its initial brief, Staff points out that the Commission has already addressed this matter in its April 18, 2018 Order in MPSC Case No. U and found that the limitation against applying the outflow credit to distribution and transmission charges was only for the portion of outflow that exceeds inflow in the modified net metering construct. Therefore, Staff recommends that such Outflow Credits be credited to the customer s account or refunded to the customer in the event of termination from the program. (Staff s Initial Brief, p. 136.) In its initial brief, the Company proposed that, upon further consideration, forfeiture of unused Outflow Credits would only apply to customers moving out of their residence. (DTE Initial Brief, p 145.) For customers who remain at their residence, the Company would agree that customers should be able to use their Outflow Credits to offset the power supply portion of their bill for up to twelve months. Id. The Company further explains in its brief that if a customer s system is sized appropriately, Outflow Credits should not build up so much that they can t be used up in twelve months. Id. Staff appreciates the Company s willingness to reconsider its position on this matter. For customers who remain at their residence and participation in the DG Program is terminated, Staff supports applying the Outflow Credit against 17

22 subsequent future bills until the Outflow Credits have been depleted. However, limiting the time period to use up the credits to twelve months could cause a customer to forfeit Outflow Credits. For customers who remain at their residence and participation in the DG Program is terminated, Staff recommends applying any remaining Outflow Credit against future bills until the Outflow Credits are fully depleted. Staff continues to assert that Outflow Credits may be applied against the entire bill and are not limited to only the power supply portion of the bill. The Company s position remains unchanged for customers who move out of their residence. Id. The Company still intends that those customers would forfeit any unused Outflow Credits. Staff continues to support returning any unused Outflow Credits to the customer s account or refunding them to the customer in the event of termination. c. The Commission should clarify that an existing net metering customer who expands their project prior to the effective date of Public Act 342 may begin a new 10-year period beginning with the date of enrollment of the new project. The Commission should clarify that if a customer expands their system before Public Act 342 went into effect on April 20, 2017, the customer s entire project will be grandfathered into the net metering program for 10 years from the date of enrollment of the expanded project. In its initial brief, DTE makes the argument that the 10-year period must be a single continuous period because that language is included on Rider 16. (DTE Initial Brief, p 158.) The language in Public Act 342 is the controlling language and Staff points out that there is no 18

23 prohibition on a new 10-year period beginning with the date of enrollment of the expanded project, provided the date is before the effective date of Public Act 342. d. DTE Electric is incorrect in using volumetric rates to justify the System Access Contribution (SAC) The Company asserts that as a result of volumetric rates there is a cost shifting that occurs thus necessitating the SAC. (DTE Initial Brief, pp ) Staff agrees that distribution rates designed strictly on energy do not provide an accurate match with current cost of service allocations. (8 TR 4240.) However, the Company s proposal fails to provide a better match, as it does not charge on the determinant used for allocation. Id. As discussed elsewhere in this brief, demandrelated costs are not truly fixed, as they vary with demand. For this reason, the Company s justification should be rejected. e. MEIBC/IEI s accusations of DG rate shock are blatant mischaracterizations. MEIBC/IEI suggests that MPSC Staff supports purported rate shock. (MEIBC/IEI Initial Brief, p 31.) In fact, Staff does no such thing. Staff does not support the Company s proposed SAC, nor does it support the Company s proposed outflow compensation. Staff s proposed tariff is cost-of-service-based. (8 TR 4234.) In quoting Staff, MEIBC/IEI left out other items from Staff s testimony that would soften the impact, such as the more appropriate cost-based pricing incentivizing changing behavior to use more generation behind the meter. (8 TR 4254.) 19

