Carl Wood and Geoffrey Brown are the Assigned Commissioners and Thomas Pulsifer is the assigned Administrative Law Judge in this proceeding.
Findings of Fact
1. The change in DA load levels between July 1 and September 20, 2001, inclusively, results in an increase in the average cost of power for remaining bundled customer because total uneconomic costs are spread over a smaller sales base.
2. D.02-03-055 determined that as a condition of retaining the DA suspension date of September 21, 2001, a surcharge must be imposed on DA customers sufficient to make bundled customers economically indifferent between a DA suspension date of July 1 versus September 21, 2001.
3. The computer simulations performed by Navigant and Henwood provide a reasonable framework for analyzing the cost shifting effects based upon inclusion versus exclusion of incremental DA load levels at July 1 versus September 21, 2001.
4. The cost shifting effects caused by the incremental change in DA load represents the increase in the average cost of net short power to bundled customer due to the migration of customers from bundled to DA load between, and including, July 1 and September 20, 2002.
5. The cost differential described in the preceding FOF represents the portion of the DWR revenue requirement incremental DA customers would need to pay to avoid cost shifting to bundled customers.
6. The total cost of generation used to serve bundled customers is the combined weighted average cost of both URG and the DWR power.
7. DWR power has been, on average, more expensive than the weighted average cost of URG power, to date.
8. DWR began buying electricity on behalf of the retail end use customers in the service territories of the California utilities: for PG&E and SCE on January 17, 2001, and SDG&E on February 7, 2001.
9. AB 1X provides for DWR to collect revenues by applying charges to the electricity that it purchased on behalf all retail end customers in the service territories of the three major utilities, as a direct obligation of these customers to DWR.
10. Consistent with AB 1X and AB 117, DA customers that took bundled service on or after February 1, 2002 are responsible for paying a share of the DWR revenue requirements, including both previously incurred costs as well as an ongoing cost component.
11. Recently, the Legislature passed Assembly Bill No. 117 ("AB 117"), which was signed into law on September 24, 2002. ((Stats 2002, ch. 838.)
12. The Legislature amended Public Utilities Code Section 366 to add subsection (d) in order to clarify its intent concerning the cost responsibility of each retail end-use customers who was a customer on or after February 1, 2001.
13. For previously incurred costs, DWR has not yet received full payment, and the State of California is now finalizing the sale of bonds to finance DWR's prior undercollections.
14. The DWR revenue requirement applicable to bond charges is currently being determined in A.00-11-038 et al.
15. Under the CLECA total-portfolio approach, the costs of both DWR and the URG resources are relevant to determining a total level of indifference costs.
16. Both the DWR and the URG variable dispatch costs for the pre- and post-DA migration scenarios are available from the DWR supplied spreadsheets. The three utilities will need to provide fixed cost URG data to compute total portfolio cost indifference.
17. Once the total indifference cost level is determined, the DWR portion of that indifference cost can be identified by calculating a cost for the IOUs' URG and subtracting that from the total portfolio indifference cost.
18. A separate DA CRS cost component needs to be determined, representing the portion of the portfolio supplied from URG resources which should incorporate a calculation of URG costs in excess of the market proxy as adopted in this order.
19. The URG-related cost component of the DA CRS needs to be separately identified because continuous DA load will be charged only this component, but not the DWR-related components.
20. Among the potential sources for a market proxy offered into evidence, the gas-fired combined cycle represents the most appropriate choice for use in determining an above-market URG component of the DA CRS.
21. The values offered by CMTA to represent the gas-fired combined cycle proxy appear high in relation to proposed values offered by other parties.
22. The combined cycle proxy value of 4.3 cents/kWh offered by ORA, representing a 15-year levelized cost estimate from a California Energy Commission study provides the most conservative combined cycle proxy value offered in this proceeding.
23. In the interests of achieving a reasonably accurate representation of the market proxy value on a going forward basis, provision needs to be made for periodic updating of the market proxy values to reflect the most contemporaneous data.
24. As a basis to analyze the cost-shifting impacts of migrating DA load, and to develop DA CRS proposals, computer modeling simulations were performed by Navigant Consulting, Inc. and Henwood.
25. Although Navigant and Henwood employed different forecast assumptions, both used Henwood's Electric Market Simulation System and accompanying database, and both used Henwood's production simulation model, PROSYM.
