Loading...
The URL can be used to link to this page
Your browser does not support the video tag.
Resolution No. 8430
2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 0M W-A 0 ! RESOLUTION NO. 8430 A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF VERNON AMENDING RESOLUTION NOS. 7608 AND 7659 IN ORDER TO AMEND THE TRANSMISSION REVENUE REQUIREMENT ASSOCIATED WITH VERNON'S HIGH VOLTAGE TRANSMISSION FACILITIES AND ENTITLEMENTS THAT WERE TURNED OVER TO THE OPERATIONAL CONTROL OF THE CALIFORNIA INDEPENDENT SYSTEM OPERATOR WHEN VERNON BECAME A PARTICIPATING TRANSMISSION OWNER WHEREAS, the California State Legislature adopted AB 1890, which created the California Independent System Operator ("CAISO") and required the CAISO to file a Transmission Access Charge ("TAC") tariff with the Federal Energy Regulatory Commission ("FERC") that would establish TACs for high voltage transmission service within the State of California; and WHEREAS, on May 31, 2000, FERC accepted CAISO's proposed amended TAC tariff for filing and ordered the CAISO to make a compliance filing in accordance with its order; and WHEREAS, on June 30, 2000, in accordance with the CAISO TAC tariff, Vernon provided its notice of intent to become a Participating Transmission Owner ("PTO"); and WHEREAS, Vernon, a municipal utility, was the first utility that was not subject to FERC's jurisdiction under section 205 of the Federal Power Act ("FPA"), to apply to become a PTO; and WHEREAS, in order to become a PTO, pursuant to the TAC tariff, Vernon was required to turn over the operational control of Vernon's transmission facilities and entitlements to the CAISO. In return, the CAISO was required to reimburse Vernon its Transmission Revenue Requirement ("TRR") relating to such transmission facilities and entitlements; and 0 9 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 WHEREAS, Vernon undertook all of the tasks necessary for it to become a PTO by January 1, 2001. Among other things, Vernon executed the Transmission Control Agreement ("ITCA") with the CAISO, which governs many aspects of PTO status and operations, including the CAISO's acquisition of operational control of Vernon's transmission facilities and entitlements; and WHEREAS, on February 21, 2001, FERC approved the TCA (94 FERCI 1 61,141 (2001)); and WHEREAS, on August 29, 2000, the City Council held a duly noticed public hearing, during which it considered the appropriate TRR for Vernon. After considering the evidence, including the testimony of an expert rate consultant, Albert Clark, the City Council established Wernon's TRR; and WHEREAS, on August 30, 2000, Vernon filed a petition for declaratory order with FERC, in which it requested that FERC accept the TRR established by the Vernon City Council; and WHEREAS, on October 27, 2000, FERC accepted Vernon's TRR, with certain adjustments, and made it effective as of January 1, 2001; and WHEREAS, on November 7, 2000, the Vernon City Council held another duly noticed public hearing during which it considered the FERC's rulings. After considering the evidence submitted at that public hearing, the City Council decided to accept the adjustments requested by FERC and, therefore, pursuant to Resolution No. 7659, approved a revised TRR; and WHEREAS, pursuant to Section 203 of the FPA, the CAISO filed (FERC Docket No. EC01-14) for approval of the transfer of Vernon's transmission facilities and entitlements to the CAISO's operational - 2 - 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 1control. In that filing, the CAISO established that the transfer of (such assets was in the public interest and was beneficial to the CAISO; land WHEREAS, on January 9, 2001, FERC approved the CAISO's Sectior 203 filing (California Independent System Operator Corp., 94 FERC 1 62,016 (2001)); and WHEREAS, on March 28, 2001, FERC approved Vernon's compliance filing as to Vernon's revised TRR (94 FERC 1 61,344) and; WHEREAS, Pacific Gas and Electric Company ("PG&E") and Southern California Edison Company ("SCE") petitioned for review of FERC's October 2000 and February 2001 orders, to the Circuit Court for the District of Columbia; and WHEREAS, on October 15, 2002, the Court remanded to FERC the question of whether the review conducted by FERC of the TRR for a non - jurisdictional entity - Vernon - that is part of the jurisdictional CAISO, was sufficient to ensure that the CAISO's rates will be just and reasonable under section 205 of the FPA; and WHEREAS, on February 17, 2004, in response to the Court's order on remand, FERC ordered that a hearing be held to explore the appropriate TRR for Vernon that will ensure that the CAISO's rates after the inclusion of Vernon's TRR, are just and reasonable; and WHEREAS, in response to FERC's order, Vernon posted Notice of Public Hearing on April 12, 2004, notifying all interested parties that the City Council would hold a public hearing to consider evidence to review and establish Vernon's TRR. The hearing was opened on April 21, 2004, and continued to April 26, 2004, and provided a reasonable opportunity for persons to comment on the establishment of Vernon's TRR and submit appropriate evidence in connection with such determination; - 3 - • 0 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 land WHEREAS, the City Council has heard and considered all evidence, both written and oral, including the testimony of experienced ratemaking, depreciation and rate of return experts: Baker G. Clay of Baker G. Clay and Associates; Edward H. Feinstein of Brown, Williams, Moorhead & Quinn, Inc.; and Frank J. Hanley, CRRA, of AUS Consultants - Utility Services. Such experts have recommended that the Vernon City Council revise its TRR; and; WHEREAS, based upon the testimony and evidence presented at the time of the public hearing, the City Council desires to amend Resolution Nos. 7608 and 7659, in order to revise the TRR for Vernon's transmission facilities and entitlements that were turned over to the operational control of the CAISO on January 1, 2001, when Vernon became a PTO. NOW, THEREFORE, BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY OF VERNON AS FOLLOWS: SECTION 1: The City Council of the City of Vernon hereby (finds and determines that the recitals contained hereinabove are true and correct. SECTION 2: The City Council of the City of Vernon further finds that all persons have had the opportunity to be heard or to file written comments to the proposed establishment of Vernon's Transmission Revenue Requirement, and after due consideration of the evidence submitted at the public hearing determines that there is substantial evidence in the record to justify the revision of Vernon's Transmission Revenue Requirement. SECTION 3: The City Council of the City of Vernon hereby Japproves, for ratemaking purposes, the depreciation study and - 4 - 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 depreciation composite rate of 3.14 percent (3.14%) recommended in the written testimony of Edward H. Feinstein, a copy of which is attached hereto as Exhibit "A" and made a part hereof. SECTION 4: The City Council approves the rate of return study prepared by Frank J. Hanley, which is set forth in his written testimony, a copy of which is attached hereto as Exhibit "B" and made a apart hereof. SECTION 5: The City Council approves the study prepared by Baker G. Clay, which is set forth in his written testimony, a copy of 1which is attached hereto as Exhibit "C" and made a part hereof. SECTION 6: The City Council of the City of Vernon hereby finds, for the reasons set forth in the testimony of Baker G. Clay, that it was constrained from making economic use of the California - Oregon Transportation Project ("COTP") facility until January 1, 1996, and that therefore, it is appropriate to not begin depreciation on the COTP until January 1, 1996, when the facility became useful to Vernon and its customers. As such, the accrual of allowance on funds used during construction ("AFUDC") on the COTP until January 1, 1996, was necessary and fair in order to allow Vernon to earn a fair return on it's investment. SECTION 7: The City Council of the City of Vernon hereby approves the recommendation of Baker G. Clay to maintain the 9.29 percent (9.29%) rate of return that was previously approved by the City Council and accepted by FERC, for purposes of determining Vernon's TRR. SECTION 8: The City Council of the City of Vernon hereby approves the revised recommended total TRR for Vernon's transmission facilities and entitlements of Twelve Million Two Hundred Fifty Three Thousand Seven Hundred Ninety Seven Dollars ($12,253,797.00), that has - 5 - • In 2 3 4 5 6 7 8 9 WIN 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 been recommended in the written testimony of Baker G. Clay. SECTION 9: The City Council will delay amendment to Vernon's TO Tariff to reflect the revised TRR until FERC determines that when IVernon's TRR is included in the CAISO's rate, the CAISO's rate will (remain just and reasonable. SECTION 10: The City Council of the City of Vernon hereby approves the written testimony of consultants, Baker G. Clay, Edward Feinstein and Frank Hanley, and authorizes Vernon's staff and Legal Counsel, to file such testimony, as well as this Resolution, with the FERC for purposes of FERC's review and determinations relating to the justness and reasonableness of the CAISO's rates after the inclusion of the TRR for the transmission facilities and entitlements that Vernon has turned over to the operational control of the CAISO. SECTION 11: Any conflicting or inconsistent terms or provisions in Resolution Nos. 7608 and 7659, are hereby repealed. SECTION 12: The City Clerk of the City of Vernon shall certify to the passage of this resolution, and thereupon and thereafter the same shall be in full force and effect. APPROVED AND ADOPTED this 26th day of April, 2004. ATTEST: BRUCE V. MALK NHORST, City Clerk LEONIS C. MALBU , Mayo - 6 - 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 STATE OF CALIFORNIA ) ) ss COUNTY OF LOS ANGELES ) I, BRUCE V. MALKENHORST, City Clerk of the City of Vernon, do hereby certify that the foregoing Resolution, being Resolution No. 8430, was duly adopted by the City Council of the City of Vernon at an adjourned regular meeting of the City Council duly held on Wednesday, April 26, 2004, and thereafter was duly signed by the Mayor of the City of Vernon. (SEAL) K - I z1f, BRUCE V. MALKENHORST, City Clerk - 7 - EXHIBIT • Ocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 1 of 19 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION City of Vernon, California ) Docket No. EL00-105-007 California Independent System ) Docket No. ER00-2019-007 Operator Corporation ) PREPARED INITIAL TESTIMONY OF EDWARD H. FEINSTEIN ON BEHALF OF THE CITY OF VERNON, CALIFORNIA 1 I. QUALIFICATIONS AND SCOPE OF TESTIMONY 2 3 A. Qualifications 4 Q. Please state your name and business address. 5 A. My name is Edward H. Feinstein and my business address is 1155 15ffi 6 Street, N.W., Suite 400, Washington, D.C. 20005. 7 Q. Please state your occupation. 8 A. I am a consulting petroleum engineer and Vice President with the firm 9 of Brown, Williams, Moorhead & Quinn, Inc. 10 Q. Please briefly describe your education, background and training. 11 A. I received my Bachelor of Petroleum Engineering degree at the 12 University of Tulsa in May 1963. From July 1963 to February 1998, I 13 worked at the Federal Energy Regulatory Commission ("Commission") 14 and its predecessor, the Federal Power Commission ("FPC"). From the 15 time of my employment at the FPC until approximately 1970, I was acket Nos. EL00-105, et al. Exhibit No. VER-4 Page 2 of 19 1 engaged in work involving economic feasibility studies in certificate 2 proceedings under the Natural Gas Act ("NGA"). This work was 3 concerned primarily with market, engineering, and financial analyses 4 for the purpose of determining the economic feasibility of pipeline 5 projects proposed in certificate applications. From 1970 to the present, 6 my efforts have been concentrated on determining the appropriate 7 depreciation rates for oil and gas pipeline facilities, including the 8 determination of potential supplies of oil and natural gas, and with other 9 rate issues such as storage utilization, operations and cost allocation and 10 gathering rates. During my nearly 35 years with the Commission, I 11 earned positions of increasing responsibility, including Chief of the 12 Depreciation Branch. In March 1998, I joined the firm of Brown, 13 Williams, Scarbrough and Quinn, Inc., precursor to Brown, Williams, 14 Moorhead & Quinn, Inc. 15 Q. Are you a member of any professional societies? 16 A. Yes. I am a member of the Society of Depreciation Professionals and 17 the Society of Petroleum Engineers. 18 Q. Have you testified in proceedings before the FPC and the FERC and 19 state regulatory commissions? Socket Nos. EL00-105, et al. Exhibit No. VER-4 Page 3 of 19 1 A. Yes. I have presented testimony in many different areas, including 2 electric, oil, and gas depreciation and salvage studies. They are listed in 3 Exhibit No. VER-5. 4 B. Scope of Testimony 5 Q. On whose behalf are you presenting testimony in this proceeding? 6 A. My testimony addresses the determination of an appropriate 7 depreciation rate to be applied to the City of Vernon's ("Vernon") 8 depreciable and amortizable electric transmission and general plant 9 properties that have been turned over to California Independent System 10 Operator Corporation ("CAISO") operational control, effective January 11 1, 2001. In this testimony, I present the results of my depreciation 12 study. My supporting schedules are found in Exhibit No. VER-6. 13 Q. Would you please summarize the results of your depreciation analysis 14 for Vernon's transmission and general plant turned over to CAISO 15 control? 16 A. As a result of my studies and determinations, I recommend that Vernon 17 depreciate and amortize all of their high voltage transmission and 18 general properties turned over to CAISO operational control by 19 employing an overall composite 3.14 percent rate. I further recommend 20 that Vernon amortize its intangible plant at that same rate. The Qocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 4 of 19 1 methodology I employed for determining Vernon's depreciation rate is 2 consistent with Commission precedent. 3 II. DEPRECIATION 4 Q. Would you please define and describe depreciation? 5 A. Depreciation is the allocation of the original cost of tangible facilities in 6 service over their useful lives. Stated another way, depreciation is the 7 mechanism by which the plant investment is recouped in an orderly 8 fashion over the useful life of the investment. For rate purposes it is 9 treated as an operating expense. Depreciation is intended to 10 systematically recover the invested capital over the useful life of the 11 universe of relevant assets. 12 1 used the Average Service Life approach and recommend that Vernon's 13 depreciation rates in this case be based on this approach. This approach 14 is the most widely used of all the methods to determine depreciation 15 rates for electric transmission systems. 16 Depreciation rates depend on estimates of service life of plant 17 investment. Because electric transmission systems are made up of a 18 host of different complex property units, it would be impractical to 19 calculate and apply separate depreciation rates for each unit of facility. 20 This calculation would place an undue burden on the accounting system 21 for depreciation purposes, requiring the maintenance of records for each Docket Nos. EL00-105, et al. Exhibit No. VER-4 Page 5 of 19 1 unit of property. Consequently, the normal approach for developing 2 depreciation rates is to calculate the rates for groups of plant based upon 3 average service lives for those groups, which are determined through 4 studies of the forces affecting the lives of the transmission facilities. 5 Under this method, individual facilities recorded to each relevant 6 account are treated as a single group by those accounts. For Vernon's 7 ratemaking, I have determined a single composite rate which 8 encompasses intangible, transmission and general plant functions. 9 III. DETERMINATION OF DEPRECIATION 10 A. THE SERVICE LIFE FACTORS 11 Q. Would you please discuss the relationship between useful life and 12 depreciation? 13 A. The measurement of depreciation recognizes that all plant will 14 ultimately reach the end of its useful life. The end of the useful life and 15 retirement from service may be caused by the following factors: 16 • wear and tear 17 • action of the elements 18 • deterioration 19 • inadequacy 20 • obsolescence 21 • requirements of public authorities 22 • adequacy of supply or market. 4ocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 6 of 19 1 2 The physical causes, such as wear and tear and deterioration, are the 3 most readily observed reasons for retirements. Functional causes, such 4 as inadequacy, obsolescence, requirements of public authorities and 5 inadequacy of markets are probably the more prevalent causes of 6 retirements in the electric industry. 7 For a transmission system such as Vernon's, all of the above causes of 8 retirement, whether physical or functional, have one thing in common: 9 they are ever -occurring and affect individual facilities. On the other 10 hand, the adequacy of supply or market is unrelated to the physical 11 characteristics of the property or the requirements of public authorities. 12 Adequacy of market is probably the single most important factor 13 resulting in premature retirements because this factor may affect a large 14 portion of a transmission system; therefore, I will treat this subject in 15 more detail. In a depreciation study, the adequacy of supply and 16 markets is referred to as the economic life. 17 B. THE DEPRECIATION MODEL 18 Q. Would you please describe the depreciation model that you employed in 19 your study? 20 A. I employed the straight-line average service life method as traditionally 21 adopted by the Commission. It is described as follows: 1 DE = DB — NSV ASL Iocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 7 of 19 2 Where, 3 DE = Depreciation Expense 4 DB = the depreciation base or original cost 5 NSV = net salvage value 6 ASL = the average service life 7 8 The determination of depreciation using the above equation 9 serves three purposes: 10 capital recovery- ratably allocates a known fixed cost, 11 12 cost of removal - ratably allocates a future obligation, 13 14 salvage - ratably reflects recognition of future value. 15 16 Q. Would you describe the average service life approach? 17 A. The concept of an average service life for a property group implies that 18 the various units in the group have different lives. The average life of 19 any group of plant items is a matter of estimate until all the items in that 20 group have been finally retired. The issue then is to determine the 21 average life before complete retirement of all units occurs. The average 22 service life method determines the average period of time the facilities 23 will be in service. This is normally done by first determining the 24 historical life of the plant group and then estimating the life expectancy 25 for the items remaining in service. The life experienced plus the Docket Nos. EL00-105, et al. Exhibit No. VER-4 Page 8 of 19 1 expected life comprises the average life for the group. This analysis can 2 be done by determining the separate lives for each of the property units 3 or by constructing a survivor curve for the entire group. In this 4 testimony, I employed the group method and I used an industry -wide 5 survivor curve for each group of facilities. 6 Q. What is a survivor curve? 7 A. A survivor curve, fitted to a particular type of plant, predicts the average 8 service life and normal retirement pattern of that plant. A survivor 9 curve graphically reflects the percent of capital investment existing at 10 each age throughout the entire physical life of an original group of 11 property. From the survivor curve, the average service life or average 12 remaining life can be calculated. 13 The survivor curves are referred to as Iowa type survivor curves (See 14 Schedule No. l of Exhibit No. VER-6.) They were originally developed 15 at the Iowa State College Engineering Experiment Station and refined 16 through an extensive process of observation and classification of the 17 ages at which industrial property had been retired. Iowa survivor curves 18 are used to account for the normal retirements that occur over the life of 19 a specific type of plant. 20 The determination and use of a survivor curve to determine the physical 21 life of facilities requires a great deal of experience and knowledge in the 10ocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 9 of 19 1 interpretation of the results of such a study. The use of judgment must 2 include investigation into whether future normal retirements can be 3 predicted based on the past performance of those facilities. 4 C. DESCRIPTION OF VERNON'S HIGH VOLTAGE 5 TRANSMISSION FACILITIES 6 7 Q. Please describe the transmission lines and facilities intended to be 8 placed under the CAISO's control. 9 A. The California -Oregon Transmission Project is an alternating current 10 transmission line with an existing rating of 1,600 MW North -to -South 11 and 1225 MW South -to -North. The Project consists of approximately 12 three hundred forty (340) miles of 500-kV transmission line extending 13 from Southern Oregon to central California, developed in three 14 segments, plus substations and other facilities. The Project is 15 interconnected with, and operated in parallel with, the Pacific Intertie 16 facilities. 17 The Mead-Adelanto Project ("MAP") is an alternating current 18 transmission line with an accepted rating of 1,200 MW. The MAP is a 19 202-mile, 500 kV alternating current transmission line constructed from 20 Marketplace Switching Station in Southern Nevada to the 500 kV 21 Adelanto Switching Station in Southern California with series capacitor Qocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 10 of 19 1 line compensation of 45 percent at Marketplace. It is utilized to deliver 2 electrical energy between Southern Nevada and Southern California. 3 The Mead -Phoenix ("MPP") is an alternative current transmission line 4 with an accepted rating of 1,300 MW. The MPP is a 256-mile, 500kV 5 alternating current transmission line constructed from the Perkins 6 Switchyard near Sun City, Arizona to Marketplace Switching Station in 7 Southern Nevada. The Project is utilized to transmit electrical energy 8 between Central Arizona and Southern Nevada. 9 D. THE DETERMINATION OF DEPRECIATION FOR VERNON'S 10 TRANSMISSION FACILITIES 11 Q. Please describe how you determined the physical life normal retirement 12 survivor curve. 13 A. The survivor curve represents the pattern of annual normal retirements 14 that will occur out to 50 plus years. I determined the normal retirement 15 curve for each of Vernon's facilities classified by each project to FERC 16 transmission plant account. For example, I determined that Account 17 353 (Station Equipment) has an average service life of 40 years, with an 18 Ri survival pattern. This is shown on Schedule No. 2 of Exhibit No. 19 VER-6. Station Equipment make up over 30 percent of Vernon's 20 electric transmission system. I determined the survivor curve and locket Nos. EL00-105, et al. Exhibit No. VER-4 Page 11 of 19 1 resulting average service life which best applies for each of the other 2 accounts as follows: 3 Transmission Plant 4 Account No. Description Average Service Life Survivor Pattern 5 352 Structures and Improvements 53 S3 6 354 Towers and Fixtures 65 S5 7 355 Poles and Fixtures 43 R2 8 356 Overhead Conductors and Dev 48 R5 9 359 Roads and Trails. 30 R3 10 397 Communication Equip. 20 L2 11 Q. Could you please explain how you determined the composite average 12 service life for Vernon's high voltage transmission system turned over 13 to CAISO control? 14 A. The composite average service life of Vernon's transmission system 15 was determined by employing the typical mortality experience of other 16 similar systems with the same type of facilities and in close proximity to 17 Vernon. To do that, I analyzed the mortality experience of transmission 18 systems of Pacific Gas and Electric Company ("PG&E") and Southern 19 California Edison Company ("SCE"). Since the average age of 20 Vernon's property is less than 10 years, there is not enough data, in the 21 form of retirements from which to construct a survivor curve. Thus, the Qocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 12 of 19 1 experience of the two other transmission companies, PG&E and SCE, 2 can be used as a surrogate for the analysis of the average service life to 3 be applied to the facilities belonging to Vernon. My analysis of the 4 average service life and net salvage is shown on Schedule Nos. 3 and 4 5 of Exhibit No. VER-6. Once the average service life of the facilities in 6 each account is established, I then determined the composite average 7 service life of the total high voltage transmission facilities belonging to 8 Vernon turned over to the CAISO. Similar study techniques were 9 applied to determine the composite net salvage. The determination of 10 Vernon's composite average service and composite net negative salvage 11 is shown on pages 1 and 2 of Schedule No„6 of Exhibit No. VER-6. I 12 arrived at a 46.62-year average service life and a net negative salvage of 13 34.95 percent of the gross plant for the first scenario, PG&E. For the 14 second scenario, SCE, I arrived at a 43.93-year average service life and 15 48.69 percent net negative salvage. The reason why such a composite is 16 determined is that Vernon's records do not include a breakout of 17 individual facilities. It is, therefore, necessary to establish a composite 18 rate.. 19 Q. Please explain why you believe that the average service life and net 20 salvage characteristics of PG&E and SCE are adequate surrogates for 21 Vernon's depreciation determination. . qwcket Nos. EL00-105, et al. Exhibit No. VER-4 Page 13 of 19 1 A. The high voltage, 500 kV transmission facilities of Vernon, SCE, and 2 PG&E turned over to ISO operational control are substantially similar 3 for purposes of appropriate deprecation rates. Clearly, SCE and PG&E 4 are the best sources of figures for such purposes as average service lives 5 and negative salvage for Vernon's lines. The lines are geographically 6 proximate. COTP is the "third AC Pacific Intertie line." It is 7 electrically and essentially physically in parallel with the two original 8 AC Pacific Intertie lines, running in large part through the PG&E 9 service territory. The three AC Pacific Intertie lines share similar 10 climate, environment, and terrain, and are under similar regulatory 11 requirements and constraints. PG&E and SCE have the bulk of the 12 rights to the capacity of "first two" AC Pacific Intertie lines. PG&E 13 also owns a share of COTP, thus its average service lives used to 14 determine its own depreciation life for high voltage facilities turned 15 over the ISO include COTP. SCE has interests in several major 500 kV 16 lines, including those connecting the SCE service area to Palo Verde, 17 Four Corners, Mead, and Eldorado Substations, that traverse the desert 18 southwest, just as do MPP and MAP, and thus are subject to similar 19 terrain, environment, and regulatory requirements, and constraints. As 20 discussed in Mr. Clay's testimony, Vernon high voltage transmission 21 lines were built to service the SCE service area. Among other things, Ocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 14 of 19 1 Vernon's high voltage transmission lines do not connect directly to 2 Vernon, but attach to the SCE and PG&E systems. For all of these 3 reasons, these lines are substantially similar for depreciation purposes. 4 Q. Please explain the term "net negative salvage"? 5 A. Net negative salvage is the amount of funds necessary to retire a 6 specific facility or group of facilities. It is the difference between the 7 gross salvage, if any, and the cost of removal. The net negative salvage 8 component to the depreciation formula is stated as a percent of gross 9 plant which will eventually be subject to retirement. That percent will 10 accrue enough funds in an orderly and fair manner to cover the cost of 11 retirement. Like capital recovery depreciation, the cost of retiring 12 facilities is a legitimate cost of doing business. 13 Q. Would you please explain the mechanics of your calculation of the 14 depreciation rate for Vernon's transmission plant turned over to ISO? 15 A. After determining the composite average service life, I then divided that 16 value into the depreciable plant plus my determination of negative 17 salvage thus arriving at the indicated depreciation expense. The 18 indicated depreciation expense for each account was totaled. This then 19 is the indicated composite depreciation expense for the total 20 transmission plant and also for the intangible and general plant 21 (Communication Equipment). The indicated composite rate for the 41ocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 15 of 19 1 intangible, transmission and general plant employing the composite 2 average service life and net salvage of PG&E is 2.89 percent. Similarly, 3 the indicated composite rate employing SCE's factors is 3.38 percent. 4 The average of the two surrogates is 3.14 percent. This rate is derived 5 as shown on Schedule No. 6 of Exhibit No. VER-6. 6 Q. What is the source of the gross depreciable plant shown on that 7 schedule? 8 A. The gross depreciable plant shown on Schedule No. 6 was developed by 9 me from the project construction costs as reported by the construction 10 managers of each project. 11 Q. What depreciation rate did Vernon have prior to December 31, 2000? 12 A. Based on my conversations with Vernon personnel, Vernon employed a 13 2.86 percent depreciation rate to all of its electric transmission system 14 properties. Further, Vernon derived the 2.86 percent rate by dividing 15 100 percent value of its plant by an average service life of 35 years. 16 Therefore, a negative salvage factor was not included in the depreciation 17 rate determination. It is my recommendation that the 3.14 percent 18 depreciation rate (which includes a negative salvage component) that I 19 support here, should supersede Vernon's current depreciation 20 methodology for these facilities. Docket Nos. EL00-105, et al. Exhibit No. VER-4 Page 16 of 19 1 Q. Would you please summarize the results of your depreciation rate 2 determination? 3 A. As a result of my studies, I found a composite depreciation rate for 4 Vernon's high voltage transmission system of 3.14 percent. The 5 depreciation rate determination for Vernon's facilities, in composite 6 form, employing two scenarios for intangible, transmission and general 7 is shown on pages 1 and 2 of Schedule No. 6 of Exhibit No. VER-6. 8 IV. VERNON AUGUST 2000 TESTIMONY 9 Q. What depreciation rate did Vernon utilize in its August 30, 2000 petition 10 for review? 11 A. Vernon utilized a 3.2 % depreciation rate, based upon a 42 year service 12 life, and a 33 % negative salvage value. 13 Q. What was the source of those figures? 14 A. They represent the depreciation figures utilized to develop the 15 Commission approved rates for SCE's contractual high voltage 16 transmission service to Vernon and other SCE transmission customers. 17 Those rates were established and approved by the Commission in 18 Docket No. ER97-3880 and remain in effect to this day. Pursuant to the 19 terms of the CAISO's Commission approved tariff, SCE has turned 20 operational control of these lines over to the CAISO subject to the pre- 21 existing contractual rights to transmission service SCE had provided to lRocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 17 of 19 1 other utilities such as Vernon. When Vernon turned its high voltage 2 transmission over the ISO, it turned over not only all of its transmission 3 facilities but also all of its contract rights to transmission service. Those 4 contract rights continue in the CAISO until the contracts expire. A 5 portion of Vernon's TRR consists of the charges that Vernon is required 6 to pay SCE for this transmission service. 7 Q. Was it reasonable for the Commission to accept the application of these 8 depreciation figures to Vernon's high voltage transmission facilities for 9 purposes of determining Vernon's TRR? 10 A. Yes. Based upon my review and the testimony presented herein by Mr. 11 Clay, Vernon's high voltage import transmission facilities turned over 12 to the CAISO are substantially similar to SCE's high voltage import 13 transmission facilities turned over the CAISO. The use of the same 14 approach to depreciation is certainly supportable, and it was appropriate 15 for the Commission to approve the use of that depreciation approach for 16 Vernon's facilities in its October 17, 2000 order. Further, Vernon paid 17 that deprecation rate in SCE's transmission service rates before Vernon 18 became a PTO, and it is the deprecation rate for transmission service 19 turned over to the ISO, In my testimony herein, I have presented a more 20 refined depreciation study that is broader based as well as more specific 21 to Vernon. The depreciation figures I present as a result of that study 14ocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 18 of 19 1 differ very little from the SCE figures. Application of these figures 2 versus the figures utilized by Vernon City Council in August 2000 in 3 establishing Vernon's TRR does not result in significant differences in 4 the resulting TRRs. Thus, while the depreciation figures I present here 5 are more precise than the August 2000 Vernon figures, my studies 6 herein effectively confirm the propriety of the use of the figures utilized 7 by Vernon in August 2000 and their approval by the Commission. 8 For that matter, I have reviewed PG&E's approach to depreciation of 9 the high voltage transmission facilities turned over to the CAISO. My 10 studies presented here and Vernon's August 2000 approach are also 11 consistent with PG&E's methodologies and results. 