24 Furthermore, the tariff change should come as no surprise to parties or customers. In PA 295 of 2008 a DG program was established with a life of not less than 10 years. MCL (2). This suggests that after 10 years the program may change, and those familiar with the law should have assumed it could change. Just because the tariff is changing does not make it rate shock, and each participant who began the program will be allowed to participate for 10 years. Lastly, MEIBC/IEI describes the change as immediate. Whenever a tariff changes, its effect could be said to be immediate, and just because it is immediate does not make it rate shock. In fact, the effect is only immediate for new customers, who would experience no rate change, and customers who have already been on the current tariff for 10 years or more. MEIBC/IEI s accusations of rate shock are baseless. f. ELPC s recommendation of a market transition adder should be rejected. ELPC has recommended a 4.5 to 5 cents/kwh adder to the DG outflow for the purposes of market transition to a value of solar. (ELPC Initial Brief, pp ) According to ELPC, Value of Solar (VoS) studies in other states consistently show this additional value. The use of VoS studies from other states is extremely troublesome. First, the cost of avoided production and distribution capacity may or may not be applicable to DTEs service territory. No party, including ELPC, has demonstrated that studies performed in other jurisdictions are applicable to DTE. Second, many of these studies propose compensating for externalities, such as 20

25 pollution. Staff has already pointed out that it may require legislation to compensate for these values. (8 TR 4245.) Lastly, Staff does not recommend compensating for all of some components, such as solar hedge value, because some of the benefits should flow to all rate payers instead of being compensated completely to the DG customer. Id. For these reasons, the market transition adder proposed by ELPC should be rejected. g. ELPC s recommendation of compensation for full generation should be rejected. ELPC has recommended that the capacity value study be based on the full generation of PV systems. (ELPC initial brief, p 23.) ELPC suggests that it is the full generation that provides benefits to the system. Under Staff s proposal, PV owners are compensated based on the capacity that they supply to the grid, not based on what is generated; this is the appropriate basis for compensation. ELPCs recommendation also has the same problem as the Company s SAC, but in the opposite direction. The Company s SAC is designed to charge distribution for generation a customer uses behind the meter, thus pulling that load out from behind the meter, while ELPC is proposing pulling the capacity out from behind the meter and compensating for capacity on that basis while the only capacity being provided is that which is provided in outflow. Therefore, the Company is pulling the load out from behind the meter and ignoring the generation, and ELPC is pulling the generation out from behind the meter and ignoring the load. For these 21

26 reasons, ELPCs recommendation of considering capacity for full generation should be rejected. h. GLREA s recommendation of a SAC credit should be denied. GLREA suggests a SAC credit for contributions the customers make to offset capacity costs at high-cost peak times. (GLREA initial brief, p 21.) GLREA seems to forget that the SAC is calculated based on distribution costs, and that it has provided no evidence that peak usage of distribution is offset by DG customers. As stated by Staff in other places, offsetting distribution is accomplished by reducing demand, and similar to Rider 3 customers, no evidence has been provided that DG customers offset their demand in any way. (8 TR 4240; 8 TR 4258.) GLREA did not calculate a SAC credit and hence its calculation cannot be scrutinized. For this reason, GLREAs suggestion of a SAC credit should be rejected. i. GLREA s recommendation to remove or eliminate the DG caps should be denied. GLREA suggests removing or eliminating the DG caps. (GLREA initial brief, p 23.) The caps put in place were originally legislated in PA 295 and were not removed by PA 342. GLREA s suggestion is contrary to law. Therefore, GLREA s suggestion to remove or eliminate the caps should be denied. 22

27 j. GLREA s assertions regarding Power Supply Cost Recovery (PSCR) double counting are confusing, vague, lacking in evidentiary support and should be rejected. GLREA accuses the Company of misappropriating benefits of PSCR credits. (GLREA initial brief, p 24.) Staff considers this statement to be unproven either in word or in example calculation. Because it lacks evidence, the bare assertion regarding PSCR double counting should be rejected. k. GLREA s suggestion that delivery costs should be included in outflow should be rejected. GLREA suggests that outflow should be credited in the following manner: Customers on non-time-based rate schedules will be credited for each kwh of outflow at the monthly average real-time locational marginal price for energy at the DTE Electric-appropriate load nodes plus distribution costs. (emphasis added.) (GLREA initial brief, p 25.) Staff responded to this in rebuttal testimony, calling the redlined tariff a return to net metering. (8 TR 4253.) Staff testified that outflow does not automatically undo the cost causation of inflow, and the mere presence of outflow does not mean that the costs caused by inflow are somehow negated. (8 TR ) For these reasons, GLREA s suggestion that delivery costs be included in outflow should be rejected. l. GLREA s concerns about appropriate solar and storage price signals are unfounded. GLREA expresses concern about solar and storage and offsetting of night time baseload generation. (GLREA initial brief, p 28.) These concerns are 23