26. PG&E, SCE, SDG&E, and ORA all base their CRS calculations on the Navigant Scenario 8 model run, while CLECA, CIU, and CMTA all base their CRS calculations on Henwood base Case model run.
27. Henwood modeled a "base case" representing a revision of Navigant's base case, updated to reflect Henwood's assumptions, resulting in higher estimates for the years 2002 through 2011 by$1.96 billion compared to Navigant modeling, thus resulting in a lower DA CRS.
28. Henwood identified a variety of modeling errors and inconsistencies in Navigant's initial computer runs, many of which were corrected in updated versions of Navigant's runs.
29. Parties' disputes concerning DWR's exclusion of residential load below 130% of baseline are moot for purposes of this proceeding since the matter is being addressed in A.00-11-038 et al.
30. DWR incurred an undercollection for costs it incurred during the period from inception of its power purchase program on January 17, 2001 through the period when DA was suspended effective on September 21, 2001.
31. Neither bundled customers nor DA customers have yet paid for the undercollection of costs incurred up through September 20, 2001.
32. The state of California is finalizing plans for the sale of long term bonds to cover the historic undercollection of DWR costs.
33. It does not result in double counting for DA customers to pay both for a pro rata portion of the full Bond Charge revenue requirement and for DWR power charges.
34. It would conflict with the Commission's mandate to achieve bundled customer indifference if bundled customers were required to pay a bond charge based on DWR's total revenue requirement while DA customers only paid the fraction of the Bond revenue requirement related solely to amortization of the historic undercollection.
35. There would be a significant magnitude of cost-shifting if DWR costs and utility-related generation costs were borne solely by bundled service customers, and direct access customers were not required to pay a portion of these costs that were incurred for their benefit.
36. The Commission has previously stated in D.02-07-032 that a cap of 2.7 cents/kWh may be reasonable for purposes of mitigating DA CRS that might otherwise increase to levels that would make DA uneconomic.
37. No party provided convincing affirmative evidence concerning the quantitative relationship between various levels of caps and the extent to which DA contracts would likely be rendered uneconomic.
38. Neither a cap as high of 4 cents/kWh or as low as 2 cents/kWh has been shown to be warranted as an initial starting point for DA CRS purposes.
39. In the absence of affirmative evidence regarding specific caps, the Commission should move cautiously in the level of any initial cap that is implemented for DA CRS purposes.
40. Consistent with the Commission's mandate of achieving customer indifference, DA customers should be responsible for financing the interest charges associated with deferring current DA CRS obligations to future periods through capping mechanisms.
41. Although the risk of setting the cap too low must be considered as it may potentially lead to a burden on bundled customers, that risk is a function of the passage of time as potential undercollections grow.
42. As long as the Commission retains the flexibility to adjust the cap after further proceedings as deemed necessary to protect bundled customers from cost shifting, bundled customer indifference is not violated by adopting an initial cap of 2.7 cents/kWh.
43. CLECA's calculations in Exhibit 28 provide an illustrative rough indication of how collections of DA CRS over an extended period could generate a surplus in later years that could be used to pay down undercollections in initial years resulting from its proposed cap, although various assumptions in CLECA's illustrative calculations do not necessarily reflect the actual charges that will apply during those periods.
44. In view of concerns regarding potential longer term effects of large undercollections that could accrue as a result of continuing to apply a 2.7 cents/kWh cap, beyond a short initial period, a further record needs to be developed on the level of a longer term cap that would be appropriate, given the need to achieve payback of the undercollection resulting from the DA cap with interest over a reasonable period.
45. The time between now and July 1, 2003 will be short enough to guard against an extended period of accumulation of undercollections, but long enough to provide for a more thorough record on which to base further assessments concerning the size of any cap, and related issues such as the appropriate compensation for the cost of money associated with bundled customers' financing of the cap undercollection, and the frequency and manner of subsequent adjustment of the cap.
46. To the extent that bundled customers are required to fund a portion of the charges applicable to DA cost responsibility in excess of the adopted cap, an accrual of interest on such amounts funded amounts needs to be credited to bundled ratepayers recognizing the time value of money in order to achieve bundled customer indifference over the period that the DA CRS remains in effect.
47. Because bundled customers will fund shortfalls in DA CRS caused by the DA billing cap, with applicable acrrued interest, neither DWR nor the IOUs will have to finance the undercollection in DA CRS from external borrowings.