12 So long as a consistent method of depreciation is utilized from the time 13 the facilities are turned over to the CAISO, there is a range of 14 appropriate deprecation rates that are appropriate. The depreciation rate 15 I present in this testimony is simply, in my opinion, a bit more refined 16 than was the depreciation rate utilized by Mr. Clark. But in the 17 circumstances of the Vernon August 30, 2000 petition for declaratory 18 order, it is my opinion that Mr. Clark's figures were in every respect 19 fair, reasonable, consistent with Commission precedent, consistent with 20 the deprecation rates used by SCE and PG&E, and otherwise 21 appropriate. *ocket Nos. EL00-105, et al. Exhibit No. VER-4 Page 19 of 19 Q. Does this conclude your direct testimony? A. Yes, it does. • AFFIDAVIT STATE OF DISTRICT OF COLUMBIA § COUNTY OF § Before me, the undersigned Notary Public, in and for the District of Columbia, personally appeared Edward H. Feinstein, who being by me first duly sworn, deposes and says that he is the individual identified and responding to the questions in the attached direct testimony and that the same is true and correct to the best of his knowledge, information and belief. Edward H. Feinstein Sworn to and subscribed before me on this day of April 2004. Notary Public My Commission expires: —i C (A —I � � � � Q (� (� rn o m v 0 ,� 00 r, c x � 3 0 o Q S. 2 2 c3D o`er m Q M G) G) Q � M ° m m v m v rn m 0 w mg �cn o c v CD can �' m Q N 5' N ° .�• ° ° ° � 0 ° 3 cQ v CD — 0 C� � m 00 m � CD Z � cn ° ai � m -, o o r ° CD 3 (D 03 3 � 3. 3 °nQi° o_0 Cn �'w3�' 3,m�' ccnn°C�--' CD Fn' 3. o`no3M,< CD�noG�S'3.=°� cn ° -0 ° n ° `� ° mo �' n �' fn 0 o � � `� o m 0: o ° 9.< = i3 n o o m oo`er330cD — 0 0 3 v 3 -v su o 3 v 3 m o a ,� `� -3a : o � 0 CO CO Cb � Cb 00 Cb Cb Cb Cb Cb C� Cb Cb 00 O Cb �I �1 �1 11 -�OMCOCDW11Cn-PW N-----OCOW-1Mv n WCDNNCnCDMN) -P,W (bO—COS-4-4O.0,0)CD T. N 6 6 CO 90 -1 O O O O O Z Cb Cn w v Q o w v v o v v v v v v v o v v o v Cn cn Cn Cn Cn Cn c s CD rCncncnCntnCncncnwwwCl) Cn_r,cn_r,cnCn �: CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD XE CD CD (Q r= (Q � fD CD CD (D (D CD CD (D CD CD CD CD fD , CD ,CD CD CD Q Q x x x x CD CD CD (D N w N N 3 3 3 3 r cn m m D m v =Q� -n n m m z cn cn cn I -I m m z cn Q Z m x Z cc o CD -Lm o w cn 0 0 DDT<-iz��oz<m ozz nmzn MR- 02 ci'.in'su'o �Sai 33� ,-���� �� s� G) OE (rncn500 rnw oco-,_�rn3 Worn @�3 N m a G) cn c N 3 m 3 G) c =v rn 0 3 cn C FF v, v, w corn w cn rn -o' w h rn cn O FF Ow cn�'v T— ao rn Zrn" G) CD O Zo � w G7 rn c � wo a rn 0 3_ = ,c n ai vo, � U) n 'U ai w R. �5-0 cn CD n�0303-cD :73 30)rnOG) w N anCDm ��n a�� 3cn ncn n c :3 w oocn w 5 can CDG73 rn= n0 0 `c cn o-0 o CD . vi �3 0 -,rn3rnO 00 '0a8--3orn�t< -oa3 no5�oo >0 -o - •0 w = rn 3 3 Do.�� 3 n. o w o o nD vm c a)n cn `. o z w w G) N O O O O O O CO CO Cfl Co CO O Co CD Co CO Co Co CO CO O CO Co Co Co NNNN-000CD-4W0CDMM-4MCnCnCnCnCnCn�W W � 4 � 'O N & 1, c!o -4 N N' GD ', & -4 .P j I CD I, W � CC-WCOO-!WO"W OCO.?NOOOCoM M M M M WNN�I-- MNCnWOM0OW COv0N 6-4 'O� 6666666666666 6 6 6 6 6 o 66 O O O O O O O O O O O O O 000000 0 0 O O O O O O O O O O O O O 00000 O TOO90 90oOovv90o�v90 90909090 cl)CnCnCnOtncn r ZZ Z Z ZG)XX O� 90 Cn C5 C/) CA Cn < Cn Cn CA CA cn r r r Cf) (!) r— Cn Cn Cn cn r Cl) Cn C: Cn Cn Cn CA Cn Cn Cn rnrnrnrnrn- CD CD rnrnrnrn- rnrn=rnrnrnrnrnrnrn '•' r'••-r-r _ .' �r '�r CQ (Q (Q .'ter ,'ter (0 .'ter .'ter .''"r '.* (Q .' .'rt+ (Q A a .a .a rn rn rn rn rn �.rn rn rn rn rn rn 0 rn rn W rn rn rn 0 CD CD CDCLC1C1C1arn CD CD aaQao aao a a a a a a a n Q n n n CL X X X X CD CD (D (D X X X X w w w w 3 3 3 3 m x Q 0 Z (Q o fD < ^' m 0 w cn cn c II II II II II II If 11 II a Cfl O -0 o o N -+ In CD v to cu (D �. NC 'U (D `< o CD < CD C CD f% (Q 0 O r CD CD (D CCDD o90 0 0 0 D 0 0 v o' m m 0 0 z = .a CD � o 1• c < � v a c�-- -0 0. m m CD CDCD Cn c Z con m " r O 0 CD m o � 3 o m X m X X X -u X -u -u 00000 -4 cn m w U1 O N C0 W w U7 c0 O O O O O O O 0 O O O 0 0 0 0 0 O 90 90 9 0) zzz" cn cn cn O90 0 0 0 0 0 C.0-a0-CL 5 3' 5' S' cn cc cn co co m x Z cn o CD < w m o w cn 0 • Exhibit No. 6 SCHEDULES TO THE TESTIMONY OF EDWARD FEINSTEIN 4) it V L. 0 .it m Q Q 0 V .CL V (Y5 N r- p OD u A C 0 0 N C d E d cr W � C U o L *a Cl) 3 L y M a+ C 3 O V c w c m u L d a i Schedule No. 3 Exhibit No. 6 Depreciation Parameters Southern California Edison Company Average Mortality Net Salvage Account No. Description Service Life Dispersion 352 Structures and Improvements 55 S3 -35% 353 Station Equipment 40 R, -116% 354 Towers and Fixtures 60 SS -86% 355 Poles and Fixtures 45 R, .115% 356 Overhead Conductors and Devices 45 R5 -95% Note: Study Data as of 2000 Schedule No. 4 Exhibit No. 6 Depreciation Parameters Pacific Gas and Electric Company Average Mortality Net Salvage Account No. Description Service Life Dispersion 352 Structures and Improvements 50 S6 .10% 353 Station Equipment 40 S3 -30% 354 Towers and Fixtures 70 S4 -50% 355 Poles and Fixtures 42 R3 -100% 356 Overhead Conductors and Devices 52 S6 -100% Note: Study Data as of 1999 A �9 L L P O! W d aW u cE' oW u cW u rc 2 rc agg a'� ac f � � mg» .03 � a `ate f- i� `• w IL cmWa»s « ;e n V ONrYd� <g <g Z m A; W p i m i a =a m .9c a9• a' as tl "s g `a ` a `a � s S O P imp > a: O 2 u E WW/��� ii�l Z4i��% �° f/.M".1CY/U:IG� UU�IlV 11G �G V//U IIUG lYIW E E E �i E � E 0 2kco � � ® ■ _ k k ! ISE § , o4„r \}f ` \\}~ �` ■2 ■| #.§,f.,! ;!eq o §!| \ !!! S �!l,,. . . . ..8.., o z LU 0 0■.,. ; r § 2; z/ s §lo 13 `M.2 ({2.).7..) |f. |c •! _ , ; X.. . -! |! kc �c l k| . | � § !| § k § \ � |� ! . /�) k ! ) ■ j � ! 8 ; � k . � k &; \$� © \� .! /) )} ! ;f ! /$� 02 } ) 2 z EXHIBIT is UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION DOCKET NOS. EL00-105-007 ER00-2019-007 DIRECT TESTIMONY AND EXHIBITS OF FRANK J. HANLEY, CRRA PRESIDENT — UTILITY SERVICES ON FAIR RATE OF RETURN on behalf of the CITY OF VERNON, CALIFORNIA APRIL 2004 AUS CONSULTANTS 155 Gaither Drive P.O. Box 1050 Moorestown, New Jersey 08057-1050 TABLE OF CONTENTS Page No. I. INTRODUCTION AND PURPOSE I II. RECOMMENDATION AND ITS BASES 5 III. ADDITIONAL PROXY GROUPS 9 IV. VERNON'S GREATER BUSINESS RISK l I V. ADDITIONAL COST OF EQUITY ANALYSES USING OPINION NO.445 METHODOLOGY 14 VI. EFFICIENT MARKET HYPOTHESIS AND THE USE OF MULTIPLE COST OF EQUITY MODELS (USED TO VERIFY OPINION NO.445 METHODOLOGY) 17 VII. COMMON EQUITY COST RATE MODELS 22 a. All Are Market -Based 22 b. DCF Model 23 c. The Risk Premium Model 25 d. The Capital Asset Pricing Model 28 e. The Comparable Earnings Model 33 VIII. CONSIDERATION OF BOND RATINGS 36 IX. CONCLUSION 37 i 0 Exhibit No. VER-1 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION CITY OF VERNON, CALIFORNIA ) DOCKET NOS. EL00-105-007 ER00-2019-007 Direct Testimony of Frank J. Hanley, CRRA on behalf of the City of Vernon, California April 2004 1 I. INTRODUCTION AND PURPOSE 2 Q. PLEASE STATE YOUR NAME, OCCUPATION AND BUSINESS 3 ADDRESS. 4 A. My name is Frank J. Hanley and I am President of AUS Consultants — 5 Utility Services. My business address is 155 Gaither Drive, P.O. Box 1050, 6 Moorestown, New Jersey 08057. 7 8 Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND 9 AND PROFESSIONAL EXPERIENCE. 10 A. I have testified as an expert witness on rate of return and related financial 11 issues before 33 state public utility commissions, the Federal Energy 12 Regulatory Commission ("Commission") and the Public Services 13 Commission of the Territory of the U.S. Virgin Islands. I have also 14 testified before local and county regulatory bodies, an arbitration panel, a City of Verno*,alifomia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 2 of 38 1 U.S. Bankruptcy Court, the U.S. Tax Court and a state district court. I have 2 appeared on behalf of investor -owned companies, municipalities, and state 3 public utility commissions. The details of these appearances, as well as my 4 educational b ackground, a re s hown i n E xhibit N o. V ER-2 a ccompanying 5 this testimony. 6 7 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 8 A. The purpose of my testimony is to provide evidence on behalf of the City of 9 Vernon, California ("Vernon" or "the City") in the form of a study of the 10 fair rate of return which it should be afforded an opportunity to earn for the 11 use of its transmission facilities that were turned over to the California 12 Independent System Operator ("CAISO") when Vernon became a 13 Participating Transmission Owner ( "PTO"). My testimony confirms that 14 the Commission's Order on Proposed Transmission Revenue Requirement 15 ("TRR") in Docket No. EL00-105-000, 93 FERC ¶ 61,103 (issued October 16 27, 2000) was very conservative on the issue of fair rate of return. Based 17 upon my studies, as discussed herein, it is my opinion that the rate of return 18 that was previously approved by the Commission is an appropriate floor, 19 but that a fair rate of return on equity for Vernon would be 12.065%. 20 21 Q. PLEASE EXPLAIN. 22 A. The Commission utilized the Southern California Edison Company's 23 ("Edison or "SCE") (FERC Opinion No. 445 in Docket No. ER97-2355- 24 000 issued July 26, 2000, 92 FERC ¶ 61,070) capital structure, embedded 25 costs of fixed capital and an 11.60% common equity cost rate resulting in a 26 9.29% overall rate of return. For the reasons set forth below I believe the 27 rate of return was conservative and establishes an appropriate minimum 28 rate of return to be considered for Vernon. City of Vemo10, alifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 3 of 38 1 First, Vernon at the time had no debt outstanding and consequently 2 no debt financed any portion of the Vernon TRR rate base. As discussed in 3 the testimony of Vernon witness Clay (Clark, Exhibit V-1 at 14-15), 4 Vernon exercised its business judgment and decided to finance its 5 transmission facilities with cash on hand rather than incur debt. However, I 6 am not aware of any circumstance in which the Commission has approved 7 the use of a 100 % capital structure for ratemaking purposes.' Since all of 8 Vernon's rate base was financed from Vernon's reserves (equity), the 9 Commission d etermined that 100% equity was not an appropriate capital 10 structure to utilize in ruling upon Vernon's proposed TRR for its 11 transmission facilities when they became part of the CAISO high voltage 12 transmission grid. 13 Second, the Commission utilized SCE's capital structure and 14 authorized rate of return of 9.29% (from Opinion No. 445) in order to 15 assure that an all equity financed Vernon rate base would not result in an 16 inordinate revenue requirement. As demonstrated by the direct testimony 17 of Vernon witness Clark at pages 16 and 17, which has been adopted by 18 Vernon witness Clay, (Docket No. EL00-105-000 re Vernon's petition in 19 August 2 000), such a n a pproach d id n of a ccount f or V ernon's a dditional 20 risk: 21 ' I believe that the highest equity ratios allowed by FERC in litigated cases have been 77.94 percent Midwestern Pipeline in June 1985 (31 FERC ¶ 61,317) and 70.50 percent for Colorado Interstate in November, 1987 (41 FERC ¶ 61,179). Since then, there have been a number of equity ratios higher than 60 percent approved in litigated proceedings. In January, 2000, the Commission approved an equity ratio of 59.08 percent for Trunkline Gas Company (90 FERC ¶ 61,017). City of Verno0alifornia 40 Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 4 of 38 1 Vernon's transmission facilities should be placed in the ISO 2 at least at the same relative risk as those of SCE. SCE's most 3 recent allowed returns on equity at both the California 4 commission and at the FERC are 11.6%. Vernon provides 5 service in the same geographical area as SCE. There should 6 not be a distinction between the incentive offered to SCE in 7 the form of a return equity and the incentive offered to 8 entities such as Vernon to invest in transmission facilities. 9 10 Indeed, Vernon's risks may exceed those of SCE. These 11 facilities are located outside the City's compact service 12 territory. These extend for long distances in California and 13 even beyond. The mere fact that a larger portion, on a 14 percentage basis, of these facilities extend to states beyond 15 California, states that may not provide the same environment, 16 puts Vernon at more risk. 17 18 Additionally, these facilities are not wholly owned by 19 Vernon. Vernon has only a small percentage of the facilities 20 (7.5497% of the COTP, 6.25% of the MAP and even a 21 smaller portion of the various segments of the MPP — see 22 Exhibit V-3). The facilities operate under a joint ownership 23 committee that is controlled by others. 24 25 Vernon's own load is also vastly different from virtually 26 every other municipal or investor owned utility. Vernon's 27 load is virtually all industrial. This makes Vernon's load 28 subject to more volatility than a utility that has a residential 29 and commercial base to serve. Industrial customers can shift 30 large loads to other jurisdictions or simply shut down 31 depending on external and internal economic conditions. As 32 an example, Vernon's peak load was historically in the area 33 of 250 MW, but declined to approximately 170 MW (a 34 decline of approximately 32%) because of the loss of 35 industrial customers. The peak load is currently back up to 36 approximately 196 MW. Only a relatively small, but almost 37 totally industrial load would place such volatility and risk on 38 a utility system. 39 City of Vernowalifornia Exhibit No. VER-1 Docket Nos. EL00-105, et A Page 5 of 38 1 Third, my own analysis confirms that Vernon is considerably more 2 risky than SCE as well as the proxies relied upon by the Commission in 3 Opinion No. 445 because of its extraordinarily small size and its 4 disproportionate percentage of industrial load/revenues vis-a-vis SCE and 5 said proxies. 6 7 II. RECOMMENDATION AND ITS BASES 8 Q. WAS IT PROPER FOR THE COMMISSION TO UTILIZE SCE AS 9 A PROXY FOR VERNON'S RATE OF RETURN FOR TRR 10 PURPOSES? 11 A. Yes. Asa municipality, Vernon does not issue common stock. Therefore, 12 the Commission appropriately concluded that Vernon needed to use a 13 proxy. As stated in the testimony of Vernon witnesses Clark and Clay, 14 Vernon and SCE are engaged in substantially similar transmission activities 15 and are otherwise similarly situated as to their high voltage, 500 kV import 16 transmission facilities, except for Vernon's higher risks, as discussed 17 herein. In summary, Vernon had a long history of close and integrated 18 operations with SCE and Vernon's transmission facilities were planned in 19 coordination with SCE under the SCENernon Integrated Operations 20 Agreement. Further, Vernon's transmission facilities parallel SCE's 21 facilities. The transmission projects in which Vernon invested competed 22 with other transmission lines that SCE might otherwise have had to finance. 23 Vernon's lines serve the same functions for the same geographic area as do 24 SCE lines. Both SCE and Vernon's lines have, of course, been turned over 25 to ISO operational control. For all of these reasons, it was logical and 26 reasonable for the Commission to have approved Vernon's use of SCE as a 27 proxy. 28 City of Verno0alifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 6 of 38 1 Q. HAVE YOU ALSO USED SCE AS A PROXY? 2 A. Yes, but I have also identified additional appropriate proxies and performed 3 additional analysis. My analyses supports the use of SCE's rate of return 4 for Vernon as the minimum rate of return that should even be considered 5 for Vernon, but demonstrates that the fair rate of return for Vernon is 6 higher. 7 8 Q. WHAT IS YOUR RECOMMENDED FAIR RATE OF RETURN FOR 9 VERNON? 10 A. I have determined that a fair overall rate of return for Vernon is 9.51%. 11 The 9.29%, rate of return originally approved by the Commission is an 12 appropriate "floor". The Commission based that figure upon the SCE 13 overall cost of capital from Opinion No. 445. My independent analysis 14 utilizing the cost of equity methodology from Opinion No. 445 and 15 additional proxy groups indicates a common equity cost rate of 11.9%. 16 Moreover, utilizing other cost of equity approaches indicates a common 17 equity cost rate of 12.23%, which further confirms the conservative nature 18 of the rate of return finding in the Commission's Order of October 27, 2000 19 on Vernon's proposed TRR. Therefore, taking the midpoint of 11.90% and 20 12.23 % and applying it to SCE's capital structure, which the Commission 21 imputed on Vernon, would result in an overall fair rate of return of 9.51 %. 22 23 Q. HAVE YOU PREPARED AN EXHIBIT WHICH SUPPORTS YOUR 24 CONCLUSIONS AS TO THE OVERALL FAIR RATE OF RETURN 25 WHICH VERNON SHOULD BE AFFORDED AN OPPORTUNITY 26 TO EARN? 27 A. Yes. I have prepared an Exhibit which has been marked for identification 28 as Exhibit No. VER-3. It consists of 13 schedules. City of VernoWalifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 7 of 38 1 2 Q. PLEASE EXPLAIN SCHEDULE 1, PAGE 1. 3 A. Page 1 of Schedule 1 presents a summary of what I believe is a overall rate 4 of return applicable to Vernon. As shown, it is 9.51%o I believe the 9.51% 5 overall rate of return is a conservative floor because my own studies show 6 that SCE, and the proxies used by the Commission for SCE in Opinion No. 7 445 and the proxies used by myself in the instant matter are less risky than 8 Vernon. Those proxies are much larger in size and derive a far smaller 9 percentage of their revenues from industrial customers than Vernon, which 10 is very small and derives more than 80% of its revenues from industrial 11 customers. Consequently, Vernon is more risky than any of the proxies. 12 13 Q. PLEASE EXPLAIN SCHEDULE 1, PAGE 2. 14 A. On the upper half of the page, I summarize the common equity cost rates 15 utilizing the Commission's Discounted Cash Flow ("DCF") methodology 16 outlined i n 0 pinion N o. 4 45. I u tilize t he u pper a nd o f t he D CF r anges 17 indicated because of Vernon's very'small size and very high percentage of 18 industrial revenues to total revenue which make for greater risk as will be 19 explained in a. The midpoint of the high end of the ranges of the DCF cost 20 rates for the three proxy groups (the group of four used by the Commission 21 in Opinion No. 445 and the two additional groups utilized herein and 22 discussed infra) is 11.90% which confirms that the 11.60% allowed in the 23 Order on Vernon's TRR dated October 27, 2000 was conservative. 24 In addition to the Opinion No. 445 cost of equity methodology, I 25 also utilized a variety of cost of common equity models consistent with the 26 Efficient Market Hypothesis ("EMH"), as discussed infra, and applied them 27 to the same three proxy groups. As shown on the bottom half of Schedule 28 1, page 2, the midpoint of the range of cost rates is 12.23% which provides City of Vernon,01ifornia • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 8 of 38 1 further confirmation of the conservative nature of an 11.60% common 2 equity cost rate and supports a higher rate than 11.60%. 3 4 Q. PRIOR TO ITS ORDER ON REMAND OF DECEMBER 23, 20029 5 THE COMMISSION UTILIZED SCE'S CAPITAL STRUCTURE 6 AND COST RATES TO ESTABLISH VERNON'S TRR. DO YOU 7 BELIEVE THAT THOSE RATIOS AND FIXED CAPITAL COST 8 RATES AS SHOWN ON SCHEDULE 1, PAGE 1 ARE 9 REASONABLE? 10 A. Yes. Vernon's transmission facilities are now a part of the CAISO high 11 voltage transmission grid. Vernon's facilities are integrated with SCE's 12 facilities2 and are actually financed with 100% equity (Vernon's reserves). 13 As discussed before, the use of a hypothetical capital structure and fixed 14 capital cost rates for Vernon by the Commission is an appropriate 15 ratemaking methodology As stated previously, I believe the Commission 16 wisely utilized SCE as the best proxy. Moreover, since such transmission 17 assets have become part of the aggregate CAISO transmission grid, it 18 would not be proper to award a lesser return on equity to more risky assets, 19 i.e., to Vernon, than is awarded to SCE at approximately the same point in 20 time. 21 I reviewed five-year financial statistics including capital structure 22 ratios for the proxy group of four electrics and combination electric and gas 23 companies relied upon by the Commission in its TRR Order dated October 24 27, 2000. In addition, I also selected two additional proxy groups utilizing 25 various criteria, including size. As a result of reviewing those proxy groups 26 and the capital structure ratios they maintained during the five years ending 2 See Exhibit No. VER-7. City of Vemoi0alifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 9 of 38 1 19985 I conclude that the use of the SCE capital structure by the 2 Commission was conservative. Those ratios were: long-term debt of 3 48.40%; preferred stock of 5.80%; and common equity of 45.80%. 4 Moreover, use of the SCE capital structure also necessitates the use of 5 SCE's long-term debt and preferred stock cost rates. 6 7 Q. PLEASE EXPLAIN SCHEDULE 2. 8 A. Schedule 2, page 1 contains various financial statistics for the years 1994- 9 1998 for the four proxy companies utilized by the Commission in Opinion 10 No. 445. As shown, the SCE's capital structure ratios adopted by the 11 Commission fall well within the range maintained by the group during the 12 five-year period. 13 Those four companies are: 14 Constellation Energy Group, Inc. 15 Duke Energy Corp. 16 PG&E Corp. 17 The Southern Company 18 19 III. ADDITIONAL PROXY GROUPS 20 Q. PLEASE DESCRIBE THE BASIS OF SELECTION OF YOUR 21 PROXY GROUPS OF FIVE ELECTRIC AND COMBINATION 22 ELECTRIC AND GAS COMPANIES CONTAINED IN SCHEDULE 23 3 AS WELL AS THEIR CAPITAL STRUCTURE RATIOS. 24 A. The complete basis of selection is contained on page 2 of Schedule 3, as is 25 the identity of the five companies. My goal was to select large companies 26 (but smaller than the group in Schedule 2), i.e., those with more than $2.0 27 billion in revenues in 1998 (the last full year prior to the updated market 28 data relied upon by the Commission in Opinion No. 445, i.e., 29 September/October 1999); bonds rated AA, AA- or A; more than 65% of City of Vemolwalifornia Exhibit No. VER-1 Docket Nos. EL00-105, et A Page 10 of 38 1 1998 total operating revenues derived from electric operations; and some 2 nuclear generation. 3 The five companies selected are: 4 Alliant Energy Corp. 5 Ameren Corp. 6 Consolidated Edison, Inc. 7 Constellation Energy Group, Inc. 8 The Southern Company 9 The average percentage of nuclear generation to total generation was 10 18%, while the average percentage of electric revenues to total revenues 11 was 83%. In addition, the range of average capital structure ratios shown 12 on page 1 of Schedule 3 based on permanent capital confirm that the ratios 13 from Opinion No. 445 for Vernon fit well within them. 14 15 Q. PLEASE DESCRIBE THE BASIS OF SELECTION OF YOUR 16 PROXY GROUP OF FOUR ELECTRIC AND COMBINATION 17 ELECTRIC AND GAS COMPANIES CONTAINED IN SCHEDULE 18 4 AS WELL AS THEIR CAPITAL STRUCTURE RATIOS. 19 A. The complete basis of selection is contained on page 2 of Schedule 4 as is 20 the identity of the four companies. The basis of selection differs from the 21 five companies discussed supra re: Schedule 3 only in the following: 22 There was no specific bond rating criteria and they had to have had 1998 23 revenues from electric operations which were less than $2.0 billion. The 24 average percentage of nuclear generation to total generation was 22%, 25 while the average percentage of electric revenue to total revenues was 90%. 26 The range of average capital structure ratios shown on page 1 of Schedule 4 27 based on permanent capital confirm that the ratios from Opinion No. 445 28 are reasonable. 29 The four companies selected are: City of Vernoo, alifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 11 of 38 1 Central Hudson Gas & Electric Corp. 2 DQE, Inc. 3 Public Service Company of New Mexico 4 The United Illuminating Company 5 6 IV. VERNON'S GREATER BUSINESS RISK 7 Q. YOU HAVE STATED THAT VERNON IS MORE RISKY THAN 8 EDISON OR ANY OF THE PROXY GROUPS UTILIZED. PLEASE 9 EXPLAIN. 10 A. I have prepared Schedule 5 which consists of 2 pages. Page 1 is a chart 11 showing size based on permanent capital for each proxy group and for 12 Vernon based on its rate base found by the Commission in its TRR Order 13 dated October 27, 2000. As is readily apparent, Vernon is miniscule in 14 comparison to the proxy group companies relied upon by the Commission 15 in Opinion No. 445, which on average are about 79 times larger than 16 Vernon, while my proxy group of five companies is about 48 times larger 17 than Vernon and even my small proxy group of four companies is about 9 18 times larger than Vernon. 19 Page 2 of Schedule 5 is a chart which shows the average percentage 20 of industrial revenues to total revenues for they ear 1998 for each of the 21 three proxy groups and Vernon (Vernon's is actually for its fiscal year 22 ended June 30, 1999). As shown, more than 80% of Vernon's revenues are 23 derived from i ndustrial c ustomers, a p ercentage o f w hich i s 4 t o 5 t imes 24 greater than those of the three proxy groups. 25 26 Q. PLEASE EXPLAIN HOW THE SIZE OF AN ENTERPRISE 27 AFFECTS ITS LEVEL OF BUSINESS RISK. 28 A. Smaller companies are less capable of coping with significant events which 29 affect sales, revenues and earnings. City of Vernwalifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 12 of 38 1 The loss of revenues from a few large customers, for example, 2 would have a greater effect on a small company than on a much larger 3 company with a larger customer base. Fore xample, if a small company 4 were to lose one or several large customers through closure, relocation or 5 bypass, it would have a much more adverse effect on its profits than a much 6 larger company with a more diverse customer base. Such has been the case 7 for Vernon, as pointed out by the Vernon Witness Clark direct testimony of 8 August 2000 cited supra. For example, since 1988 Vernon has lost many 9 large customers. The companies that have left vary in the type of business, 10 but many were manufacturers that were significant customers of the Vernon 11 electric utility, including: Sunlaw, Filtrol, Oscar Meyer, Agrashell, Ladish, 12 Genstar Typsum (Dumtar), American National Can, Jerseymaid, and Alcoa. 13 These companies had loads between 900 kilowatts and 10,000 kilowatts, 14 and represented a significant decrease in demand on Vernon's system. In 15 addition, NI Industry, a very large electric utility customer, dramatically 16 decreased its load from a cumulative demand of approximately 23,000 17 kilowatts, to about 3,000 kilowatts. The load lost from NI Industry 18 represents over 10% of Vernon's peak load. In the case of a public utility, 19 such events are viewed negatively by credit agencies because they reflect 20 poorly on customer mix and diversity and prospects for economic growth. 21 The size "phenomenon" is well recognized in the financial literature. 22 Schedule 6, which consists of 9 pages, is from Ibbotson Associates' 1999 23 Yearbook — SBBI (Stocks, Bonds, Bills and Inflation). This book, and 24 hence Schedule 6, was available to investors in the Summer and Fall of 25 2000. On page 2 (original page 127), it is indicated clearly that small 26 companies have higher returns than large ones. While this may not be so in 27 the short run, over the long run this financial precept is true — keeping in 28 mind that the cost of equity is over the long run. In fact, the standard DCF City of Vernoloalifornia Exhibit No. VER-1 Docket Nos. EL00-105, et A Page 13 of 38 1 model used in rate regulation, including that used in Opinion No. 445, 2 assumes an infinite (long run) investment horizon. 3 Also, in the remaining pages of Schedule 6, Ibbotson Associates 4 demonstrate that the smaller the size of the company, the greater the risk 5 and therefore, the greater the size premium for return on equity required by 6 the marketplace. 7 8 Q. PLEASE EXPLAIN THE SIGNIFICANCE OF SCHEDULE 7, 9 STANDARD & POOR'S ("S&P") CORPORATE RATINGS 10 CRITERIA. 11 A. Schedule 7 consists of 12 pages. Pages 3 through 9 contain discussions by 12 S&P of its utilities "Corporate Rating Criteria." On page 3 (original page 13 29), S&P explains why it scrutinizes customer mix. It states: 14 ...heavy industrial concentration is viewed cautiously, since a 15 utility may have significant exposure to cyclical volatility. 16 Alternatively, a large residential component yields a stable 17 and more predictable revenue stream.... 18 19 The foregoing confirms that Vernon's extraordinarily high reliance upon 20 industrial customers/revenues with a very miniscule residential customer 21 base equates to much greater risk. For example, Vernon had only a 22 minimal number of residential customers which accounted for only a 23 fraction of one percent of total revenues during its reporting period ending 24 June 30, 1999. 25 26 27 28 29 City of Verno0,alifornia • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 14 of 38 1 V. ADDITIONAL COST OF EQUITY ANALYSES 2 USING OPINION NO. 445 METHODOLOGY 3 Q. PLEASE DISCUSS YOUR COST OF EQUITY ANALYSES 4 CALCULATED UNDER THE SPECIFIC METHODOLOGY 5 SPECIFIED IN OPINION NO. 445. 6 A. I have performed such analyses which are contained 'in Schedule 8, 7 consisting of 8 pages. 8 I did not attempt to duplicate the results specified by the 9 Commission in Opinion No. 445 based on the four proxy electric and 10 electric and gas companies upon which it relied. The ranges are shown at 11 the top of page 1 of Schedule 8 and were taken directly from Opinion No. 12 445. The Commission determined that a cost rate for SCE should be the 13 midpoint between the average and high end of the range, or 11.73% (9.59% 14 + 12.44%/2 = 11.02% to 12.44% or 11.02% + 12.44%/2 = 11.73%); 15 however, allowed only 11.60% because 11.73% exceeded SCE's own 16 request.3 17 My analysis of Vernon's extraordinary risk, discussed supra, 18 confirms that Vernon's cost of equity should be at the high end of the 19 Opinion No. 445 DCF methodology cost rate range, which is 12.44% based 20 on the high end of the range for the proxy group utilized by the 21 Commission. However, I also calculated ranges of DCF cost rates in a 22 manner totally consistent with the methodology specified in Opinion No. 23 445 for the two proxy groups which I have selected (as discussed supra) for 24 purposes of determining common equity cost rate and ascertaining the 25 reasonableness of the 11.60% common equity cost rate authorized by the 3 92 FERC at pp. 61,266-67. City of Vemo*aliforma Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 15 of 38 1 FERC in its October 27, 2000 Order on the TRR. Those data are also set 2 forth in Schedule 8. c1 4 Q. PLEASE EXPLAIN SCHEDULE 8. 5 A. On page 1 is a summary of the ranges of DCF cost rates by company and 6 the relevant ranges, consistent with Opinion No. 445, for the Commission 7 group as well as the two additional proxy groups which I selected and 8 discussed supra. The appropriate ranges (from midpoint of the overall 9 ranges to the upper end of the ranges) are 10.48% - 11.36% for the proxy 10 group of five companies with 1998 revenues greater than $2 billion and 11 10.67% - 11.75% for the proxy group of four companies with 1998 12 revenues less than $2 billion. The appropriate cost rates applicable to 13 Vernon are the upper end of each range, which are: 14 15 FERC proxy group (Opinion No. 445) 12.44% 16 Proxy Group of Five Electrics & Combos 11.36% 17 Proxy Group of Four Electrics & Combos 11.75% 18 19 Range of All Three Groups 11.36% - 12.44% 20 Midpoint of Range 11.90% 21 22 Pages 2 through 8 of Schedule 8 contain the supporting information for the 23 summary data on page 1 of Schedule 8. Page 2 contains the details of the 24 low DCF cost rates by company and group while page 3 contains the details 25 of the high end of the ranges of DCF cost rates. Page 4 contains dividend 26 yield information while page 5 contains the Value Line BR + SV and 27 I/B/E/S growth rate data. Page 6 contains the details of the BR + SV 28 calculations while page 7 contains the details of the projected internal rates 29 (except for the Commission group for which BR + SV growth rates were 30 taken directly from Opinion No. 445). Page 8 shows the calculation of the City of Vernongalifornia • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 16 of 38 1 average dividend payout ratios and average returns on common stock for 2 the t wo p roxy g roups w hich I h ave s elected. T he f oregoing c alculations 3 indicate that a DCF cost rate of 11.90% is appropriate for Vernon at a 4 minimum. 5 6 Q. WHY DO YOU BELIEVE THAT AN 11.90% COST RATE OF 7 COMMON EQUITY CAPITAL IS THE MINIMUM RATE THAT 8 SHOULD BE CONSIDERED FOR VERNON RELATIVE TO A 9 45.80% COMMON EQUITY RATIO? 10 A. As discussed supra, the Commission approved for Vernon, in its TRR 11 Order of October 27, 2000, an overall rate of return of 9.29%, which was 12 based on the award to SCE in Opinion No. 445, utilizing SCE's cost of 13 capital which included an 11.60% common equity cost rate relative to a 14 45.80% common equity ratio. 15 Because of Vernon's small size and almost exclusive reliance upon 16 an industrial customer base, if Vernon were viewed as a stand-alone utility, 17 I believe that it would have to finance with a much greater percentage of 18 common equity than the 45.80% assumed applicable to Vernon. Vernon's 19 100% a ctual e quity i s n of appropriate t o s et the T RR under Commission 20 ratemaking methodology, but perhaps a 60% or 65% common equity ratio 21 would be appropriate given Vernon's risk. Because Vernon is willing to 22 accept the SCE capital structure as a conservative assumption for purposes 23 of determining its TRR, an 11.60% common equity cost rate is very low. 24 Indeed the 11.90% which I have calculated, and which has been discussed 25 supra, is a minimal cost of equity because I have made no attempt to adjust 26 it upward to reflect: 27 City of VemoniP,alifornia • Exhibit No. VER-1 _Docket Nos. EL00-105, et al. Page 17 of 38 1 (1) greater risk related to a 45.80% equity ratio which should be 2 higher for Vernon consistent with its greater level of business 3 risk; or 4 (2) no adjustment was made to the cost of equity of either 5 11.60% or 11.90% to reflect Vernon's small size and 6 extraordinary dependence on industrial customers/load. 7 8 As can be gleaned from the Ibbotson Associates' data on size 9 premiums shown on pages 7 and 9 of Schedule 6, over the long run the cost 10 of such small size could be up to nearly two hundred basis points in the cost 11 of equity for companies with a very small market capitalization of perhaps 12 between $100 and $200 million. However, I have made no such 13 adjustment; hence, I believe that the previously authorized 9.29% overall 14 cost of capital, which included an 11.60% rate of return on a 45.80% 15 common equity ratio is very conservative and is the very low end of the 16 range of cost rates that must be considered for Vernon. 