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1 Walter S. Foster Richard B. Foster Theodore W. Swift John L. Collins Webb A. Smith Allan J. Claypool Gary J. McRay Robert J. McCullen Stephen I. Jurmu William K. Fahey Stephen O. Schultz William R. Schulz David H. Aldrich Scott A. Storey Charles A. Janssen Charles E. Barbieri James B. Jensen, Jr. Scott L. Mandel Michael D. Sanders Sherry A. Stein Brent A. Titus Brian A. Kaser Robert E. McFarland Stephen J. Lowney Patricia A. Calore Michael J. Bommarito Jean G. Schtokal Glen A. Schmiege Brian G. Goodenough Matt G. Hrebec Mark H. Canady Eric E. Doster Stephen J. Rhodes Melissa J. Jackson Steven H. Lasher Nancy L. Kahn Deanna Swisher Mark J. Burzych Alan G. Gilchrist Thomas R. Meagher Douglas A. Mielock Scott R. Forbush Peter R. Albertins Christopher A. Ballard Scott A. Chernich Donald E. Martin Jennifer M. Van Horn Paul J. Millenbach Dirk H. Beckwith Bruce A. Vande Vusse Anne M. Seurynck Richard L. Hillman Alan T. Rogalski Andrea J. Hool Steven L. Owen John M. Naber Rebecca S. Davies Barbara J. Oyer Claire V. Groen Jennifer Kildea Dewane John P. Nicolucci Michael D. Homier Molly L. Chan Keith A. Castora Kirsten M. McNelly Robert M. Hartley Emily L. Matthews Benjamin J. Price Ronald D. Richards, Jr. Joseph E. Kozely Pamela C. Dausman Terrence G. Quinn Jacqueline E. Bayley Ethan E. Rii Dana M. Bennett Tina M. Sellers Radhika P. Drake Of Counsel Lawrence B. Lindemer John W. Ester David VanderHaagen Michael G. Harrison Allan O. Maki Frederick B. Bellamy Gilbert M. Frimet Deborah J. Williamson Writer's Direct Phone: (517) September 16, 2004 via Electronic Filing and Hand Delivery Ms. Mary Jo Kunkle Executive Secretary Michigan Public Service Commission 6545 Mercantile Way Lansing, MI Dear Ms. Kunkle: RE: In the matter of the application of The Detroit Edison Company to increase rates, amend its rate schedules governing the distribution and supply of electric energy, implement Power Supply Cost Recovery plans, factors and reconciliations in its rate schedules for jurisdictional sales of electricity and for miscellaneous accounting authority and regulatory asset recovery (MPSC Case No. U-13808) Enclosed for filing are an original and four copies of The Detroit Edison Company s Exceptions and Attachments XVI, XVII, XVIII and XIX, along with a Certificate of Service. Also enclosed is an extra copy of each document to be stamped and returned with our courier. Please contact me if you have any questions. Very truly yours, FOSTER, SWIFT, COLLINS & SMITH, P.C. Stephen J. Rhodes /mkr Enclosures cc: Hon. Daniel E. Nickerson, Jr. Parties of Record S:\122\SJR\EDISON\13808\kunkle wpd

2 STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of ) THE DETROIT EDISON COMPANY ) to increase rates, amend its rate ) schedules governing the distribution ) and supply of electric energy, implement ) Case No. U Power Supply Cost Recovery plans, ) factors and reconciliations in its rate ) schedules for jurisdictional sales of ) electricity and for miscellaneous ) accounting authority and regulatory ) asset recovery. ) ) STATE OF MICHIGAN ) ) ss COUNTY OF INGHAM ) CERTIFICATE OF SERVICE Stephen J. Rhodes, being duly sworn, deposes and says that he is an employee of Foster, Swift, Collins & Smith, P.C., and that on September 16, 2004, a copy of The Detroit Edison Company s Exceptions, Attachments XVI, XVII, XVIII and XIX, and Certificate of Service, were served upon: See Attached Service List Service was accomplished via electronic mail and by depositing same in a United States Postal Service mail depository, enclosed in envelopes bearing first-class postage, fully prepaid, and properly addressed. Stephen J. Rhodes

3 SERVICE LIST MPSC CASE NO. U ADMINISTRATIVE LAW JUDGE Hon. Daniel E. Nickerson, Jr. Michigan Public Service Commission 6545 Mercantile Way P.O. Box Lansing, Michigan (517) phone (517) fax MICHIGAN PUBLIC SERVICE COMMISSION STAFF David A. Voges Patricia S. Barone Kristin M. Smith Assistant Attorneys General Public Service Division 6545 Mercantile Way, Suite 15 Lansing, Michigan (517) phone (517) fax THE KROGER CO. Michael L. Kurtz Boehm, Kurtz & Lowry 2110 URS Center 36 East Seventh Street, Suite 2110 Cincinnati, Ohio (513) phone (513) fax Kevin Higgins Energy Strategies 39 Market Street, Suite 200 Salt Lake City, UT (801) phone (801) fax NATIONAL ENERGY MARKETERS ASSOCIATION; CONSTELLATION NEWENERGY, INC. John M. Dempsey, Jennifer L. Frye Dickinson Wright, PLLC 101 N. Main Street, Suite 535 Ann Arbor, Michigan (734) phone (734) fax Craig G. Goodman Stacey L. Rantala National Energy Marketers Association 3333 K Street, N.W. Suite 425 Washington, D.C NORDIC MARKETING, LLC. Joni M. Fixel Nordic Marketing, LLC 2010 Hogback Road, Suite 4 Ann Arbor, MI jfixel@baardpower.com ABATE Robert A. W. Strong Clark Hill PLC 255 S. Old Woodward Avenue, 3 rd Floor Birmingham, Michigan (248) phone (248) fax rstrong@clarkhill.com James T. Selecky Brubaker & Associates, Inc Fern Ridge Parkway, Ste 208 St. Louis, MO (314) phone (314) fax jtselecky@consultbai.com