Conclusions of Law
1. In implementing AB 1X, the Commission in D.01-09-060 suspended the right to enter into direct access contracts or arrangements after September 20, 2001.
2. The implementation provisions set forth in this decision are reasonable and consistent with our determinations in D.02-03-055 that did not change the suspension date ordered in D.01-09-060.
3. In order to achieve bundled customer indifference as intended by D.02-03-055, bundled rates should neither increase nor decrease solely as a result of the migration from bundled to DA load between July 1 and September 20, 2002, inclusively.
4. In D.02-04-067, the Commission expressly modified D.02-03-055 to make clear that the DA CRS will take into account recovery of relevant non-DWR costs and that DA customers will be held responsible for such costs as required by AB 1X and other statutes, for example, AB 1890.
5. Determinations in this decision concerning the application of above-market URG-related costs as part of the DA CRS are subject to any subsequent determinations the Commission may make in other proceedings where the impact of AB 1X and 6X are being examined as they relate to AB 1890.
6. The Commission has authority under AB 1X to impose DA CRS relating to DWR-related costs.
7. Under Public Utilities Code Section 701, the Commission has broad authority to regulate public utilities and to "do all things...which are necessary and convenient in the exercise of such power and jurisdiction."
8. Consistent with its broad authority to regulate, together with Public Utilities Code Sections 451 and 453 prohibiting discrimination, bundled customers may not be arbitrarily charged for obligations which rightfully are the responsibility of DA customers.
9. Within its broad statutory authority, the Commission has specific authority to establish charges for the collection of costs incurred by DWR pursuant to AB 1X applicable not just to bundled customers, but also applicable to DA customers to the extent that DWR purchased power on their behalf or for their benefit.
10. Pursuant to AB 1X and Public Utilities Code 701, and consistent with the provisions in D.02-02-051, the Commission has legal authority applying the DWR Bond Charge to DA customers to the extent they are found to bear cost responsibility for the historic period during 2001 that DWR was incurring undercollections for its power procurement.
11. As prescribed in D.02-02-051 and the Rate Agreement, the Commission has an obligation to impose charges on electric customers sufficient to compensate DWR for its costs, including payment of DWR bond principal and interest payments.
12. It is consistent with the goal of achieving bundled customer indifference as prescribed in D.02-03-055 for DA customers to share in the obligation for payment of principal and interest on the DWR bonds on a pro rata basis along with bundled customers.
13. As determined in D.02-02-051, the Commission is not necessarily required to impose DWR bond-related charges only on the power that is purchased by DWR on behalf of the retail end use customers, but is given great flexibility to devise means to recover DWR's revenue requirements.
14. The DWR Bond Charge should be imposed on all DA customers except for those that have been on DA continuously both before and since DWR began procuring power under AB 1X.
15. Consistent with the provisions of the Water Code, DA customers that took bundled service on or after February 1, 2001, are responsible for paying a share of the DWR revenue requirements, representing both previously incurred costs as well as an ongoing cost component through the duration of the DWR power contracts.
16. Section 366(d), as amended by AB 117 is relevant to this DA CRS proceeding.
17. The cost responsibility imposed by AB 117 applies to DA customers who took bundled service from an electrical corporation on or after February 1, 2001.
18. Thus, the issues concerning an appropriate cut-off date (whether it should be July 1, 2001 or not and what it should be based on) have been made moot by AB 117.
19. Pursuant to AB 117, the cut-off date for purposes of applying Department Power Charges for DA Customers is set as of February 1, 2001.
20. Pursuant to AB 117, DA customers who were took bundled service, e.g. purchased electricity, on or after February 1, 2002, from an electric corporation are responsible for the DWR Power Charges.
21. This assignment of cost responsibility to those DA customers designated above is consistent with the legislative intent and mandate set forth in AB 117 that each retail end use customer, including a DA customer who took bundled service on or after February 1, 2001, bears "a fair share" of Department electricity power costs.
22. This assignment of cost responsibility is also consistent with further "intent of the Legislature to prevent any shifting of recoverable costs between customers, " as expressed in Public Utilitites Code Section 366(d)(1).
23. The criterion for determining DA status for DA CRS billing purposes should be the "DA active" date as contained in utility billing records, not contract execution date.