17 I have also utilized other techniques and cost of equity models 18 consistent with the EMH to verify the foregoing conclusions, which I 19 describe below. 20 21 VI. EFFICIENT MARKET HYPOTHESIS AND THE USE OF 22 MULTIPLE COST OF EQUITY MODELS (USED TO VERIFY 23 OPINION NO.445 METHODOLOGY) 24 Q. PLEASE DESCRIBE THE CONCEPTUAL BASIS OF THE EMH. 25 A. The EMH is the cornerstone of modern investment theory. It was 26 pioneered by Eugene F. Fama4 in 1970. An efficient market is one in 27 which security prices at all times reflect all the relevant information 4 Fama, Eugene F., "Efficient Capital Markets: A Review of Theory and Empirical Work", Journal of Finance, May 1970, 383-417. City of VernoValifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 18 of 38 1 available at that time. An efficient market implies that prices adjust 2 instantaneously to the arrival of new information and that the process 3 therefore reflects the intrinsic fundamental economic value of a security.5 4 The essential components of the EMH are: 5 1. Investors are rational and will invest in assets which provide the 6 highest expected return for a particular level of risk. 7 8 2. Current market prices reflect all publicly available information. 9 10 3. Returns are independent in that today's market returns are unrelated 11 to yesterday's returns as that information has already been 12 processed. 13 14 4. The markets follow a random walk, i.e., the probability distribution 15 of expected returns approximates the normal bell curve. 16 17 Brealey and Myers state: 18 19 When economists say that the security market is `efficient", 20 they are not talking about whether the filing is up to date or 21 whether desktops are tidy. They mean that information is 22 widely and cheaply available to investors and that all relevant 23 and ascertainable information is already reflected in security 24 prices. 25 26 There are three forms of the EMH, namely: 27 1. The "weak" form asserts that all past market prices and data are 28 fully reflected in securities prices. In other words, technical 29 analysis cannot enable an investor to "outperform the market". 30 5 Morin, Roger A., "Regulatory Finance — Utilities' Cost of Capital", Public Utilities Reports, Inc., 1994, p. 136. 6 Brealey, R.A. and Myers, S.C., "Principles of Corporate Finance". McGraw-Hill Publications, Inc., 1996, 323-324. City of Verno0alifornia 10 Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 19 of 38 1 2. The "semistrong" form asserts that all publicly available 2 information is fully reflected in securities prices. In other words, 3 fundamental analysis cannot enable an investor to "outperform the 4 market". 5 6 3. The "strong" form asserts that all information, both public and 7 private, is fully reflected in securities prices. In other words, even 8 insider information cannot enable an investor to "outperform the 9 market". 10 11 The "semistrong" form is generally held as true because the illegal 12 use of insider information can enable an investor to "beat the market" and 13 earn excessive returns, thereby disproving the "strong" form. 14 15 Q. PLEASE EXPLAIN THE APPLICABILITY OF THE EMH TO THE 16 DETERMINATION OF A COMMON EQUITY COST RATE. 17 A. Common sense affirms the semistrong form of the EMH, i.e., market prices 18 paid for securities reflect all relevant information available to investors and 19 that no degree of sophistication and/or analysis can enable investors to 20 outperform the market. Consequently, it confirms that all perceived risks 21 are taken into account by investors in the market prices they pay which 22 reflect the information inexpensively or freely available such as bond 23 ratings, and analyses of the rating agencies and financial analysts, and the 24 various methodologies employed to determine common equity cost rate as 25 discussed in the academic and financial literature. Thus, in an attempt to 26 emulate investors' actions, I believe it is necessary to take into account the 27 results of multiple cost of common equity models and have done so in this 28 specific instance in order to verify the conservative nature of the 29 Commission's rate of return determination in establishing Vernon's TRR in 30 its Order of October 27, 2000. 31 City of Vernonialifornia • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 20 of 38 1 Q. IS THERE SPECIFIC SUPPORT IN THE ACADEMIC 2 LITERATURE FOR THE NEED TO RELY UPON MULTIPLE 3 COST OF COMMON EQUITY MODELS IN ARRIVING AT A 4 RECOMMENDED COMMON EQUITY COST RATE? 5 A. Yes. For example, Phillips? states: 6 Since regulation establishes a level of authorized earnings 7 which, in turn, implicitly influences dividends per share, 8 estimation of the growth rate from such data is an inherently 9 circular process. For these reasons, the DCF model `suggests 10 a degree of precision which is in fact not present' and leaves 11 `wide room for controversy and argument about the level of 12 V. (italics added) (p. 396) 13 14 15 Despite the difficulty of measuring relative risk, the 16 comparable earnings standard is no harder to apply than is 17 the market -determined standard. The DCF method, to 18 illustrate, requires a subjective determination of the growth 19 rate the market is contemplating. Moreover, as Leventhal has 20 argued: `Unless the utility is permitted to earn a return 21 comparable to that available elsewhere on similar risk, it will 22 not be able in the long run to attract capital'. (italics added) 23 (p. 398) 24 25 26 Also, Morin states: 27 Sole reliance on the DCF model ignores the capital market 28 evidence and financial theory formalized in the CAPM and 29 other risk premium methods. The DCF model is one of many 30 tools to be employed in conjunction with other methods to 7 Charles F. Phillips, Jr., The Regulation of Public Utilities — Theory and Practice, 1993, Public Utility Reports, Inc., Arlington, VA, p. 396, 398. 8 Roger A. Morin, Regulatory Finance — Utilities' Cost of Capital, 1994, Public Utilities Reports, Inc., Arlington, VA, pp. 231-32, 239-40. City of Vernonfalifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 21 of 38 1 estimate the cost of equity. It is not a superior methodology 2 that supplants other financial theory and market evidence. 3 The broad usage of the DCF methodology in regulatory 4 proceedings does not make it superior to other methods. 5 (italics added) (pp. 231-232) 6 7 Each methodology requires the exercise of considerable 8 judgment on the reasonableness of the assumption underlying 9 the methodology and on the reasonableness of the proxies 10 used to validate a theory. The failure of the traditional 11 infinite growth DCF model to account for changes in relative 12 market valuation, discussed above, is a vivid example of the 13 potential shortcomings of the DCF model when applied to a 14 given company. It follows that more than one methodology 15 should be employed in arriving at a judgment on the cost of 16 equity and that these methodologies should be applied across 17 a series of comparable risk companies. ...Financial 18 literature supports the use of multiple methods. (italics 19 added) (p. 239) 20 21 Professor Eugene Brigham, a widely respected scholar and 22 finance academician asserted: 23 24 In practical work, it is often best to use all three methods - 25 CAPM, bond yield plus risk premium, and DCF — and then 26 apply judgement when the methods produce different results. 27 People experienced in estimating capital costs recognize that 28 both careful analysis and very fine judgements are required. 29 It would be nice to. pretend that these judgements are 30 unnecessary and to specify an easy, precise way of 31 determining the exact cost of equity capital. Unfortunately, 32 this is not possible. (pp. 239-240) 33 34 Another prominent finance scholar, Professor Stewart Myers, 35 in his best-selling corporate finance textbook stated: 36 37 The constant growth formula and the capital asset pricing 38 model are two different ways of getting a handle on the same 39 problem. (italics added) (p. 240) 40 City of Vernon'"California • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 22 of 38 1 In an earlier article, Professor Myers explained the point more 2 fully: 3 Use more than one model when you can. Because estimating 4 the opportunity cost of capital is difficult, only a fool throws 5 away useful information. That means you should not use any 6 one model or measure mechanically and exclusively. Beta is 7 helpful as one tool in a kit, to be used in parallel with DCF 8 models or other techniques for interpreting capital market 9 data. (italics added) (p. 240) 10 11 In view of the foregoing, it is clear that investors are aware of all of the 12 models including comparable earnings. The EMH requires the assumption 13 that investors use them all. 14 15 VII. COMMON EQUITY COST RATE MODELS 16 a. All Are Market -Based 17 Q. ARE ALL OF THE MODELS YOU EMPLOY MARKET -BASED 18 MODELS? 19 A. Yes. The DCF model is market -based as current market prices are 20 employed. The Risk Premium Model ("RPM") is market -based as the 21 current and expected bond ratings and yields reflect the market's 22 assessment of risk. To the extent betas are used to determine equity risk 23 premium, the market's assessment is reflected because betas are derived 24 from regression analyses of market prices. The Capital Asset Pricing 25 Model ("CAPM") model is market -based for much the same reason as the 26 RPM except that the yield on U.S. Government Treasury Bonds is used in 27 lieu of company -specific bond yields. My application of the Comparable 28 Earnings Model ("CEM") is also market -based because the selection 29 process of comparable risk companies is based upon statistics which result City of Vernon;'California • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 23 of 38 1 from regression analyses of market prices which reflect investors' 2 perception of all risks. 3 4 b. DCF Model 5 Q. WHAT IS THE THEORETICAL BASIS OF THE DCF MODEL? 6 A. DCF theory is based upon finding the present value of an expected future 7 stream of net cash flows during the investment holding period discounted at 8 the cost of capital, or the capitalization rate. The theory suggests that an 9 investor buys a stock for an expected total return rate which is expected to 10 be d erived from c ash flows i n t he f orm o f d ividends a nd a ppreciation i n 11 market price, i.e., the expected growth rate. Thus, the dividend yield on 12 market price plus a growth rate equals the capitalization rate. The 13 capitalization rate is the total return rate expected by investors. 14 15 Q. PLEASE DESCRIBE YOUR APPLICATION OF THE DCF MODEL 16 AND HOW IT DIFFERS FROM THE METHODOLOGY 17 SPECIFIED IN OPINION NO. 445. 18 A. My analysis is set forth in Schedule 9 which consists of 16 pages. It 19 generally follows the DCF methodology set forth in Opinion No. 445 with 20 regard to the use of ranges but differs in the determination of dividend 21 yields and growth rates. The dividend yields I reviewed are spot yields as 22 of September 9, 1999 (which were the latest yields available prior to 23 September 11, 1999, the date of the latest Value Line Investment Surveys 24 apparently relied upon by the Commission in Opinion No. 445) as well as 25 for the six months ended August 31, 1999. I utilized the low and high, 26 respectively, dividend yields, i.e., spot or average for each company in all 27 three proxy groups. Those yields were adjusted by one-half the growth 28 rates. The growth rates that I utilized in this application of the DCF model City of Vemongalifomia • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 24 of 38 1 are expected growth in earnings per share ("EPS") from Value Line and 2 I/B/E/S, i.e., those which were available in August/September 1999. 3 4 Q. WHY DO YOU RELY UPON EXPECTED GROWTH IN EPS? 5 A. Investors recognize that analysts' forecasts provide greater insight into 6 prospective growth in per share value than historical accounting measures 7 of growth. Analysts' forecasts, which incorporate historical information, 8 are readily available from Value Line and I/B/E/S. While investors are 9 influenced by short-term earnings growth such as forecasts for the next 12 10 months, I believe that they are more influenced by the longer term five-year 11 forecasts. Five years typically is the longest future period for which 12 analysts' forecasts are available. The use of a long-term period such as five 13 years is more consistent with the long-term investment horizon implicit in 14 common stocks than single 12-month growth rates. It is clear that EPS 15 growth rate expectations, although they do not fully account for changes in 16 market value, are the most investor -influencing of all accounting measures 17 of value. It should be clear, even to the casual market observer, that the 18 market reacts favorably when EPS expectations are met or exceeded and 19 unfavorably when they are not. 20 21 Q. PLEASE EXPLAIN THE RESULTS OF YOUR APPLICATION OF 22 THE DCF MODEL FOR THE THREE PROXY GROUPS. 23 A. They are summarized on page 1 of Schedule 9. Pages 2 and 3 contain the 24 details of the low and high DCF cost rates. Page 4 contains the spot and 25 six-month average dividend yields. Page 5 contains the Value Line and 26 I/B/E/S projected five-year EPS growth rates. Pages 6-16 are the latest 27 Value Line Investment Surveys which were available as of September City of Vernonialifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 25 of 38 1 1999) the latest month upon which the Commission apparently relied in 2 Opinion No. 445. 3 As shown on page 1 of Schedule 9, the resultant ranges of DCF cost 4 rates for each proxy group applicable to Vernon (using the Opinion No. 445 5 range methodology) are as follows: 6 7 FERC proxy group of four electrics & combos 11.43%-13.09% 8 Proxy group of five electrics & combos 9 (more than $2 billion revenues) 11.36%-13.09% 10 Proxy group of four electrics & combos 11 (less than $2 billion revenues) 10.97%-12.25% 12 Range of High DCF Cost Rates 12.25%-13.09% 13 Midpoint of High DCF Cost Rates 14 Applicable to Vernon 12.67% 15 16 c. The Risk Premium Model 17 Q. PLEASE DESCRIBE THE THEORETICAL BASIS OF THE RPM. 18 A. The RPM is based upon the theory that the cost of common equity capital is 19 greater than the prospective company -specific cost rate for long-term debt 20 capital. In other words, it is the expected cost rate for long-term debt 21 capital plus a premium to compensate common shareholders for the added 22 risk of being unsecured and last -in -line in any claim on the corporation's 23 assets and earnings. 24 25 Q. PLEASE DESCRIBE YOUR RPM ANALYSES. 26 A. They are shown in Schedule 10, which consists of 9 pages. As shown on 27 page 1, I have estimated the projected bond yield on Moody's A rated. 28 utility bonds to be 7.55% in September 1999. As explained in Notes 3 and 29 4 on page 1, adjustments are required to be made to the 7.55% yield on A 30 rated public utility bonds to reflect the average bond rating of each proxy City of Vernon"Califorma Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 26 of 38 1 group as shown on page 2 of Schedule 10. Those adjustments are shown 2 on Line No. 4 of page 1. The resultant expected bond yields applicable to 3 each proxy group are shown on Line No. 5 of page 1. The equity risk 4 premiums applicable to each proxy group are shown on Line No. 6 of page 5 1. The sum of the prospective bond yields on Line No. 5 plus the equity 6 risk premiums on Line No. 6 equal the RPM common equity cost rates for 7 each proxy group. 8 9 Q. PLEASE EXPLAIN THE BASIS OF THE EQUITY RISK 10 PREMIUMS SHOWN ON LINE NO. 6, PAGE 1 OF SCHEDULE 10. 11 A. I evaluated the results of two different historical equity risk premium 12 studies, as well as Value Line's forecasted total annual return on the market 13 over the prospective yield on high grade corporate bonds. These analyses 14 are summarized on page 5 of Schedule 10. 15 16 Q. PLEASE EXPLAIN THE BASIS OF THE EQUITY RISK 17 PREMIUMS SHOWN ON LINE NO.9, PAGE 6 OF SCHEDULE 10. 18 A. Those premiums were determined utilizing betas. Equity risk premiums 19 determined through the application of the beta approach are meaningful 20 because the betas were derived from regression analyses of the market 21 prices of common stocks over a recent five-year period then ending. The 22 market prices reflect investors' long -run expectations. Consequently, beta 23 is a meaningful measure of prospective risk relative to the market as a 24 whole and thus is a logical means by which to allocate a relative share of 25 the total market's equity risk premium to a specific company or groups of 26 companies. 27 The historical beta -derived market equity risk premium is based 28 upon the Ibbotson Associates' data on holding period returns for the S&P City of Verno0,aliforma Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 27 of 38 1 500 Composite Index and Salomon Brothers Long-term High-grade 2 Corporate Bond Index covering the period 1926-1998 (available in 1999). 3 The use of holding period returns over a very long period of time is useful 4 in the application of the beta approach. Ibbotson Associates, in its 1999 5 Yearbook (relevant pages shown as Schedule 11, which consists of 6 pages) 6 provides sound reasoning why the use of a long-term historical time period 7 and the arithmetic mean of such returns is appropriate when estimating the 8 expected equity risk premium. 9 The bases of the historical market equity risk premiums are detailed 10 in Line Nos. 1 through 3, page 6 of Schedule 10, while the bases of the 11 forecasted equity risk premiums are detailed in Line Nos. 4 through 6 of the 12 same page. 13 14 Q. WHY DO YOU ALSO UTILIZE FORECASTED EQUITY RISK 15 PREMIUMS? 16 A. The long-term historical arithmetic average market equity risk premium is 17 the most likely to be experienced over the long-term future. A prospective 18 element is contained in the use of beta because beta is derived from market 19 prices which reflect investors' expectations of the future. Moreover, beta is 20 also utilized in conjunction with the prospective yield on A rated public 21 utility bonds. 22 23 Q. PLEASE DESCRIBE THE DERIVATION OF THE HOLDING 24 PERIOD EQUITY RISK PREMIUMS SHOWN ON LINE NO. 29 25 PAGE 5 OF SCHEDULE 10. 26 A. These equity risk premiums are those long-term historical holding period 27 returns applicable to public utilities, i.e., the S&P Public Utility Index for 28 the period 1928-1998, inclusive. The long-term average provides a good City of Vernon, alifornia • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 28 of 38 1 basis for future expectations as all types of events are included, even 2 "unusual" ones. The analysis is summarized on page 8 of Schedule 10. 3 After the adjustment necessary to reflect the average equity risk premium 4 applicable to each proxy group based on each group's average bond rating 5 (Line Nos. 4a and 4b on page 8), equity risk premiums applicable to each 6 proxy group were derived. 7 8 Q. WHAT ARE THE RESULTANT RPM COST RATES? 9 A. They are shown on Schedule 10, page 1, Line No. 7. They are as follows: 10 FERC proxy group of four electrics & combos 11.63% 11 Proxy group of five electrics & combos 12 (with 1998 revenues in excess of $2 billion) 11.74% 13 Proxy group of four electrics & combos 14 (with 1998 revenues less than $2 billion) 11.80% 15 16 Range of RPM Cost Rates 11.63%-11.80% 17 Midpoint of Range 11.72% 18 19 d. The Capital Asset Pricing Model 20 Q. PLEASE EXPLAIN THE THEORETICAL BASIS OF THE CAPM. 21 A. The CAPM defines risk as the covariability of a security's returns with the 22 market's r eturns. T his c ovariability is measured b y b eta ( "P"), an i ndex 23 measure of an individual security's variability relative to the market as a 24 whole. A beta less than 1.0 indicates lower variability than the market and 25 a beta greater than 1.0 indicates greater variability than the market. 26 The CAPM assumes that all non -market or unsystematic, risk can be 27 eliminated through diversification. The risk that cannot be eliminated 28 through diversification is called market or systematic risk. The model City of Vernon,Olifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 29 of 38 1 presumes that investors require compensation for risks that cannot be 2 eliminated through diversification. Systematic risks are caused by 3 socioeconomic events that affect the returns on all assets. In essence, the 4 model is applied by adding a risk -free rate of return to a market risk 5 premium. This market risk premium is adjusted proportionally to reflect 6 the systematic risk of the individual security relative to the market as 7 measured by beta. 8 9 The traditional CAPM is expressed as: 10 11 Rs = Rf + R (Rm — Rf) 12 13 Where RS = Return rate on the common stock 14 Rf = Risk -free rate of return 15 Rm = Return rate on the market as a whole 16 P = Adjusted beta (volatility of the security 17 relative to the market as a whole. 18 Beta is adjusted for regression bias.) 19 20 21 Numerous tests of the CAPM have confirmed its validity. These 22 tests have measured the extent to which security returns and betas are 23 related as predicted by the CAPM. 24 The empirical CAPM ("ECAPM"), discussed by Morin, reflects the 25 reality that the empirical Security Market Line ("SML") described by the City of Vernonolifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 30 of 38 1 traditional CAPM is not as steeply sloped as the predicted SML. Morin 2 states: 3 At the empirical level, there have been countless tests of the 4 CAPM to determine to what extent security returns and betas 5 are related in the manner predicted by the CAPM.10 The 6 results of the tests support the idea that beta is related to 7 security returns, that the risk -return tradeoff is positive, and 8 that the relationship is linear. The contradictory finding is 9 that the empirical Security Market Line (SML) is not as 10 steeply sloped as the predicted SML. With few exceptions, 11 the empirical studies agree that the implied intercept term 12 exceeds the risk -free rate and the slope term is less than 13 predicted by the CAPM. That is, low -beta securities earn 14 returns somewhat higher than the CAPM would predict, and 15 high -beta securities earn less than predicted. 16 17 18 Therefore, the empirical evidence suggests that the expected 19 return on a security is related to its risk by the following 20 approximation: 21 22 K = RF + x(RM - RF) + (1 - X) R (RM - RF) 23 9 Id., at p. 321. io For a summary of the empirical evidence on the CAPM, see Jensen (1972) and Ross (1978). The major empirical tests of the CAPM were published by Friend and Blume (1975), Black, Jensen, and Scholes (1972), Miller and Scholes (1972), Blume and Friend (1973), Blume and Husic (1973), Fama and Macbeth (1973), Basu (1977), Reinganum (1981B), Litzenberger and Ramaswamy (1979), Banz (1981), Gibbons (1982), Stambaugh (1982), and Shanken (1985). CAPM evidence in the Canadian context is available in Morin (1981). City of Vernon, alifornia 0 Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 31 of 38 1 Where x is a fraction to be determined empirically. ...the 2 value of x that best explains the observed relationship is 3 between 0.25 and 0.30. If x = 0.25, the equation becomes: 4 5 6 K = RF + 0.25(RM - RF) + 0.750(RM - RF)" 7 8* 9 The ECAPM is a return adjustment, i.e., a y-axis adjustment and 10 thus does not increase the adjusted beta, which is an x-axis adjustment and 11 accounts for regression bias. 12 As a result of the foregoing, I apply both versions of the model 13 (CAPM and ECAPM) which are contained in Schedule 12, which consists 14 of 4 pages. 15 16 Q. PLEASE DESCRIBE YOUR SELECTION OF A RISK -FREE RATE 17 OF RETURN. 18 A. My applications of the CAPM and the ECAPM reflect a risk -free rate of 19 5.93%. I t i s b ased u pon the average c onsensus f orecast o f the reporting 20 economists in the September 1,1999 issue of Blue Chip Financial 21 Forecasts for the yields on 30-year U.S. Treasury Bonds for the six quarters 22 ending with the fourth calendar quarter 2000 as shown in Note 2 on page 4 23 of Schedule 12. 24 The average expected yield on 30-year U.S. Treasury Bonds is 25 almost risk -free and its term is consistent with the long-term cost of capital 26 to public utilities measured by the yields on public utility bonds. Moreover, 27 it more closely matches the long-term investment horizon inherent in ' 1 Id., at pp. 335-36. City of Vernon California Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 32 of 38 1 utilities' common stocks and it is consistent with the long-term investment 2 horizon, which is presumed to be infinite, in the standard DCF model such 3 as utilized by the Commission. 4 5 Q. PLEASE EXPLAIN THE BASIS FOR YOUR ESTIMATION OF THE 6 EXPECTED MARKET EQUITY RISK PREMIUM. 7 A. I estimate investors' expected total return rate which is based on an average 8 of forecasted and long-term historical return rates from which I subtract the 9 risk -free rate. The result is a market equity risk premium, some proportion 10 of which must be allocated to each proxy group. I utilize betas to allocate 11 the market equity risk premium because it is a measure of risk relative to 12 the entire market. 13 The basis of the expected market equity risk premium is explained in 14 detail in Note 1 on page 4 of Schedule 12. The 3-5 year total market 15 appreciation projection, when converted to an annual rate plus the market's 16 average dividend yield equals a forecasted total annual return rate of 17 15.23%. The long-term historical total annual arithmetic mean return rate 18 on the market of large company stocks is 13.20% from Ibbotson 19 Associates' 1999 Yearbook (1926-1998). T he r elevant r isk-free r ate w as 20 deducted from each total market return rate. For example, from the Value 21 Line projected total market return of 15.23%, the forecasted average risk- 22 free rate of 5.93% was deducted indicating a forecasted market risk 23 premium of 9.30%. From the Ibbotson Associates' arithmetic mean long- 24 term historical total return rate of 13.20%, the long-term historical income 25 return rate on long-term U.S. Government Securities of 5.20% was 26 deducted indicating an historical equity risk premium of 8.00%. Thus, the 27 average of the projected and historical total market risk premiums of 9.30% 28 and 8.00%, respectively, is 8.65%. City of Vernon,I �alifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 33 of 38 1 2 Q. WHAT ARE THE RESULTS OF YOUR APPLICATIONS OF THE 3 CAPM AND ECAPM? 4 A. They are shown on page 1 of Schedule 12. The average of both the CAPM 5 and ECAPM cost rates range from 10.51 % - 10.90%, with a midpoint of 6 10.71%. it 8 e. The Comparable Earnings Model 9 Q. PLEASE DESCRIBE THE THEORETICAL BASIS OF THE CEM. 10 A. The comparable earnings standard recognizes the fundamental economic 11 concept of opportunity cost. This concept states that the cost of using any 12 resource — land, labor and/or capital — for a specific purpose is the return 13 that could have been earned in the next best alternative use. The 14 opportunity cost to an investor in a utility's common stock is what that 15 capital would yield in an alternative investment of similar risk. The 16 opportunity cost principle is consistent with one of the fundamental 17 principles of utility price regulation, i.e., it is intended to act as a surrogate 18 for the competition of the marketplace. 19 The problem in using returns on book equity (the ROEs) of non- 20 price regulated companies is determining whether such companies are 21 similar in risk to the price -regulated utility. The ROEs of other similar, 22 price -regulated firms should not be relied upon because they reflect the 23 results of regulatory awards which may not be indicative of what could 24 have been earned in a competitive market. Moreover, such use would be an 25 exercise in circularity. Consequently, application of the CEM is most 26 appropriately implemented by examining the ROEs of similar risk, 27 domestic, non -price regulated firms. There is a long regulatory history for 28 the use of the comparable earnings concept. Moreover, the use of ROEs of City of Vernon alifornia - • Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 34 of 38 1 comparable non -price regulated firms is appropriate because under the rate 2 base/rate of return paradigm, the rate of return (including the rate of return 3 on common equity) is applied to a rate base measured at original (i.e., 4 book) cost. 5 6 Q. PLEASE DESCRIBE YOUR CEM ANALYSIS. 7 A. My CEM analysis is contained in Schedule 13 which consists of 6 pages. 8 Page 1 is a summary of the results. Pages 2, 3 and 4 contain the results for 9 each proxy group as indicated, while pages 5 and 6 contain notes related to 10 pages 2 through 4. 11 It is critical to the application of the CEM to select proxy groups of 12 non -price regulated companies similar in total risk to the price -regulated 13 utilities. The proxy groups of comparable domestic, non -price regulated 14 firms (in this instance the groups used as proxies for each of the three proxy 15 groups of electric and combination electric and gas companies) should be 16 broad -based in order to obviate individual company -specific aberrations. 17 Utilities should be eliminated to avoid circularity since the rates of return 18 on their book common equity are substantially influenced by the rate 19 determinations of their respective regulatory commissions, many of which 20 are the result of negotiated settlements and, because of the give and take 21 involved in such settlements, are not truly market -based results. Rather, 22 they are often just a "fall -out" of many issues. 23 My application of the CEM is market -based because the selection of 24 the comparable non -price regulated firms is based upon statistics derived 25 from the in arket prices paid b y investors. S pecifically, I relied upon the 26 betas and related statistics derived from Value Line regression analyses of 27 weekly market prices over the most recent 260 weeks ended June 15, 1999. 28 The bases of selection resulted in proxy groups of domestic, non -price City of Vernonialifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 35 of 38 1 regulated firms comparable to the price -regulated utilities, i.e., comparable 2 in total risk, the sum of non-diversifiable market risk and diversifiable 3 company -specific risks to each of the three proxy groups of electric and 4 combination electric and gas companies. 5 The bases of selection were as follows: 6 1. They must be domestic, non -price regulated companies, i.e., 7 non -utilities. 8 2. They must be covered by Value Line Investment Survey 9 (Standard Edition). 10 3. Their unadjusted betas must lie within plus or minus three 11 standard deviations of the unadjusted betas of each proxy 12 group. 13 4. The standard errors of the regressions must lie within plus or 14 minus three standard deviations of the average standard error 15 of the regression for each of the three proxy groups. 16 Betas are a measure of market, or systematic, risk. The standard 17 errors of the regressions were used to measure each firm's company- 18 specific risk (diversifiable, unsystematic risk). The standard errors of the 19 regressions measure the extent to which events specific to a company affect 20 its stock price. Because market prices reflect investors' perceptions of total 21 risk, all risk which is not systematic market risk (beta) is reflected in the 22 standard error of the regression which is a measure of total non-systematic 23 risk which is diversifiable. In essence, companies which have similar betas 24 and standard errors of the regressions have similar total investment risk. 25 The use of three standard deviations captures 99.73% of the distribution of 26 unadjusted betas and standard errors of the regressions, thereby assuring 27 comparability. City of VernonP,alifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 36 of 38 1 I eliminated projected ROEs less than the expected yield on A rated 2 utility bonds of 7.55% and 20.00% or greater. An expected ROE less than 3 the expected cost of debt is contrary to fundamental financial precepts of 4 risk and return. Return rates of 20% or greater are not realistic expectations 5 for price -regulated utilities. In addition, I applied Student's t-statistic at the 6 95% level of confidence to eliminate any potential additional extremes, or 7 outliers. 8 9 Q. WHAT ARE THE INDICATED CEM COST RATES? 10 A. As shown on page 1 of Schedule 13, the CEM cost rates range from 11 13.50% to 14.00% with a midpoint of 13.75%. 12 13 VIII. CONSIDERATION OF BOND RATINGS 14 Q. IN YOUR ANALYSIS OF VERNON'S RISK RELATIVE TO THE 15 PROXY GROUPS, DID YOU CONSIDER THAT THE AVERAGE 16 BOND RATING OF BBB+ FOR YOUR SMALLER PROXY GROUP 17 OF FOUR ELECTRIC AND COMBINATION ELECTRIC AND GAS 18 COMPANIES IS LOWER THAN SCE'S BOND RATING? 19 A. Yes. The Commission went into the upper end of its DCF cost rates (i.e., 20 between the midpoint and upper end of the range of low to high cost rates) 21 in recognition of SCE's greater riskiness based on its bond rating (Opinion 22 No. 445, 92 FERC at p. 61,266). My smaller proxy group has an average 23 bond rating of BBB+ which is lower than SCE's A+ (Opinion No. 445); 24 lower than my larger proxy group with an average bond rating of AA- and 25 also lower than the Commission proxy group utilized in Opinion No. 445 26 which had an average bond rating of AA-. Thus, lower average BBB+ 27 bond rating or equivalent calls for a higher rate of return on common 28 equity. City of Vernon,' Palifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 37 of 38 1 2 Q. WHY? 3 A. I believe that Vernon, if viewed as a stand-alone entity, would not be rated 4 better than the bottom of the BBB category or BBB- in view of its very 5 small size and high risk based on a revenue/sales mix which is 6 overwhelmingly industrial (refer to page 2 of Schedule 7 for S&P's view of 7 such a mix and also to the comparative data contained in the charts in. 8 Schedule 5). I believe that Vernon might even be rated below investment 9 grade. Consequently, due to its greater risk, Vernon ideally should be 10 entitled to a higher rate of return than indicated by analyses of the proxies. 