4 MICHIGAN ATTORNEY GENERAL Donald E. Erickson Assistant Attorney General Special Litigation Division G. Mennen Williams Building 525 West Ottawa Street, Floor 6 P.O. Box Lansing, Michigan (517) phone (517) fax ericksond@michigan.gov RESIDENTIAL RATEPAYERS CONSORTIUM Diane R. Royal Shaltz & Royal, P.C W. Saginaw Street, Suite C-1 Lansing, Michigan (517) phone (517) fax shalroy@voyager.net ENERGY CONVERSION, LLC; NORTH AMERICAN WIND ENERGY, LLC; MACKINAW POWER, LLC; Robert C. Evans 4121 Okemos Road, Suite 17 Okemos, Michigan (517) phone (517) fax nanr@tcimet.net Richard F. Vander Veen 1102 Lincoln Lake Road Lowell, Michigan (616) phone (616) fax rfv3@baywindpower.com LOCAL 223, UTILITY WORKERS UNION OF AMERICA, AFL-CIO, MR. PIETRO ZEBRI, MR. DOUGLAS MOORE Samuel C. McKnight, David R. Radtke Klimist, McKnight, Sale, McClow & Canzano 400 Galleria Officentre, Suite 117 Southfield, Michigan (248) phone (248) fax smcknight@kmsmc.com dradtke@kmsmc.com ENERGY MICHIGAN Eric J. Schneidewind Varnum, Riddering, Schmidt & Howlett, LLP The Victor Center 201 North Washington Square, Suite 810 Lansing, Michigan (517) phone (517) fax ejschneidewind@varnumlaw.com Richard A. Polich Energy Options & Solutions 921 Pratt Ridge Ct. Ann Arbor, MI rpolich@umich.edu MEC/PIRGIM Donald L. Keskey Clark Hill, PLC 2455 Woodlake Circle Okemos, Michigan (517) phone (517) fax dkeskey@clarkhill.com THE DETROIT EDISON COMPANY William K. Fahey Stephen J. Rhodes Foster, Swift, Collins & Smith, P.C. 313 S. Washington Square Lansing, Michigan (517) phone (517) fax wfahey@fosterswift.com srhodes@fosterswift.com Bruce R. Maters Jon P. Christinidis Richard P. Middleton Michael J. Solocinski 2000 Second Avenue, 688 WCB Detroit, Michigan (313) phone (313) fax matersb@dteenergy.com christinidisj@dteenergy.com middletonr@dteenergy.com solocinskim@dteenergy.com S:\122\SJR\EDISON\13808\service list - newest list.wpd

5 STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of ) THE DETROIT EDISON COMPANY ) to increase rates, amend its rate schedules ) governing the distribution and supply of ) electric energy, implement Power Supply ) Cost Recovery plans, factors and reconciliation ) in its rate schedules for jurisdictional ) sales of electricity and for miscellaneous ) accounting authority and regulatory asset ) recovery. ) Case No. U THE DETROIT EDISON COMPANY S EXCEPTIONS THE DETROIT EDISON COMPANY Bruce R. Maters (P28080) Jon P. Christinidis (P47352) Richard P. Middleton (P41278) Michael J. Solocinski, Jr. (P57092) 2000 Second Avenue, 600 WCB Detroit, MI (313) William K. Fahey (P27745) Stephen J. Rhodes (P40112) Foster, Swift, Collins & Smith, P.C. 313 S. Washington Square Lansing, MI (517) Dated: September 16, 2004

6 TABLE OF CONTENTS INTRODUCTION... 1 EXCEPTIONS... 1 Exception No. 1. The PFD Incorrectly Ignores the PSCR, the Inclusion of Transmission Charges in the PSCR, and Wholesale Power Sales Mitigation....1 A. Detroit Edison s 2004 PSCR Plan....3 B. Changes in MISO and Transmission Charges Should be Recovered Through the PSCR Process...9 C. SO 2 Allowance Related Costs Should Be Recovered in the PSCR Process...12 D. PSCR Base and Factor...12 E. Mitigation...14 Exception No. 2. Rate relief must be based on Edison s projected 2004 test year because it provides the best representation of future business activity...18 I. RATE OF RETURN ADJUSTMENTS Exception No. 3. Edison should have a capital structure consisting of 50% equity and 50% debt Exception No. 4. The ALJ s recommendations of short-term debt in the amount of $279 million at an interest cost of 2.0% are erroneous...33 A. Staff was Inconsistent in its Approach and Recommendation B. Staff Understates Forecasted Short-Term Interest Rates...35 Exception No. 5. Edison s authorized return on common equity should be 11.5% A. Edison s Authorized Return on Common Equity Should be 11.5% Cost of Equity Estimates CAPM Estimates a. Risk Free Rate b. Beta c. Market Risk Premium d. CAPM Results ECAPM Estimates

7 4. Historical Risk Premium Estimates DCF Estimates B. Staff s Recommendation Should be Adjusted Upward C. The ALJ Erred in His Consideration of the Relationship of Return on Equity and Business Risk D. The ALJ Erred in His Consideration of the Relationship of Return on Equity and Capital Structure...45 E. The ALJ Erred in his Consideration of Flotation Costs...47 F. The ALJ Erred in his Consideration of the Common Equity Cost of Capital as Authorized in Other Jurisdictions G. The ALJ Erred in his Common Equity Conclusion...50 II. NET OPERATING INCOME ADJUSTMENTS Exception No. 6. The ALJ s assessment of Choice sales volume is inaccurate...50 Exception No. 7. The ALJ failed to properly calculate Edison s production O&M expense...53 Exception No. 8. The ALJ improperly recommends a reduction in Edison s recovery of its portion of the control premium from the acquisition of MCN Energy...55 III. REVENUE DEFICIENCY ADJUSTMENTS Exception No. 9. Edison s Revenue Deficiency is $582,635, IV. RATE DESIGN ADJUSTMENTS Exception No. 10. Allocation of Rate Increase to Retail Access Service Tariff and Bundled Tariffs (excluding deficiency attributed to Customer Choice)...62 Exception No. 11. Transitional Primary Supply Rate and the Imputation of Revenue Discounts Exception No. 12. The Commission should not follow the ALJ s recommendation on Electric Choice metering...65 Exception No. 13. Edison s proposals to change RAST Sections 2.4 and 2.6 should be adopted...68 ii