28 overblown. Storage could be used early evening instead of at night and early evening is when the residential distribution peak occurs. (8 TR ) Another outcome is the price signals may result in customers shifting load to coincide with generation. Id. Also, given industry trends, the description of latenight discharge may be extremely appropriate. Id. The tariff sends appropriate price signals and customers will react; that does not make the reaction bad. In fact, the opposite is true. GLREAs concerns regarding storage are not correct and should be rejected. m. GLREA s recommendation of phase-in period for Rider 18 should be rejected. GLREA wants to know the impact on rates, monthly bills and financial impact on DG systems it owns or may acquire. Further, GLREA wants to wait 24 months to collect the data before moving to Rider 18. (GLREA Initial Brief, p ) The proposal is onerous and unnecessary. Each DG customer has different loads and different sized generators. While bill comparisons for non-dg customers are accomplished reasonably enough by using a variety of different monthly usages, bill comparisons for DG customers would need to have a variety of usages, systems sizes, and assumptions about usage behind the meter. The Company should not be expected to produce a bill comparison for each individual DG customer. Furthermore, if this proposal has merit, using only forward-looking data would be inappropriate, as the Company clearly has some historical inflow/outflow data because it used it to calculate the SAC. If a current or prospective DG customer 24

29 wants their historical inflow/outflow data they only need request it, and then they can perform their own analysis. Lastly, the Company cannot calculate the financial impact, because it does not know what each DG customer paid for their generation system. GLREA s phase-in recommendation should be rejected for these reasons. n. Soulardarity s recommendation of compensating DG for externalities should be rejected. Soulardarity argues that externalities should be compensated for in the DG tariff. Soulardarity considers the quantifiable benefits of holistic environmental and health costs to be reimbursable. Soulardarity initial brief, pages Staff disagrees. Externalities that are not charged to the Company are not considered in ratemaking and should not be considered avoided. DTE owns hundreds of megawatts of wind and solar generation and is not compensated at all for the health and environmental benefits. Staff points out that some environmental benefits are included in the power supply portion of the rate. (8 TR 4245.) Staff further suggests that cost-based rates do not include externalities, unless those externalities are otherwise quantified. Id. The investment tax credit (ITC) is a federal tax credit available to all customers that install solar. The ITC is a social cost which is funded by taxpayers. The ITC, funded by society, reimburses DG customers for the social benefits that they are providing. Therefore, it is not necessary for the Company to consider compensating DG customers for social benefits because they are already being 25

30 compensated by society via the ITC. For these reasons, Soulardarity s recommendation of compensating DG for externalities should be rejected. o. MEIBC/IEI s and the ELPC s arguments in favor of caps on EV demand charges should be rejected. MEIBC/IEIs recommends caps on EV related demand charges. It claims that demand charges can significantly increase the cost of electricity because of low utilization. (MEIBC/IEI s initial brief, pp ) Staff responded to these arguments in rebuttal testimony, stating, During the early adoption phase there may be merit to having a demand charge holiday. However, as demand is the current cost allocator for many costs, demand charges in rate design provide the correct price signals for alignment to cost causation. If the Commission were to order a demand charge holiday, Staff would recommend that the Commission be specific about the holiday and not make it permanent. For example, the Commission could establish a DCFC tariff based on the underlying standard rate that has no demand charges for the next 2-5 years, and then for 2-5 years after increases demand charges until they reach parity with the D4 tariff. Staff does not support capping the demand charge ratio as suggested by the witness. [8 TR ] Staff would like to point out that at no point did MEIBC/IEI claim that demand charges do not reflect cost-causation. Staff also points out that rate D3 is available to these customers and that rate has no demand charges. Id. Long-term, it is preferable for rates to reflect cost-of-service principles in order to send appropriate price signals and incentivize efficient usage. For the purpose of a pilot to kick-start the EV industry it is acceptable to ignore such concerns, but long-term it is inappropriate and inefficient to provide the EV industry with special privileges from a rate design perspective. Therefore, if an alternative is considered it should 26