11 12 IX. CONCLUSION 13 Q. WHAT IS YOUR SPECIFIC RECOMMENDATION? 14 A. I conclude that the 9.29% overall rate of return approved in the TRR Order 15 of October 27, 2000) was very conservative and should be the low end of 16 the zone of reasonableness of the rates of return that must be considered for 17 Vernon. An 11.60% common equity cost rate relative to a 45.80% 18 common equity ratio is very, very conservative, given Vernon's level of 19 risk as discussed supra. Using then the high end of the Opinion No. 445 20 DCF methodology cost rates, a cost rate of 12.44% is indicated based only 21 on the proxy group relied upon by Commission in Opinion No. 445, but the 22 use of the midpoint of the high end of the range of DCF cost rates for all 23 three proxy groups indicates that an 11.90% cost rate is appropriate. 24 My methodology using multiple cost of equity models indicates that 25 a cost rate of 12.23% is appropriate. Consequently, I conclude that 11.60% 26 is an acceptable floor, but that a fair common equity cost rate for Vernon 27 would be 12.065%, which is the mid point between 11.90% and 12.23%. 28 Therefore, taking into consideration Vernon's higher risk when compared City of VernonP,alifornia Exhibit No. VER-1 Docket Nos. EL00-105, et al. Page 38 of 38 1 to SCE, I believe that 9.51 % is the proper overall rate of return for Vernon 2 in this proceeding. This rate of return should still be considered 3 conservative, given that although Vernon is riskier than SCE and would 4 likely require a higher equity ratio in its capital structure, Vernon is using 5 SCE's capital structure as a proxy. 6 7 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 8 A. Yes. EXHIBIT NO. VER-2 PROFESSIONAL QUALIFICATIONS OF FRANK J. HANLEY, CRRA PRESIDENT AUS CONSULTANTS - UTILITY SERVICES Exhibit No. VER-2 Page 1 of 7 PROFESSIONAL QUALIFICATIONS OF FRANK J. HANLEY EDUCATIONAL BACKGROUND I am a graduate of Drexel University where I received a Bachelor of Science Degree from the College of Business Administration. The principal courses required for this Degree include accounting, economics, finance and other related courses. I am also Certified by the Society of Utility and Regulatory Financial Analysts, formerly the National Society of Rate of Return Analysts, as agate of Return Analyst (CRRA). PROFESSIONAL EXPERIENCE In 1959, I was employed by American Water Works Service Company, Inc., which is a wholly - owned subsidiary of American Water Works Company, Inc., the largest investor -owned water works operation in the United States. I was assigned to its Treasury Department in Philadelphia until 1961. During that period of time, I was heavily involved in the development of cash flow projections and negotiations with banks for the establishment of lines of credit for all of the operating and subholding companies in the system, which normally aggregated more than $100 million per year. In 1961, I was assigned to its Accounting Department where I remained until 1963. During that two-year period, I became intimately familiar with all aspects of a service company accounting system, the nature of the services performed, and the methods of allocating costs. In 1963, I was reassigned to its Treasury Department as a Financial Analyst. My duties consisted of those previously performed, as well as the expanded responsibilities of assisting in the preparation of testimony and exhibits to be presented to various public utility commissions in regard to fair rate of return and other financial matters. I also designed and recommended financing programs for many of American's operating • Exhibit No. VER-2 Page 2 of 7 subsidiaries and negotiated sales of long-term debt securities and preferred stock on their behalf either directly with institutional investors or through investment bankers. I was elected Assistant Treasurer of a number of operating subsidiaries in the Fall of 1967, just prior to accepting employment with the Communications and Technical Services Division of the Philco-Ford Corporation located in Fort Washington, Pennsylvania. While in the employ of the Philco-Ford organization, as a Senior Financial Analyst, I had responsibility for the pricing negotiations and analysis of acceptable rates of return to the corporation for all types of contract proposals with various agencies of the U.S. Government and foreign governments. In the Summer of 1969, I accepted a position with the Financial Division of The Philadelphia National Bank. I was elected Financial Planning Officer of the bank in December 1970. While employed with The Philadelphia National Bank, my responsibilities included preparation of the annual and five-year profit plans. In the compilation of these plans, I had to perform detailed analyses and measure the various levels of profitability for each organizational unit. I also assisted correspondent banks in matters of recapitalization and merger, made recommendations and studies for their use before the various regulatory bodies having jurisdiction over them. In September 1971, I joined AUS Consultants - Utility Services Group as Vice President. I was elected Senior Vice President in May 1975. I was elected President in September 1989. EXPERT WITNESS QUALIFICATIONS I have offered testimony as an expert witness on the subjects of fair rate of return and utility financial matters in approximately 300 various cases and dockets before the following agencies and courts: before the Alaska Public Utilities Commission and its successor the Regulatory Commission of • 0 Exhibit No. VER-2 Page 3 of 7 Alaska, the Arizona Corporation Commission, the Arkansas Public Service Commission, the California Public Utilities Commission, the Public Utilities Control Authority of Connecticut, the Delaware Public Service Commission, the Florida Public Service Commission, Hawaii Public Utilities Commission, the Idaho Public Utilities Commission, the Illinois Commerce Commission, the Indiana Public Utility Regulatory Commission, the Iowa Utilities Board, the Public Service Commission of Kentucky, the Maryland Public Service Commission, the Massachusetts Department of Public Utilities, the Michigan Public Service Commission, the Minnesota Public Utilities Commission, the Missouri Public Service Commission, the Public Utilities Commission of Nevada, the New Jersey Board of Public Utilities, the New Mexico State Corporation Commission, the Public Service Commission of the State of New York, the North Carolina Utilities Commission, the Ohio Public Utilities Commission, the Oklahoma Corporation Commission, the Pennsylvania Public Utility Commission, the Rhode Island Public Utilities Commission, the Tennessee Public Service Commission, the Public Service Board of the State of Vermont, the Virginia State Corporation Commission, the Public Services Commission of the Territory of the U.S. Virgin Islands, the Washington Utilities and Transportation Commission, the Public Service Commission of West Virginia, the Wisconsin Public Service Commission, the Federal Power Commission and its successor the Federal Energy Regulatory Commission. I have testified before the New Jersey Division of Tax Appeals and the United States Bankruptcy Court - Middle District of Pennsylvania with regard to the economic valuation of utility property. Also, I have testified before the U.S. Tax Court in Washington D.C. as an expert witness on the value of closely held utility common stock in a contested Federal Estate Tax case. In addition, I have appeared as a Staff rate of return witness for the Arizona Corporation Exhibit No. VER-2 Page 4 of 7 Commission, the Delaware Public Service Commission and the Virgin Islands Public Services Commission. I have testified on the fair rate of return on behalf of the City ofNew Orleans, Louisiana, and also acted as project manager for my firm in representing the City in the 1980-1981 rate proceeding of New Orleans Public Services, Inc. The City of New Orleans then had, as it does now, regulatory authority with regard to the retail rates charged by New Orleans Public Service, Inc., for electric and natural gas service. I have also acted as a consultant to the District of Columbia Public Service Commission itself -- not in the capacity of Staff. I have testified before a number of local and county regulatory bodies in various states on the subject of fair rate of return on behalf of cable television companies as well as before an arbitration panel in Ohio and a State District Court in Texas. I have testified before the Public Works Committee of the Nebraska State Senate in relation to Legislative Bill 731 which proposed permitting Public Power Districts and Municipalities to enter the Cable Television field. PROFESSIONAL ASSOCIATIONS, PUBLICATIONS AND GUEST SPEAKER APPEARANCES I am a Member and Director of the Society of Utility and Regulatory Financial Analysts (SURFA), formerly known as the National Society of Rate of Return Analysts. I am a Certified Rate of Return Analyst (CRRA). I am on the Advisory Council of New Mexico State University's Center for Public Utilities which is endorsed by the National Association of Regulatory Utility Commissioners (NARUC). I am also a member of the Executive Advisory Council of the Rutgers University School of Business at Camden. AUS Consultants — Utility Services is an associate member of the American Gas Association (AGA) and I am a member of AGA's Rate and Strategic Issues Committee. I am also an i �. Exhibit No. VER-2 Page 5 of 7 associate member of the National Association of Water Companies and a member of its Finance Committee, and also an associate member of the Energy Association of Pennsylvania. AUS Consultants — Utility Services is an associate member of the New Jersey Utilities Association. I often attend SURFA meetings during which considerable information on the subject of rate of return is exchanged. I have also attended corporate bond rating seminars held by Standard & Poor's Corporation. I continuously review financial publications of institutions such as Standard & Poor's, Moody's Investors' Service, Value Line Investment Survey, and periodicals of various agencies of the U.S. Government. I co-authored an article with A. Gerald Harris entitled "Does Diversification Increase the Cost of Equity Capital?" which was published in the July 15,1991 issue of Public Utilities Fortnightly. Also, an article which I co-authored with Pauline M. Ahern entitled "Comparable Earnings: New Life for an Old Precept" was published in the American Gas Association's Financial Quarterly Review, Summer 1994. I also authored an article entitled "Why Performance -Based Incentives Are Essential" which was published in THE CITY GATE, Fall 1995, a magazine published by the Pennsylvania Gas Association. I have appeared as a guest speaker before an annual convention of the Mid -American Cable Television Association in Kansas City, Missouri and as a guest panelist on the small water companies' operation seminar of the National Association of Water Companies' 77th Annual Convention in Hollywood, Florida. I addressed the Second Annual Seminar on Regulation of Water Utilities sponsored by N.A.R.U.C., at the University of South Florida's St. Petersburg campus. I have spoken on fair rate of return to the Third and Fourth Annual Utilities Conferences, as well as the special conference on the cost of capital in El Paso, Texas sponsored by New Mexico State University. In �I Exhibit No. VER-2 Page 6 of 7 1983 I also made a presentation on the Cost of Capital in Atlantic City, New Jersey, at a seminar co- sponsored by Temple University. I have also addressed the Public Utility Law Section of the American Bar Association's Third Institute on Fundamentals of Ratemaking which was held in Washington, D.C. and I addressed a Conference on Cable Television sponsored by The University of Texas School of Law at Austin, Texas. Also, I addressed a meeting of the New England Water Works Association at Boxborough, Massachusetts, on the subject of Enterprise Financing. In addition, I was a speaker and mock witness in three different Utility Workshops for Attorneys sponsored by the Financial Accounting Institute held in Boston and Washington, D.C. I also was on a panel at the 23rd Financial Forum sponsored by the National Society of Rate of Return Analysts. The topic was Rate of Return Determination in the Diversified and/or Partially Deregulated Environment. I addressed the 83rd Annual Meeting of the Pennsylvania Gas Association in Hershey, PA. My topic was the Cost of Capital Implications of Demand Side Management. In June 1993, I lectured on the cost of capital at the American Gas Association's Gas Rate Fundamentals Course. In October 1993, I was a guest speaker at the University of Wisconsin's Center for Public Utilities -- my topic was "Diversification and Corporate Restructuring in the Electric Utility Industry - Trends and Cost of Capital Implications." In October 1994, I was a guest speaker on a panel at the Fourteenth Annual Electric & Natural Gas Conference in Atlanta, Ga., sponsored by the Bonbright Utilities Center of the University of Georgia and the Georgia Public Service Commission. The panel topic was "Responses to Competition and Incentive Rates." In October 1994, I was a guest speaker on a panel at a conference and workshop called "Navigating the Shoals of Cable Rate Regulation" sponsored by EXNET in Washington, D.C. The panel topic was "Rate of Return." Also, in March 1995, I was a guest speaker on a panel at a 0 • Exhibit No. VER-2 Page 7 of 7 conference entitled, "Current Issues Challenging the Regulatory Process" sponsored by New Mexico State University - Center for Public Utilities. My panel topic concerned the electric industry and was titled, "Impact of a Competitive Structure on the Financial Markets". In May 1995, I was a guest speaker at the 87th Annual Meeting of the Pennsylvania Gas Association in Hershey, PA. My topic was "The Pennsylvania Economy and Utility Regulation: Impact on Industry, Consumers. and Investors." In May 1996, I was on a panel at the 28th Financial Forum of the Society of Utility and Regulatory Financial Analysts. The panel's topic was "Revisiting the Risk Premium Approach" and was held in Richmond, Virginia. Since May 1996, I have participated as an instructor in 2-3 seminars per year on the "Basics of Regulation" (and the ratemaking process in a changing environment) and also in a program called "A Step Beyond the Basics", all sponsored by New Mexico State University's Center for Public Utilities and NARUC. In March 2002, I was a guest speaker before the Rate and Strategic Issues Committee- of the American Gas Association in St. Petersburg, Florida. My topic was Rate of Return Strategies. In December 2002, I was a guest speaker at a seminar entitled, "Service Innovations and Revenue Enhancements for the Energy Distribution Business" sponsored by the American Gas Association in Washington, DC. My topic was "The Impact of Volatile Energy Markets on Rate of Return Strategies". In February 2003, I spoke at the Rutgers University -Camden, NJ M.B.A. Speaker Series. I addressed M.B.A. students and interested faculty on the role of the expert witness in the public utility ratemaking process. In November 2003, by invitation, I was a Guest Professor at Rutgers University — Camden for a class of undergraduate finance students. City of Vemon. Caiifomia Table of Contents to the Financial Supporting Schedules of Frank J. Hanley Schedule No. Summary of Cost of Capital and Fair Rate of Return 1 Financial Profile of the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No.. ER97-2355, et. al.) 2 Financial Profile of the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion 3 Financial Profile of the Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion 4 Comparison of Total Permanent Capital for the Year 1998 and Percent of 1998 Industrial Revenues for the Proxy Groups and the City of Vemon 5 Excerpt from Stocks Bonds Bills and Inflation: 1999 Yearbook 6 Standard & Poor's Public Utility Rating Methodology Profile and Revised Public Utility Financial Benchmarks 7 Indicated Common Equity Cost Rate Using FERC's Discounted Cash Flow Model per Opinion No. 445 8 Indicated Common Equity Cost Rate Using the Discounted Cash Flow Model 9 Indicated Common Equity Cost Rate Using the Risk Premium Model 10 Excerpt from Stocks Bonds Bills and Inflation: 1999 Yearbook 11 Indicated Common Equity Cost Rate Using the Capital Asset Pricing Model 12 Indicated Common Equity Cost Rate Using Comparable Eamings Analysis 13 0 0 Exhibit No. VER-3 Schedule 1 Page 1 of 2 City of Vernon, California Summary of Cost of Capital and Fair Rate of Retum Based upon an Southern Califomia Edison Company s Capital Structure and Embedded Costs of Fixed Capital as Authorized by FERC in Opinion No. 445 Type of Capital Ratios (1) Cost Rate Weighted Cost Rate Long -Tenn Debt 48A0 % 7 430 % (1) 3.60 % Preferred Stock 580 6 560 (1) 0.38 Common Equity 45.80 12.065(2) 5.53 Total 100.00 % 9.61 % Notes: (1) Southem California Edison Company's capital structure and embedded cost rates of fixed capital as authorized in FERC's October 27, 2000'Order on Proposed Transmission Revenue Requirement" for the City of Vernon, California, Docket No. EL00-105-000. Capital ralios and embedded cost rates of fixed capital from the prepared direct testimony of Mary C. Simpson, witness for Southern Cafifomla Edison Company in Docket No. ER97-2355 et. al. (2) A common equity cost rate of 12.065% is an appropriate common equity cost rate for Vernon based upon the mid -point of a common equity cost rate of 11.90% utilizing the FERC Opinion No 446 Methodology on page 2 of this Schedule and a cost rate of 12.23% based upon the use of multiple cost of common equity models (which are summarized on page 2 of this Schedule). Exhibit No. VER-3 Schedule 1 Page 2 of 2 City of Vernon. Califomia Brief Summary of Common Equity Cost Rate FERC Opinion No 445 Methodology Indicated Common Equity Cost Rate Average Through Use of the Standard 8 Une FERC Discounted Pools Bond No. Cash Flow Model (1) Raling (2) Proxy Group of Four EleciOc and Combination Electric 8 Gas Companies Relied Upon by FERC i. in Opinion No. 445 (Docket No. ER97-2355 et 12 44% AA - Proxy Group of Five Electric and Combination Electric 8 Gas Companies vrilh Total 1998 2. Revenues Greater than $2.0 Billion 11.36% AA - Proxy Group of Four Electric and Combination Electric 8 Gas Companies Mfh Total 1998 3 Revenues Less than $2.0 Billion 11 75% BBB+ Range of Indicated Common Equity Cost Rate 4. Applicable to the City of Vernon 11 36% - 12 A4% Recommended Common Equity Cost Rate 5. Applicable to the City of Vernon (3) 11.90% Hanley Methodology- Multiple Cost of Common Equity Models Indicated Common Equity Cost Rate Applicable to the City or Vernon 6 Discounted Cash Flow Model (4) 12.67% 7_ Risk Premium Model (5) 11.72% 8. Cepilal Asset Pricing Model (6) 10 71% 9 Comparable Earnings Analysis (7) 13.75% Range of Indicated Common Equity Cost Rate 10. Applicable to the City of Vernon 10.71% - 13 75% Conclusion of Common Equity Cost Rate 11. Applicable to the City of Vernon (6) 12.23% Notes: (1) From page 1 of Schedule 8 of this Exhibit. (2) From page 2 of Schedule 10 of this Exhibit. (3) Based upon the midpoint of the range of indicated common equiy cost rate of 11.36% - 12A4%. (4) From page 1 of Schedule 9 of this Exhibit (6) From page 1 of Schedule 10 of this Exhibit. (6) From page 1 of Schedule 12 of this Exhibit (7) From page 1 of Schedule 13 of this Exhibit (8) Based upon the midpoint of the range of indicated common equity cost rate of 10.71% - 13 75% 4) 9 y � � N m m $ N KId m O �)�{, m m 8 n° � n 0 Id a, tG x ❑❑U. rod as Zm 0 g" v Sm � N N t a c� x IIx x x 1f! m Rl ig o cl � ri of � 0 U W W Z J O t ffimm }} a.7.7 �yy} Q o 3 M r8 f2-wwj �wirW B zLl J,x: U m m l� Q J W M � EL Do am `L F- 3.0 1< IWil O N 0 1� ri �ui� tm � N N IV ri NtJ � � r cpm n m mm Wmv,$y� , griN x x K 9H4 fgHN0 N g C A m 01 G aa`SW Sa o� A <H �a ENg Exhibit No. VER-3 Schedule 2 Page 1 of 2 y W � Q � S u�Ci < J Z J:kj y<G W o�a wrrc u Uo3� c yZU W ? : N wiz Um< t� 0 Exhibit No.. VER-3 Schedule 2 Page 2 of 2 Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket ER97-2335, et. al.) Capitalization and Financial Statistics 1994-1998, Inclusive Notes: (1) All capitalization and financial statistics for the group are the arithmetic average of the achieved results for each individual company in the group, and are based upon financial statements as originally reported in each year. (2) Computed by relating actual long-term debt interest or preferred stock dividends booked to average of beginning and ending long-term debt or preferred stock reported to be outstanding.. (3) Coverages - excluding all AFUDC represent the number of times available earnings, excluding all AFUDC, cover fixed charges. Selection Criteria. The basis of selection was to include those electric and combination electric & gas companies utilized by FERC Trial Staff and relied upon by FERC in setting an allowed return on common equity for Southern California Edison Company in Opinion No. 445, Docket No. ER97-2355, et. al.. The group includes the following four companies: Constellation Energy Group, Inc. Duke Energy Corp. PG&E Corp. The Southern Company Source of Information: Standard & Poor's Compustat Services, Inc., PC Plus Research Insight Database Company Annual Forms 10-K Exhibit No. VER-3 Schedule 3 Page 1 of 2 yt 91 e x ttL7 qmai i� b W t'1 fV N 1A Y] OiI R V to tN nl O V ' } ^Gtl Q e x R ae se ae x yt � ie :R eL y'• ;e x N� Ifl� W�/7 I74N my�ry� Cf�1 F1 � oN1+f OI W c+iNri � of N m N qq K ye 3e X y! 32 x 3 vCS, mlc� 1 n N as ~ r i L n o t p g �? 0 N iE e e4I ae X x FNN e: in t%17 ai r� aQ v v`" U � � LL N X ee x X x og tTlAN t�l ri vi lvN Q Q a Ol 0' G oN N � �w2 Too v cn QQ U F 8 U Wkm 93 O IL I pQJm Op�p,, pFU OO�WLL04 2.UaEN mW :1 zw10 r y at7aDO O� yOZ �O 0 O OrW Q QZYW LL zZZc�ao0o dpOt aoa" <"'O�aCI cWi)�aOza5O Is z��ZS$ — — IL a Exhibit No. VER-3 Schedule 3 Page 2 of 2 Proxy Group of Five Electric and Combination Electric &Gas Companies with Total 1998 Revenues Greater than $2.0 Billion Capitalization and Financial Statistics 1998-2002, Inclusive Notes: (1) All capitalization and financial statistics for the group are the arithmetic average of the achieved results for each individual company in the group, and are based upon financial statements as originally reported in each year. (2) Computed by relating actual long-term debt interest or preferred stock dividends booked to average of beginning and ending long-term debt or preferred stock reported to be outstanding. (3) Coverages - excluding all AFUDC represent the number of times available earnings, excluding all AFUDC, cover fixed charges. Selection Criteria: The basis of selection was to include those electric and combination electric & gas companies:1) which are assigned an SIC Code of 4911 (Electric Services) or 4931 (Electric and Other Services Combined) by the Securities and Exchange Commission (SEC) ; 2) which have common stock actively traded; 3) which are included in Value Line Investment Survey and I/B/EIS; 4) which have not cut or omitted their cash common stock dividends during the five calendar years ending 1998 or through September 1999, the period of time encompassed by this study; 5) which have some nuclear power generation; 6) which, in September 1999, were not expected to be acquired by or merged into another company; 7) whose operating electric subsidiaries have bonds rated either Aa2, Aa3, Al or A2 by Moody's and AA, AA-, A+ or A by Standard & Poor's; 8) which had more than 65% of their 1998 operating revenues derived from electric operations; 9) which had more than $2.0 billion in revenues for the year 1998; and 10) which are included in S&P's Compustat PC Plus Research Insight Data Base.. The following five companies met these criteria: Alliant Energy Corp.. Ameren Corp. Consolidated Edison, Inc.. Constellation Energy Group, Inc. The Southern Company Source of Information: Standard & Poor's Compustat Services, Inc., PC Plus Research Insight Database Company Annual Forms 10-K r v� a gyp@ be 2e at p� /A - {A�f, O Nl O Obi, O�ll pp "Id H�4O I�OQt��10 aN N �I se ;qe :R JC 1 p, tm7 N m QNIq m m ICI V! dt ve Se ?e 10 NM Q OO �Q. OAi E �I$ � h Z N V, Z d Z X LL of in is aryov �tcOv a 1 IGR NN OI NNVI m � N�� 0 N J t a a v a6 iR x ie x x po OYf yf • NP1 fN ype� pRp�� ��xyy pp F4A V M W N 1 x � K m o�ti mr4N Ir tu 8 'd 6 IsF§ F 5 a F a = z IL o �¢ 'aZeo rW� C�Z th Ix f� a �zaZ� o�§zw2 2 2P Jw�� a t oo m �w2 tu-U� OELI, U("w Z lw- f5 aJZZ zw- Zwwul u�gg�� p z U U z ( ttj W H 9 U Exhibit No_ VER-3 Schedule 4 Page 1 of 2 Exhibit No. VER-3 Schedule 4 Page 2 of 2 Proxy Group of Four Electric and Combination Electric &Gas Companies with Total 1998 Revenues Less than $2.0 Billion Capitalization and Financial Statistics 1998-2002, Inclusive Notes: (1) All capitalization and financial statistics for the group are the arithmetic average of the achieved results for each individual company in the group, and are based upon financial statements as originally reported in each year.. (2) Computed by relating actual long-term debt interest or preferred stock dividends booked to average of beginning and ending long-term debt or preferred stock reported to be outstanding.. (3) Coverages - excluding all AFUDC represent the number of times available earnings, excluding all AFUDC, cover fixed charges. Selection Criteria: The basis of selection was to include those electric and combination electric & gas companies: 1) which are assigned an SIC Code of 4911 (Electric Services) or 4931 (Electric and Other Services Combined) by the Securities and Exchange Commission (SEC) ; 2) which have common stock actively traded; 3) which are included in Value Line Investment Survey and I/B/E/S; 4) which have not cut or omitted their cash common stock dividends during the five calendar years ending 1998 or through September 1999, the period of time encompassed by this study; 5) which have some nuclear power generation; 6) which, in September 1999, were not expected to be acquired by or merged into another company; 7) which had more than 65% of their 1998 operating revenues derived from electric operations; 8) which had less than $2..0 billion in revenues for the year 1998; and 9) which are included in S&P's Compustat PC Plus Research Insight Data Base. The following four companies met these criteria: Central Hudson Gas & Electric Corp. DQE, Inc. Public Service Company of New Mexico The United Illuminating Company Source of Information: Standard & Pooes Compustat Services, Inc., PC Plus Research Insight Database Company Annual Forms 10-K fiJ o a 0 0 0 8 0 0 dg i» 69 if? t� Exhibit No. VER-3 Schedule 5 Page 1 of 2 c Lei. CO 0 t0 C E `m ? O O o O O C � `o•a�' CO +�+ CO Exhibit No. VER-3 * Schedule 5 Page 2 of 2 0 0 S 0 o cP, 0 0 0 O O tQ0 tLO �f m N O T G 0 E m 0 3 0 CL 0 3( 0 0 a LO O m Ca '2 V 0 20 . m c cis Iq 0 a 0 E C� vi �. o oV L d 0 a ll! u- Cow C � 'e N t 99 -A�tB40K r:; A R K7 U.LTS Exhibit No. VER-3 Schedule 6 Page 2 of 9 Firm Size and Return Chapter 7 Firm Size and Return The Firm Size Phenomenon One of the most remarkable discoveries of modern finance is the finding of a relationship between firm size and return 6 On average, small companies have higher returns than large ones. Earlier chapters document this phenomenon for the smallest stocks on the New York Stock Exchange (NYSE). The relationship between firm size and return cuts across the entire size spectrum; it is not restricted to the smallest stocks. In this chapter, the returns across the entire range of firm size are examined. Construction of the Decile Portfolios The portfolios used in this chapter are those created by the Center for Research in Security Prices (CRSP) at the University of Chicago's Graduate School of Business. CRSP has refined the methodology of creating size -based portfolios and has applied this methodology to the entire universe of NYSE listed securities going back to 1926. In 1993, CRSP changed the method used to construct these portfolios, thereby causing the return and index values in Table 7-2 and 7-3 to be significantly different from those reported in previous editions of the Yearbook. Previously, some eligible companies had been excluded or delayed from inclusion when the portfolios were reformed at the end of each calendar quarter. The New York Stock Exchange universe is restricted by excluding closed -end mutual funds, real estate investment trusts, foreign stocks, American Depository Receipts, unit investment trusts, and Americus Trusts. All companies on the NYSE are ranked by the combined market capitalization of all their eligible equity securities. The companies are then split into 10 equally populated groups or deciles. The portfolios are rebalanced using closing prices for the last trading day of March, June, September, and December. Securities added during the quarter are assigned to the appropriate portfolio when two consecutive month -end prices are available. For securities that become delisted, when the last NYSE price is a month -end price, that months return is included in the portfolio's quarterly return. When a month -end NYSE price is missing, the month -end value is derived from merger terms, quotations on regional exchanges, and other sources. If a month -end value is not available, the last available daily price is used. Base security returns are monthly holding period returns. All distributions are added to the month -end prices. Appropriate adjustments are made to prices to account for stock splits and dividends. The return on a portfolio for one month is calculated as the weighted average of the returns for the s Rolf W. Baru was the first to document this phenomenon.. See Bartz, Rolf W.., "The Relationship Between Returns and Market Value of Common stocks,' Journal ofFinancid Economic, Vol. 9 (1981), pp. 3-18. Ibbotson Associates 127 • 0Exhibit No. VER-3 Schedule 6 Page 3 of 9 Chapter 7 individual stocks in the portfolio. Annual portfolio returns are calculated by compounding the monthly portfolio returns.. Aspects of the Firm Size Effect The firm size phenomenon is remarkable in several ways. First, the greater risk of small stocks does not, in the context of the Capital Asset Pricing Model, hilly account for their higher returns over the long term. In the CAPM, only systematic or beta risk is rewarded. Small company stocks have had returns in excess of those implied by the betas of small stocks. Secondly, the calendar annual return differences between small and large companies are serially correlated. This suggests that past annual returns may be of some value in predicting future annual returns. Such serial correlation, or autocorrelation, is practically unknown in the market for large stocks and in most other capital markets. In addition, the firm size effect is seasonal. For example, small company stocks outperformed large company stocks in the month of January in a large majority of the years. Again, such predictability is surprising and suspicious in the light of modern capital market theory. These three aspects of the firm size effect (long-term returns in excess of risk# serial correlation and seasonality)' will be analyzed after the data are presented. Presentation of the Decile Data Summary statistics of annual returns of the 10 deciles over 1926-1998 are presented in Table 7-1. Note from this exhibit that the average return tends to increase as one moves from the largest decile to the smallest. (Because securities are ranked quarterly, returns on the ninrh and tenth deciles are different than those suggested by the small company stock index presented in earlier chapters. The inclusion of American Stock Exchange and over-the-counter data in the small company stock index beginning in 1982 is also partly responsible for these differences. A detailed methodology for the small company stock index is included in Chapter 3.) The total risk, or standard deviation of annual returns, also increases with decreasing firm size. The serial correlations of returns are near zero for all but the smallest three deciles. Table 7-2 gives the year -by -year history of the returns for the different size categories. Table 7-3 shows the growth of $1.00 invested in each of the categories as of year-end 1925. The sheer magnitude of the size effect in some years is noteworthy. While the largest stocks actually declined in 1977, the smallest stocks rose more than 15 percent. A more extreme case occurred in the depression -recovery year of 1933, when the difference between the first and tenth deciie returns was 128 SBBI 1999 Yearbook Table 7-1 Size-Decile Portfolios Summary Statistics of the NYSE of Annual Returns Exhibit No, VER-3 Schedule 6 Page 4 of 9 Firer Size and Return From 1926 to 1998 Geometric Arithmetic Mean Standard Deviation Serial Correlation Decile Mean I -Largest 10.4% 12.1 °% 18.9% 005 2 113 137 222 0.03 3 11.5 141 23.9 -001 4 117 148 264 -001 5 121 155 27.2 -001 6 119 156 282 007 7 118 16.0 306 003 8 12.0 170 34.4 0.09 9 122 179 370 009 10-Smallest 131 210 45.8 018 Mid -Cap 3-5 11.7 146 25.1 -001 Low -Cap 6-8 120 160 30.0 006 Micro -Cap 9-10 126 18.7 39.2 012 WSE Total Value weighted Index 10.8 12 7 20.1 0.02 Results are far quarterly re -ranking for the deciles. The small company stock summary statistics presented in five to 1982. Moreover, starting in earlier chapters comprise a re -ranking 1982, the small company stock series of the portfolios every years prior presented in earlier chapters includes NASDAQand AMEX stocks; the deciles presented here ate constructed entirely from NYSE stocks, Ibbotson Associates 129 Exhibit No. VER-3 Schedule 6 Page 5 of 9 Pages 130 —136 omitted as they contain backup data only Exhibit No.. V_ER-3 Schedule 6 Page 6of9 Firm Size and Return far more substantial. The divergence in the performance of small and Iarge company stocks is a common occurrence. In Table 7-4, the decHc returns and index values of the NYSE- are broken down into mid -cap, low -cap, and micro -cap stocks. Mid -cap stocks are defined here as the aggregate of deciles 3-5. Based on the most recent data, companies within this mid -cap range have market capitalizations at or below $4,199,948,000, but greater than $918,323,000. Low -cap stocks include deciles "and currently include all companies in the NYSE with market capitalizations at or below $918,323,000 but greater than $252,109,000. Micro -cap stocks include deciles 9-10, and include companies with market capitalizations at or below $252,109,000. The returns and index values of the entire NYSE are also included. All reruns presented are value -weighted based on the market capitalizations of the deciles contained in each sub -group. Graph 7-1 graphically depicts the growth of $1.00 invested in each of these capitalization groups. Size of the Deciles Table 7-5 reveals that most of the market value of the stocks listed on the NYSE is represented by the top three deciles. Approximately two-thirds of the value is represented by the first decile, which currently consists of 189 stocks. The smallest decile represents less than one -quarter of one percent of the market value of the NYSE. The data in the second column of Table 7-5 are averages across all 73 years. Of course, the proportions represented by the various deciles vary from year to year. In columns three and four are the number of companies and market capitalization. These present a snapshot of the structure of the deciles near the end of 1998. It is important to note that these proportions are not representative of the American Stock Exchange (AME)Q or the over-the-counter (OTC) market. Small firms, as defined by NYSE rankings, make up far higher proportions of value in the AMEX and OTC markets. The aggregate market value of small firms in the AMEX and OTC markets is much larger than the corresponding value on the NYSE. Thus, one cannot assume that findings that hold for NYSE firms will hold for firms traded elsewhere. The lower portion of Table 7-5 shows the largest firm in each decile and its market capitalization. 