8 Exception No. 14. Energy Michigan s proposals regarding enrollment deadlines and penalties should not be adopted...70 Exception No. 15. Edison s proposal for telemetry for interval meters should be adopted...70 Exception No. 16. The PFD failed to address and approve Edison s proposal for changing the language of RAST Section Exception No. 17. The ALJ proposes significant modifications to the Commission s current interim stranded cost methodology A. A Regulatory Cost Adjustment Must Be Implemented to Address Existing Rate Subsidies...73 B. A Definitive Termination Date for Stranded Cost Recovery Cannot Occur Without Legislative Changes...77 C. Staff s Date for Termination of the Current Stranded Cost Methodology Does Not Comply with the Staff Report...78 D. Staff s New Definition of Stranded Cost Does Not Comply with its 1996 Report, Subsequent Commission Orders and Current Analysis Exception No. 18. The ALJ Erred in Accepting Staff s $43.6 million Historical Stranded Cost Amount which has Major Flaws in the Methodology Stranded Costs Through Year-End Stranded Costs Through the Date of the Interim Order Historical Net Stranded Cost Summary Exception No. 19. The ALJ is Incorrect That Edison has Accepted all of the Staff s Adjustments Regarding the Regulatory Asset Recovery Surcharge (RARS) Exception No. 20. The Commission Must Apply Consistency and Order the Use of the Authorized Pretax Rate of Return on all Unrecovered Regulatory Asset Balances...89 Exception No. 21. If the Commission Approves a Short-Term Carrying Charge of Only 7% for Implementation Costs, then Edison Should be Able to Begin Collecting Them Effective with the Final Order in this Case...90 Exception No. 22. Return to Service Criteria Must Be Definite and Fair Exception No. 23. Rider 4 should not be modified...93 Exception No. 24. The Commission Need Not and May Not Require a Detroit Edison Renewable Energy Program iii

9 A. Evaluation of Renewable Energy Resources must be conducted on a statewide basis using a common systematic analytical approach, or by the developers who stand to profit from the sale of the energy produced...96 B. Establishing a required amount of renewable energy to be sold by a utility is counter to the principles of Customer Choice...96 C. No separate reporting requirement relative to evaluating potential renewable energy sources and energy efficiency measures for meeting current and future environmental compliance costs should be imposed D. Renewable Energy Summary RELIEF iv

10 INTRODUCTION The Detroit Edison Company ( Edison or the Company ) submits these exceptions to the Proposal for Decision ( PFD ) issued on August 26, 2004 by Administrative Law Judge Daniel E. Nickerson, Jr. ( Judge Nickerson or the ALJ ). Edison has attempted to be succinct but complete in developing its exceptions. Further detail regarding Edison s positions and the reasons therefore on many of the exceptions presented herein may be found in Edison s May 14, 2004 Initial Brief and May 28, 2004 Reply Brief, and the attachments to those briefs, which are incorporated by reference herein. 1 For consistency and ease of reference, these exceptions are largely presented in the order that they arise in the PFD. EXCEPTIONS Exception No. 1. The PFD Incorrectly Ignores the PSCR, the Inclusion of Transmission Charges in the PSCR, and Wholesale Power Sales Mitigation. The PFD contains only the following discussion of Detroit Edison s 2004 PSCR Plan: Concerning Detroit Edison s proposal to conduct a Power Supply Cost Recovery Plan (PSCR) in the context of its general rate case pursuant to MCL 460.6j(18), Detroit Edison states: Detroit Edison will abide by the Commission s decision and therefore anticipates a separate 2004 reconciliation, and the filing of a separate 2005 plan case by September 30, The ALJ finds this is effectively a withdrawal of the request. There is considerable discussion and argument presented concerning whether transmission costs are properly included in the PSCR base and whether their approved recovery would constitute double recovery. The ALJ concludes that based on Detroit Edison withdrawing its PSCR proposal the issue is not properly before the Commission at this time. (emphasis added)(pfd, p 121) 2 1 Edison, of course, maintains all of its appellate rights. 2 The PFD also makes minimal (and unclear) references to zeroing out the PSCR upon issuance of a final order and what appears to be a $93 million mitigation requirement (Case No. U PFD dated August 26, 2004 pp 64, 70). 1