24. Legal authority exists for imposing charges on all DA customers for their share of the uneconomic utility-related costs.
25. DA CRS should be established on a utility-specific basis rather than on a uniform statewide basis to be consistent with cost-based regulatory principles and to avoid cross subsidizing customers' in higher-cost service territories by customers in lower-cost service territories.
26. Because of the uncertainties regarding the long-term forecasts underlying the modeling performed by Navigant and Henwood in this proceeding, it is not appropriate to set a DA CRS based upon a levelized fixed charge approach.
27. A one-year-ahead forecast should be used as the appropriate time frame to use for setting DA CRS.
28. Inconsistency in the use of forecast assumptions to establish DA CRS versus those used in the DWR revenue requirement proceeding in A.00-11-038 et al. would result in either under or over recovery of the respective shares of DWR costs from bundled and DA customers, and our goal of bundled customer indifference would be undermined.
29. Since the DWR power charges applicable to bundled customers is being determined in A.00-11-038 et al., the assumptions underlying the calculation of DA CRS should be consistent with the 2003 DWR/Navigant modeling underlying the revenue requirement implemented in the A.00-11-038 et al. proceeding.
30. In the interests of consistency in the establishment of DWR power charges allocated between bundled customers and DA customers for (1) the historic period of September 21, 2001 through December 31, 2002; and (2) the prospective period of calendar year 2003, the final determination of these charges should be performed using the forecast resource assumptions underlying the DWR revenue requirement being implemented in A.00-11-038 et al.
31. Since Navigant is responsible for running the model in the determination of the DWR revenue requirement in A.00-11-038 et al., it would not promote consistency to use the resource assumptions under the Henwood base case in this proceeding for purposes of computing a DA CRS.
32. The charges assigned to DA customers for DWR costs covering the historic period of September 21, 2001 through December 31, 2002 should be consistent with the assumption that were applied in setting power charges for bundled customers in D.02-02-052, subject to any true ups or adjustments applicable to this historic period being implemented as part of the DWR 2003 revenue requirement proceeding in A.00-11-038 et al.
33. For purposes of calculating the URG-related component of the DA CRS, each of the utilities should utilize the most recent Commission-adopted URG data.
34. The URG component for DA CRS purposes shall be computed as the incremental costs after applying the market benchmark proxy as adopted in this proceeding to URG resources. This element of the DA CRS shall be applied to the portion of the total portfolio that is supplied by URG sources.
35. The market proxy for purposes of computing the above-market URG component of the DA CRS for 2003 should be based on a gas-fired combined cycle plant and should incorporate a value of 4.3 cents/kWh based on a 15-year levelized cost estimate as reported in ORA's testimony, referencing a California Energy Commission study.
36. The value adopted for the market proxy adopted for purposes of the 2003 DA CRS calculation should be subjected to regular updating with each annual revision of the DA CRS based on the most updated and reliable information available at the time.
37. The determinations in this order concerning the treatment of URG-related costs in connection with the DA CRS may be subject to subsequent adjustment, depending on further Commission consideration and determinations in A.00-11-038 et al, and other related proceedings regarding the timing of the end of the rate freeze, the corresponding impact on transition cost recovery, and the definition of what were formerly considered stranded costs. Nothing in this order prejudges or is intended to prejudge the outcome of these pending matters.
38. A compliance workshop should be held in coordination with proceedings in A.00-11-038 et al. at a time to be scheduled by ALJ ruling for the purpose of performing a revised run of the DWR/Navigant model and implementing the necessary calculations to place into effect the DWR power charges to be remitted (1) by DA customers versus (2) bundled customers for the above-referenced time periods. The workshop shall also be used to compute the URG-related component of the DA CRS.
39. The revised computer model run should provide a revised calculation of the DA in/out scenarios that similar to that run on Navigant Scenario 8, but updated to reflect the resource assumptions underlying the DWR revenue requirement being implemented in A.00-11-038 et al., and applying the methodology for computing the DA in/out scenarios consistent with the positions adopted in the instant order.
40. Since bundled customers have already been remitting funds to DWR for the period since September 21, 2001 forward which includes the portion of costs for which DA customers are responsible, bundled customers are entitled to a credit, including interest, equal to the DWR power charges that will be assessed on DA customers covering this historic period as determined in this order.