1bbotson Associates 137 Exhibit No. VER-3 Schedule 6 Page 7 of 9 Chapter 7 Table 7-5 Size-Decile Portfolios Bounds, Size, of the NYSE and Composition From 1926 to 1998 Historical Average Percentage of Recent Number of """ Decile Markef Capitolization in thousands) Recent Percentage of Total Capitalization P Decile Total Capitalization Com anies $5,985,553,1d6 72.60% 1-Lac -Largest 9 2 65..15% 14.48% 189 189 1,052, i 31,226 476,920,534 12.76% 5.78% 3 4 7.63% 4.61% 190 189 273,895,7d9 170,846,605 3..32% 2,07% 5 6 3.01 % 2.03% 189 189 114,517,587 78,601,405 1.39% 0.95% 7 8 1.37% 0.90% 190 189 53,218,441 27,647,937 0.65% 0.34% 9 0..55% U5% 189 190 10,764,2b8 0.13% 10-Smallest Mid -Ca 3-5 P 15.25% 566 568 921,662,888 246,337,d34 11.18% 2.99% Low -Cap 6-8 A. % p,80% 379 38,412,205 0.47% Micro -Cop 9-10 Sauer. Center for Research in Security Prices, University of Gbrrago.mrs� the last 73 y of the docile market values Historical average percentage of total capicilizatioo shows the average, N over decil s, recent marltar capitalizarioa of les of September 30,)mpan,1998in the total S caated each year. are deciasa and recent percentage percentage coral Decile I-apnaiizolnn: (in thousands) Company Name I Aargest $296,077,749 9,635,796 Genera{ Electric . Fort James Corp 2 3 4,199,948 Century Telephone Entrprs Inc. Darden Restaurants Inc. 4 2,2b6,948 1,266,156 396,666 Commerce Group Inc. Mass 5 6 323 Downey Financial Corp. Maine Power Co- 7 b32,639 Central Subur6an Propane Partners L.P.. 8 452,109 Gray Communications Systems inc. 9 10-Smallest 23,872 Rowe Furniture Corp. Soum: Center far Research in Security Prices, University of Chicago. in defile as of September 30, 1998.. Market capitalization and name of largest company each — SBBI 1999 Yearbook Exhibit No. VER-3 Schedule 6 Page 8 of 9 Firm Size and Return Long -Term Returns in Excess of Risk The Capital Asset Pricing Model (CAPM) does not fully account for the higher tino se each delcile of company stocks. Table 7-6 shows the returns in excess of risk over the past 73 years the NYSE. The beta of each decile indicates the degree to whited beIn sseta,see turnhaprove wiequUonsth aat of 31) the overall market. For a more detailed description of CAPM and (32). the riskkss rate on historical The CAPM is used here to calculate the CAPM return in exc� should consist of the driskless rate, in performance. According to the CAPM, the return on a security ditional return to compensate for the risk of the security. Table 7-6 uses this case 5.2 percent, plus an ad nent of ZO-y the 73-year arithmetic mean income return compooasduration, ura io , f he ri kl� S�c with riskless rate. (However, it is appropriate to match the maturity, (beta) multiplied the investment horizon.) This CAPM return in excess of the hissorical riskless return is that compensates by the realized equity risk premium. The realized equity r premium is investors for taking on risk equal to the risk of he market as a whole (estimated by the 73-yer arithmetic mean return on large company stocks, 13.2 percent, less the historical riskless rate, 5.2 percent). A beta greater than 1 indicates that the security is riskier hdin tl�e m�kHow� ccbasednon hig to storical M equation, investors are compensated for taking on his e NYSE decile porr return data on thfolios, the smaller deciles have had returns that are not fully explainable by the CAPM. This return in excess of CAPM, grows larger as one moves from the largest rn is micro - companies in decile 1 to the smallest in decile 10. The excess retuaPev� Ioy P n to he nCAPM which cap stocks (deciles 9-10). This size related phenomenon has prompte includes a size premium. Chapter 8 presents the modified CAPM theory in more detail. ty market This phenomenon can also be viewed graphically, as depicted in rem umPBassed on the risk o beta) of line is based on the pure CAPM without adjusting for theP expected a security, he expected return should fluctuate along the security market line. However, the returns for the smaller deciles of he NYSE lie above the line, indicating that these deciles havvee had returns in excess of their risk. Ibbotson Associates 139 NYSE: Exhibit No. VER-3 Schedule 6 Page 9 of 9 Chapter 7 Table 7-6 Size-Decile Portfolios of the NYSE: Long -Term Returns in Excess of CAPM from 1926 to 1998 Arithmetic Actual Return CAPM Return in Excess of Size Premium (Return in Mean in Excess of Riskless Rate" Riskless Rate +► Excess of CAPM) Decile Beta` Return 0 28 9b 1 0.90 12.12% 6 91 % 7.19% 828 0.18 2 1.04 1366 1411 8 46 8.91 867 0.25 3 1.09 1.13 1476 9.56 8 057 109 q 5 5 1.16 15.52 10.31 9.22 941 099 1.18 1560 10.40 10 79 9.81 098 7 1.28 1.27 15 99 1705 1185 10.13 1.72 96 1.96 8 9 1.34 1785 12.65 1068 11.48 4.35 10 144 2103 15.83 Mid -Cap, 3-5 1.11 1456 9.35 8 9 86 86 49 10.49 Low -Cap, 6-8 121 1601 18.70 13 49 10.90 2.60 Micro -Ca 9-10 1.37 7-2 Size-Decile Portfolio Security Market Line 25% 20% 0% OB 1 12 14 16 0 02 0.d 0.6 Belo ' Betas are estimated horn monthly returns in excess of the 30-day U.S. Treasury bill total return, January 1926-December 1998. " Historical riskless rate measured by the 73-Year arithmetic mean income return component of 20-year government bonds (5.20). 140 SBBI 1999 Yearbook Exhibit No.. VER-3 Schedule 7 Page 1 of 12 Standard & Poorrs CORPORATE - RATINGS CRITERIA 0 [ 0, • J , • t Dear Reader, This volume updates the 1994 edition of Corporate Finance Criteria. There are several new chapters, covering our recently introduced Bank Loan Ratings, criteria for "notching" junior obligations, and the role of cyclicality in ratings. Naturally, the ratio medians have been brought up to date. Standard & Poor's criteria publications represent our endeavor to convey the thought processes and methodologies employed in determining Standard & Poor's ratings. They describe both the quantitative and qualitative aspects of the analysis. We believe that our rating product has the most value if users appreciate all that has gone into producing the letter symbols. Bear in mind, though, that a rating is, in the end, an opinion. The rating experience is as much an art as it is a science. Solomon B. Samson Criteria Committee Chairman, Corporate Ratings Oki htlrW Corponia Aran CrArrkJteP�tbq or dhtrmudnq Ckm an Rrlugr WAodr vralww the Comm of Avow tdrowwptbq Ne pubt I r I. pr Oki to.For Womradon oa dncowde6 pun rater. or ow tA7(rervica. D 1212120E 11 Standard & Poore 07 A nshrm olrl.eMoGrovHraCmrpada ._�.. �,,.,.r,■r a oeor■.a oNtlonol Thr IkGravfHa,Compank�. Exhibit No. VER-3 Schedule 7 Page 2 of 12 &t�t3UaliU'&P.OfI}iSEtATtNt3S5ER1t1Gkb :� �><� Presidetd Leo G O'Neill Executive Vice Presidents Hendrt'ic J. Kranenburg Robert E NUt = Executive Managing Directors Edward Z. Emmerp Corporate Finance Ratings Clifford M. Grie , Financial Institutions Ratings Vladimir N Taub, Public I surana Rati gs rigs Vickie A Tillman, Structured Final," Ratings Joanne W. Rose, Senior Managing Director General Counsel Glenn S. Goldberg, Managing Direetorp Ratings Development er Communications Senior Tice President Jeffrey R. Paterson Via President Robert Pr"P ProduatMaaagsr Olga & Sdortino Marketing SPacialist Suzan, Perrunno Managing Editor Linda Saul EditonatManagers RachelL. leG idea Steve D. Homan Copy Editor Peter Dinelfo ■ PRODUCTION Dhectmof Dosiga.Produclioo Laurel8errrstein &MaaufacWdng DUKTOP PUgUSHING Menager.Produe6onOP1113110as Randi Bender Production Manager Barr' Ritz production Coordinattim Hary Aronson Aliei —101 Elise Lichteratan SeniorProdueliontissistaate L-,iu rnsa omCoprEditor Stephen Williams DESIGN Manager.An&Dstiga Sara Burris SadorDesigners claudisBaudo Dandle Sawyer Designer Giulia Fat JuaiorDesignet Heidi Weinberg TECHNoLDGY Bt DEVEt.O4MENr senior ProductionManagar EdwardHanapole ProduetioaMenager Theod—licrez Senior production Assistant JasoaRock SALES Via Presidant Sarah Forgnwm Director, Global Sales George SrhepP Sales Managers Steve Flaws. Ewroppss Michael Naylor. Asia Pad/k Customer service Manager RoiertBaumohl Iy/ wGraw )II presidenSN t 'Id andCNdeparalhg ��y y"oumplet""iaa, ThbmatC RrW�pr CAIxL trvm ■wn:n barevd to be tIMI , novmer. o9e —... w»-.-, _. r b nol reoporalbietar W Inereer ondssisa or feraa,,cenb obabd Imm►h up o! aydrbdomadoa. n to as publCatbes aWeaber thrbnanoimKhzecureksorbytbeuadrrwdlenpaNr7a1 Sue,dadaPootn`TmationlorratlnpdebtotiptWm.aucbmmmpprmalbnbbuedontbeamraMeaonloddeltnbalAenbrpardknonmlyp tr! h the dbtrmudon thneoi. the lea geneaVJ v■Qr from r2b00 to $50t'D0. Y11dk Sanded 8 Poore s"rva as ftm a dkrsmlmn the ndnp. a rxoMa ro pa7mns for doing oo, euept for wbwlPdo Exhibit No. VER-3 Schedule 7 page 3 of 12 aTANDARQ & POOA S`C3RPORATi RATtTJGS G.E3171=A1A . > :: »' Utilities The utilities rating methodology encompasses two basic components: business risk analysis and financial analysis - Evaluation of industrycharacteristics, the udIJVs position within that industry, its regulation, and its management provides the context for assessing a firms financial condi- tion. Historical analysis is a tool for identifying strengths and weaknesses, and provides a starting point for evaluating financial condition. Business position assessment Is the qualitative measure of a utility's fundamental creditwor- thiness. It focuses on the forces that will shape the utilities' future. The credit analysis of utilities Is quickly evolving, as utilities are treated less as regulated monopolies and more as entities faced with a host of challengers in a competitive environment Marketplace dynamics are supplanting the power of regulation, making it critically important to re- duce costs and/or market new services in order to thwart competitors' inroads. Markets and service area economy Assessing service territory begins with the economic and demographic evaluation of the area inwhich the utility has its franchise. Strength of long-term demand for the product Is examined from a macroeconomic perspective. This en- ables Standard & Pool's to evaluate the affordability of rates and the staying power of demand. Standard & Poor's tries to discern any secular consump- tion trends and. more importantly. the reasons for them. Specific items examined include the size and growth rate of the market, strength of the franchise, historical and projected sales growth, income levels and trends in popu- lation, employment, and per capita income. A utility with a healthy economy and customer base —as illustrated by diverse employment opportunities, average or above -av- erage wealth and income statistics, and low unemploy- ment—wW have a greater capacity to support Its opera- tions. For electric and gas utilities, distribution by customer class is scrutinized to assess the depth and diversity of the utility's customer mix. For example, heavy industrial con- centration is viewed cautiously, since a utility may have significant exposure to cyclical volatility. Alternatively, a large residential component yields a stable and more pre- dictable revenue stream. The largest utility customers are identified to determine their importance to the bottom line and assess the risk of their loss and potential adverse effect on the utility's financial position. Credit concerns arise when individual customers represent more a e than %of revenues. The company or industry may playsignificant role in the overall economic base of the service area More- over, large customers may turn to cogeneration or alterna- tive power supplies to meet their energy needs, potentially leading to reduced cash flow for the utility (even incases where a large customer pays discounted rates and Is not a profitable account for the utiity). Customer concentration is less significant for water and telecommunication udU- ties. Competitive position As competitive pressures have intensified in the utilities industry, Standard & Pooes analysis has deepened to in- clude a more thorough review or competitive position, Electric utility competition For electric utilities, competitive factors examined in- clude: percentage of firmwholesale revenues that are most vulnerable to competition; industrial load concentration; exposure of key customers to alternative suppliers; com- merdal concentrations; rates for various customer classes; rate design and flexibility: production costs. both marginal and fixed; the regional capacity situation; and transmission constraints. A regional focus is evident. but high costs and rates relative to national averages are also of significant concern because of the potential for electricity substitutes over time. Mounting competition in the electric utility industry derives from excess generating capacity, lower barriers to entering the electric generating business. and marginal costs that are below embedded costs. Standard & Pooes has already witnessed declining prices in wholesale mar- kets, as de facto retail competition is already being seen in several parts of the country. Standard & Poor's believes that over the coming years more and more customers will want and demand lower prices. initial concerns focus on the largest industrial loads, but other customer classes wW be increasingly vulnerable. Competition will not necessar- 20 fly be driven by legislation. Other pressures will arise from global competition and improving technologies. whether it be the declining cost of incremental generation or ad. vances in transmission capacity or substitute energy sources like the fuel cell. It is impossible to say Precisely when wide-open retail competition will occur. this will be evolutionary. However, significantly greater competition in retail markets is inevitable. Exhibit No. VER-3 Schedule 7 Page 4 of 12 ante their tight budgets) Also, water utilities are not fully Immune to the forces of competition: in a few instances wholesale customers can access more than one Supplier - Gas utility competition Similarly, gas utilities are analyzed with regard to their competitive standing in the three major areas of demand: residential, commercial, and indusstri�t� Although gas ree�s fated as holders of monopoly po have for some time been actively competing for energy market share with fuel oil, electricity. coal, solar, wood, etc. The long-term staying power of market demand for natu- ral gas cannot be taken for granted. In fact. as the electric utility industry restructures and reduces costs, electric power will become more cost competitive and threaten certain gas markets. In addition, independent Base market- ers have made greater inroads behind the city g and are competing for large gas users Moreover, the recent trend by state regulators to unbundle utility services is creating opportunities for outsiders to market niche products. Dis- tributors still have the upper hand, but those who do not reduce and control costs. and thus rates, could find com- petition even more difficult. a somewhat Natural gas pipelines are judged to carry higher business risk than distribution companies because they face competition in every one of their markets. To the extents pipeline serves utilities versus industrial end users, its stability is greater. Over the next five years, pipeline competition will heat up since many service contracts with customers are expiring. Most distributor or end -use cus- tomers are looking to reduce pipeline costs and are work- Ing to improve their load factor to do so. Thus, pipelines will likely find it d0cult to recontract all capacity in coming years. Being the Pipeline of choice is a function of attractive transportation rates, diversity and quality of services provided, and capacity available In each particular market. in all cases though, periodic discounting of rates to retain customers will occur and put pressure on profit ability. Water utility competition As the last true utility monopoly, water utilities racevery c Ea be the ratio of employees per ]O,ODO access lines, an little competition and there is currently no challenge to the Y measurementtions have oft cited conttnuadon of franchise o ned wa ec companies have employees per 10.000 lines are bet efficiency. seen. down from the been cases where investor typical 40 or more employees per 10.000 ratio of only a few been subject to condemnation and municipalization be-e a o. cause of poor service or political motivations In that re- Y g Bard, Standard & neirhborin uclose tilities d national ao costs vert- inlcreasingly digitallYn addition. rsw'i switched and able to accommodate tat rates in relation to neighboring agespncontrast, the priivvaatizaio ofpublhan ticipaeedaThisicas high-speed ccco smodate switched broadband services will be built has begun. albeitPinto occurring ilyartnershlps. and not in ass operating contracts and t transfers. advanced networks will enabletelephonecompanies to public/privatep value-added serv- This trend should continue as cities look for ways to bat- look to a greater variety of high margin. Telephone competition The Telecommunication Act of'l99 accelerates m e�� , ��) timing challenge to the local exchangeP century -old monopoly in the local loop. Competitive ac- cess providers (CAPS), both facilities -based and resellers. are aggressively pursuing customers, generally targeting metropolitan areas, and promising lower rates and better service. Most long-distance calls are still originated and termi- nated on the local telephone company network. To com- plete such a call. the long-distance provider (including AT&T. MCI. Sprint and a host of smaller interexchange carriers or'1XCs') must pay the local telephone company a steep *access' fee to compensate the local phone tom pany for the use of its local network. CAPS. in contrast. build or lease facilities that directly connect customers to their long-distance carrier. bypassing the local telephone company and avoiding access fees, and thereby can offer lower long-distance rates But the LECs are not standing still: they are combating the loss of business to CAPS by lowering access fees, thereby reducing the economicincen- tive for a high usage long-distance customer to use a CAP. LECs are attempting to make up for the loss of revenues from lower access fees by increasing basic local service rates (or at least not lowering them), since basic service Is far less subject to competition. LECs are Improving v ating efficiency and marketing high margin. alue added new services. Additionally, in the wake of the Telecommu- nications Act. LECs will capture at least some of the inter- LATA long-distance market As a result of these initiatives. LECs continue to rebuild themselves —from the traditional utility monopoly to leaner, more marketing oriented or- ganizations While LECs, and indeed all segmentscompetition, till the telecomhere nicatlons sector, face increasing P fa- vorable Industry factors that tend to offset heightened business risk and auger for overallratings stability for most LECs. Importantly, telecommunications is a declining -cost business. With increased deployment of fiber optics, the cost of transport has fallen dramatically and digital switch- ing hardware and software have yielded more capable, trouble -free and cost-efficient networks. As a result. the maintenance has dropped sharply. as Mus- ices. In addition to those current services such as call waiting or caller ID. the delivery of hundreds of broadcast and interactive video channelsww be possible. While these services offer the potential of new revenue streams. they will simultaneously present a formidable challenge. LECs will be entering the new (to them) arena of multimedia entertainment and will have to develop expertise in mar' keting and entertainment programming acumen; such skills stand in sharp contrast to LECs' traditional strengths In engineering and customer service. Operations Standard & Pooes focuses on the nature of operations from the perspective of cost. reliability. and quality of service. Here. emphasis Is placed on those areas that re- quire management attention In terms tlf time icaL or money a d which, if unresolved, may P competitive problems. Exhibit No. VER-3 Schedule 7 Page 5 of 12 ence. In essence, favorable nuclear operations offer sogn�L cant opportunities but. ifs nuclear unit runs Poorly at all. the attendant risks can be great Operations of gas utilities For gas pipeline and distribution companies, the degree of plantutilization, the physical condition of the mains and lines, adequary of storage to meetseasonal needs#'lost and unaccounted for" gas levels, and per -unit nongas operat Ing and construction costs are important factors. Efficiency statistics such as load factor, operating costs Per customer. and operating income per employee are also evaluatedwhole, comparison to other utilities and the industry Operations of electric utilities For electrics, the status of utility plant investment is reviewed with regard to generating plant availability and utilization, and also for compliance with existing and con- templated environmental and other ravary standards. lity. load The record of plant outages, equivalent factors, heat rates, and capacity factors are examined. Also important is efficiency, as defined by total megawatt hour per employee and customers per employee. Transmission interconnections are evaluated in terms of the number of utilities to which the utility in question has access, the cost structures and available generating capacity of these other utilities, and the price paid for wholesale power. Because of, mounting competition and the substantial escalation in decommissioning estimates, significant weight is given to the operation of nuclear facilities. Nu- clear plants are becoming more vulnerable to high produc- tion costs that make their rates uneconomic Significant asset concentration may expose the utilityto poor perform- ance, unscheduled outages or premature shutdowns, and large deferrals or regulatory assets that may need to be written off for the utility to remain competitive. Also. nuclear facilities tend to represent significant portions of their operators' generating capability and assets. The loss of a productive nuclear unit from both power supply and rate base can interrupt the revenue stream and create sub- stantial additional costsfor repairs and improvements and replacement power. The ability to keep these stations run- ning smoothly and economically directly influences the ability to meet electric demand, the stability of revenues and costs, and, by extension, the ability to maintain ade- quate creditworthiness. Thws,economic oars examined In .safe operation, and long-term operation epdL Specifically, emphasis is placed on operation and mainte- nance costs, busicosts, 1Rn forced outages, pantirsNCevaluatios, the po- tential need for repairs, operating licenses, decommission - tang estimates and amounts held in external trusts, spent fuel storage capacity, and management's nuclear expert. Operations of water utilities As a group, water utilities are e continually and to grading ding their physical plant to satisfy gut additional supply. Over the next decade, water systems will increasingly face the task of mai a d infrtaing astructure ance- as drinking water regulations change anrcarre ages. Given that the Safe Drinking Water Act was author- ized in 1974. the first generation of treatment plants built to conform with these rules are almost 2 eyi cis old on sat- tionally. because the focus during this pr 1sfying environmental standards, deferred maintenance of distribution systems has been asp cially In older urban areas.The increasing PP Yi gtreat dwater argues against the high level of unaccounted for water witnessed in the industry. Consequently, Standard & Poor's anticipates capital Planes for rebuilding distribution lines and major renewal and replacement efforts aimed at treatment plants. Operations of telephone companies For telephone companies. cost -of -service es of analysis lb-- ruses on plant capability nd lsascertainedbylooking qualltyof service. Plant capabilitydigitally switched at such parameters as percentage of gi lines; fiber optic deployment, in particular in those por- tions of the plant key to network survival; and the degree of broadband capacity fiber and coaxial deployment and broadband switching capacity. Ef,iciency measures in - dude operating margins, the ratio of employees Per access lines, and the extent of network and oper�s ns consolidation. Quality of, service encompasses tion of quantitative measures. such as trouble reports and repeat service calls, as well as an assessment of uandaive factors, that may include service quality goals by regulators. Regulation Regulatory rat -setting actions are reviewed on a case - by -case basis with regard to the potential h � of n credit turnis worthiness. Regulators' authorizing g rates of little value unless the returns are earnable- Furthermore, allowing high returns based on noncash items does not benefit bondholders. Also. to be viewed positively, Mull tory treatment should allow consistent performance from 31 period to period, given the importance of financial stabWty as a rating consideration. The utility group meets frequently with commission and staff members. both at Standard & Pooesoffices and at d commission headquarters, demonstrating importance Standard & Poor's places on the regulatory arena for credit quality evaluation. Input from these meetings and from review of rate orders and their impact weigh heavily in Standard & Pooes analysis. Standard & Poor's does not 'rate" regulatory commis- sions. State commissions typically regulate a number of diverse Industries, and regulatory approaches to different types of companies often differ within a single regulatory Jurisdiction. This makes it all but impossible to develop inclusive "ratings" for regulators. Standard & Pooes evaluation of regulation also encom- passes the administrative, judicial, and legislative proc- esses involved in state and federal regulation. These can affect rate -setting activities and other aspects of the busi- ness, such as competitive entry, environmental and safety rules, facility siting, and securities sales. As the utility industry faces an increasingly deregulated environment alternatives to traditional rate -making are becoming more critical to the ability of utilities to effec- ovely compete, maintain earnings power, and sustain creditor protection. Thus, Standard & Pooes focuses on whether regulators, both state and federal, will help or hinder utilities as they are exposed to greater competition. There is much that regulators can do. from allocating costs to more captive customers to allowing pricing flexibfl- Ity-and sometimes just stepping out of the way. Under traditional rate -making, rates and earrings are tied to the amount of invested capital and the cost of capital. This can sometimes reward companies more for justffying costs than for containing them Moreover. most current regulatory policies do not permit utilities to be flexible when responding to competitive pressures of a deregulated market Lack of flexible tariffs for electric utal- ties maylure large customers to wheel cheaper power from other sources. In general. a regulatoryjurisdiction is viewed favorably if it permits earning a return based on the ability to sustain rates at competitive levels. In addition to performance - based rewards or penalties, flexible plans could include market -based rates, price caps, index -based prices, and rates premised on the value of customer service. Such rates more closely mirror the competitive environmentthat utW- ties are confronting. Electric industry regulation The ability to enter into long-term arrangements at ne- gotiated rates without having to seek regulatory approval for each contract is also important in the electric industry. (While contracting at reduced rates constrains financial performance, it lessens the potential adverse impact in the event of retail wheeling. Since revenue losses associated with this strategy are not likely to be recovered from rate- payers, utilities must control costs well enough to remain 32 Exhibit No. VER-3 Schedule 7 page 6 of 12 competitive if they'are to sustain current levels of bond- holder protection.) Natural gas industry regulation In the gasindustry. too.several state commission polides weigh heavily in the evaluation of regulatory support. Examples include stabilization mechanisms to adjustreve- nues for changes in weather or the economy, rate and service unbundling decisionwe and ost flexible allocation betweensales and transportation in- dustrial rates. and the general supportiveness of construc- tion costs and gas purchases. Water industry regulation In all water utility activities, federal and state environ- mental regulations continue to play a critical role. The legislative timetable to effect the 1986 amendments o8� Safe Drinking Water Act of 1974 was quite aggressive. environmental standards -setting has actually slowed over the past couple ofyears due largely to increasing sentiment that the stringent, costly standards have not been justified on the basis of public health. A moratorium on the prom- ulgation of significant new environmental rules is antid- pated. Telecommunications industry regulation Despite the advances in telecommunications deregula- tion, analysis of regulation of telephone operators win continue to be a key rating determinant for the foreseeable future. The method of regulation may be either classic rate -based rate of return or some form of price cap mecha- nism The most important factor is to assess whether regulatory framework —no matter which type —provides sufiident financial incentive to encourage the rated com- pany to maintain its quality of service and to upgrade its plant to accommodatenew serviceswhilefaringincreasing competition from wireless'operators and cable television companies. Where regulators do still set tariffs based on an author- ized return, Standard & Pooes strives to explore with regulators their view of the rate -of -return components that can materially impact reported versus regulatory earnings. Specifically these include the allowable base upon which the authorized return can be earned, allowable expenses, and the authorized return. Since regulatory oversight runs the gamut from strict. adversarial relationships with the regulated operating companies to highly supportive pos- tures, Standard &Poor's probesbeyond the apparent regu- latory environment to ascertain the actual impact of regulation on the rated company. Management Evaluating the management of a utility is of paramount importance to the analytical process since management's abilities and decisions affect all areas of a company's op- erations. While regulation, the economy, and other outside factors can influence results, it is ultimately the quality of management that determines the success of a company. With emerging competition, utility management will be more closely scrutinized by Standard & Pool's and will become an increasingly critical component of the credit evaluation. Management strategies can be the key determi- nant in differentiating utilities and in establishing where companies be on the business position spectrum It is imperative that managements be adaptable. aggresslve, and proactive if their utilities are to be viable in the future: this is especially important for utilities that are currently uncompetitive - The assessment ofmanagement is accomplished thraougi meetings, conversations, and reviews of company plans. is based on such factors as tenure, industry experience, grasp of industry issues, knowledge of customers and their needs. knowledge of competitors, accounting and financ- ing practices, and commitment to credit quality. Manage- ment's ability and willingness to develop workable strategies to address their systems needs, to deal with the competitive pressures offree market, to execute reasonable and effective long-term plans, and to be proactive in lead- ing their utilities into the future are assessed. Management quality is also indicated by thoughtful balancing of public and private priorities, a record of credibilityand effective communication with the public. regulatory bodies. and the financial community. Boards of directors will receive ever more attention with respect to their role in setting appro- priate management incentives. With competition the watchword, Standard & Pool's also focuses on management's efforts to enhance financial condition. Management canbolsterbondholder protection by taking any number of discretionary actions, such as selling common equity, lowering the common dividenndd payout. and paying down debt Also important electric industry will becre�ivityI s thentering at mprovrategc alliances and working p P deny, such as central dispatching for a number of utilities or locking up at -risk customers through long-term con- tracts or expanded flexible pricing agreements. Proactiv management teams will also seek alternatives to tradf tional rate -base, rate -of -return -making. move to ado higher depredation rates for generating facilities. segment customers by individual market preferences. and attem to create superior service organizations. In general. management's ability to respond to mountin competition and changes