11 Detroit Edison submits that the ALJ s findings do not comport with what the Company said in its Reply Brief Concerning Final Rate Relief, and runs afoul of the Commission s December 18, 2003 Order restarting the PSCR clause for Detroit Edison in (Case No. U Order dated December 18, 2003, p.11). Detroit Edison s Reply Brief Concerning Final Rate Relief stated: The Attorney General reasserts his argument that Edison did not file a proper PSCR plan case (brief, pp ). Edison maintains that its filing was proper, as explained at pages 2-6 of its October 31, 2003 Reply Brief Concerning Implementation of the PSCR Process, and at pages of its February 10, 2004 Interim Reply Brief. The Commission, however, disapproved Edison s PSCR procedure in its December 18, 2003 Opinion and Order, and February 20, 2004 Interim Order. Kroger agrees (brief, p.2). As the Attorney General essentially asserts, Edison s filing is being considered as a conjoined PSCR plan case and general rate case, which have been combined under the same docket for hearing and administrative efficiency. R (5). The Attorney General states (brief, p. 19): At this date, this will mean that the Commission should conduct a 2004 PSCR reconciliation under MCL 460.6j(12)-(15) without applying MCL 460.6j(18) and should require DECo to file a 2005 PSCR plan case under MCL 460.6j(3)-(7). Edison will abide by the Commission s decision, and therefore anticipates a separate 2004 reconciliation, and the filing of a separate 2005 plan case by September 30, (emphasis added) (Detroit Edison s Reply Brief Concerning Final Rate Relief, pp 13-14) There is no question that the Commission must approve a 2004 PSCR plan and factor in this proceeding. 3 It appears that the PFD overlooked this necessity and wrongly assumed that all PSCR issues would be addressed in another docket. However, in reality, the 2004 PSCR Plan will be addressed in this docket. The Commission must approve Edison s 2004 Power Supply Plan, Factor and Base in this proceeding. As a conjoined PSCR plan case and general rate case, which have been combined under the same docket for hearing and administrative efficiency. (R (5)), the Attorney General s claim that Edison s PSCR request in this case does not comply with MCL 3 The Commission could have addressed the 2004 PSCR Plan in its February 20, 2004 Interim Order, but declined to do so. (Interim Order, p 39) 2

12 460.6(18) (Initial Brief, pp 17-19) will be rendered moot. In any case, the Commission must resolve a number of important issues that the PFD either left undecided or insufficiently addressed: 1. The Commission must approve a 2004 PSCR Plan; 2. The Commission must approve a new PSCR base and factor effective with the final order in this proceeding The Commission must include a determination of how to address SO 2 costs, NO x costs, and transmission costs in the PSCR process. 4. The Commission must address the treatment of wholesale power sales mitigation and related issues. A. Detroit Edison s 2004 PSCR Plan. On June 20, 2003 Detroit Edison filed its 2004 PSCR Plan and 5-year forecast ( ) in this proceeding. The Company has fully satisfied the filing requirements of MCL 460.6j. The Company s 2004 PSCR Plan is reasonable and prudent as illustrated below. 5 Staff has concluded that Edison s witnesses have adequately supported its projected fuel and purchased power costs. (14 T 2970) Mr. Byron testified that Edison s power supply actions and costs are reasonable and prudent in light of the significant and ongoing changes in the electric industry in Michigan and throughout the nation. Therefore, the Commission should approve Edison s 2004 power supply plan, as well as all of the costs and actions described in Mr. Byron s testimony and exhibits (5 T 538). Mr. Byron described Edison s Long Range Resource Plan (5 T ; Exhibit A-16, Schedule F2) to supply its summer bundled rate adjusted peak demand with resources available to Edison and additional summer purchased power as required for the years 2003 through This plan is based on Edison s reasonable load forecast as presented in the testimony of Dr. Aldo 4 The Commission approved a 2004 PSCR factor from January 1, 2004 to the date of the final order in this proceeding in its February 20, 2004 Interim Order at p Edison incorporates its prior filings, and notes that the issues appear to be narrowed due to the Staff s non-opposition to the inclusion of NOx allowance expense as PSCR costs (14 T 2968) and the Staff s acceptance of Edison s projected fuel and purchased power costs (14 T 2970). 3

13 Colandrea, the current net demonstrated summer operating capability of Edison s owned generation resources, the planned changes in capacity shown on Schedule F1 of Exhibit A-6, and the long-term purchased capacity that is under contract to Edison (5 T ). 6 Mr. Byron testified that Edison utilized the PROMOD IV System computer software to develop its power generation and purchased and net interchange power projections (5 T ). The methodology used to develop the information for the projections was similar to that used in previous filings with the Commission, with some changes in modeling the wholesale electric market (5 T ). He further testified that Exhibit A-16, Schedule F7-1 reflects the actual and projected purchases of power and energy for the years 2002 (actual) through 2008 (5 T 513) and he described those purchases (5 T ). Exhibit A-16, Schedule F2 shows that Edison projects to purchase 1,483 MW (rounded to 1,500 MW for summer planning) of total summer capacity for Of this amount, Edison projects to purchase 400 MW as 5x16" standard contracts for June through August, and the balance through a mix of call options (5 T ). Energy imbalance purchases and sales are not forecasted, but will be included with the purchases and sales of wholesale power as they 6 As of May 1, 2003, Edison s total owned summer capability was 11,043 MW, consisting of 7,913 MW from fossil steam plants, 1,111 MW from the Fermi 2 nuclear plant ( Fermi ), 917 MW from the Ludington Pumped Storage Hydroelectric facility ( Ludington ), and the Michigan Public Power Agency s ( MPPA ) control of 234 MW due to its ownership interest in the Belle River Power Plant (5 T ). With the Marysville Power Plant in cold standby status, however, Edison s 2003 summer available operating capability was 10,959 MW (5 T ). Edison has also contracted for 103 MW from PURPA Qualifying Facilities ( QF ), including contracts for purchases from waste-to-energy facilities that the Commission approved under 1989 PA 2 (5 T 499, ). Edison also anticipates seasonably purchasing power from the wholesale power market to achieve the total resources required to serve the forecasted adjusted bundled rate peak demand. Such purchases are economic and prudent given the uncertainties regarding the amount of Choice load and market prices (5 T ). 4