41. The issue raised by CIU regarding revocation of the one cent surcharge is beyond the scope of this proceeding, and more appropriately addressed in other proceedings, e.g. the advice letter filing of PG&E. For SCE, the issue is moot to the extent that the charge has already been eliminated on a prospective basis.
42. Provision should be made for at least annual updating and true ups of the DA CRS for each utility to be implemented in this proceeding. Scheduling of the DA CRS update should be coordinated, as appropriate, with the annual DWR revenue requirement update proceeding.
43. Provision should be made for the utilities to maintain tracking accounts to permit segregation of the revenues collected and remitted to DWR as between bundled customers and DA customers.
44. This decision construes, applies, implements, and interprets the provisions of AB 1X (Chapter 4 of the Statutes of 2001-02 First Extraordinary Session). Therefore, Public Utilities Code Section 1731(c) (applications for rehearing are due within 10 days after the date of issuance of the order or decision) and Public Utilities Code Section 1768 (procedures applicable to judicial review) are applicable.
IT IS ORDERED that:
1. This order shall apply to Southern California Edison Company (SCE). Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E).
2. A Direct Access Cost Responsibility Surcharge mechanism is hereby adopted applicable to designated direct access customers in the service territories of PG&E, SCE, and SDG&E, composed of the following elements:
a. DWR Bond Charge, covering cost responsibility for the period from the inception of DWR's power purchase program through September 20, 2001.
b. DWR Power Charge, covering the historic period from September 21, 2001 through December 31, 2002.
c. DWR Power Charge, covering the prospective period for the Calendar Year 2003.
d. Utility-retained generation component applicable to above-market costs.
3. The DA CRS shall be subject to updating and true up on at least an annual basis in accordance with the processes and procedures as adopted below.
4. The DWR Bond Charge applied to all DA customers, except those that were continuously taking DA service both before and after DWR began its power purchase program. "Continuous" DA customers shall be defined to include those that have been taking DA service continuously both before and since January 17, 2001 (in the PG&E and SCE service territories) or February 7, 2001 (in the SDG&E service territory).
5. The DWR Bond Charge portion of the DA CRS shall incorporate a pro rata share of the full Bond Revenue Requirement as is being determined and implemented in A.00-11-038 et al.
6. The specific per-kWh DWR Bond Charge component of the DA CRS shall be calculated and implemented in a separate order in A.00-11-038 et al. as part of the implementation of Bond Charges for bundled customers.
7. The Bond Charge shall take effect for designated DA customers on the same basis as is adopted and implemented for bundled customers pursuant to a separate order in A.00-11-038 et al. The actual implementation of the Bond Charge from DA customers, however, will occur only after legal challenges have been exhausted per the Rate Agreement Section 4.3.
8. The DWR Power Charge component of the DA CRS for the historic period September 21, 2001 through December 31, 2002 shall be determined by performing a DA in/out computer model run, in accordance with the methodology adopted in this order, and consistent with the inter-utility allocations adopted for the historic period in D.02-02-052 adjusted for any true ups to adjust for recorded cost and operational data covering that period, as shall be implemented in connection with the 2003 DWR revenue requirement in A.00-11-038 et al.
9. Interest charges shall accrue on the unpaid balance due under the DWR Power Charge component of the DA CRS for the historic period September 21, 2001 through December 31, 2002, covering the period from September 21, 2001 until bundled customers have been fully reimbursed for all applicable charges of principal plus interest due from DA customers.
10. The DWR Bond interest rate shall be used for computing interest credits due from DA customers to bundled customers.
11. The DWR Power Charge component of the DA CRS for the prospective 12 months beginning January 1, 2003 shall be determined by performing a DA in/out computer model run in accordance with the methodology adopted in this order, and consistent with the inter-utility allocations and operational cost assumptions underlying the 2003 DWR revenue requirement that shall be adopted in a separate order in A.00-11-038 et al.
12. The DWR Power Charge component of the DA CRS for the prospective 12 months beginning January 1, 2003 shall be implemented concurrently with DWR 2003 power charges applicable to bundled customers as shall be determined in A.00-11-038 et al.
13. The DWR Power Charge component of the DA CRS shall apply only to those DA customers that took bundled on or after February 1, 2001. DA customers that took bundled service on or after February 1, 2001 shall not be excluded from the DWR Power Charge component of DA CRS.