in the utility industry in as s and appropriate manner will be necessary to credit health Fuel, power, and wafer supply Exhibit No.. VER-3 Schedule 7 Page 7 of 12 reserve margins, fuel mix. fuel contract terms. demand - side management techniques. and purchased power rangements. The adequacy of generating margins is examined nationally, regionally. and for each individual company. However, the reserve margin picture is mud- died by the imprecise nature f peak -load growth forecast ing, and also supply uncertainty relating to such things as Canadian capacity availability and potential Plant shut downs due to age, new NRC rules. add rain remedies. fuel shortages, problems associated with nontraditional reserves tech- nologies, and so forth. Even apparently amp he quality of may not be s hat as important as the size of rseem. Moreover. eserves. Corn capacity is J panies reserve requirements differ, depending upon indf- vidual operating characteristics. Fuel diversity provides flexibility in a changing environ- ment. Supply disruptions and price hikes can raise rates and ignite political and regulatory pressures that ulti- mately lead to erosion in financial ial pes erformance. take Thus. f ability to alter generating lower cost fuels is viewed favorably. Dependence on any single fuel means exposure to that fuel's problem electric utilities that rely on oil or gas face the potential for shortages and rapid facilities face escalating ties that own nuclear generating costs for decommissioning, and coal-fired ncconcern spacity e o� environmental problem stemming add rain and the 'greenhouse effect' n fa - Buying power from neighboring utilities. qualifyi g ditty projects, or independent power producers maybe the best choice for a utility that faces increasing electricity demand. There has been a growing reliance on purchased power arrangements as an alternative a to new plancte the con- struction. This can be an important purchasing utility avoids potential construction cost over- runsaswellasriskingsubs ant al amu�yearcconlitlesion avoid the financial risks typicalprudence e program that are caused by regulatory lag and nhance reviews. Furthermore, purchased power may cat supply flexibility, fuel resource diversity. and maxi load factors. Utilities that plan to meet demand projections cat with a portfolio f supply-side options also may be better able to adapt to future growth uncertainties. Notwith- g standing the beneflts of purchasing. such a a strategy long-term gt risks associated with it By 8 tarn purchased power contract that contains a fixed -cost com- ponent. utilities can incur substantial market. operating, regulatory. and financial risks Moreover, regulatory treat- ment of purchased power removes any upside potential that might help offset the risks. Utilities are not compen- Assessment of present and prospective fuel and power sated through incentive rate -making: rather. purchased trittllty analysis. while ower is recovered d supply is critical to every elecc uollar-for-dollar as an operating ex' gauging the long-term natural gas supply Position for gas plpellne and distribution companies and the water re- sourrxs of a water tlllty is equally important There Is no similar analytical category for telephone utilities. Electric utilities For electric utilities emphasis is placed on generating P pew. To analyze the financial impact of purchased power. Standard &Pool's first cal payments (discounted at O%j •ates the net present This e Of future annual capacity p y represents a potential debt equivalent —the off -balance - sheet obligation that a utility incurs when it enters Into a longterm purchased power contract. However. Standard 33 & poor's adds to the utility's balance sheet only a portion of this amount, recognizing that such a contractual ar- rangement Is not entirely the equivalent of debt. What percentage is added Is a function of Standard & Poor's qualitative analysis of the s �dfi a culatory risks ontract and the extent are borne to which market. operating. g by the utility (the risk factor). For unconditional, take -or - pay contracts, the risk factor range is from 40%-80%. with the average hovering around 60%. A lower risk factor is typically assigned for system Purchases from coal-fired utilities and a higher risk factor is usually designated for unit -specific nuclear purchases. The range for take -and - Pay performance obligations is between 10%-5096. Exhibit No. VER-3 Schedule 7 page 8 of 12 Having adequate treated waterstorage end has helped maities has ny come important in recent Years can summer periods. Of systems meet demands during p. interest is whether the resources are owned by the utility or purchased from other utilities or local authorlties Owt►- Ing properties with water rights provides more supply security. This is especially so in states like California where water allocations are being reduced, particularly since re- cent droughts and environmental issues have created alarm. Since the primary cost for water companies is treat- ment, it makes little dif'ferencewhether rawwater 1s owned tate water re bought In fact, y high. e overall cofederal andst to deliver regulations is very Bhp treated water to consumers remains relatively affordable. Gas utilities For gas distribution utilities, long-term supply adequacy obviously is critical, but the supply role has becomeeveEnergy more important in credit analysis since th Regulatory Commfsslods Order 636 eliminated the inter- state pipeline merchant business. This thrust gas supply responsibilities squarely on local gas distributors. Stand- ard & Pools has always believed distributor management has the expertise and wherewithal to perform the job well, but the risks are significant since gas costs are such a large percentage of total utility costs. In that regard. It Iisb p state tantforutilitiestogetpreapprovaLsofsupplyPOr well regulators or atleast keep the staff and corrurrissioners Informed. To minimize risks, a well -run program would diversify gas sources among different producers or mar- keters, different gas basins in the U.S. and Canada. and different pipeline routes Also. purchase contracts should be firm. with minimal take -or -pay provisions, and have prices tied to an industry Index. A modest percentage of fixed -price gas is not unreasonable. Contracts. whether of gas purchases or pipeline capacity,should be intermediate term. Staggering contract expirations (preferably annu- ally) provides an opportunity to be an active market player. A modest degree of reliance on spot purchases provides flexibility, as does the use of market -based storage. Gas storage and on -property gas resources such as liquefied natural gas or propane air are effective peak -day and peak - season supply management tools Since pipeline companies no longer buy and sell natural gas and arejust common within connections thoswith varied of reserve basins and many wells great Importance. Diversity of sources helps offsetthe risks arising from the natural production declines eventually experienced by all reserve basins and individual wells. Moreover, such diversity can enhance a pipeline's attrac- tiveness as a transporter of natural gas to distributors and end users seeking to buy the most economical gas available for their needs. Water utilities Asset concentration in the electric utility industry In the electric industry, Standard & Poor s follows the operations of major generating facilities to assess If they ace well managed or troubled. Significant dependence on one generating facility or a large financial investment in a single asset suggests high risk. The size or magnitude of a particular asset relative to total generation, net plant In service, and common equity is evaluated. Whertan- tial asset concentration exists. the financial profile f a company may experience wide swings depending on the assess performance. Heavy asset concentrationunits most prevalent among utilities with costly nuclear Nearly all water systems throughout the US. have ample long term water thesupplies, capability of treatment comfort. Standard 81 Pools assesses the production plants and the ability to pump water from underground aquifers in relation to the usage demands from consumers - 34 Earnings protection In this category- pretax cash income coverage Ofall inter- est charges is the primary ratio. For this calculation. allow- ance for funds used during construction (AFUDC) is removed from income and interest expense. AFUDC and othersuch noncash items do not provide any protection for bondholders, To identify total interest expense, the analyst reclassifies certain operating expenses, The interest com- ponent of various off -balance -sheet obligations. such as leases and some purchased-powerai interest expense. This provides the most direct Indication of a utility's ability to service Its debt burderL rotes While considerable emphasis In assessing P lion is placed on coverage ratios, this measure does not provide the entire earnings protection picture. Also Impor- tant are a company's earned returns on both equity and capital, measures that highlight a firm s earnings perform- ance. Consideration Is given to the interaction of embed- ded costs, financial leverage. and pretax return on capital. Capital structure Analyzing debt leverage goes beyond the balance sheet and covers quasi -debt items and elements of hidden flnan- dal leverage. Noncapitaiized leases (including sale/lease- back obtlgations).o eat guarantees-oles er and purchased -power are all considered debt equivalents and are reflected as debt in calculating capital structure ratios. By making debt level adjustments, the analyst can compare the degree of leverage used by each Utility Company. Furthermore. assets are examined to Identify underval- ued or overvalued Items. Assets of questionable value are discounted to more accurately evaluate asset protection. Some firms use short-term debt as a permanent piece of their capital structure. Short-term debt also is considered part of permanent capital when it is used as a bridge to permanent financing. Seasonal, self-liquidating debt is ex- cluded from the permanent debt amount, but this situation is rare —with the exception of certain gas utilities. Given the long life ofalmost all utility assets. short-term debt may expose these companies to interest -rate volatility. remar- keting risk bank line backup risk, and regulatoryexposure that cannot be readily offseL The lower cost of shorter -term obligations (assuming a positively sloped the risk oield f In Interest - rate s a positive factor that partially g rate variability. As a rule of thumb, a level of short-term debt that exceeds 1 o% of total capital is cause for concern. Similarly, if floating-rate debt and preferred stock con- stitute over one-third of total debt plus preferred As level is viewed as unusually high and may concern. It might also indicate that management is aggres- sive in its financial policies, A layer of preferred stock in the capital structure is usually viewed as equity —since dividends are discretion- ary and the subordinated claim on assets provides a cush- ion for providers of debt capital.. A preferred component of up to Io% is typically viewed as a permanent wedge in the capital structure of utiUti& However, Etna - viewed regulation is phased out. preferred by utilities —as many industrial firms; would —as a tempo- rary option for companies that are not current taxpayers that do not benefit from the tax deductibility of interest. Even now, floating-rate preferred and money market per- petual preferred are problematic" a rise in the rate due to deteriorating credit quality tends to induce a comparry to take out such preferred stock with debt. Structures that convey tax deductibility to preferred stock have become very popular and do generally afford such financingswith equity treatment. Exhibit No. VER-3 Schedule 7 page 9 of 12 Cash flow adequacy Cash now adequacy relates to a company's ability to generate funds internally relative to its needs. It is a basic component of credit analysis becau dividends, and make t takes cash to Pay expenses, fund capital spending. pay d both common and interest and principal payments, preferred dividend payments are important to maintain capital market access. Standard &Poor slooks at cash flow measures both before and after dividends are paid. To determine cash flow adequacy, several quantitative relationships are examined. Emphasis is placed on cash flow relative to debt, debtservice requirements. and capital spending. Cash flow adequacy is evaluated with respect to a flrrn s ability to meet all fixed charges, including capacity ice the payments under purchased -power conditional nature of some contrails. the purchaser is ob- ligated to pay a minimum capacity charge. The ratio used is funds from operations plus interest and capacity y Pay- ments divided by interest plus capacity payments. Financial flexibility/capital attraction Financing flexibility incorporates a utility's financing needs. plans, and alternatives, as well as its flexibility to accomplish its financing program under stress without damaging creditworthiness. External funding capability complements internal cash flow. Especially since utilities are so capital intensive, a firm's ability to tap capital mar- kets onanongoingbasismustbeconsidered. Debt capacity ebt reflects all the earlier elements: earning p eC leverage, and cashnow adequacy. Market access at reason- able rates is restricted if a reasonable capital structure is not maintained and the company's financial prospects dim. The analyst also reviews indenture restrictions and the impact of additional debt an covenant tests. Standard & Poor s assesses a company's capacity and willingness to Issue common equity. This is affected by various factors, including the market -to -book ratio. divi- dend policy, and any regulatory restrictions regarding the composition of the capital structure. 35 Exhibit No• VER-3 Schedule 7 pane to of 12 Formulas for key ratios operations + interest expense pretax interest coverage Pretax income from continuing Po Gross interest inducting rents . Pretax income from continuing operations +interest expense +gross rents pretax fixed charge coverage Gross interest + gross rents PPretax funds flow+ interest expense pretax funds flow interest coverage Gross interest Funds from operations as a % of total debt- Funds from operations x 1oo Total debt cash flow as a /e of total debt s Free operating cash flow x 100 Fuse operating Total debt pretax return on permanent capital s Pretax income from continuing operations + interest expense x 100 Sum of (1) average of beginning of year and end of year curten maturities, long-term debt, noncurrentduring yeas disciosed and in (2) average short-term borrowings footnotes i]perating income as a % of sales" operating income x 1oD Sales of capitalization s Long-term debt x 100 Long-term debt as a 9/6 Long-term + equity Total debt Total debt as a % of capitalizationx 100 tal des Tobt +equity italization Total debt + 8 times gross rentals paid x 100 Total debt + a times rents as a k of adjusted cap To�g times gross rentals paid + equity Glossary Equity Free operating cash Row Funds from operations Gross interest Gross rents interest expense Long-term debt Net cash Row operating income pretax funds flaw Total debt 90 Shareholders' equity (Including preferred stork) plus minority Interest Funds from operations minus capital expenddures, minus (Pius) the increase (decrease) in working capital (excluding changes in cash, marketabie securities, and short-term debt). Net income from continuing operations Plus depreciation, amortization, deterred income taxes and other nori items. btracting (1) capitalized ed rnteres(2) interest income. Gross interest incurred before su Gross operating rents paid before sublease income. zation of capiialu ed interest interest incurred minus capitalized interest, plus As reported on the balance sheet, including capitalized lease obligations. Funds from operations less preferred and common dnridends. selling, general and Sales minus cost of goods manut ctured (before depreciation and amoltmlion), g, 9e administrative, and research and development costs. Pretax Income from continuing operations plus depredation, smortizat'ron, and other noncash items. Long-term debt plus current maturities, commercial paper, and other short-term borrowings. Exhibit No. VER-3 Schedule 7 Page 11 of 12 June 21,1999 Vol. 6; No, 29 tandard G' Porn's UTILITIES o PERSPECTNES Utility financial Targets Are Revised Standard & POer'S quantitative review on the overa9 credit analysis of the utility sector. Standard & Poors recognizes that the nature of utilities' business strategies is changing significantly and is shifting toward higher -risk endeavor. These undertaldrigsdva obeer risk characteristics that are more rears f an Therefore. industrial company than a ragulated utility' Standard & Poor's also incorporates a greater reliance on several additional ratios in fts credit anahrsfs. These include, but are not limited to. o � obligal, nent capital, funds from operati om earnings before interest and taxes to torsi assets, rot cash flow to capital expendituies, and capital idaes to average WWI capital. Additionally. further analysis of the cash flow coverage of all obligations (including Feferr ed sj7A is peed. Atdhough those measures do not have published targets, broader use of these fmamW ratio& combined with the four principal targets. provides g� depth to the fundamental analysis used in the evaluation process. Consislarrt with Standard & Pools ratings mathodology. the four published financial targets will be used with other quantitative measures, business risk analysis. and comparative analysis of peer groupings to determine credit ratings. The new targets are designed to assist utilities. utility affiliates, and the investmerttcommunity in assessing the relative financial strength of issuers.■ Ronald F4-Barone New York (11212-438.7662 John W. Whitlock New York (1)21 Z438-7678 Scott A. Beicke New York (1) 212.439-7663 Stan,disedanf & Poors has revthe tour principalfinan- ciatargets that it uses to analyze the credit quality of all investor -owned electric. natural gas, and water utili- ties in the U S. (see table on page X Standard & Poors has created a single set of financial targets that can be applied across the different utility segments- These financial measures reflect the convergence that is occurring throughout the utility industry and the changing risk profile of the industry in general. No rating changes will result fromestablisWrill uesenew financial targets since they were developed by integrating pTW U614 financial benchmarks and historical industrial madams The new financial targets. like the precious benchmarks, pertain to risk -adjusted ratios that distinguish between louver -risk and higher -risk activities. The targets have beenbroadened to correspond with Standard & Poo(s 10-pomtbusiness profile assessmems.The businessproflle scores assess the qualitative attnlxfts of a firm. with "1' bemg considered lowest risk and'10' highest risk — Thus -the new targets allow for comparability on a single scale between typically lower -risk activities, such as water operations. gas distribution, and electric transmission, and higher -risk activities, such as merchant prnn+er generation, oil and gas e)ploration and production, and energy trading and marketing For example, a water utility, whi n 8�i� can expect to have a lower business risk Prof integrated electric utility. will be required h meet teas stringent financial targets for any given rating categOW. Funds from operations to total debt. funds from operations interest coverage. pretax interest coverage, and total debt to total capital are the four credit.protection ratios that are an integral part 01 fcdHinnedonP.VeX AEPXSW Merger May Close by Year End ................ Page 2 I 0 Exhibit No.. VER-3 Page 12 of 12 ����� � 1 � 11 r ifnnflNlPft ilnRl.nAd� W.-. Revised Utility Group Financial Targets* FFO to total debt ...:........._......... ,A. ............._. _..... BHH'::;:::':; .BB. Business position 20D,::°::.:•t6.5_ ::, 155 12S '::.12b:=`J9:' dA 2 :25A;;':::::'21.0 21A 16.0 a: 16A:,+::':;:.1DS:: 20.0 ;14D 14A 9.5 '9S 3 <r':315:;; :: 26A 305 i' 30.5 .'2AA ?; 24.5 „ 245.,. 175::; 175 12D 4 5 40A.::',;;33D:; 33A 270 :'i:::;27.0:F:'20.5 31.0 : 31D;:'.:':22A;': 205 22A 150 ..:15A:::.:,75:, 16.D 47A .; ;39A : 56O..c.::>i47A.': 39A 470 365 i.:'.:365.?:`:.?;245: 245 17A 19.5 a;:aBS,.t�:12D�, 7 6 65A:.' 55A 425 `.:a:425,3.;;;::27.5'::' 49.5 495 :,' 32.0 275 32D 22D ZZA 9 645 Min ... 6o5 (:: 60.5: :39A 390 28A 10 FFO interest coverage A. _._ .. ,BH. Business position ;': <OD <02 33 2.5 IS 21 1.3 ';13 3 :_,,::;.4.5:;:::'::35 39 31 3.6 27 ':.6A't:i':i';48.`. 4.5 JOB 4D 31)2.1 ':S:;Zt:;:i_11;:i 22 .22. 5 8 65;';<.`;`tr.`:57::_ 57 45 i:'.i;:4bs;j1'':`.31: 33: 31 33 23 i`::23. Y 59 as :i 3.5 3.5 2'9 8 9 9.5 113 3.. :i 71 43 53 10 ........................... Pro= interest Business position 1 2 3 4 5 6 7 8 9 10 W - 29 23 28,::;>:;:;;tg;; 18 11 ;03'. 3A 0 28 ;::t 3.3 .i33' ':i':22.: 22 1.3 OS::' 4.3 3.5 <':'t35 ```C:;;:2A. 4.0 ;_;: 2D: ; 2A 2A 15 1B 52 6.5 4.0 ::: 4.7 2A 29 2D>=:;11 an &0 5.5 ':ii55;; zr 3A::� 66 3A 37 25 i:;35tA 8.1 111 8-4 .'.:.:6837:> '.:' '&4 :; c.:SD :?: 5A 3.3 ? ' '.33.:?.:. :;1-8 UTILITIES& PERSPECTIVES Util'tties/13miect Financeilnfrastructum General Contacts CurtisMouim Now York(11212.438-2054 JohnBilardello NewYork(11212-436.7664 Cheryl Richer New York III 212.436-20M William Chow Now York(11212438.7981 United States John Wardell% Now Yark (11212438.7684 . US krvastor-Domed Utilities Canada Thomas Connell Toronto (1) 416-202.601a1 Latin America Jane Eddy New York (I 1212.438.7995 Eampo/Middfe EasgAtrice 44 171.826.3516 tondmrl 1 AidanO'M81mr4r Asia/Pacific Paul Coughlin Hong Kong (BUI 2533-3502 RidrStupherd Moibounrel6l)3.9631-2040 Dan Fukumni Tokyo (81)3.359 i 8714 Telecommunicati0 s General Contact Richard Sidermen NewYodr(1)2124387863 ed States; United Siderman Airirderm Now York (1) 212-438-76M Canada Thomas ConNil Tormm (i) 416-202.8001 Latin America Laura Feinland Katz New York (1)212 438 7893 Europe/Middle East/Alrica Juan.lose Garc(a London (gg)171826 3642 Total debt to totalcepitel^. _ - ° A. BgB'::.';;'_ IBB' "' Aaia/Pacc Metrouma161)39631.2076 Boca Warvra-Champs Business position p :'AA.:-'' 55D 605 .'60S.?s.i:'.675 >B7 S Dan Fulailor i Tokyo let) 3.3593 0714 2 ":46.5'.!.... 51.0•, 5111 475 565 53D <16.5.e5, i":;53A.'`:?i<',61Ar`i ;635?., �63.5 to 62.5 67D ?'i%;67A,'. `74.0 3 q i'42A.::`.475;; :375 _ ;:43A i 43D 495 's`: 495':' ?;57A:;i 47A.;. 55A 57D 55.0 6Z5 `.` A 5 6 36A 915' 32S 415 395 47D 469 46A. 6$S ' 5 S 605 595 tiOS 89.0 7 .:...995 '3D5.:i i::^37S ( 375 458 43A !;t;i95b.;:::52S.g 'r;43Aiii:`::.ii::51Bs 51.5 581 9 _ _ 35A 35D 39D :}`3i1.0 (;:;975. '`.930:' 475 40.5 54A 46D ;v'A6A:f i<53A:i 10 :.':=:'..-.. 24A 33A P::`40S?1 'As of ,me199 IM-fvndsiromGWRAIM Visit us at www.standardandpoors.com/ratings for more U.S. utility credit information, or at www.ratingsdirectcom to subscribe to Standard & Pootrs on-line rating service. For fast answers to utility questions, please e-mail as at utility helpdesit®standardandpoom-com Page 3 June 21,1999 Standard & Poor's Utilities & Perspectives Exhibit No. vER-3 Schedule 6 Page 1 of a City of of Verno�omhe The FERC Discounted Cash Flow Model Summary of Conclusion Range of Indicated DCF Return Rates to Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC In Odnion No A45 (Docket No. ER97.2355, et. 10 39 % Constellation Energy Group, Inc. 9.% 11 47 1244 Duke Energy Corp 8.42 1015 PG&E Corp. 10.21 1136 The Southern Company Range of indicated DCF Cost Rate 959% 1244% Range of Indicated DCF Cost Rate Based upon 7 7 02 % 12 44 % FERC Opinion No. 445 Mr Hanlays Conclusion of DCF Cost Rate Applicable to the City of Vernon (due to its 12 44% greater risk) proxy Group of Frye Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than 52.0 Billion 9 36 % Alliant Energy Corp 8.57 % ass 986 Ameren Corp 858 903 Consolidated Edison. Inc 959 10.39 Constellation Energy Group. Inc 10.21 1136 The Southern Company Range of Indicated DCF Cost Rate 959% 1136% Range or Indicated DCF Cost Rate Based upon 10 48 % 11.36 % FERC Opinion No. 445 Mr Harky's Conclusion of DCF Cost Rate Applicable to the City of Vernon (due to its 11 36% greater risk) Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1996 Revenues Less than 52.0 Billion 8 % 8.42 % Central Hudson Gas & Electric Corp 8 77 1 1175 DOE. Inc Public Service Company of New Mexico 903 832 9.61 9.58 The United Illuminating Company Range of indicated DCF Cost Rate 958% _ 1175% Range of Indicated DCF Cost Rate Based upon 1067 % - 11175 % FERC Opinion No. 445 Mr Hanieys Conclusion of DCF Cost Rate Applicable to the City of Vernon (due to its 11 75% greater risk) Range of Indicated DCF Cost Rate Applicable to the City of Vernon (based upon the high end of if 36 % _ 12 44 % the ranges) Midpoint of the Range of High DCF Cost Rates' ...�.--�11.90% Notes: 11) From column 5 on pages 1 and 2 of this Schedule. FERC Opinion No. 445 methodology. but (2) Based upon of the range to reflect the City of at the high end Vemores greater risk as detailed in Mr Hanleys accompanying direct testimony Exhibit No. VER-3 Schedule 8 Page 2 of 8 r'iN ofof V�aitfomie indicated common Equity Cost Rafe Through Use of the FERC Discounted Cash Flow Modal for FERC in Relied Upon by the Proxy Group of Four Electric and Combination Electric & Gas Companies Combination& the Proxy Group of Five Electricr'arno� Opinion No 445 (Docket No ER97-2355, el at). of FourE and Greater than $2.0 Billion, the Proxy P Gas Companies with Total 2002 Revenues Electric & Gas C m antes with Total 2002 Revenues ess than $2.0 Bilti Combination 4 5 - 2 3 Dividend Indicated Dtu CF Re Average Low Growth Adjusted Return component Dividend Growth Rate Role to p Dividend Yield @ (_ 4_ � --'—"'- Yield Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in 9 59 % Opinion No 445 (Docket No. ER97- 5 74 3.85 % 63 % 011 % 7.60 11.47 Group- Constellation Energy p• Inc5 3.73 014 367 470 8A2 Duke Energy Cap. 3.72 3.t13 0.09 628 4.93 1021 PG&E Corp. 4.80 0.13 The Southern Company Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues 1 80 �° 8 57 % Greater Ilion $2.0 Billion 0.06 % 637 6.71 % 2.47 8.88 Alllant Energy Corp. 6.41 6.33 0.08 4 00 4 58 858 Ameren Corp. Consolidated Edison, Inc. 449 0.09 0 11 574 3.85 5.526 9.59 10 21 Constellation Energy Group. Inc. 80 0.13 493 480 The Southern Company proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion 5,30 1 00% 6.30 % 527 % 003 % 500 87103 Central Hudson Gas & Electric Corp. 3 0.09 3.71 9 DOE, Inc. 0.10 409 494 3 99 6 32 2 00 832 Public Service Company of New Mexico 62b 0.06 The United illuminating Company Notes: (1) From Column 1. page 4 of this Schedule. roj ected five year (2) This reflects a growth rate component equal to one-half the average projected growth rate in FPS (from Column 4 x Line No. 1 to reflect tire periodic payment of dividends (Gordon Mode!) as opposed to the continuous payment. Thus. 5.63% x ( 112 x 385%)=0.11%. (3) Column 1 + Column 2 e 5 of this Schedule (4) The lower growth rate from either Column 1 or Column 2 on page (5) Column 3+column 4 Exhibit No. VER-3 Schedule 8 Page 3 of 8 City of Vernon, California indicated Common Equity Cost Rate Through Use of the FERC Discounted Cash Flow Model rot FERC bt . the Proxy Group of Foul Etecitic and Combination Electric Gas s 'allies, Relied ElectricCombination on and Combine on Electric & Opinion No. 445 (Docket No ER97.2355, et. at). the Proxy P Five Gas Companies with Total 2002 Revenues Greater than $2 0 Billion, the Proxy Group of Four Electric and ess than 2.0 Billion Combs ration El tint & Gas Comoanies with Total 2002 Revenues L$ Proxy Group of Four Electric and Combination Elechlc & Gas Companies Relied Upon by FERC in Opinion No 445 (Docket No. ER97 Constellation Energy Group, Inc. Duke Energy Corp. PG&E Corp. The Southem Company proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1996 Revenues Greater than $2.0 Billion Alliant Energy Corp. Ameren Corp. Consolidated Edison, Inc Constellation Energy Group, Inc. The Southern Company proxy Group of Four Electric and combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Central Hudson Gas & Electric Corp. DQE, Inc. Public Service Company of New Mexico The United illuminating Company a A- Dividend Indicated Average High Growth Ad usled i Dividend Rate — OCF Rot um Dividend Dividend Coro Component ) Yield (3) f4) _._____--- Rete (5) Yield (1) 6.16% 013% 6 4.10% 3.13 1039% 12.44 4.14 D.17 4 31 31 40 615 1015 3.88 0.12 5 51 SOS 1136 6.35 0.16 7 29 % 0 07 % 7.36 2.00 % 3.00 9 36 % 9 86 676 010 686 495 4 08 903 4.85 O 10 29 10 1039 6:16 013 5 565 1136 5.35 0.16 5.64 4b 0.08 % 572 2 70 % 8 42 %7 69 1176 3.91 016 406 540 961 450 0.11 7 05 2.53 958 696 0-� Notes: (1) From Column 2 page 4 of (his Schedule a projected free year (2) This reflects a growth rate component e1 equal to one-half the average P growth rate in EPS (from Column 4 x Line No 1 to reflect the periodic Payment of dividends (Gordon Model) as opposed to the conlinunus Payment Thus. 6.16% x ( 112 x 4.10%)=0.13%. (3) Column 1 + Column 2 (4) The higher growth tale from either Column 1 or Column 2 on pogo 5 of This Schedule (5) Column 3 + Column 4. City of Vernon California Derivation of Dividend Yield for Use In the FERC Discounted Cash Ftow Model Exhibit No, VER-3 Schedule 8 Page 4 of 8 2 Average Dividend Yield for the Six Months Ended August 30 1999 Average Low Average High Dividend(i) Dividend(2) Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC In Opinion No. 445 (Docket No ER97-2355 et. ai.) Constellation Energy Group, Inc. 5.73 % 4.1% 4 9Y►P- 3.63 3.8 Duke Energy Co 3.63 .8 PG&E Corp. 5_35 The Southern Company 4.80 Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion 6 % 7 29 % Alliant Energy Corp. 6.33 6 76 Ameren Corp. 449 4.85 Consolidated Edison, Inc 5.63 6.16 Constellation Energy Group, Inc. 5.35 The Southern Company 4.80 Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Central Hudson Gas & Electric Corp. 5 27 % 5.64 % DOE, Inc 3.62 3.91 Public Service Company of New Mexico 3.99 4.50 The United Illuminating Company 6.26 6.96 Notes: (1) eased upon the average low monthly dividend yields for each of the six months ended August 31,1999. (2) Based upon the average high monthly dividend yields for each of the six months ended August 31, 1999 Source of Information: Standard & Poors Compustat Services, Inc PC Plus Research Insight Data Base Exhibit No. VER-3 Schedule 8 Page 5 of 8 City of Vernon California Development of Growth for Use in the FERC Discounted Cash Flow Model 1 2 IIBIEIS Value Line Projected Projected Five -Year BR + SV Growth Rate Growth Rate (1) in EPS Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No ER97-2355 et. ai.) u 3_850 0� (2) Constellation Energy Group, Inc. 4.10 i6 T 60 8.130 (2) Duke Energy Corp 4,70 6.153(2) PG&E Corp. 5.28 5 850 (2) The Southern Company Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion t 2.00 % A Iiant Energy Corp . 2.47 3.00 Ameren Corp 408 4.00 Consolidated Edison, Inc. 410 3.85 Constellation Energy Group, Inc. 585 The Southern Company 528 Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $20 Biilbn 1,00 % 769 Central Hudson Gas & Electric Corp. °16 7 69 5•01) DOE, Inc. 4.94 500 Public Service Company of New Mexico 2 53 2.00 The united Illuminating Company Notes: (1) From Column 11 on page 6 of this Schedule (2) From FERC Opinion No. 445, Docket No. ER97-2355, et al_ re: Southern California Edison Company, pp. 18 and 21 Source of Information: Standard & Poor's Earnings Guide - August 1999 Exhibit No. VER-3 Schedule 8 Page 6 of 8 W ay B w pC We B S a oll E WEEm 6 Eas� 8 N Y y aEc003 �Em w � u�g g az� � 4 o E c at of o0 <�U mN W wi rc $ 4 m E 5 M g p W U K o Er 3 JE S U- E� u" D. �q 41 IUT U E UWH IE3 Ems' E W. s f. VRS ..:viC4 x 088 m C r] � v IF ornoo C4 $'p�p�tea N V O $ogg Cs <o$ ri3� oo�$ gg.C6 n 1lf �ppm m C Q O i p Q ooaoW �oep air wPi m. 8 o m F o Z GiiLc° 04 b~ w up p ac t movcoa7 Y' E c U y n m g g W e—= e Suvt U) c ��bm m' �f 8 a$�rc Exhibit No. VER-3 Schedule 8 Page 7 of 8 Exhibit No. VER-3 Schedule 8 Page 8 of 8 x x a SEE 885i8. o`mr r dt dt �88 Ci err "`r�r � >R m Rio aA3 aa!9 o w3�m mmnl'�1.� O K 7R xryry rV� W oo tVmO� C O � _ Wow B � �.dd 3 S t.- S 'D N ml y�j M M N fifi 7 0 m T - 2 8 < m N aoa� N!I 1 14 m '^ NI N of W N -1 W pp vm N p N pp�m U N fH CJ 01 g e J a UA�� wi0— c�W WurL.c .a c �3g �m.T+ E o w c e a3 u a<83 E E c 0 g 1313 i ` Exhibit No VER-3 Schedule 9 Page 1 of 16 city of Vernon CaI omta Discounted Cash Flow Model SumMaro of Conclusion Ranoe of indicated DCF Retum Rates (1L Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC jr, Opinion No 445 (Dnckat NO ER97-235.5 et _ 977 % 13 09 % Constellation Energy Group. Inc 1209 1222 Duke Energy Corp 884 - 1046 1229 PG&E Corp. 1106 The Southern Company 13 09 % 9 77 % - Range of Indicated DCF Cost Rate Range of Indicated DCF Cost Rate Based upon 11 43 % - 13 09 % FERC Opinion No. 445 (2) Mr Hanley's Conclusion of DCF Cost Rate Applicable to the City of Vernon (due to Its greater 13 09% risk) proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than S2.0 Billion 9 06 % 9 37 % Alliant Energy Corp 963 - 987 917 Ameren Corp Consolidated Edison. Inc 672 977 1309 Constellation Energy Group. Inc. 1106 12.20 The Southern Company 13 09 % Range of Indicated DCF Cost Rale 963 % Range of Indicated DCF Cost Rate Based upon 1136 % - 13 09 % FERC Opinion No 445 (2) Mr (ianleys Conclusion of DCF Coal Rate Applicable to the City of Vernon (due to its greater 13 09% risk) proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than S2.D Billion 621 % 6 46 % Central Hudson Gas & Electric Corp 885 - 1225 DOE. Inc Public Service Company of New Mexico 678 801 946 969 The United Illuminating Comparry 9 69 % 12 25 % Range of Indicated DCF Cost ROIL, Range of Indicated DCF Cost Rate Based upon 1097 % - 12.25 % FERC Opinion No 445 (2) Mr Hanieys Conclusion of DCF Cost Rate Applicable to the city of Vernon (due to its greater 12 25% risk) Range of Indicated DCF Cost Rate Applicable to upon the high end of 1225 % 13 09 % the City of Vernon (based the ranges) Conclusion Applicable to the City of Vernon (2) � 6 12 Notes: (1) From column 5 on pages 2 and 3 of this Schedule (2) Based upon FERC opinion No 445 methodology - but only as to the rang ap proach as explained in Mr Hanleys accompanying direct testimony Exhibit No. VER-3 Schedule 9 Page 2 of 16 M^f Vernon Cafifomia Indicated Common Equity Cost Rate Through Use of the Discounted Cash Flow Model for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC In Opinion No. 445 (Docket No ER97-2355, etal), the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion, the Proxy Group of Four Electric and Combination Electric & as Com an es with Total 998 Revenues Less han 2.0 Billio 4 Dividend Adjusted Indicated DCF Average Low Growth Component Dividend Yield Growth Rate Return Rate (� Dividend Yield (1) (2) _- Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 9 77 % 445 (Docket No ER97-2355 et. al.) 0 011 % 5 92 3 85 % 12. 