14 actually occur. It is anticipated that energy imbalance will be handled through the MISO energy market when it starts (5 T ). 7 Mr. Byron testified that Exhibit A-16, Schedule F8-1 shows the actual electric generation and fuel expense that Edison incurred in Schedules F8-2 through F8-7 show the projected electric generation and fuel expense by plant for each year, as developed through the use of the PROMOD IV production cost simulation computer program (5 T ). 8 Mr. Byron testified that Exhibit A-16, Schedule F11-1 shows a summary of all fuel and purchased power costs by the various categories from 2002 through 2008 (5 T 530). Dr. Aldo F. Colandrea, the Company s Corporate Forecaster, testified that: Service area sales are forecast to increase from 52,038 GWh in 2002 to 62,232 GWh in This represents a 1.8% average annual increase in sales. Bundled sales are forecast to decrease from 49,047 GWh in 2002 to 43,266 GWh in This represents a 1.2% average annual decline in sales. This is due to the growth in Electric Choice sales expected in this period. (4 T 119). 9 He added that the forecast is consistent with the 1.9% average annual increase in sales from 1997 through 2002 (4 T 120). After explaining the general forecasting methodology, assumptions, data sources, and reliability (4 T ), Dr. Colandrea went on to explain that service area Residential Class Sales will grow 1.3% annually, on average, through 2012 (4 T 125); service area Commercial Class Sales 7 Mr. Byron also explains and justifies the cost impacts of the reconfigured transmission regulatory environment and describes how these costs should be accounted for and recovered on a goingforward basis. (5T 527). 8 Related PSCR expenses for SO2 and NOx are also explained and justified by Mr. Byron. (5 T ; Exhibit A-16 Schedules F8-8 and F8-9). 9 The forecast of annual sales and system output for Edison s service area, for years 2003 through 2012, is described in Exhibit A-16, Schedule F1-2. This schedule also includes historical data back to The forecast of bundled sales and output is described in Exhibit A-16, Schedule F1-2, Page 2 of 4. The forecast of Electric Choice sales is described in Exhibit A-16, Schedule F1-2, Page 3 of 4 (4 T 116). 5

15 will grow 2.5% annually, on average, through 2012 (4 T 126), and service area Industrial Class Sales will grow 2.5% annually, on average, through 2012 (4 T 128). Dr. Colandrea explained that Edison forecasts annual and monthly peak demands by using HELM, which aggregates hourly demand profiles from various sales or end uses into a system annual loadshape (4 T ). Service area system peak demand is forecast to increase from 12,085 MW in 2002 to 14,038 MW in 2012, an average compound annual growth rate of 1.5% (4 T 130). Bundled peak demand is forecast to decline from 11,423 MW in 2002 to 10,833 MW in 2012, an average compound annual growth rate of -0.5% primarily due to increased Electric Choice sales. Dr. Colandrea s forecast is based on, and consistent with, a variety of well-regarded economic forecasts and data sources (4T ). Mr. Lapplander explained the method that Edison used to develop its fuel forecasts for 2003, 2004, and for years 2005 and beyond (5 T ). Edison s method of fossil fuel forecasting is reasonable and prudent (5 T 445). Mr. Lapplander supported Edison s total unit fuel prices and total fuel expenses for all Edison fossil-fueled plants (reflected on Exhibit A-16, Schedules F 8-1 through F 8-7, for the years 2002 through 2008) as reasonable and prudent (5 T 441, ). He further supported the coal, oil and gas prices for 2002, and the forecast of prices for those fuels in 2003 through 2008 (reflected in Exhibit A-3, Schedule F10) as reasonable and prudent (5 T 441,446). He explained that, as shown on Schedule F10, Edison expects coal expense to decline through 2005 and increase slightly for the remainder of the forecast. Oil expense is expected to decline in the short term and remain flat for the longer term. Natural gas expense is forecasted to decline from 2003 to 2006 and then increase slightly for the remainder of the forecast (5 T ). Edison s total actual and projected generation and purchase power costs for 2002 through 2008 are summarized on Exhibit A-16, Schedule F11-1. Mr. Lapplander supported the fossil fuel expense for electric generation and industrial steam expense set forth on Lines 4 and 25 (5 T 447). 6

16 Mr. Lapplander testified that Edison expects to supply its projected coal purchases for the forecast period through a combination of long-term and spot market purchases. This mix of purchases provides reliability of supply with sufficient flexibility to meet the needs of the electric generating plants (5 T 450). 10 Edison expects to supply the No. 2 oil that will be consumed in the forecast period under agreements that are less than one year in duration. Edison expects to supply its No. 6 oil requirements under agreements of similar duration, plus monthly spot market purchases (5 T 452). Edison expects to supply its natural gas requirements through purchases from local distribution companies under Commission-approved tariffs plus spot market purchases (5 T 453). Mr. Lapplander testified that the long-term forecast of coal prices assumes that Edison will continue to rely on low sulfur western (LSW) coal for a significant portion of its coal requirements (5 T 453). He then summarized why Edison s fuel supply plan is reasonable and prudent: I believe that we have developed a fuel supply plan that meets Detroit Edison s requirements, is consistent with both the Company s policy and objectives, delivers electric generation to Detroit Edison customers at a reasonable price consistent with reliable supply and is otherwise both reasonable and prudent. The Company has aggressively tested LSW coal at various Company electric power plants. This supply option is not only economic but also among the cleanest coals available. The Company has also continued to expand the arena of competition for both eastern and western coals. The ability to blend and burn coals from several coal supply regions along with utilizing multiple transportation options has provided the Company with the leverage to negotiate the most competitive delivered fuel prices available. 10 The Company has also prudently managed its fossil generation fleet to ensure economic generation unit availability. Mr. Baig explained Detroit Edison will continue to focus on maintaining high summer availabilities and low summer ROR s [Random Outage Rates] for its fossil plants through the forecast years. Such actions go a long way toward insulating the Company s electric customers from the volatile summer wholesale power markets. (4T 327) 7