31 be modeled on Staff s proposal above and not MEIBC/IEI s. MEIBC/IEI s caps on EV demand charges should rejected. The ELPC makes similar arguments about EV demand charges. (ELPC initial brief, pp ) For the same reasons explained above, ELPC s arguments should be rejected. p. The MEIBC/IEI and the ELPC s arguments in support of limiting a DCFC charge to the price of gasoline should be rejected. MEIBC/IEI is concerned about monopoly power in a limited market and argues that the commission should place price caps on EV fast charging. They posit that the rate for charging should be tied to the equivalent price of gasoline. (MEIBC/IEI initial brief, pp ) Staff argues that if the Commission begins to regulate charging that it will be hard for the Commission to exit and if charging rates are subsidized it may be hard to raise the prices in the future. (8 TR 4255.) Staff also points out that charging too low a price will result in demand that is too high, and since fast charging is likely detrimental to the distribution system it will result in unintended consequences. Id. For these reasons, MEIBC/IEI s argument to tie fast charging prices to the price of gasoline should be rejected. The ELPC makes similar arguments about fast charging and gasoline prices. (ELPC initial brief, pp ) For the reasons listed above, ELPC s arguments should likewise be rejected. 27

32 q. The ALJ and Commission should exercise caution in considering the ELPC s recommendation of pass through of TOU rates to level 2 stations. ELPC recommends pass through of time-of-use (TOU) rates to level 2 stations. (ELPC initial brief, pp ) Staff responded to this suggestion in rebuttal testimony, stating, Staff is neutral. While the passing through of rates seems reasonable, innovation in the pricing of charging service should not be stifled. As stated earlier, the pricing of charging services should be unregulated by the Commission. Staff would not oppose the Company encouraging TOU charging rates from charging companies. [8 TR 4256.] Staff s only recommendation with regard to ELPC s proposal is that the Commission should not regulate EV charging rates. r. MEIBC/IEI s recommendation of a workplace charging tariff should be rejected. MEIBC/IEI recommends a Level 2 charging tariff designed to incentivize desirable standards. The recommendation is based on the notion that charging at parking lots is a new end use. (MEIBC/IEI initial brief, p 48.) Staff disagrees. Staff does not support a new tariff for each new end use. (8 TR 4256.) Staff is unclear what these desirable standards for workplace charging are and the testimony of MEIBC/IEI fails to provide additional information. Id. While facilitating market development is a reasonable goal, that is exactly what the rebates are for, so there is no reason to impose a tariff on top of it. For these reasons MEIBC/IEI s recommendation of a workplace charging tariff should be rejected. 28

33 s. Residential and Commercial Secondary Customer Charges i. The Company s Assertion that distribution system design cost is caused by the number of customers is unsupported and should be rejected. The Company makes a claim that distribution system design cost, when viewed prospectively, is caused or driven by the number of customers on the system. (DTE Electric s initial brief, p. 114.) However, the Company offers no support for this claim, which contradicts the Company s assertion that for distribution, the parameters used to design and build the system determines costs causation. The principle system design parameters are the geographic area to be covered and the maximum demand placed on the system at a given voltage level. (7 TR ) Neither of these factors is determined by the number of customers, but rather maximum demand and the amount of materials needed to cover a geographic region. The Company cannot explain this difference by using the caveat that the method differs when viewing the distribution system design costs prospectively. As the Company explained, because rebuilding a circuit is expensive, distribution planning must consider future load growth and reliability. (7 TR 3218.) Therefore, the Company is already looking into the future and accounting for future load growth in its design of the distribution system, with costs being driven by the geographic area to be covered and the maximum demand placed on the system at a given voltage level. (7 TR ) Furthermore, the NARUC Electric Utility Cost Allocation Manual is clear in that distribution demand costs do not vary with the number of customers but are 29