09 Constellation Energy Group, Inc. 5.81 b 3 93 016 4.09 5.00 00 5.8 8.4 Duke Energy Corp. 375 0.09 3.84 5 21 5.85 1106 PG&E Corp. 5.06 0.15 The Southern Company Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than 9.06 %00 $2.0 Bilion 6 99 % 0 07 % 7.0 6 2 DO % 3. 9.63 Alliant Energy Corp. 6.53 0.10 6.63 672 Ameren Corp Consolidated Edison, Inc. 4.67 0.05 011 472 5.92 385 3 85 9.77 11.06 Constellation Energy Group, Inc. Sal 015 5.21 5.85 The Southern Company 5.06 Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than 621 % $2.0 Billion 5.18 % 0,03 % 521 1.00 % 500 8.85 Central Hudson Gas & Electric Corp. 376 009 3 85 2.50 678 DQE, Inc. Public Service Company of New Mexico 423 0.05 0 4.28 6.01 2.00 8.01 The United Illuminating Company 5.95 Notes: (1) The lower dividend yield from either Column 1 or column 2 on page 4 of this Schedule (2) This reflects a growth rate component equal to one-half the average projected rive -year growth rate in EPS (from Column 4 x Line No. 1 to reflect the periodic payment of dividends (Gordon Model) as opposed to the continuous. payment. Thus, 5.81% x ( 112 x 3.85%) _ 0.11%. (3) Column 1 + Column 2 (4) The lower growth rate from either Column i or Column 2 on page 5 of this Schedule. (5) Column 3 + column 4 • Exhibit No. VER-3 Schedule 9 Page 3 of 16 city of Vernon,Cafifomia Indicated Common Equity cost Rate Through Use of the Discounted Cash Flow Model for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied upon by FERC In Opinion No. 445 (Docket No. ER97-2355, at al), the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2 0 Billion, the Proxy Group of Four Electric and Combination Electric &Gas Companies with Total 1998 Revenues Less than $2.0 611110n Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No 445 (Docket No ER97-2355, at, al.) Constellation Energy Group, Inc Duke Energy Corp PG&E Corp. The Southern Company Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion Alliant Energy Corp. Ameren Corp. Consolidated Edison, Inc. Constellation Energy Group, Inc. The Southern Company Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Central Hudson Gas & Electric Corp. DOE, Inc Public Service Company of New Mexico The United Illuminating Company Average High Dividend Yield (1) 5.88 % 3.93 4.18 5.11 2 Dividend Growth Component (2) 0.21 % 0.16 0.13 018 5 Adjusted indicated OCF Dividend Yield Growth Rate Return ate (3) {4) 609 7.00 % 13 09 % 409 813 1222 431 615 1046 5.29 7.00 1229 7 30 % 0 07 % 7.37 200 % 9.37 %3.00 9.87 6.77 010 6.87 4.OD 9.17 SW 0.10 5-17 6.09 7A0 13.09 5.88 021 5.29 7 00 1229 511 018 5.45 °% 0.03 °� 548 � 1.00 % 6.48 % 1225 4. 0.16 8 00 5.00 9-46 4.35 35 0.11 446 669 300 9.69 659 0.10 Notes: (i) The higher dividend yield from either Column 1 or Column 2 on page 4 of this Schedule (2) This reflects a growth rate component equal to one-half the average projected five-year growth rate in EPS (from Column 4 x Line No. 1 to reflect the periodic payment of dividends (Gordon Model) as opposed to the continuous payment. Thus, 5 88% x ( 112 x 7 00%) 021% (3) Column 1 + Column 2 (4) The higher growth rate from either Column 1 or Column 2 on page 5 of this Schedule. (5) Column 3 + Column 4- Exhibit No. VER-3 Schedule 9 Page 4 of 16 city of Vernon Califomia Derivation of Dividend Yield for Use in the Discounted Cash Flow Model 1 � Dividend Yield Average for the Six Spot Months Ended (09/09199) (1) Au9ust� (2 Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No 445 (Docket No ER97-2355, at, al.) 5.88 % Constellation Energy Group, Inc. 5.61 % 3.83 3.93 Duke Energy Corp 418 3.75 PG&E Corp. 511 506 The Southern Company Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion 7 34 % 6.99 % Alliant Energy Corp- 677 6.53 Ameren Corp 5.07 4.67 Consolidated Edison, Inc 5.81 5.88 Constellation Energy Group, Inc 511 5.06 The Southern Company Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1993 Revenues Less than $2.0 Billion 5 45 % Central Hudson Gas & Electric Corp 5 % 4.09 3.78 DOE, Inc.423 Public Service Company of New Mexico 55 6 59 The United Illuminating Company Notes: (1) The spot dividend yield is the current annualized dividend per share divided by the average of the high and low spot market price on 09/09199. (2) Based upon the average of the high and low monthly dividend yields for each of the six months ended August31, 1999. Source of Information: Standard & Poofs Compustat Services, Inc., PC Pius Research insight Data Base Exhibit No. VER-3 Schedule 9 Page 5 of 16 City of Vernon Cafrfomie Development of Projected Growth for Use In the Discounted Cash Flow__. Model 1 7. Value Line Projected 111305 1996 -'98 Projected 2002 - '04 Five -Year Growth Rate Growth Rate in EPS (1) _ in EPS Proxy Group of four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No ER97-2355 et. al.) Constellation Energy Group, Inc. 7.00 % 3.850 °h (3) 6.130(3) Duke Energy Corp. Boo 5.00 6153 (3) PG&E Corp 7.00 5 850 (3) The Southern Company Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion NMF °b 2 00 % Alliant Energy Corp. NMF 3.00 Ameren Corp. 2.00 4.00 Consolidated Edison. Inc. 7.00 3.85 (3) Constellation Energy Group. Inc- 7 AD 5.85(3) The Southern Company Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1996 Revenues Less than $2.0 Billion 1.00 °6 100 % Central Hudson Gas & Electric Corp. 800 00 5.00 DOE, Inc. 250 5.00 Public Service Company of New Mexico 3 00 2 DD The United Illuminating Company Notes: 0) From pages 6 through 16 of this ExhibN. (2) Average of Columns 1 and 2. (3) From FERC Opinion No 445. Docket No. ER97-2355, etal. re: Southern California Edison Company, ppand 21. Source of information: Value Line investment Survey. (Standard Edition), July 9. Aug and September 10,1999 Standard & Poor's Earnings Guide - August 1999 Exhibit No. VER-3 Schedule 9 Page 6 of 16 l RELEHI PIE Tra19nP13B 30 12.7 (6ledun 146) PIE O a1 D 5�60/0 , P�R34ID . CONSTEII N EGY GR Ni SE-CEG PRICE RATIO 295 34.3 35.3 31. Targat Price Range 2002 2003 2004 High: 22b 233 23.1 228 24A 27.E 25.5 24.0 22A 22.0 250 248 293 24.. � ToELINESS 3 mcitain Low- 19.6 1 A 163 172 19.8 .204 80 SRFEfY 2 Laraed3r1N9i LE6END6 , �..• 122 a Dritlmdsp ski Rde _ - _ - _ - SD 40 TEf1iNICAL 4 Raw Bino airi4W by inured . Re�idre Rin Sua�gm 31a•2 - - - - - - - _ - 92 BEm SO Dm • Y>teal 7iaa s Yp 02 2002-04 PROJECTIONS rimed amcs i+6ratls recrsvun - - - s " • " Ir „ tr I "' • 24 20 Ann9Tota1 Return Price IR 45 (Sls f.11'Ar Nit....... J ,,i P• 18 12 18 Lover 30 insider Decisions p N O J F Y A Y J 0a00000 %TOT•.REiURNBO 6 begy 01 Dptear 00000000 bso 000000000 - nay � 4 Sreol Institutional Doclatons 1atp1 a01t11 101111 Percani 6A j20 shams aA 80.37 r 13yr. _ _ 5yr. -- toes _ b $$4u 105 10T tmmd 20 - N 6n47 67921 62167qB9 25.90 Hie1 ' 1828 1867 1883 18A7 19 1889 12 122 0 122fill 123,90 22390 Revenulow"Par 19H3 19134 198 1 1555 1415 14.94gil '1781 33 827 886 310 3.45 393 4.59 35 5'45 493A70 3.8D Casa Flaw"pe►td 240 EamlissparshA 5.05 315 331 3A0 3.15 3B4 367 231 3.45 2A3 291 1.0 3.08 15Z 1B3 iB5 193 tar 19T 135 i'� 168 DlvdDaddperafi� t72 2 1B5 1B5 1BT 210 23t 97 1.03 1.12 i.19 125 3.6D t71 32i 32T 245 2Z1 Zi5 210 Cap' SPendingpors 21� 95 21 218 292 27 3A6 4 4.40 11.3E 12.18 tat 1382 14.83 15.8E 16.60 17.t0 i7.D0 1763 1794 4.42 17.53 143.7 ,A6A3 147. 147.53 47.35 t47A7 19.44 4925 50A tA7.6 149.25 15R00 t50.50 Common hs0uls g AvgAnnIPIERea 15 t15.82 117 3 tt793 117 ti8. 118A5 12052 DA 10.4 121 1 7 1ZG69 1 132 13 13.5 11B 1 14T 15.3 Oordrgaas 9t 9i YdwLkw Relativa PIE Ralla, ./S 7.7 102 9.1 b7 $3 58 61 i6 1A2 14 .62 T7 62% 59% astimmas Avg Anni Div'd Yield 59% 5'3% 4.6% 3935 ,52 9.6% 92% 7.7% 5.7% 6.0% 6.3% 6.5% 7.3% 2159.3 7.0% 6B% 59% 783. 2458.5 24913 266&7 2783A 29348 31632 600 RBtpm61 5i 3307,E 3358.1 95d5 3375 Revenues(Sm110 455 CAPRALSTRUCTURE asot813W99 Total 0 still. Duo Y' 20041 30 8% 32 Z% 33.4% 34 9% 35B% 3 % 35 0 - 35A% income Taa 1Wa AFUDCXIofletPre6t 3i01S IT Debt SY535 LT interest o5 $2226 0 t1� (LT interest earned: 3 bx) 22 gX 121% 15b% 25A% 27 2% 1B 1% 76.0% 63% 73% 10.4% 6.5% 439% 8.3% 46.3% 52% 3.0% 25% 25-b 45.5% 49.7% 415% 47 0A t 11 Term Debt Rags ISb% 520% Pension Liability None 46.4% 43.4% 45.7% 43.2% 46.8% 43A% 471% 44B% 42.1% 411.3% 43.7X 469% 47.5% 479% common E 46.6% 4T3% 48235 49.5% Totem Cap let(iarUiaOa 7D35 PfdStock5t90.0ma. PidDlv'd$13.6mIA Ied.400A00 she 7125% prefaenoe, cal able 496E3 5ill 5475.3 969 54168 5497.6 55824 565U 66 T 5755 7 5n Return o5980 a Told Cap? 752' BLOBS 71V03;500,000shs.6.97%Pro4p0.101110% 6.70 pmf, caL 111104; 600,DD0 she. 4144A 7 7% 4513 t 6 31S 417T39 45% 6.6% 6.9% 1.2% 7 3% 6 7% 9.I% 6.8% 6.9% 10.1% 1Da% 11.0% fiASi RetumonSfirEqultY D 120% 126% 400,000 ohs , G99%Pmf., Cal tOf1105:a05100par. not subj. lo it1% g2% 8.6% 8.5% 98% 10.1% 102% 102% 104% 8.6% 0% 10.1% 1D3% t151S 11.5'n Return d10coal Eq 5 mand.redemptbn 7.57i 3.5/. Common Stock 149,556,416 sits. as of 7131M 122% 'D 3% •BB% 6B B1% 73% 71% A!1 Oiv'ds m Net prom MARKET CAP: $4.5 bl0fos (Mid Cap) 7 991i 9A% 88% 82%. 00% 79% 81% 64% �% ELECTRIC OPERATIING STATISTICS 19+ 6 1 17 +99B BUSINESS: COnstslla00n Energy Gmup• through its Batanoro Gas sources: tssIA:'nu ear, 40 wT' c 21 3.0 ; 1, 1 , other, 10.E >;ewfitaal§ar costs 72-6% 01,9111 lec revs Has 9,400 employees 6639 1079 1017 2A and Elocalo subsdiery, sells oledraaly 166% of•revenues) and gas Pmne teals: 'nuclear, 40.2%; coati 53.0%: oihar, 6 6% Fuel per• r i 4.52 4.63 4.61 (13%) Iluougbout cenaal Maryland to a PoPuialkm of appr�analoy Dar•jL Tate; d Dpy�a4re�9r�6800 6741 6422 n �g�aon a mmsh mond% of revenues a de derived from fsources.omthe Ik�in H Poindexter• P-- & C O.O 4 Edwaal A Crooke Ina MD perltsd,�aas(8!e) 5955 5980 60A5 kcadtmdfe S+bB 56 7 5j g msidl, 42.7%: com'6 41.1%; ind7, 9.5%: other, 6.7%• 86 gas rev Addr P.O. Box 1475, Bata,pra, MD 2t203. Te1:4107811 35929. xttany tarocm� ad) land regulators are now weigh- Poweterp r, subsidiary o of merchant cludes t plants. FtadC6:�Ca. 229 264 254 Maryland g the merits of Constellation Energy Power, n other operator ANNUAL RATES Pant Past Esi'd"it"ll Group's industry restructuring settlle Powe, Source, abma marketer ofoelectricity. otdonge(pYd,) tOYa SYn• toro2 Ot ment The agreement is backed by the Through various investments in North and "Cash sit 3 5% 8.0% 2 5% Constellation Power has "Cash Flav/" 2A% 8.0% 3.5% stale Public Service Commission tP South prtrerica, Earnings 1.5% 3.5% 70% staffdus. the Office of the Peoples Counsel, in- generating base of 3.800 Earnings 1.5% 25% f 0% staff ai and commercial Pycoups, Enron, accumulated a g Consstellation Power BookVaiue 3.0% 2.5% 3.5% and several other parties- ttetaii competf- megawa�Reh >uY�don Power Holdings WARTERLYREYENUES15mDq Full don would begin for all customers on July venturSourcee tin which Goldman, Sarkis is a Cat hose -in plan social, IA L31 Jun.30 Se .30 DK31 Year 1 2000. sooner than a p Vie.), purchased a total of 2.51E ws 1996 8613 7317 826A 734.2 3153.2 (through 2002) regwired by state law; the p 1997 8877 T46A 860.E 0127 33076 Baltimore Gas &Electric (BG&E) subsidt- o generation from Consolidated n 1998 666.1 7675 934.0 79DA 33551 would recover $528 million in stranded and Niagara Mohawk for $975 milli 6,200 1999 9323 1320.0 995 8427 358E �' held b BG&E will come 1999 935 826 993 $45 360D casts tout of a requested 3897 million) the above settlement is approv through a surcharge: the utility would ion and of capacity Y �s con Call- EARNINGSPERSIIAREA Fell celeste plant depredation by $150 "Ilion under the subsidiary's clout i the ondw Maa31 Jun30 So .30 Doc.31 Year from mid-1999 to mid-200D, further cut- trot. g 1996 62 35 93 d 05 155 tin stranded costs: resldential tariffs energy trading arena. nt look for non- 1997 44 .05 111 37 197 g rvwth over the next 3 would fall by fi.59b and be frozen for six regulated activities to contribute a sizable 199E .50 39 108 09 �6 years; commercial and industrial rates portion of earnings g 1g9g 55 AS 1.10 .25 would hold steady for four to six years; to 5 years. ality stock offers appeal- 2000 •67 .45 1.10 .28 240 and BG&E•s generating assets would be This returns to Z002-2004, versus Cal- WNiTER DIMEWSPAID Om Year transferred to a nonregulated urdL We �g industry averages• even though endar Mar.31 Jun.30 So 30 Doc31 view the agreement as positive. The PSC cite tr]r 1 9dlng 5 335 39 A9 AD 1 8 i�elycOnonreits conelated sector, ober CEGstis wearnings P spects for conservativethe company�s rmore 1996 AO 40 41 At i£2 building a large asset -based energy volatile nonregulated operations. 1999 David M. Reimer September !0, 1998 Ai Al 42 .42 166 trading business- The Constellation En B,w 1999 .42 .42 42repany's Financial StrenBla 10 81 Next dN'd meal. Oc1.15. NaA ox da4 Dec T� VOL+L R 1 i 4�5 d o sioak a Price staaliRy 2A (A) Besme esmmga Excl eras i�h in 81, 1 ir,d, de d wm. 11.4%.9%. Ra • CGm: Avg. (il in price Growth Persistence s0 23¢;'97, 25¢ Ind. wr0edowns, net of a gear M 8. iv'd Purl. dates Ore 1c1 d Jan., Apr., Ju aavvgg gg Esmings Pmdictat lRly s in A8: 54161sh (D) Rota base delemti: mrT., edj d for stock sp8t Exd ESOF'ds � Part'� 98, from real esWle snails. and venluras:'87. OcL ■ Dry d reMved plan oval (C) (31;); TOI, (701 Next cgs. repot due mld•Od Alg, •• . , . a 1499. Yatro liw W65sh'ttgg arc. N �n'gglse resrnd. Paaud matNMl a oaarrce horn sowrns bdie±nd 10 bo rd'aaW and a ei�i.d<Pdtdkn � a P� 111E PU6USIp:A 6 tAr RESPOHSrelEi Ofl ArrY FaflORS�ofltlic tl tlNDex feo4fluiiµbetd � 9 mygybe p�ypisW orm, noa•wnane,ori'eaaet asc. o d a nay ee aWassid eras! a tremmtad'a tl0 P^^� Exhibit No. VER-3 Schedule 9 Page 7 of 16 CT5$ 5.G(a) QUA 0.99 nD$.$% A� n1vCco�..._. P - ��• and Targeted TSAEIINM 5 tarercd92" Lw SAFM 1 Nc 12271' 1 �Ec TECHNICAL 41.-medom BETA a9 Om • µsdus) o m o N c J F M A el d 0 0 0 0 0 0 0 0 0 d4.9 43.0 47.9 55 37.9 33 4 35A 3" 30ta1 40irt1 tOt17! Pnrcnnl 8.0 204 271 2I8 esterase BA. a Son 193 212 24B trndad 7A wa 197o3o 185532 195515 1999 1990 1991 1992 1993 199A 1995 1996 145SL 148.51 Duke Energy Corpora8on was formed32 through the merger of Duke Power COPIpa• 1797 18.17 18.65 1934 26.01 2DB9 Z5A9 26.71 ny and PanEnergy Corp. in •June of 1997 555 524 5.61 221F,43 6.01 2.9 325 337 251 343 Duke Power issued 15(ih444 and upon COW 152 1.40 2.60 576 1.84 122 2- 0 2-08 2-16 220 for each PanEnergy 3T7 3.48 321 3 5 plelwn of the merg9r changged its name to 5.33 4.80 370 2B D k Este y Data for 1997 wete restaled 1895 1884 19 0 E04B6 204 87 204 g6 2D4 86 201 359 363.01 125 100 s0 s0 so 40 30 25 20 1s yam= 10 %TOi RE7URN 8M_ _ 76 1 n. +s sole 371 392 5 yr. 843 tOB3 54.68 11.00 RevsnuesparA in 750 "CashPlval'perdl 3,55 3.95 Eamingspersh A 25 9D 27.85 Book iidae per sh r U e rag 10 reDeclthe pooling of interests. Data prior 20 D 5B 20ij 11 a 1A.3 i� 1 133 12JG 1 17t+ 91 -- Vafhsliro RelathaPlERaBa to 1997 are for Duke Power atone and are 13 tBB T3 30 1.1D a 5% 3a% asdaafa AvgAnnlDiv'dn not comparable with Duke Energy data 623 5,.65 5.7% s.t% 4S% 5.0% 4B% 4 % 1761D P0600 223D0 Revenues CAptrAL STRUCTURE as of 3131N9 D D W Due In 5 Yrs 52526.OmN 3639.3 3G815 3817D 39515 A2B19 42793 4t767 4758.0 mere 7145 73D.0 1G309 _9744 12t00 l365 -153Q Ne1Pro6t{SndlD Total Debt 5723 . m . LT Debt 561609 mN. LT inlerast S4620 mil 571.6 538 2 583b SQB, 563JB33.7% (LT ydarest earned 4 Sx) UncapiteOzadAnnual Wish $B5.0 all. 341.6 14.0% 318 20.3% 120% 37A', 4.2' Leases, pension Liability Now P1dStark S7233.0mig.PfdDied $91.0�L525: 595%-8.375%, $25 Par- 39.5% 57.1% 405% 397% 49.8% 51.t% 51-1%79%5 39A' six 3.657.185 she 7,664,989.sbs.AbO'Y7.95X.5100.par, 510ai� 71.1% 79.2% It 8132 B881 Sim 94; 750.000 shs. Au Saner A. - 7917.3 84502 269 . - ------ 92% 9A% 5.v71 - -- -. cat Si00, tnd Trust I'relened Securities (UX- 9b% 8T% 91% 73% 69'b Bb% deducUb�}:5339m9472%Ss m>r7376% hi 131% 11B% 722% 103% 12296 720% 13.1% 13.1% 11b% 13.4% 12b% f40% Returnarcar % 130% t39% 14.0% 12.6Yr 15.2% 115% l4.0'n' Retum0ntol 0 i Retalnad fo Ci IS 79.00 L25 SB9 Z40 1.09 32% 29500 13.8% CommonStock364.224, 14.2 illy% 13.0% 'ON 132 5.0% 6. as of 4130199 59% 42% 59% 72% 4.6% 4 3% 5A% 5.4% 7 3Xr 5S% 64% 59% AU DWS 10 Net Paul MARKET CAP: $21 billion ftarOD Ca 65% 82% 6B% 69% 64% W% 75% G+e% nudea6 51% M an for Z7%; other. 11% Gonera9ng sources, Tig: coax 48%: ELECTRIC OPERATING STATISTICS irdrasad, 5% Fuel, gas 6 patrotaum curb �% +ga984 1987 1988 BUS1NE55: Duke Energy Corporation M a hotting company es,15A,000wmmo"dood� 1 a 3 M.6 which suppT4rs dechicBy fo 2 rni{6on cos- 44%; other, 3%: P p� Rd�ykt 3457 3455 34D5 Duke power co98 mpany, h 0i raver Has 22 000 emPl r' Upls4y[<pplPee✓rrNj t 4 57 4.03 <-� Iomers kr a 20,000-sq. mL area of North & South Carolkra Thm08 fate. 3 B% Chakman. gh Cl and 8 t EO.: Rtfi N G�tstrKdpral. rmn p'rpe6ws, SDP 6197. E)Odrk my 8. Priory. Inc: NC. Address: 422 SoulU ChurGr St Chatb00. 14C its 7730T t 4 03 17134 12% at the natural gas nsed in Our U.S H� reported pr PeBlm4` `J t 6i 7 1 59.3 1 59.D several nonuh7dy subs. ArA'd PonEner9Y �rP 27% Urdustriai Z8202-1904. Tet:70A•594 62DD. Mlernat www.duke ena9y.com t cu ni>� 6V 593 +26 Meandaam. 98: msbenOal 35%: eanrnerola 1999. A warmer-thannormal summer has Duke Energy is expanding its interna- an has made helped Duke Power in the current 4t1 era. FaedoQlrca 36T 3t9 438 tional presence. The comp Y s liquids will ANNUAL RATES; toYn past Eo'd IN)$ three acquisitions in Latin Anterice. one benef`itithe omPanytoo.�Tbe atduleiPasN D% et to dose (it will likely n sh°uld surge in 20�0 n is Revenues 2.0%% 1i 5!L re°'2 of the deals has y `CashFbW' do so soon). but when it has been rorn- Fare onalserving New Earnings 4.0% 4A°A H0% fetedBoo . Duke will have paid $1.2�billion fin afj�eynreas°n Also, as pipeline linovem- Oividonds 4.0 4.0% 20% land will 0 into service this eookvatue 3 5% 2.0% jrn�megawava of gad Argentina I7 ere England SUme of Duke growth El Salvador. generating plants under Cal- MTERI.YREYENOES)Smet) Fair purchases will add a few cents to share bell Beyond 2 00, ender Mac91 Jurr 30 Se .30 pec.31 Year P eras a as Pipe" nda MaT. 1720 t292 Dec. 4758.0 earnings in 1999 and an estimated $0.12 will come from 1996 1162 3113 1292 4iJB45BD 4758 in 20W. Duke should be able to enhance constructionthe s he drawing 9-boaplp line serving demand in Florida- during 1996 4115 4014 5296 4163 7610 the value of the assets through capital the United States. and P 1999 A160 4681 6300 4849 0000 spending and the use of its energy trading ast couple of weeks. after having to Duke stock has re ounded dozing e ars to 2000 5350 5280 6600 5350 2500 itsdstrategy in Aus�lia, here the similarpastP in what ape EAANDIGSPERSHAREA fail n bought some gas assets last year. Duke formed Poorlyoveee�on to a somewhat dis- ndar Mac31 Jun.30 se .30 Dec.31 You, y d a as pipeline there that is been an uarter earnings re rL is ri- 1996 Be 71 125 53 scheduledforgas in lass The nor invest second-q t997 84 •43 89 .b1 Z51 company is looking for more assets in For investors with along -term time 9.led ers a e All t°]d, we estimate that 5-year total return on a risieldd3Is one J99Bgif ,889 76 77 1a0 0 3A3 eLatin ntering Europe. and it is very interested in zon, Duke stock ear ahead,vthehyi�e to 2000 1.60 .85 1.40 Duke's international businesses will con- basis.. For the y dif- cah QUARTERLY DD11DEND5PA0•• Year tribute around $0.20 a share to earnings percentage F r pellet below the average for ender Marl Jun.30 Se .30 Der-3 next year. Although these acquisitions are electric utilities u a much narrower r 11 a li the t995 .49 .49 51 51 200 necessitating heavy external financing. rerence than usual. ns equity to 189 Titnellness 1996 51 51 53 53 2.oB Dukes finances will remain very sound. ranking system pegs 1997 53 53 55 2126par- CFA September ja 1999 1996 55 55 A strong esteem earningsincreasele Paul H..eDebbes, marketad 1999 55 55 Duke top yy 1g�g lit dates t61h d Mama. Jurre, Sept, (El Rats besr�Neari9inal curl Rates "rowed Stock s pdntStabl6�ly strength B9 NNCC 198: i Price Growth Parsbbnes TO ( Berk EPS. Eut nomearmng 9a ( } gym° PS In Pla $237 bUt. earned on avg. corn e9 • g& 158% Regina Eamtn9s Predistabl6ty ?i9, S19Z NeM earnings roped Oec. • prs�d relnves>Rrerd Plan awdabb. on corn- • A duo lets Oct. (B) Nazi dtdd mee8ng about Od C) Ind. deferred ctmrg lit. Cory Climate: Average ; ► t ; t 1 Irca sources bdvsad to be rdbhe and 's Pvndad welad �r•antMs d ony kid. , . 2E Goes era about Nw 9. ApprOr urmle diva Fus(i8)ts a aauMillpdms, adJ, for sock sD oar naorpr use 90 ' r e 1999, VAM rare We:sren4 Inc Al r reread. "'a"a seierr to subs is �� � y,arice a P 71E PUBUSHEa 5 NOT ROE a0Nro5sR OAb T�s�� a Kim Cana usd for grarnoM a morMcrrg and P01 d I nay an rapadaae OU of5R199 -"Exhibit No. VER-3 Schedule 9 Page 8 of 16 eat TfalOn IV RHATH O 31 RATIO 14,4 (�dla� 1lA) PIE 9ATID , QZ � 3 9% PG&E CORP. NYSE-PCG 35..1 34.0 rice Range Hlgh: IDA 220 4 tsedSt 17320 25 38 24.0 34.0 38 29A 31.8 35`0 21A 30.0 243 264 195 RD 2a022003 2004 291 295 80TM NE55 Lon: 14.0 SAFEN 3 Ner7row LEGENDS -- 1.133 O MM&Pto eo 50 TECHNICAi 4 isaaed B9199 i °�, 1 o 40 ... BEfA AS as Oao. tuatl) 0 ns: 4WD hdokstmKslan 1J ,,.•v ., �. r, dnim `-• 24 2002414 PROJECTION Ann'l.row �,. F' ..n, d" , t to 20 Pries Gain Edurn JI,,js +.rs to 12 insider Decisions 10 8 5 0 N D J F M A M beef 0 3 0 1 3 0 0 3 0 ,• %TOT RETURN71M 8 b°• 000 a 0000 a 1OP5dl 100 a a a a a 0 in -, 4 san Institutional Decisions 301ne 40im icim 1.0 t yr TA $5.0 31 643 73.5 _ Percent e" 137 141 1633 shares G.0 betraded 3.0 syr. e0.0 1285 1996 7999 2D00 INC. 0 MS, IM 2D4759 201343 202233 1984 1985 19B6 1987 1988 1989 i990 1991 1992 1993 1994 1995 1996 1997 Revenuesperch 5212 3T.15 55 60 n 30.85 1983 2212 24 71 24 99 2123 18.51 16.58 20.02 123 420 254 225A 23A2 498 2412 2477 SA2 5.A2 242E 59B 2324 6.3t 23AZ 624 35.87 5.98 *Cash Ro 6.06 LID E95 °CashFlow"paf41 POT A 13 250 479 366 3.12 3.98 499 259 U2 2.65 2,60 266 130 190 225 224 22 233 275 196 295 1.96 216 1:7 157 120 1 0 2" I30 olldE2rnlecrdps r sh so 1.28 15B 1.69 191 1.90 1.92 1.53 1.4D 332 fS2 356 1.64 420 1]6 1.88 5A1 A 254 225 3. A �ZO 0.3 Cap ndln9D TL70 gookValusper5he 6A3 6W 6.34 A 3.42 1639 1T.18 18.05 19.D6 18.68 t6.79 17.38 1796 iB.4D 19.41 19.T1 2097 20.i7 43DZ4 414.3 20.73 4D . 21W 417,67 21.08 21.80 3826 766.80 355.80 Common Shs Outst'g 60.� 49 317.91 337 3 38B 31 411.44 42899 42DZ2 41 .57 42G 85 42l 1A9 9 9.4 109 155 Wd La" Avg Ann-1 Vic: Uos �� 1 6.0 55 .9 9.0 B.1 iZ7 103 195 109 121 .77 123 .75 BT 62 .63 .3 .89 vyr Negro PIERS cdm,rm Avg Anal DWd Yhid •3 4.0% 51 51 56 .61 .54 .78 102% 11.7% 99% 0.1% 92% 92% 7.2% .74 6.6% 6.0% 5.6K 55% 15K T.1% 75X 96216 9610.0 49% 15400 39% 19942 2f0B0 20870 Revenues { 28660 CAPRAL STRUCTURE as of 3171ry9 05BB.3 Debt $9389.0 mill Due la 5 yrs $5718.0 m/ 90D.6 9470.1 10501 97781 1026A 10296 1D582 11T0.6 10651 lo"T 1235.3 1321.9 9241 6472 460% MS 746JD 875 870 Net Profit Rell m 433K dam 43.0% Income Tax 945 43.0% Total LT DebtST232.Omt. LT Internal$6B0.Oml. 446% qqg% 45.7% 43.7% AB.6X 428% AD.A% 13% 375% AFUOC%toNelPro6t 7D% (LT interest earned:2.9a) 4.8% PollsionUa6l8tyNone 47.6% 45% 475% 4.1% 481% 7.1% 11.3% A7.6% A9.9% 2.6% 477% 46A% 458% "11% 45.6% ICE 410% Long Tam DebtRallo Radlo 3d5% 57 P1d Stock $780.0 mill. Pfd Div'd $27.0 mill 8181 17487 16973 17395 1626E 13u t59Y%S To1710 13I0 rodLemSfromS25.00to52715;57B4,usamPm 66417 cum nonrodeem.and 526 1666E 1633 17076 1691E 17671 17600 iB621 16761 19684 1399 1B9t8 1W0B 20472 t Plantlilill 165% 11.0% 1T.0% RetumonToinCep 17.0% 5.60%to6.oi par, 5,500,9W;1 6.30% to 657%, cum. S25 Par. 7 7% 8S% 8.1% B 8% 7 7% gin% 9.4% 72% 5.6% 6Ji% 8.4% 9.5% 9.SY, RelupaonSM Equcoin iL0% mardatredem 12.00,OODshe 790%$25par 105%. 122% 1f.e% t27% If^ 13.0% 14,0% 10.D% 6.3% E ll g Return on a 1A 107% 12.7% 122% 13.2% 119% 13.6% 14.6% 107% % 50% Wood to0% � Common Sieck 383,567,880 sm. ns MARKETCAP:$11.9billion(LargeCap) 2916 42% 3.4% 4A% 25% 4.0% 5.016 1.0% 1.3% 63% 57% 54% All ON'dstoHit Prol 53% ELECTRIC OPERATING STATISTICS T6% TO% T5% 69K BO% 72% 67% 91% 8276 1998 1997 1898 BUSINESS: PG&E Corporation k a holding w. for Padfc Gas E 15%; IosSR fuels it%; nuckm IIN other, 57% Fuel crib 1CLu4and8S7ks 43 +63 -1.B Electric Company and nonulB cuts ds Supp1"' efoctdc8y (36% 01 (clad): 34% of revs.: labs costs (system} 15% 118 doprec m1m Ni. hA d Use QdW0 12499 15054 14936a. Has 19,800 emDd°YeM 162 260 ArD hdnlRes (� 6.37 6A9 5.74 revs), gas {B%). other {56%) h 4B �wnmer 40%Eft3%). Indust, common shareholders Chrmn. CEO. d Frei Robert 0 Glynn, gp�dped( 22724 23157 NMF rev, preakdawn: resW, 4e t Q6%rJr. ki Pul tard, l 21437 21862 NMF 13% {1%); other. 6% (%Sg than i%). PehoNum refining industry D4186. TeLe7-8W367-Tf31. Internet www.P9ecarD•e°re• Anmdtadrrda )) �� +53 �Mi the largest elect and gas customer. 9B energy sources: hydm, iChnllCsMosmOrmdj Faea Ca. 292 228 243 PG&E seeks to retain its hydroelec- proved by the regulators. customer rrate pay - ANNUAL RATES Pant Past Eat'd'9243 tnc Plants' The 4.000 megawatts of ca- menu will not rise until the rate freeze is ANNUAL torts. PAM tid'S s pacity have a book value of $1.3 billion. lifted. That will occur by the earlier of Revenues TA% 95% w. The company has proposed transferring April rs it or the date on which PGaE utiH- "cash raw' 3 u% 9 5% 4.0% the system to its U.S. Generating aiiiliate recovers its stranded costs In a separate the cc Earnings 1.5% CIS% 5.0%% rather than putting !t up for sale Though r11 sit allowed returnmmis anocommon from owered e 11-2% 1>ivdends 2S% 4.5% 2 0% the assets have a tax base of only $500 ty' BookVak7e t.5% 2D% 4 million, their market price could be six to 10..G96. retroactive to January 1999. CTMar.31R11MYREYERUEBOni Full times that figure, Thus, a sale would We look for higher earnings this year. enJDn.30 Ss .30 Dec.31 Year entail payment of a substantialcapital The company will benefit from lower lnter- 12135 7.521 27D3 9610.0 gains tax Moreover, the net gain would be eat expense and fewer common shares out- 1997 3365 3063 4083 4869 15400 applied against stranded costs, thereby standing. In addition, the »Gnutillty sub 1996 4353 478T 5307 rv135 1932 lowerin stranded cost recovery of other sidiaries will likely turn in a better per- 1999 5257 4820 UN 5603 21080 g 2000 4460 4860 3440 5640 2g490 assets.. But a broad coalition has opposed formance than they did in 1998. Its, EAAM069 5440 .5 Fu►i the company's plan to keep these assets, despite the refueling of both Diablo Can- cai- on the grounds that it would reduce com- you nuclear r)awtses°dmate aewas shut 14°% rise in ondar Mac31 Jun 30 So .3D Doc 31 Year petition !n the California electric market down last year). 1896 61 .44 55 56 216 and pose serious environmental harm- 1999 earnings to 52n a share. An iet- 1991 .42 31 62 22 157 Too, some local lawmakers are considering proved performance in the nonutiHty stx- 1998 36 •46 55 51 ISO us�g the surplus proceeds from the utill- for points to better results next year. For 1999 .42 .49 .9 •57 s rate reduction bonds to purchase part now, the stock is untimely. 2000 .511 .52 .70 .58 330 ty QUARTFALYDjMENDSPAWoi Full of the system.. The state legislature is con- because n of an increase inbe 'ow in COnAng noncore assets C0i Year sidering the various proposals. under Mar.3 Jun.30 Se 30 Doc.31 The 1999 general rate case may be de- which normally disburse a lesser percent. 1995 .AS .49 .49 A9 196 cided next month. The company has re- age of profits than the electric sects 1996 49 .49 .49 33D quested 5495 million in higher electric Thus, income -oriented tylvescol s will pmb- 1997 30 30 30 rates and a $377 million boost in posted ably fare incites elsewhere- 30 t 20, 1991 1998 30 30 30 30 120 gas tariffs. Regardless of the amount ap- Arthur H. Medalle 1999 .30 .30 .30 Rate base: net Compan 's Financial Sireagth B+s p) EPS basic Fact rronremR geina (bsaes . (t3) Neal dN'd meeTg about Oil. 20. Next ea 57.701sh. (D) In mlions (. >� �44t) in TS3; (51.05) 65 in'87; (S1.A0) in'8B; (75 1 dale about Sopl 10. DiV'd payment d211 ates orig. ws1• Ra10 °Ibwed on com. aq• m '99: 5toc G rice Persists B Earnings Predictability in 55t) 7n 94; 4y' M'95; 86, net (416); 97. about 151h o1 Jan . Apr, July, Oil ° Div d 10.6%. Farr ad an avg. com eq. In 8B: 8 5% EarnsPrice Growth ictabili y on 1 Next cgs. report due late Oil reinvest pion ava0 (Cj irrcl krtarrg. In 138: Rogulalary Cgrn.: Above Avg e 7999. Wue L9re tea N rarrred. le., matedm tS Nxtinrd Iron sources adeacd b � un 11Q pUe11511FR Is NOT RESPONSIOIER ANY ERRORS OR OMISLONS NEREN. ilm puNaadrn fA �r a Noamiic pdxaafinn 1crw+r° a Rem - d i may be try odraN suet a sammbed it a7 pled tlsmerdc a a7 a bm a esed (or geerNrq Exhibit No. VER-3 Schedule 9 Page 9 of 16 SOUTHERNCO. RECENT Pk iral6ng:159 RELATPIE PRICE 27 RATIO 14.2(�edim::, 4) PIPA11D jl 94 Dl1PD js.o�/ , 1f Y� M 0 NYSE -so 14 i10 i%3 9A 21.1 19.9 239 27-8 2002t2003Price fi2004 TIMELINESS '.(air Rtsvd7Jl0199 Lrovr. 1es 0.2 i1S t29 162 18.5 SAFETY a Riaed1816N4 LEGENDS •, `so 40 TECHNICAL 4 loaned sis" ---- 1.11 a Omdenas p oh d: din py nitres Ran - - _ . - _ - 32 t BETA AS VM Alum) Rentivc Pike Saagrr 1pfpa•1 sp0 3O1 Snade'dacanerares, slim All 1 " t r•+- «• • 24 � 1e ,••• ' r;rrn 2002414 ROJECWNS Ann lTolal q P' r r .r. „ ro Price Gain Ro4tu9m '+10% 149G 7% 12 18 Lm9s 30 Insider Decisions B O N p J F N A M J Is Buy 001001100 4 Opb", 0 0 0 0 0 0 0 0 0 %TfTE RETURN 8199 3 1ss, 100000010 na nos- Institutional Decisions 11111151 411111118 term 6.0 STOCK umex 1 yr. 11 23.3 m 210 201 220 Percent shares 4-011 traded 2J1 Syr 435 60.3 fill 5, 91.2 109.5 111 2569160 54 253985 252187 1983 19ti4 1985 1986 19871988 1989 1999 1991 1992 1993 1994 1995 1996 1997 1998 1999 200D nVALUEIINEPUB MC. 02OA 1180 1225 1267 1202 Ili? 11.46 1117 1213 1175 1276 1321 12.63 1310 1530 18.41 16.31 1&45 11.15 Revenues persh 2t15 3.90 425 4.00 4.35 'CashFIow"psrsh SIO 2A1 257 267 27D 255 267 136 150 1AD 159 136 136 285 2A 2.77 3M 313 3.22 352 3M 134 130 124 151 157 162 156 183 158 173 185 200 EamingsperahA 250 L34 DWOcl'dPIshBe t34 87 92 98 1J14 1.07 1.07 3 2T7 1.07 1.UT 19T 1.10 1.14 1.18 1.22 126 213 1. 178 175 224 234 t92 1.30 I.34 1.34 271 2JI7 3.3 325 CapdDSpend gpue A4D 772 2 411 4.1 8.10 928 9.92 1055 1D.44 10.59 1087 10.74 11.05 11A3 1196 12.46 13.09 13.61 (77.00 14.08 14.02 13,60 13.75 BookValuapI 1&70 685.00 69B.667200 647.00 CommonShsOutsl'gC 64.00 459.10 D 3.77 5593 590.83 631.30 G91 1 G3.1 31.31 792 642.65 657.00 670. 11S 11.5 135 129 13.2 1 Avg MnT PIE Ratio 14.0 144 15.1 6arrd 5.9 5.A 7.6 8 9 82 50 5.4 .52 .52 .W .0 9.6 9 .,a 74 T3 .70 W 65 'N ff8 qua JI1 .82 Relative PIE RaBo .0 A.9% esdm sea Avg Mn7 DiV d Yleid 3 8% 10.8%[11.3%9.6X 8.6% 89% 9.6% CAPITAL STRUCTURE as of W30SO 6.3% 83% 7.5% 62% 5.4% 6.0% 5.6% 5.5% 74920 7975.0 BO50.0 8073.0 B489.0 g297,0 918D.0 ip358 5.9% 12611 11403 11650 11500 Revenues (5� i310D Total Debt $15,410 mill. Due In 5 Yrs $7,100 mle. IT Debt $10.264 mit. LT Interest $710.0 m8L 969A 937.0 886.0 1057.0 1095.0 1076.0 1191.0 1234.0 381% 36.5% 352% 3B9% 39.2% 378% 1245.0 1372.0 1470 1520 Not Pre6l IMPIL 1825 369% 24 i% 350% J5.08 Income Tax Rate X0% (LT Interest earned: 3.6x) 33.8% 341% iBJI% 16.0% 7A% 21% 20% 2.7% 2.1% 1,9% 16.0% 1.1% U% 1.5% 1.5% AFUDC y, to Nat Pre81 1.5% 4&5% Phl Stock SZ784 mill. PfdDWd$203,tm6, Ind. 1�5D,000 shs 42%-7 0%, cum. pid., S100 5D9% 49.0y.457% 45.1% 44.1% 449% 428% 46.4% 459% 455Z: 4QOtt Long•TermDeblRaOo 4U% 41.5% 41.0% Common Equity Ruda 4 par, 8 mil she. 5.2%•6.B%, am 111 $25 par S235 MD 6.85%-7.00%, mend. redeem pfd4 $297 40.0% 409% 428% 45.7% 46.1% 47.6% 47A% 49.7% 16B36 16599 16301 15M 16429 17211 18510 16553 4U% 22158 221111 21855 21655 saw Ca hat (imel) 713 mkL7.13%-T38%,mend.redeem pfd.;$415mill. 7.60%-7.63%. mand. redeem pld ; $649 m6. 16998 16BIl 16609 16489 20013 21111 23D26 23269 rJ% 79% Bxh 23652 24124 I5533 I6B85 Nat Plan! Sm0 3f0110 71% T.6% 1l5% 8.5% Return R1 told Ca i &5% 7 75%. rnand. redeem pid; tr 8.1% 8A% 7.8% 8.5% 79X 117% 115% 107% 123% 121% 11.2% 117% 11.6% 10.5% 1t 1% 125% 13.0% Retain on Shr. Equity 1315% 9.00% all $2 rig val. Common Stock 683,159,074 she. as of 7131I09 12.3% 121% 112% 132% 13.0% 121% 126% 122% 112% 122% 14.0% 15A% Return on Corn Equity a 15.0% LOiG 5,0% Retained is Com Eq 7.0% MARKET CAP: S1BA WIN (Largo Cap) 25% 22% 1S% 3.6% 3.6K 2.7% 3.3% 3.016 64% BB% 76% 75% 79% 75% 77% 20% 27% 84X Bi% 75% 70% All Div'ds to Not Prof 59% ELECTRIC OPERATING STATISTICS 19.3 +1.1 +62 +3 3 +t.t +62 82% 1 BUSINESS: The Southern Comporry's five operating subsidiaries noes. Fuel sources: wal T3%; nuclear, 15%; hydro, 4%; 08 and 6% FueI & Pw. Pon. costs: 32% of'BB revs %Chyya�Reai5lks Arp.hdtdUse� 3106 3387 3688 4JN 3.95 4,10 electricity to about 122,DDO square miles of Georgia (52% of cePPN mV 1898 revs.); Nabama (35%); Florida (7%); and Mississippi (6%). gas, 3%; par PI Has about 37,B50 employees. 