17 The Company maintains one of the largest utility railcar fleets, not only to facilitate control over delivery of coal but also to optimize the cost savings associated with rail moves in private equipment. The Company continues to aggressively market coal and transhipment services to third parties through its subsidiary, MERC. Third party revenues and the equity received from MERC s joint venture contribute to a significant reduction in Detroit Edison fuel expense and thus the ultimate electric rates for Detroit Edison electric customers. The Company is also determined to pursue all reasonable avenues to resolve disputes with its suppliers, including negotiation, arbitration and litigation, if necessary. Considering the above as well as the actions the Company has taken to minimize fuel costs, and given that the Company expects to provide a majority of its fossil fuel requirements with coal, I believe that Detroit Edison s present fuel supply policy, objectives, and strategies (as set forth in my testimony and exhibits) are reasonable and prudent. (5 T ). Mr. Colonnello explained that nuclear fuel expenses directly tied to projected generation use are shown on Line 16 of Exhibit A-16, Schedule F5-1.1a. Relatively small additional fuel expenses are anticipated between years 2004 and 2005 as well as 2007 and 2008 in connection with the economic Extended Power Uprate project to increase Fermi s net generation (4 T 207). Fermi fuel expenses are directly dependent on expected generation targets and include the compulsory annual fee and disposal fees paid to the Department of Energy ( DOE ) (4 T ). Mr. Colonnello supported Fermi s fuel expenses, testifying: I believe these fuel expenses will be equal to or better than industry median performance. Historically, Fermi has been extremely successful in managing its fuel expense. Since 1999, we have reduced our fuel expense from $6.56/MWh to the projected 2003 expense of $3.92/MWh. This represents approximately a 40% reduction. I am confident we can continue to manage these expenses effectively going forward and therefore, I believe the projected fuel costs for Fermi are reasonable and prudent. (4 T ). 8

18 He further explained the concerted efforts that contributed to Fermi s success in significantly reducing its fuel expenses (4 T ). In summary, with respect to Fermi s O&M and fuel expense levels, Mr. Colonnello testified: I consider these expenses to be prudent and reasonable. I believe, based on historical performance that the assumptions relative to plant performance used in my projections are reasonable. Specifically, since 1998, the plant has demonstrated significant improvements in capacity factor, UCLF and in reducing overall costs. In fact, in 1999 Fermi 2 had the highest capacity factor of any boiling water reactor (BWR) in the U.S. and was second in the world. Similarly, we have reduced direct O&M expenses by 5% since 1998 while absorbing economic escalations. I believe Fermi 2 has demonstrated significant performance improvements by utilizing resources prudently and effectively. (4 T 211). Mr. Colonnello also explained that Edison strives to ensure that, during high demand periods like the summer months, Fermi 2 runs with a low Unplanned Capacity Loss Factor ( UCLF ). This minimizes the risk of having to purchase power on the spot market at high prices, which in turn minimizes fuel supply costs and customers exposure to such costs under the PSCR mechanism. Fermi has realized significant UCLF improvement, and its performance since 1999 is comparable with industry median performance (4 T 205; Exhibit A-16, Schedule F5-1.3). As is evident from the above evidence, Detroit Edison has developed a cogent and reasonable power supply cost recovery plan and 5-year forecast. B. Changes in MISO and Transmission Charges Should be Recovered Through the PSCR Process. Transmission and Midwest Independent System Operator ( MISO ) charges were not included in the PSCR process for purposes of Edison s request for interim relief. The Commission found that those costs were reasonable and should be included in base rates for purposes of interim relief (Interim Order, p 48). The Commission added that the vehicle for the future recovery of such costs should be deferred to the final order (Id). 9

19 Mr. Champley explained that in response to MCL w, MPSC and FERC policy, DTE divested its transmission system by selling its affiliate, The International Transmission Company ( ITC ), to an independent third party. Edison no longer owns the transmission system in its service territory and now purchases transmission service for its customers pursuant to FERC rates (5 T 521). 11 Mr. Byron further explained that Edison now relies on ITC to transmit electric capacity and energy to its distribution systems in Southeast Michigan. ITC is a member of the MISO and has transferred the responsibility for most of the operations of its transmission system to MISO. Thus, when obtaining the needed transmission services to and throughout its service territory, Edison does and will pay for its transmission and associated services based on the FERC approved rates for ITC and MISO transmission services. 12 The network transmission expense is accounted for as O&M expense Each investor-owned electric utility in this state shall, at the utility s option, either join a FERC approved multistate regional transmission system organization or other FERC approved multistate independent transmission organization or divest its interest in its transmission facilities to an independent transmission owner. MCL w(1). 12 FERC has jurisdiction over the rates, charges, rules and regulations concerning transmission service pursuant to Sections 201, 205 and 206 of the Federal Power Act (16 USC 824; 824d and 824e) FERC-approved charges for transmission service to retail customers must be passed through by the MPSC. As established in the pre-emption doctrine, and explained by the US Supreme Court in Fidelity Federal Savings & Loan Assoc. v. De La Cuesta: The pre-emption doctrine, which has its roots in the Supremacy Clause, U.S. Const., Art VI, cl. 2, requires us to examine congressional intent. Preemption may be either express or implied, and is compelled whether Congress command is explicitly stated in the statutes language or implicity contained in its structure and purpose. [citation omitted] Absent explicit pre-emptive language, Congress intent to supercede state law altogether may be inferred because [the] scheme of federal regulation may be so pervasive as to make reasonable the inference that Congress left no room for the States to supplement it, because the Act of Congress may touch a field in which the federal interest is so dominant that the federal system will be assumed to preclude enforcement of state laws on the same subject, or because the object sought to be obtained by the federal law and character of obligations imposed by it may reveal the same purpose. [citation omitted] Even where Congress has not completely displaced state regulation in a specific area, state law is nullified to the extent 10