14. For purposes of determining a customer's DA or bundled status as of February 1, 2001 for purposes of paying the DWR Power Charge, the customer's billing records shall be used, and not contract execution date.
15. All DA customers, irrespective of the date they began to take DA service shall be required to pay the URG-related component of the DA CRS.
16. For purposes of determining the URG component of the DA CRS for 2003, each utility shall apply the market proxy value for a gas-fired combined cycle unit, as adopted in this order to compute the above-market portion of URG.
17. A preliminary listing of the major categories data inputs and calculations necessary to perform the DA in/out model runs on a total portfolio basis is set forth in Appendix F of this order.
18. The assigned ALJ shall issue a procedural ruling setting a schedule for necessary workshops and compliance filings necessary to compile necessary data inputs, perform revised computer model runs and compute the applicable DA CRS components both for the historic period (i.e., September 21, 2001 through December 31, 2002) and the 12-month prospective period beginning January 1, 2003 to be coordinated, as appropriate with A.00-11-038 et al. proceedings.
19. A initial cap of 2.7 cents/kWh shall be applied in determining the maximum amount that may be billed to DA customers for amounts currently due for DA CRS in each of the three utility service territories as determined by this order.
20. The revenues generated under the 2.7 cents/kWh cap shall be applied first in priority to the DA CRS components DWR Bond Charge and second in priority to the DWR Power Charge for 2003. In order to permit SCE to cover its one-cent HPC, however, we shall permit it to recoup this charge from the DA CRS cap after the Bond Charge has been covered. To the extent that insufficient revenue is generated from the 2.7 cents cap to cover the full DWR Power Charge, the shortfall shall be temporarily remitted to DWR from bundled customer proceeds.
21. The ALJ is directed to issue a ruling to set a schedule to develop a further record regarding an appropriate longer term DA CRS cap to apply to each of the utilities after the initial interim period through July 1, 2003 in order to determine that any accrued undercollections can be paid off with interest over a reasonable time horizon.
22. The further proceedings on the cap shall consider the maximum level of undercollection that would be generated by each of the utilities and the maximum number of years required for payback under the various cap proposals that have been offered by parties to this proceeding. The calculations of potential undercollections shall build upon the record that has already been developed in this proceeding regarding long term forecasts, with appropriate updating of data as may be deemed relevant.
23. The further proceedings on the cap shall also consider appropriate measures for ongoing periodic reassessment of the adequacy of the level of any cap. Possible trigger mechanisms should be considered that would require reassessment of whether to adjust the cap either upward or downward to ensure that over time, the cap is sufficient to provide reasonable assurance that bundled customers will be indifferent over time for the effects of DA migration.
24. The further proceedings on the cap shall also consider the appropriate factor to reflect the cost of money associated with bundled customers funding shortfalls due to the cap and shall consider any additional relevant evidence concerning the risks of making DA uneconomic.
25. The ALJ shall issue any additional procedural rulings, as warranted, to develop a further record on the outstanding issues identified in this decision, including the issue of appropriate methodologies for performing backcasts.
26. The utilities shall be required to file compliance tariffs necessary to implement the DA CRS provisions adopted in this order following conclusion of the implementation workshops ordered herein and the calculation of the specific DA CRS elements to be implemented in accordance with this order. The ALJ shall issue a further ruling scheduling a date for the applicable tariff filings to become effective upon review by the Energy Division.
27. TURN's recommendation to the costs of the WAPA contract in the DA CRS calculation is hereby adopted.
28. TURN's recommendation to move the costs of interruptible rate discount programs for PG&E and SCE to the distribution rate component is hereby adopted. The ALJ shall issue a ruling concerning the timing of implementation of this measure.
29. The top-100-hour allocation method adopted in D.00-06-034 shall be used for purposes of revenue allocation of the URG component of DA CRS using the factors presented in the utilities' testimony.
This order is effective today.
Dated November 7, 2002, at San Francisco, California.
HENRY M. DUQUE
GEOFFREY F. BROWN
MICHAEL R. PEEVEY
I will file a dissent.
/s/ LORETTA M. LYNCH
I will file a dissent.
/s/ CARL W. WOOD
I will file a concurrence.
/s/ MICHAEL R. PEEVEY
Appendixes A-E, D0211022
Appendix F D0211022
Appendix G D0211022