20 All MISO charges in Edison s case are developed from the bundled customers requirement and do not include the Choice customers or wholesale sales for resale transmission expense. 14 In any event, the PSCR process will allow parties to annually scrutinize these expenses. All network MISO charges, except Schedule 17, are calculated from bundled customer demand or load. Schedule 17 is based on injection/withdrawal of energy from the transmission system, and Edison s Schedule 17 costs do not include Choice. The Staff agrees that network transmission expenses should be included as PSCR costs, in accordance with prior Commission decisions (14 T ). See also, Michigan Environmental Council v Public Service Comm, unpublished opinion per curiam of the Court of Appeals, decided May 11, 2004 (Docket Nos and ). that it actually conflicts with federal law. Such a conflict arises when compliance with both federal and state regulations is a physical impossibility, [citation omitted] or when state law stands as an obstacle to the accomplishment and execution of the full purposes and objectives of Congress. [citations omitted] Federal regulations have no less preemptive effect than federal statutes. Fidelity Federal Savings & Loan Assoc. v. De La Cuesta, 458 U.S. 141, ; 102 S. Ct (1982). Furthermore, under the Narragansett Doctrine as established in Narragansett Electric Co. v. Burke, a State PUC may not reopen the issue of the reasonableness of a FERC-approved rate. Narragansett Electric Co. v. Burke, 119 R.I. 559, 381 A.2d 1358 (1977), cert denied, 435 U.S. 972 (1978). 13 Exhibit A-16, Schedule F7-4, is the actual (2002) and projected, 2003 through 2008, bundled customer network transmission expense detailed as network transmission Schedules 1 and 9 expense; MISO Schedules 10, 16, and 17 expense; FERC transmission expense, and SECA transmission expense. Schedules 1, 9, 10, 16, and 17 are transmission and ancillary service schedules for transmission service under the MISO Open Access Transmission Tariff (OATT) as filed with FERC. As a network customer, these are non-bypassable charges to Edison and Edison is required to purchase each of these services from MISO. Once the Commission grants approval, the network transmission expense will be included in the PSCR (5 T ). 14 See for example, Marketer means an entity that (i) generates, brokers, markets or otherwise procures power to be supplied to ITC at the transmission Point of Receipt, obtains transmission services and with whom a customer s Alternative Electric Supplier has arranged for the Receipt of Power (emphasis added) (Edison RAST Sec. 1.4); FERC Electric Tariff 4 of the Detroit Edison Company and associated service agreements. 11

21 Mr. Falletich explained that there is no merit in ABATE s assertion that the addition of transmission to PSCR costs would result in industrial customers being charged twice for the same transmission. This is a rate design issue that results in no change to the total revenues collected from the industrial class (13 T 2892, ). 15 C. SO 2 Allowance Related Costs Should Be Recovered in the PSCR Process. Staff witness Mr. Ancona recommends that sulfur dioxide (SO 2 ) allowance expense should not be included as a PSCR expense (14 T 2968). Mr. Byron explained, however, that it is appropriate to recover the prudently-incurred costs of SO 2 emissions allowances through the PSCR mechanism, because Edison s practice of purchasing SO 2 emission allowances and higher sulfur coal results in the lowest total Clean Air Act compliance costs. Alternatively, Edison could burn more low sulfur, higher-cost coal (subject to practical limitations in fuel blending necessary for equipment performance), to meet the Clean Air Act s requirements. Such higher fuel costs would be passed on to Edison s customers, who instead now enjoy savings from SO 2 allowances, which are, in effect, a component of the as burned booked cost of coal (13 T ). SO 2 allowances are an integral part of prudent fuel procurement and utilization, so their costs should be included as an expense recoverable through the PSCR clause (13 T ). Because SO 2 allowances must be secured in order to burn the fuel, and are utilized or used up in the process of burning the fuel, they are in fact a booked cost of fuel burned for electric generation and vary with the amount of generation output. Mr. Ancona agreed with the Company s proposal to include NO x allowances in the PSCR. The same rationale applies to both NO x and SO 2. D. PSCR Base and Factor 15 This is true because the PSCR Base itself is not billed to customers as a specific identifiable charge but instead is a compilation of costs that are billed elsewhere in base rates. Operation of the PSCR clause will, of course, reflect the up or down changes in transmission expenses from year to year and result in incremental adjustments in revenues. 12

22 The ALJ found that the PSCR factor may be reset to zero effective with the final order in this case. (PFD, pp 69-70). The ALJ did not discuss the base point or loss multiplier that must accompany the PSCR factor in accordance with Rule B-4.6, Power Supply Cost Recover Clause, of Edison s Tariff. Edison witness Falletich proposed that the existing PSCR base, PSCR factor, and loss factor included in the Company s Tariff Rule B-4.6 be revised to reflect not only the level of the Company s forecasted 2004 power supply expenses, but also for the recovery of transmission expenses associated with the procurement of transmission services from the ITC and the MISO (10 T ). Power supply expense levels were based on those costs supported by Mr. Byron and included fuel costs, power purchases, interconnection revenue, transmission costs, and emission allowance costs for SO 2 and NOx. The proposed changes would be implemented coincident with a final order in this case. Mr. Falletich proposed that the existing PSCR base of mills/kwh be revised to mills/kwh if the Commission approves the recovery of transmission costs through the PSCR mechanism. If transmission costs are not included, Mr. Falletich stated that the proposed PSCR base would be mills/kwh. In addition, the PSCR factor would be reset to 0.00 mills/kwh and the existing Rule B-4.6 loss factor of 7.8% would be revised to 7.2%. Staff witness Ancona also proposed a revised PSCR base. Mr. Ancona utilized the same fuel expenses and purchased power expenses and also stated that the Staff does not oppose inclusion of network transmission expenses as PSCR costs (14 T 2968). Mr. Ancona did include two adjustments to Edison s fuel base calculations. First, Mr. Ancona excluded SO 2 allowance expenses as PSCR costs. Second, as part of Staff s Choice Sales mitigation proposal, Mr. Ancona did not utilize the revenue from third party sales as an offset to PSCR costs. Mr. Ancona s proposed PSCR loss factor and PSCR base are shown on Exhibit S-123, lines 12 and 13 as (7.2%) and $ /kWh (18.55 mills/kwh) respectively. Edison, as discussed previously, opposes Mr. Ancona s exclusion of SO 2 allowance expense because the least cost environmental compliance 13

23 strategy to meet SO 2 emission limits is a combination of burning low sulfur coal and utilizing SO2 allowances. In effect, SO 2 allowances are, therefore, a component of the as burned booked cost of coal and should be recovered through the PSCR process. 16 (13 T ) In order to be consistent with other portions of the PFD which adopted the Staff s case, Edison believes the Staff Exhibit S-123 (Revised) must form the basis for determining the PSCR base. On Exhibit S-123 (revised), Staff developed a PSCR Base at Generation value of $ per kwh using a loss multiplier of The Staff s base includes transmission expense as developed by Mr. Byron on Exhibit A-16, Schedule F 7-4 and is inclusive of Network Transmission, MISO charges, FERC Transmission, and SECA Transmission as explained by Mr. Byron at 5 T As explained earlier, Edison believes that SO 2 allowance expense that Staff removed on Exhibit S- 123 (Revised) should be included and would increase the base by: $1,450,000 43,788 GWh = $ per kwh Adding this into the PSCR base increases the PSCR base at generation to $ per kwh. Edison believes that a PSCR Base of $ per kwh is appropriate when taken in context with the Staff s Choice sales mitigation proposal, discussed in the following section E, and the ALJ s finding that Detroit Edison s backfill proposal should be approved. 17 (PFD, pp 69-70). E. Mitigation 16 MCL 460.6j(l)(a) provides in pertinent part: Power supply cost recovery clause means a clause in the electric rates or rate schedule of a utility which permits the monthly adjustment of rates for power supply to allow the utility to recover booked costs, including transportation costs, reclamation costs, and disposal and reprocessing costs, of fuel burned by the utility for electric generation and the booked costs of purchased and net interchanged power transactions by the utility incurred under reasonable and prudent policies and practices. 17 Edison s backfill proposal is discussed at 6 T 767, 10 T 1577 and 10 T Staff s discussion appears at 14 T As discussed in Edison s testimony, the Company proposes to include the total rate increase surcharge in the tariff, but implement only to a level not to exceed the rate level approved for customers under existing Commission approved tariffs. 14

24 While far from clear, it appears that the ALJ has accepted the Staff s position that Detroit Edison is required to mitigate the production fixed costs associated with electric customers that abandon Detroit Edison generation assets in favor of Alternative Electric Supplier generation resources. 18 Conceptually, this Staff position appears to mean that Detroit Edison s traditional generation revenue deficiency has been reduced (ie. Edison cannot recover the deficiency from its remaining bundled customers) and the Company has been charged with the responsibility to sell the output of its freed-up generation at wholesale to attempt to recover what it can in the wholesale electric market. Thus, in the PSCR process, Edison would no longer credit PSCR customers with all of the proceeds from its wholesale interconnection sales to third parties. 19 Edison would instead retain 90% of the proceeds from these wholesale interconnection sales to third parties as a means to mitigate a portion of the significant financial impact caused by the exodus of retail Choice customers. To the extent that interconnection sales exceed 110% of Choice sales volume on an annual basis, all net proceeds from those sales will be credited to PSCR customers. (Ancona Testimony, 14 T 2972) The specifics of the process can best be illustrated in the following table: FOR ILLUSTRATIVE PURPOSES ONLY Previous PSCR Proposed Staff Treatment Treatment Fuel Costs for Generation($million) The PFD describes a $93,113,000 reduction in Detroit Edison s revenue deficiency as an Adjustment to Revenue Deficiency. (PFD, p. 64) This number corresponds exactly to the amount of the Staff s position as calculated on Exhibit S-118, Schedule A-3. It is assumed that the current $93,113,000 million amount is linked to Staff s presently predicted Choice sales level of 7,565 GWh and would change to match the amount of Choice sales determined in the final order in this proceeding and in subsequent Edison rate cases. 19 It would only make sense that Edison s total mitigation would constitute only the amount of revenue received in excess of its average jurisdictionalized power supply costs. Average jurisdictionalized power supply costs would, of course, include (a) PSCR Sales and Mitigation Sales less R-10 and other interruptible sales, and (b) SO 2 and NO x Emissions costs; and exclude jurisdictionalized network transmission costs associated with bundled sales. 15

25 Purchased Power Costs($million) Total Expense($million) Total (PSCR + Interconnection) Sales(GWh) 50,000 50,000 Average Power Supply Cost($/MWh) Total Choice Sales (GWh) 7,565 7,565 Interconnection Sales (GWh) 6,000 6,000 Avg Sale Price($/MWh) Avg Net Proceeds($/MWh) Net Proceeds($million) Edison Share($million) 0 92 PSCR Share($million) The adoption of the Staff s Choice Mitigation proposal naturally, results in a few modifications to Edison s 45 day PSCR report required by MCL 460.6j(11), which the Commission should adopt in its final order in these proceedings. The adoption of these changes should be effective February 20, 2004, the date of the Interim Order. For instance, Edison would (1) make an adjustment to the net over(under)recovery equivalent to 90% of the proceeds from interconnection sales which are less than or equal to 110% of annual Choice sales, (2) determine the Expense Allocation Factor to be applied to Total Power Supply Costs based upon PSCR and interconnection sales, (3) report and account for interconnection sales within a particular reporting month that exceed 110% of Choice sales such that the 90%/10% net proceed split applies given that annual 16