187,055 shareholders. T18 dapreda- A1p.hdtd8r2pa (() Capa71j1tPeal 31078 31146 31161 28934 Revenue dlsbin. (98); residenUak 38%; Industrial, 28%; mmma- Lion rate: 4.7% Estimated plaid age: 11 years. Chairmen &CEO: W. Dahlberg, Mc: Del, Addr: 64 Perimeter Center East, Atlanta, Perilm4,&rss 27190 27334 623 59A+21 60.0 eial 33%; other, i% TexWe, chemical and paper companies am largest customer groups, aoCoulrling for the bulk of industrial revs- A. GA 30346. Te1:401.393-0650. InlemaL• vrww.so erneo.com. %clalmdflda %GanpeCWaeen�ppd) +2A +21 +2.0 290 226 196 Though not now timely, top-quality New York, Pacific Gas & Electric, Com- Eastern Utilities Flud to ) Est'd 96'98 Southern stock offers utility investors monweaith Energy, and Associates. Too, last month. SEI and its ANNUAL RATES Pass Past otdongo(parIII toVra 6YtL ta's2-'D4 appealing potential returns to 2002- 2004. The company's traditional electricity partner NRG Energy were successful ire Revenues 3.5% 55% 4 "Cash Ale 4.0% 55% 4.59E 70% business serves four states in the South- their S2.026- billion bid to buy the bankrupt Cajun Electric Power Coopera- Earnings t.5% 3.0% Divkfends 21 35% 3% 3.Dro east and earns a better -than -average re- turn on equity Retail deregulation Istive's g prog- p 700 Mws fossil- fueled Iants (1, Book Value 3.0% 4.0% ressing slowly in the region, since tariffs Moreover, Southern is adding new gas Col. OUfUTTERLYREVENUES(mlpyF Full are quite low. Still, Southern is building a plants (2,264 Mws) to its generating base Order MAIM Jun.30 Sap,30 Doc.31 Year considerable nonregulated presence in the The company is sharpening its int4x 1996 2416 Z538 29i7 2487 1035E 2416 2538 2911 2457 10358 U-S and overseas. Share net will likely national focus. SEI has significant In- in Europe, Latin America. Asia, 1996 1998 2495 2913 3457 2536 11403 match management's targets of $1.85 this vestments the Far East_ We expect the subsidi- 1999 2442 2791 3356 2462 11050 11SOU year and $2..00 in 2000. Thereafter, earn- ings may well rise 6K%-896 a year, sup- and ary to participate In the ongoing industry 2000 2550 2909 3500 2550 EARNIN6SPERSRiUiEA pre r ported by common stock buybacks. The share does not adequately reflect consolidation in Europe. in Asia, the CEPA unit Is expanding, most notably In na Mar31 Jon.30 So M Dac.31 Year price Southerns good 3- to 5-year prospects. China. And a big power pro ect in the to begin 1998 35 .43 69 21 1.68 1996 28 31 71 28 168 35 39 74 25 158 An expanding generation base will support Southern's status as a leading Philippines (Saul) is on tra� service by year end. Management IS Will- investment in CEMIG a 1997 1999 32 .45 .60 .20 1.85 domestic power marketer. Manage- believesthat a asset will nlistic about its ft- itThereanarein- cat. UA Y11 .83 .32 200 Cde DUAR7ERLTDIVBSOP30AiDae Full tmdlnbase ensure In energy The Narthast Midwest. South, and West nesss inthean local economy. deed risks, though, as indicated byy pro- ondar Mar31 Jun.36 Se 39 Dec.31 Year 33055 Coast have all become potential profit cen- osed distribution rate cuts In Britain SVII and SETS plans 1995 35 3 5 3 5 122 325 326 130 ters. Recently, the Southern Energy Inc (SEI) subsidiary acquired generating as Southern owns to sell underperforming utility assets in 1997 325 325 1998 336 335 335 335 134 sets (6,100 megawatts) from Orange & Rockland Utilities, Consolidated Edison of Argentina and Chile. David M. Reimer September 10, 1999 1999 .335 .335 .335 (A) Exd names hems:'93, d1E';'61, 50; '87, 2B. OWd pint dates: the 51h of Mar., June. value; FL, GA. orig. coal. Aid mhun on Corn. Company's Financial Strongth fA d40d;'90, d35 r 51, 160;'97, d150;'98, d330, Sep., so Dec ■ Dtv d reinvest plan oval eq: 10.0%•74 5%.Earn on avg. core 9..'98: Stock's Price 51ah0ify Growth Persistence 49 Ind. severance chg : S4.90. Next cgs. rpt. Iola (CI Ind. derd fts In'98, S3.421sh. (D) In 10.04%. Reg. Clbn.: AL, GA, MS -Avg.; FL- Price 1B. Goss Oct adi for split. (E) Role base: At, MS. fair Above Avg (F) Excl marketing revs. bag '08. Earnings Predlelab191y 90 Del. (8) Next dN'd meety,�Od. eu mills. e 1999. Vjkm the ti�i'a c" hie Al shies resrnm. FoOuol nmKmtl Is obIaI ham swees bdia+sd to be rrLalsr am h Parlors without vrarMI of airy find. r r r • : 1 1 ! I . ., o onu.. nR auv FRRaRs OR OMISSIONS NEREW.ihsa@rcW- isceidlyrurabviam's arn.nm�'nrac!eal HerWasc. No pad of it way be rgxadua4 stored Of IMMI IN airy pdimd, ekdrordc 0 ar" ram or us" ra goon"It o rmxcug my e,ac, v Exhibit No.. VER-3 Schedule 9 Page 10 of 16 At�.1ANT ENERGYNYSE-LNT � CE 28 �� 127 (pia 13o) ` 0¢73 7.�°l0 TargetPriceRange High: 239 245 253 32b 38A 31.3 26A 2.3 329 34A 349 26A 2002 2003 2094 T0IEUNESS � F 1.3 2 . 20.0 226 29.6 31 3 26.4 27 3 27 5 2G.8 28.0 2GA 1001 SAFEii 2 Nea7nd9T LEGENDS 80 1.11 i I,Y,W�eMS a Sa tt4 TECW(:AL - f .. netn0ed¢o '�"wtuayar 48 errA ed nm.ramld) opp'ons Y¢s - 40 D4 PROJECTIO Snarled aaa adraus rare on - - _ 32 2062 ZR1TOW "' a. ll 71n v1"� 24 ........ Price Gain Return " "20 Hlph 35 (+25Ye !1X to Low 25 10% 51G insider Decisions 12 A 50 NOJFMA •• e leper 3 0 1 5 010 7 2 1 7i 000000 TOT. RETURN 5198 6 Opase o e a 0 0 0 0 0 0 MIS YL maw ooto InstltutiOneI Decisions t yr 73 5.5 1010 401"1 tonll Pest 6A 3yr. 225 5T.3 l0b&&bdrryry01 73 T2 ST 03 sherds 4.0 Syr. 63.4 124.1 lot, 1t1 18662 16797 10389 tended 21 3195 Allis 1 Corporation, forfnedy called inlet- 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 CVALUEIDIE C. 02 � State Apn7 21r,19981hF�ottgholhe me er of PL L425 4.62 2471 45 25.32 2493 5.J33 3511 2so 4.65 6.00 2235 "lCesbflow'r h sh Noldmgs, 98 Industries, and inlerstale 193 223 243 211 211 224 233 7 190 126 220 235 Earnings Da rd pus 265 Power. WPL stockholders received One 1.68 1.74 1.60 Jill 19D 1.92 194 197 2j; ! 00 208 2DQ Div Dad d push a• 4.15 IN share of Interstate Energy slDdt iw each 3.63 2 D 3.40 452 491 491 3. 4i11 A.1 A79 J50 4.i5 Cap'ISpesdnppar 86 PL share,tate IES stockholders received 1.14 2- z6 66 26.e z7at 10.44 Son 3Q.77 3o.7r 30.13 77 63 MAD T&4o common sn f3ulstg LAB share, and integrsstate Power stockholders 120 10 112 159 16.4 1 .8 121i 13.3 155.06 133 aey� s� Re9Annl PIE aWeP1ERa90 1.75 received 1.11 Interstate Energy shares for 91 .78 .72 .� 97 •84 .84 J3 es11 Avg 7.6% each Interstate Power share. Data prior to 7.3% 7.7% 6.6% 6.6% 5.5% 6.7% 6.6% 65% 7.0% 6.3% tsfp 1998 are for WPL Holdings only and are not 6D1•g 616.5 6481 6517 773.1 815.2 8073 932J 919.3 2130.9 ZIN 2270 Revenues ($MR 50 comparable with Interstate Energy data 55.3 63.4 68.8 6D.8 66.5 73.5 749 G49 64.6 1014 18Q .0 Inc Profit Rat 363% CAPITAL STRUCTURE as of 3ri1199 327% 31.0% 31 G% 271% 27A% 325% 325% 382% 0.8% 3GA16 36 D% 36.0% AFUDC %1 Bale TotaTIAL 17626mUl.Duoln5Yrs5469.6mµ. 3.3% 21% 13% 22% i5% 1.4% 9% 13% 43% 6.6% 3.0•l. 3A% AFUDC%fo#1tPro0t �Oif IT Debt $1545.3 mill. LT IMerost 5716.3 mfB 39.9% A20Ye 415% 43.6% 395% 405% 39.6X 352% 40.7% 47 3% 4T.5' 4ZSo .Long Tartu D.... odO (557G {LT interest named: 25x) 52T% 51.0% 51.7% 502% 54.6% 5d.1% 54.9% 59.0% 59A% 49.2% 49.0% 49.5% Common E ui Ra110 515X Pension Liability 5221 mUL in'98 vs. no In 9T BM i 857 T 6652 95BB 1060.0 11059 tOD79 1029.9 1125.1 32629 3310 3370 Toffi1 capital {im81 2975 111) Pill Stock 5113.5 mill. Pfd Div'd S6.7 n 449.765 shs. $100 par, 599,460 slur 525 par, e620 1041.5 1011.8 11329 122D.7 12663 12999. 12949 1244.8 31D1.T 30T5 JOBQ NeiMant(Sm 1.121.787 shs SO par 8.6X 9A% 9.5% 6.1% 6.0% 6.3% 8.3% 6.0% 7A% 4 9% 7.0% L5% Retum oa Totd Cap1 i1J1% 166%iA% 127% 133% 112% 183% 112% 11.4% 105% 9.1% 69% 10.0% 10.5% RoblmonShrEquih' Common Stock 78,116,596she asat4130f99 t12.1% 13.6% 142% It$% 10.1% 11.7%12.0%109% 10jj .1% NMF6.0% 11.0% 11.5%RotamonCom Eq n t MARKET CAP: S22 billion (µid Cop % 3.D% 3. % 51% 3.6% 35% 100% NMF 91% 86% All D ads to HslProf % 79% 75% 6D% 67% 7216 rsY,at Rudear, 12%; d1wr. £LECTRIC OPERATING STATISTICS named lr4arslate Ene k a 13%; other. 3Y. Fuel sources, 98: coal 56% late' 35% 1995 1997 993 BUSINESS: RYiant Energy, tortnerly on %gal9Raz75r4s *23 +3.7 holding campany formed through Ole merger of WPL Holdings, lES E .d plaid & t0uyrs Has 6,352 empls. 76,0433 ono Sikh" A1T.bantUte� 4861 3.57 3J5 industries, and interstate Power Supplies sled l66 . ofnnes.o, gas 9 ' An.. MA 3.61 3 57 3.75 17% and other services (17%) in Wisconsin, lawn. Minnesota 6 Clow: Lee Liu. Pies 8 C E.O.: Fang 6. Davis Jr Inc: 1M Ad dadp or 2300 2337 522e ( 1• by state: lest Washington Avg �adddLlmeFFelsa ) 65 70.36 699. MY. braekkawm mW., 3%;5wmm1, 2 % indl, 0% wholesale them Internet www.aUwtd•en iscom•1 xfaanpaC161eaesti•ad) +z3 +21 •rt2 Iant's steam generators- The Wiswn- On May 20, 1999. A)li� Energy re P regulators determined that the genera - Ford Ca. 285 252 199 placed Interstate Ener as the co S sin A PATS Past Past Est'd'96•198 payy 5 name.Since change, a a action svo]V strengthen tors dthe ereliablility of the at 's ahl10Yrs 5Yrs. IOroi•94arne Revenues 3.0% 3.5% NMF have to surrender their stock certificates.. electrical system. n exchange for proceed Cash Flow% 20% 2 5X NMF in with the work, the owners asked for Earnings -1.5% .1.0% NMF The ticker symbol remains LNT. g Dividends 25% 11% NMF The company has sold a portion of its and received authorization to implement a Book Value 3.096 2.0% NMF investment in McLeodUSA, an rode- temporary surcharge on ratepayers and to re Cab DUARTERLYREVENUES(tmDJ Fog pendent and 1999 N f catrrrhasti ed 0..3 mil- tars. This wirovider. In accelerate ll allow ciatiLNT to recover on on the newits $37 endar mar.31 Jun.30 Se 30 Dec31 Yons ear McLeod 1996 26D.9 208.3 7122 2514 932 lion shares of May, sold 64 on f shares million htoand a half yeathise project's cost over 1997 2617 206.7 214.4 236.5 919 g 1998 555.3 4910 555.3 5283 2130. for an aftertax profit of $20 million. Its Al- Merger savings will help lift earnings JOBS 54&9 Sip Soo 5511 2190 liant Ener Foundation (a charitable or- in 1999. Too, last year's merger costs. 2000 565 530 600 575 2270 ganizEneration Sold 300,000 shares. LNTS which penalized earnings by $D..46 a share, Col. FARNINGSPERSHAREA Fun current holding of 9,360.000 shares is will be absent tills year, The company will ender Mar.31 Jun.30 Se 30 Dee31 Year worth about ng million. In conformity also benefit from a 514,5 millionfrom electric sconsin and 1090 1.03 A3 AS 36 227 with Generally lpc�yte�oAluso Accounting proving non ore pPrin- rate increase in ierations., n all, weieS- 1997 54 26 72 36 1.90 1998 d 12 tell 33 126 value of its investment on the balance timate a 7596 rise in current -year earnings lggg 54 40 .80 _46 2.20 sheet But no profit is mcorded on the in- to S2-20 a share. Further merger saving 2000 6D 43 .85 d7 235 come statement until the shares are sold.. point to expectbettnodividend rresults In �increase for Cal- OUART£RLYDMDENDSPAIDe• Full Under a contract with McLeod, LNT can the Qex y g p y- endar Mer.31 Jun.30 Se .30 Dec.31 Year sell up to 1596 of its holdings in an one the next few ears, due to the high a 1996 ADS ASS .485 485 194 year. it does not plan to sell additional stlll mnsiderotheseisharesented ibecause of Might 1996 A92 492 .A92 A92 127 shares this year.. year -ahead yield Y 1997 50 50 50 50 Zoo ATIiant and its partners have agreed above-aversg a ye Jul 9, 1999 1998 50 50 50 50 200 to replace the Kewaunee nuclear Arthur H. 11-fedalie e*IF Nth (A) Basis EPS Fed nonlecla gain ppower): pmld dalas: Feb 14, May 75. Aug, 15. Nw. tA. COII1 eq in '95: WI, 11.7%; eamod on avg. Company'I.s Flnto Siren NMF 84, (111); 85. {93�) T1S. (A and 11d. Nail • fit, reinvest plan avall. (C) Ind. deferred cam. eq. 9B: 6.0% Unranked due b shoo price Grorwth Persistence NMF egs rpL due late July. (a) Next div d ml%g chgs. In'9R: 5444.9 mUL, S5 tt3lsh to) In mill Avg.; d, Below Avg (Fa Earnings Prodictabfldy about July 21. Goes ax about July 29. DW (E) Role base: 04. cast Rate ell owed on trading A pvrioed wlroul walouses d rend 1 . • ; 1 1 t 1 11 . e 18a9, Va4e Ibe Pu66shfiq. Inc N n-gMr res¢w1s1. Fodud materid is aNeined been solaces bfi¢!i¢d to b¢ idiab and is semce padat 111E Pt18UsNER 5 NO7 OESPONSBILE FOR ANY ERRORS OR OMISSIONS MIISor SIOeN�e�RE mad 's �e� a eely ro+9 enY prYdm deomc inu" � c o oP.I. d e m y be Nproduoea slomf a eanvriaed in any pmx¢d 11MF111i 3 Rebea 100M " SAI IY 1 Rallad?AW tEc TECHNICAL 4 Loleradumn BOA S0 00-Mold) oy� tii!n A 6 0 N 0 J F Y A b.4 000 000000 Dplisl 0 0 a 010000 fosse 00701a a 0 0 7QIp1 IOIas _ - Penitent 15.0 106 131 138 shares 10.0 7B 91keIs_tl bo traded 5A Ameren was formed on December .51, 1997 through the merger of Union Electric and CIPSCO. Each common share of Union Electric was exchanged far 1.00 share of Ameren, while each common share of CIPSCO was exchanged for 1.03 Ameren shares Premerger data are for Union Elec- tric only and are not Comparable to Ameren data CAPITAL STRUCTURE as of =151 Total Debt 525328 mM Duo In 5 Yrs 6554.7 MIL IT Debt $2265.7 mi LT Interest $173.0 mM (full debt discount ) LT interest owned: 4 ass)) Pension Liability $19.0 MR 1n'98 vs now in 97 Pfd Stock S235.2 mM. Pfd olv'd S12 6 mM. 1,137,595 all $3.50 to $7.64 cum. (no par), stated at Ilqufd. value; 1.657.500 she. 51735. 525 000 hs 4 00%to 5 525% Who 38 AETio 12.9 Medlar 31-8 311 44.6 395 42.0 265 31.6 35.11 30.e 1 34.6 0Exhibit No.. VER-3 Schedule 9 Page 11 of 16 0.74 °" 6.7% 443 429 35.e 35.8 100 80 64 48 40 32 24 20 16 u i a _ 6 %JIMRETURN 5199AM nsaaa smcs 1 yr 11.5 5A '-'- ayr 26A 673 -_ 5 vr. 692 124.1 _ 1989 199U 1991 181114 -syya s721 20.13 iw•+ 20.59 --- 2213 --• 2424 -- 2418 IS.30 25.05 10DIlUBSParak 1815 19.69 5,09 19,51 4955.24 2053 5.24 1973 4 98 2023 4 B3 5.13 5.14 5.12 496 5.36 SIS 830 "Cash Flow" perch 3.10 Earnings pashA ?AS 345 291 274 Hi 2,65 ZT7 3AI 295 2.46 2B6 2.51 2.44 254 Z82 2�1 215 254 2S4 Dhed Ded d per A Z62 202 2t0 20B 19.79 10212 99 718 20.62 10 10.6 226 2 21.19 102,12 13.4 2.34 2B7 21.60 1OZ12 14.6 240 3D8 2222 10212 N.6 76 22.71 022 12.6 94 31 23.06 1021 1 6 A6 277 2 T 22.00 2U7 13722 17 15S 1. 99 75 3b5 4.l0 Cap Spond gpbrsh 2R70 23.I5 a"' 'userlh � 137.20 137�0 AvmMnIPIERe11orB W- �e Re ll PIE Ra80 3 45 37 0 !20 .9 1B9 19.14 f0212 89 .67 79% .74 79% .68 69% B1 6.4X .86 59% 69% 6.6% 6.3% G.7% 63X "em ms Avg Anal Dlv'd Yield 6.4% 20J03 26238 2D969 2015.1 2066.0 2056.1 21027 22604 3326.5 33�82 �14 70 344a gotProfit(3MIM 98T60 485 3.5% 6928.0 par BOD. s ii 0.6% e.176 saavo 118% 123% 129% 124% 11B% 9A%L32%4.0% 10.7% 121% 12S% 13.0% Return on Shr Equity 13.0% c Common Stock 137.215,462abs.asor4130I89 14 5% 15.2% 12.3% 128% 13.6% 13.0% 1Z4X 11.1% 12.6% 13.OX lZ5% lusamid oCacom E q 2�'e 13.5% MARKET CAP: $52 billion (Large Cap 4.7% 1S% 2.0% 7 6% 22% 1.6% 06% 111 00% 04% 88% 1% 12% �% 90% 82% All D1v'dsiW Nel Prof T7% ELECTRIC OPERATING STATISTIC8 tags 189TE lags +3.5 +480 71% n formed llntough BUSINESS: Assistant Corp. is a holding comps y : c dro, 4%. Fllei rafining. I998 fuels: oval, 18%; nudear, 18%; try labor costs. 72%. 1998 deprec rate: 3.0 %panpeAt$Srgs # bdodusIit 1412 1471 1954 Matutra krs.p c 4.40 4.33 4AI the merger of union Electric and CIPSCO. Supprms eleddcily aad to 1,800,000 customers In MlssauH (83% elect revs) and II- costs. 27% of revs.; Hmaled plant 999: 16 years Has 7A50 employees, 126.000 stock- W Mueikr Inc Nis- kputrdPert(ppansseq�9120 11312 11444 Peatuad 5dcarpla) 6085 997E 10592 �s ni 17% Eled.row rrsid., 41%; nommar.36%; Indust, 19%; ( ) metals uldudhg (' holders• Charms. C.EO. and Prey: Charts sol Address: 1901 ChoWaau Suset, St. Louis, Missouri 63166, 4nwstmdtrlo 55A 55-0 547 %StaapeCWaarn�p•eld! +,8 +,8 +.5 other, 4%. Largest Indust astomero: primary coke produdisxl), chemicals, bansportaoon equipment, petroleum Telap:314.621.3222 Internet vAvw.arnamn.rw/rr. Feed Ca 393 363 4o6 Ameren plans new generation to on management's cover sforelcast of demand.er 2 annual rates May 2002.. use An those f Its neighbors, expect that deregulati nlwill enable it to new accounts.. In the legi ANNNUA(pe RATES ill tPast SYnt �w�a2ro488 Revenues 20% 3.0% NMF 'Cash Final t.0% 5% NAW electric sales growth for the next few years and a reserve margin of only 7%, the cam- gain governMissouring c lature took no action governing electric its 19el Session. But ere, Earnings 5g� .5% NMF Dividends Al 2.5% NMF pany will need additional capacity shortly- build six restructuring in too. the company is well prepared to meet Hoolcvatue 2.0% 1.0% NMF To meet its obligations, AEE will gas -fired, simple -cycle peaking units in be- the competitive challenge because of its relatively low rates- Cat WARTERLYREVENUES(SmOljt Full Order III Jun.30 Sail Dill Year central Illinois. Three of the units will come operational in 2000. A fourth will go dest earnings gains We look for morTemental both this year and next In 1996 495.6 545A 743.7 475.7 2260.4 1997 7597 791A 1043 73Z0 3326.6 on-line in 2001. Siting arrangements must for the remaining two savings attributable to the late 1997 1998 1999 700.6 B216 1117 678.6 735.9 850 1140 744.1 3316.2 3410 still be made facilities. The total capacity of the plants merger of Union Electric and CIPSCO will $21 million to net.. Other pluses in - 2000 750 875 1170 765 3560 will be 735 megawatts. The cost of the package is estimated at $260 million. The add clude a probable increase in kilowatt-hour a $9 million gas rate hike. But EARMNGSPERSKMAE Cab Dolor Mat31 Jun.30 Se .W Dsc.31 company has not yet decided what per- tentage of the output will be allocated to sales and these gains will be offset, in part. by a Full 5% electric rate re- 59 1.78 1996 1997 36 .13 .33 58 167 d.04 support native load and how much will be in the open market. Cash flow from year of last August's duction in Illinols and costs to malts the 1998 Joss 29 61 173 19 40 .43 1.72 .20oppeerations L44 sold should be sufficient to pay for compputer system compliant for the year 2000. On balance, we estimate a 595 rise in 2DD0 .42 .05 1,00 .23 the plants' construction, obviating the need for additional long-term borrowing. 1999 earnings to S2.95 a share and further Cal- Crider ender DUARTERLYDMDENDSPA10$E■ Mw31 Jun.30 Ss .30Doc31 Retail electric competition in the company's Illinois jurisdiction will October. At that time, large com- improvement next yew - The high payout ratio suggests no div ideas increase for a few years. But 61 .6! 61 625 246 1sso 625 625 625 M 696 635 Z61 Z64 start an merdal and industrial ratepayers will be income -oriented investors might still be at- -average Joel 1998 1998 .635 .6% 635 635 .635 .635 254 able to select their energy provider- All will have the same option in tracted by the above yield. Arthur fi Medalle Y 9, 1999 1999 635 .635 customers A) EPS basic. FxcL norrecur. gain (Wss):'89•Fm, Sept 30. Dec. 29 • OH'd reMvest• aqq. m W 127%. Regal Cfims Average. (Dj In Company's Financial Strength 10� m9fions IEl Data oxcepi blut0, for Stock s Pdeo Stability25 30Zi;'92 18G. Next egs repose due early Rug.an eves (C) Rate base odg. rose }e} Next tlfv'd mt5 about Aug. V. Naxt ex daleted. Rafe eoowad in M0 on common Union Electric only '97 31, VS: 12 5%; earned on average can tonne deEa her AmarEa pro Earnings price Growth Persistence 88 about Sept 7. iv'tl pnW data$: March ind. r : 1 1 e 1999. vaure Lino W Inc M ry�p5 re "na, reseal ma•8d b oseI f,m souses bdievod to be satiable end b Pei •dboor warram C$ Of a kpan It E PraUSIIER IS NDT RESPONS OLEFOR ANY ERRORS OR OMISSIONS HEREIN. Ilk Pnlisa n § W'e,p�y�� id subsalbers •wv'° ° PC w sonicd ° for dmi a eau 6, •e7 t� d 1 may be eteodaed sewed a aamamod it eery Fall dolaae a all Iran a Iced 9wen • Exhibit No. VER-3 Schedule 9 Page 12 of 16 CON. EDISON NYSE-EU Ri eEtif pAICE 44 Pii: Tredion:11.0 RE1AT)VE RATIO � 3,8 tMediln:11.4, PiE RATIO 0 88g42.672002 Range TIMELINESS 4 twAvedi2f15Pl3 FD h• 23.8 LmBv. 20.4 299 293 222 19.8 28.8 32.9 37.8 U-6 25A 30.3 32A 23.0 323 25.5 348 25.9 415 27.0 56.1e 39.13 2004 SAFETY 1 Nee7111150 LEGENDS „ - 1.11 a Dndaes p 9t 100 80 TECHNICAL 4 Loam 1I9199 n im�c� seta # BETA So (lMl. Marxd) Sl�a•1 epN 7R9 OSlWedima ixk,as mreitiJn _ _ 48 - - _ - 40 - ` _Its_ 2002-04 PROJECTIONS 1 r Prtu Gain Return ''q,P � 24 r 40 3% 20 1 1"' II a .. n 1 Load (•1DN6 •• 16 Insider Decisions - 12 ONOJ FM AY J to Buy 0 1) 0 1 2 1 0 0 0 g byarlr 0 D 0 0 0 0 0 0 1 %TaLRETURNIN heal 000001103 - NM 8 Institutional Decision- 30101 IOIM 1oiM Percent 6.0 Naaa 1 yr 47 33.3 &&ryry IoWO 149 159 15µ0 sfueas 4.0 traded 2D 3 9&6 602 Syr. 119.7 1095 616r 4N 92561 93829 95B30 1983 1984 1985 1986 19B7 19BB 1989 199t) 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 dVAL1ffLINEPUB WC. 02 W 2125 22.05 2274 2193 2236 2241 24M 25.15 2532 25.36 2673 2113 2782 29.62 3014 30.46 31.65 3155 Revenuesparrh 36.25 4,87 497 &08 529 5.65 &60 "cash no** push 610 319 332 3.31 3.33 353 312 298 Z24 213 2-13 221 247 392 3.84 3.91) 4A6 438 477 2.49 234 232 L46 7-66 298 293 293 295 394 i15 3.15 Earnings per sit • 3J5 tt6 OWdDed'dperA e a 222 .94 IN 110 1.34 1AS in in 1.62 1.B6 1.90 194fl 21g 2.10 212 214 3. 3.39 3. 331 2,87 270 2 280 2It Capri Spending pet sit L" 1.62 i 03 211 226 252 1427 15.441615 17.03 1759 1&44 2. 19.21 19.73 2D.18 20A 2t.63 24.3125.t8 25JS6 2515 2835 HookVafueperah� 2910 vv 235A9 232.63 21040 213 CommanSbsuilmll 201.5.4 259.50 259 2 237 227m 2219 105 10 99 228.15 2283 23 Z343T234.99 109 103 10.8 119 13.1 10,1 109 i53 Bad 6g.Aee a,e Avg Ann? PIE Palo 1i0 5 46 54 55 .7i 67 .15 76 .77 .69 J'E .77 .63 .63 81 IW-Li a Relative PIE Rate Ji5 6.5% 4.6% e°M/°°e Avg Mn'IDiv'dYield 5.2% 8.4% 8.1% T.1% 6D% 6.7% 72% CAP MAL STRUCTURE as of 6)311199 69% 75% 7.5% 65% 5.6% 7.0% 5550.6 5738.9 5873.1 59329 6265A 6373.1 6536.9 6959.7 71213 70931 6940 7150 Revenues (imW) 7500 7T0 Total Debt $4459 mil Duo In 5 Ym S1509 trap. IT DebtS4200m8t LTInterest$3043mr1 606.1 571.5 566.9 604.1 6585 734.3 723.9 694.1 712.E T299 730 726 Net Profit 1 34A% 33,6% 339% 345% 35.7% 37.4% 35A% 36.4% 348K 35.8% 3fa0% 36.0'd income 36.0% (IT Interest owned: 4.8x) Pension llaWefyNone 22% 1.6% 15% 23% 1.6% 1.6% 5% .7% .9% .5% 1.0% 1,0% AFUDC%toNelProBl 1.0% 38.0% 392% 391% 39.1% 393% 40.7% 39.1% 411% 40.1% 39Z% 420% 42SSt Long•TenoDebtRaOo 4JA% Phi Stock S249.7 mil. PM Dlv'd S14.T mIL 1,915,319 shs 55 cum. to par, call S 105 a ah ; 54.1% 533% 53.5% 539% 13.1% 53,0% 54.5% 553% 56.8% SBA% 55.5% 55.D% Common E u Ratio $4 � 8093.4 8950.7 8606.0 9074.6 B403S 1OD32 10125 10289 i0437 10325 10155 iD240 IONS wpBai ( ol" 375,626 sit 4.65%trim 61DD par, cat $101111 Fund ends 2009; 370.500 B4111 8815.2 9263.0 9729.1 i11156 iMi 10814 11067 11267 11407 11490 11550 Nat Plant Sm16 11670 8.Z% 8A% 8.6% 9.0% 8SG Return on Total CapT d0% 51Dz5D a sh.6ksk3ssg shs 6.125%cum $100par y.6% 82% 82% 82% 85% 88% 6.6% i21% 111% 105% 1o.9% 115% 123% 117% 115% IIA% 115% 125% f25% Return anShcEquity 115% Common Stock 223,iD1,749 shs. 13.0% 1 119% 115% 11.6% 123% 132% 12.5% 11.7% 11.7% 115% 13.0% 125% Mum on CO-4 ult a 11Ji% 3.2% A% 5.6% 4.0% 4.0% R6Wnad io Com Eq t0% MARKET CAP: $9.6 billion (Large Cap) 4.0% 2.6% 23% 2JiK 33% 43% 3.8% 71% 79% 81% 1 79% 74% 69% 71% 74% 72% 70% 69% 67% Ali DIVdstoHot Rd 67% ELECTRIC OPERATING STATISTICS 1990 1987 1998 %aa�9sWSrks +3.1 BUSINESS; Consolidated Edison, Inc, parent oT Consotldated p US. Fuel vests: 3Z% W revs.; labor twin, 147. 1998 reported deprSe Bale: 3.4% Esl'd plant age: 9 years Pool sources: tonal N NA bq IsosstOsepAVl� NA NA NA Arp.hmuitrrs 0) NA NA NA Edison Company of New Yak• Inc, sel6 elect. (809e of revs.), gas (14%), and steam (6%) in roost of New Yak City and Westchester 33%; nuclear, 6%; lam p>��. 41%; other pumbilses, 20% Has 14A22 emits, 124,9DD commas shareholders. China. C.E.O. Cipr4friPedl �ej, 13625 13957 13686 Potlad• sr ) Bibs 8158 10919 County. Acquired Orange A Rockland UI8iilas 7W. Commercial rev. ratio (57%) compares with 32% for the Industry. Noninco n r & Pros.: Eugene R. McGrath. Inr.: N.Y Add.: 4 living Piece, New %mt3S4�PCfaartsi 58.6 A9� 503 lax9s and avg. price per k9owaU•hour am among the highest In York, N.Y.10DO3. Tot: 212-4W9D3.Internet orMNconed•oam• fond to 1x 361 384 405 Consolidated Edison has completed plots south of the United Nations complex We think these could also be ANNUAL RATES Paid Past Est'd 96'B8 T the acquisition of Orange and Rock- land Utilities. Last July, the company properties sold at prices above their book value. Part otcts�UALR loan Sast to'02•'04 ofC"o(e 3.0% 39% 30% Revenue"Cash bought all of O&R's common shares for of the proceeds from the plant sales have 081Z The Floor3.5% 4.5% 309 Earnings 25% 3.5% 20% $790 million in cash. The merger adds a fi- been allocated to the purchase. nandall strop uti13 to ED's solid bal- remainder will be used to buy back S1.15 Y g Ty Divldends 35% 2.0% 10% Book Value 3.5% 4.0% z"t ante sheet Since O&R has sold all of its generating assets, the purchase is largely billion of common stoat through 2001.rn We look for steady, but slow earnings The cal• DUARTERLYREYENUESiite9lj Full Year endar Mar31 Jun.3D Se .30 Dea31 Year for O&R's transmission and distribution tam. That's In line with ED's strategy growth over- the next 3 to 5 years. expiration of some high -cost, purchased 1996 1867 )540 1920 1o,- 6959.7 192D "' ex riding its network of wires. The two power contracts and fewer common shares 1996 1067 1540 1720 213 1997 1086 1561 2011 1720 712130W93.1 companies estimate that the alliance will outstanding are pluses. Too, O&M costs be down because of the absence last 1999 1M W9 2960 1624 6940 produce savings of $450 million in 10 will t The first full year of the con- year's Indian Point shutdown.. But these 2800 1830 1550 2100 1670 7150 Years. solidation should add about $0.20 a share gains will be reduced somewhat by lower Cal- EARNINGSPERSURE� Fug ear eCaar Mar.31 JOn30 SS 30 Dac31 Yoer nda to ED's earnings. The company has sold its fossil -fueled electric rates, (it might be noted that out ages caused by last July's extended heat 78 28 138 .49 1906 69 18 1.35 295 pplains in New York City. The winning wave will have a minimal adverse effect on All told, we estimate 1999 earn- .59 1993 .73 26 1.49 56 104 biddPss paid $1.65 billion for the three profits.) ings of $3.15 a share and a further gain in 1999 76 30 1.53 .56 3.15 3.25 stations. That represents about twice their book value. The regulators have allowed 2000. The stock is untimely. 2000 1 .80 .30 1.67 .58 the company to keep the first $50 million These shares are an average electric Cal oUAILTERLYDNB)ENDSPAIDBa Fail endar MoOl Jun.30 SD 30 Dac31 Year of the aftertax gain. The second $50 mil- utility selection. The yield is near the ln- lion will be applied to the writedown of the dustry norm. Though dividend growth 1995 61 .51 51 51 Y.04 1995 52 62 52 52 204 Indian Point 2 nuclear facility. The com- prospects are a cut below average, conser- investors might be attracted by the 1997 626 US 525 525 2.10 mission has not yet decided on the alloca- votive don of the remaining $300 million. ED company's strong finances. 1998 53 63 53 63 212 logo also has available for sale three prime ArthurH. Meda/ie September !0, 1999 .535 .635 .535 A EPS bask. Nest mpor! due late Oct. vest plan oval {C) Includes Intangibles. In'BB. latory Cl'anate: Average (E) !n m oornl, ad- Company's Financial SNan;:IM,*oh A++ �e; about Nor 24. Goes S237hh. (0) Rale base: not original cost Rate justad for stock sp8t 61ock'a Price Stability 25ex Next dividend meefing about Od 8. DMidend payment dales: Mar and aiec. cossm on equity: T46, 103%; Sam 15, June 15. Sept 15. Dee 15. a Diva reins96 average common equity: 12A% Reip1• Pike Growth Persistence es Earnings Predictabilitytltdd b ctg ired f- romm bdk'ved l4 be .dWO vId is Pwided rrkrwd a iK*ns et on W r 1 r 1 • , coo R rxrr RF OaN4121 F Ran ANY ERRORS OR OMISSIONS HEREIN. This putliction Is Sol* Ice IadWibW3 ern, non-cerrrim Leerai u14. �o d I Hoy be IgHW=d rimer a banNllbed i1 ary pined. dediNk a duet lam a usal For g=101119 a 0101112" WV pa,m a ,ms+ - F--•^-•• •-•••-- - r Exhibit No. VER-3 Schedule 9 Page 13 of 16 CENTRAL HUDSONNYsE�Wy ' 14 3�TrelBng:,4911ili-Kn (� �� 43 61ahBerc„A PkRAT10 91 D1�° 5 0% . . Target Price Range TtMEUNESS .r) Loaesedt711199 High; 219 24.i 20.b 24.9 29A 313 35.48 30A 319 315 a39 20.0 22-6 259 2BA 279 25A 28A 299 47..1 45A 3B9 35A 2002 2003 2080 SAFETY 2 wld 3nme tow; 18.0 LEGENDS , 094 a pwidmds � $ Ba rig TECHNICAL 4 Loosed 59an ex dal roan Bak ,ire Samgn .0 ------- 40 9E7A 30 "'o • ata,kd) pp.bo.a aRoita+a $hadeAMa i7[fmiet rercesson - _ - _ _ _ - - 32 2002 P ECT�n9 TWaI '^ 24 21) Prise Gale Return 35 !20% 114 ' 18 12 LWall 10 Insider Decislons O N a J F Al A M J B to by a00 a00aa0 opu's o o a D 0 0 0 0 0 %TOT. RETURN 09 B 000000 bra o00 STDCK Tune= - 4 Instiluuonal Decisions 1 y, 4.4 333 --- - boor r010 40151 w152 Poreord 0.0 ahoms 41 3.yr EGA BUZ Syr. 7209 t0a3 - blA 0553 0207 04 2 todad 2.0 1989 1990 1991 1992 1993 1994 1995 1996 1997 1996 1999 2000 °YALUEONEyUB BNC 02•D4 O 1983 1984 1985 1986 4924 4753 4187 31A9 1987 1988 29.88 30.10 JiBB 33.68 3138 3266 30.52 29.91 2928 2928 30.11 5,80 25.83 3900 3200 Cos Five 5 &1 SOD 6.15 Cash flow" per sit J4.110 5B0 617 6.50 6.02 4A9 4.60 410 4.66 266 2.63 22B 6.11 4 99 522 623 525 5.33 51>9 238 2-40 255 250 US 274 299 297 290 190 295 Earnings per sit A 216 Dl Jd Dacl'd per dl s ■ 1200 394 4A3 4.57 2.63 2.78 7-93 2.96 265 1.72 1.76 1.62 190 135 205 208 210 212 214 ZB7 2 216 2 i6 27 3.9 295 CeP'ISPBndingpseh 10 8.71 10 10T6 iZt 77 An 7791 29.49 31.18 6,67 79 20.35 2124 21.76 329 4.44 .13 3 7 22.31 22M 23SO 24.65 25.33 25 % 2687 27.611 ZB•00 2&75 19' B common ook value Shams Ourrib Ltii g '200 9.62 6.1 trot 4.6 12uf 5 B 14,11 vI.JD ?A 9.5 7b ,.,, 9J3 _. 9b 10.7 _- 1 122 tD.O 103 /0. 11S ! ' �W11 tea" RelaUve PIE Rage A 68 78 52 .43 .47 60 .64 $3 .74 .71 .6B b8 .72 69% 63% Jib 68 iB% 7.5% Gi "dw■rd 7.0% 63% 51X AvgAnnlDiv'dYldd 55% 1t.0% 13.7% 10.8X B9% t05% 6.6% T9% 470.0 &1% lA% 5D3.6 4947 623.6 517.4 515.7 5122 514.0 520.3 503.5 5YS $4D Revenues (Sm01) 575 65.1 525 $10 53.0 Net Profit11MIM CAPITAL STRUCTURE as of WWII Total Debt $386.6 milt, Due In S Ym SS4 7 mIL IT DebtSW2_SMI. ITInterest$23.0mU. 30'1 326% 41.0 429 332% 332% 462 50.4 345% 35A% 50J 52.7 345% 352% 56.1 35all 323% 353X 17.0% 37A% lowmolaxRate 20% AFUOC %fo Net Pra61 18% (LT interest Named:4,5x) Pension Llabitity Nana 1.1% 527% 4.1% 5.1% 49B% 48.5% 3A% 3.1% 490%6 44.0% 2.7% 28% 429% 43.3% 1,8% 1.2% 1.7% 20% 407% 4 JA7, 40.3% 39A% 36 D% Long Term Deht RaSo Common E ut Ratio 5580tS Ptd Stock $56.0 colic Pfd Ofv'd $3 2rrdA 37.8% 4D.6% 420% 8223 8573 420% 469% 890.5 8907 48.1X 60.5% 9D71 899.5 53A% 53.3% 53.3% SGS% 57.5% 8B9B 0950 8851 890 870 Total CapRat {1mBq 9D0 210,300 she 4%%-4.96% cum, $100 Par, redeemable' a15101•Sto7lsh. 350,000 she. 520%- B491 847.8 655.1 885A 904.6 914.9 931IJ 937.1 939E 9328 9282 925 925 Net Plant {1m0 72% 7.D% 75% Rntumon7olalCap' 7A% 6.80%cum,sub)ecltomendateryredempibn 7.0% 7 0%97% 7A% 6,9% 6.8% 73% 71% 73% 10.3% 7B% T.4% l0.6% 10.3% 9.9% 9.6% 9.5% Relum on $hr. Equk 9.5% after 1W1103. Common stack 1S.862,081 all 1DA% 9.9Ye 9.7% 10.6% 10.8% 10.1% 1D.1% 10.7% 1D.7% 9B% 10.5% 10.5% 112% 10.9% 10.4% tOJ)% 10A% Return on Cora E ull a 9.5% 25% RetainedtoNdPraarl ELI 3.0% MARKET CAP:S72Smillion(SmallCap) .4% 26% 73% 2.5% 26'% 24% 25% 79% 78% 33% 3.1% 27K 23% 72% 73% 76% 76% 75% A1I Div'ds to Net Prot 73% ELECTRIC OPERATING STATISTICS 19� 19297 998 Bo% BUSINESS: 79% 81% Central Hudson 70% 78% Gas E Electric Corporation pmvldss sourms, TN6: waL 40X; 00, 79K; nucteae 10%; gas, tell hydro, 23%. Fuel costs:34% of revs 9B reported depme , %ClobFI'll SaksPlY7ii) 16-9 1521 1439 5.71 5.45 ekdridly (03%. of ravenous) and gas (17%) to the Mid•Hudson VaP 2%; purchased, Ley regime, enwmyassing a 2,6g0 s4uara+nBe area 26 miles north Tots: 3 2% Has 1,150 employees, 21,400 wnunon stoctlwtd E J. GaneL President S C.O.Oa Carl Ar1.N0gevEpe Nj 5.72 Ca dPril (pkkr�o��]]1116 1107 1106 83B 9t7 90D of Now York CRY and 10 miles south of Albany. Electric my break. Chakman 8 C.EEO.: Paul e 31%; Industrial, 17%; Meyer. ins.: Now York. Address: 284 south Ave.. Poughkeepsie, Peatta4 c aael0a) ��p j 67.0 61.0 63.0 down VS, residential. 43%; wmmemial, 9X. IBM accoudied for 8% of electric mvs. in'98. Generating New York 126014879. Tel.:914.452.200D. Web: wvvw.wnhud.cem � SC Calaom(at71 +.7 +1A +1.6 other, The auction of most of Central Hud• utility is allowed.. At some point (possibly December). Central Hudson will form a O Etrd cer.i$) 323 30D 295 son Gas & FEW generating assets in could begin before yearend. The assets holding company in order to increase its 11- A nancial flexibility. 8295 ANNUAL RATES Pawl Past E ANNUALRAT) tPost Past tofu 04 Revenuas .1.0% 25% 'rash Foe/ 1.0% 25% 2 5p%% have a book value of $170 million. provi- sion in Central Hudson's regulatory agree- I" t Le will couldhrisei n 2000. AI- Ywinter Eamings -t.0% 3A% t. X Dlvldaff& 45% IA 5l meat with the New York commission al- year. hurt It e 1 of y(fordthe Book value 1.5% 3.0% 2.5% lowssecond year teesutili ales,uto p 5 million after ratquarter earnings in a row}, Central Hudson has been able m Cat- under QUARTERLY REYENUES(SmSL) Mar.31 Jun.30 Se .30 Dec.31 taxes. Central Hudson may bid on its own assets through a nonregulated afliliate; it make up the shortfall thanks to a hot July effective expense control. The utility is 1996 1997 153.5 1170 117.7 125.5 1519 118.6 1235 126.3 has not yet decided whether 3t will do so. and on schedule, the now bumping up against its ROE cap, so it 1998 1439 i121 125.7 1218 130 r525 B• everything pproeeds winning bidders) will be announced in the has little growth potential. Central Hud- earn $2.90 to $3.00 a share in 82000 1999 145 5 1110 131.E 120 130 130 second quarter of 2000. with closing in the should on the performana of its Cal- 160 EARIBNGSPERSNAREA 30 Doc 31 Year Year fourth quazter. Central Hudson is interested in ex- nonregulated operations. Addition non- investments next year would proba- nde Mar31 Jun.30 So 58 73 2 panding its nonregulated operations. utility and bly send earnings toward the low end of 1997 .-3 1 Z1 1.20 55 72 52 297 It owns three small generating plants Central Hudson is al- this range, given their lower returns.. 1997 1.18 55 77 63 297 290 a fuel -oil distributor. Jawed to transfer up to $100 million in We believe some takeover speculation in the stock price.. Several 1999 2000 1.09 .51 .80 .50 1.20 .75 .60 2ss equity from its utility to its nonregulated is reflected small utilities in the Northeast are being Cal .50 OgARTERLYDMDEHOSPAiDB■ QUARTERLYE Full options To date, it has transferred $25 5 million. Although the company's boogght out, and Central Hudson could cer- tainly attract an acquirer. But we wouldn't under nde .30 DecaYear 525 525 209 nonutility activities could enhance Its long they are buy this untimely stock an that basis. Due 1996 52 52 525 525 53 53 2t1 earnings growth irr the run, a near -term drag ber8lue, although profit- to the stocks current valuation, we thlnle are available elsewhere. 19966 101 53 53 535 535 135 535 54 54 213 215 able, they are earning a much lower re• better selections turn on equity than the 10,596 that the Paul E. Debbas, CFA September 10, 1999 1999 .64 .54 .64 divd payrnent dates: tsl al Feb., (E) Rafe base: Not original cost Rete allowed (eleddc);.10.fi%; Cam splice any's Financial Strength 1W Pllcu 255 A) Fici. rmnreaning gain {loss):'87,' proxtrrota �510.79); 'g2 10y'. Nevi earnings mporl tlue late October. {B Next dN'd meeting about October 7 Ap May, Aug., Nov. ■ Div d rateviudmil d plan chars ava9abte. C) Ind. delened es. in •98 $176.0 S10A41sh (D) in millions. on common .o%; m '9& T)6 as): tO.OX; earned on avg. rpm eq g 1,10, X Regulatory Climate: Aveiage. Growth Persistence Earnings Predictability September 24. Goes ex about . o t999, Vake Ilne FL Inc. N t. w res""d. Fadual m3Mriri is oiled horn sources bakmed to be rdbNo and b paeided vdh3el vanerdes or an mod. THE PUBLISHER IS NOl RESPOrNSV FORANy ERRORS OR OMISSIONS nEREaL This pgblkaUm a a1'ra sabsoibc�l'S "ru P.�f�lCiak a polka osateao9 �07 p s a d i oay ba np,udaad, shoal a baombeil h ary pi" dusnodc a arm last a mar is a,vA4 a • Exhibit No.. VER-3 Schedule 9 Page 14 of 16 RE 39 PhD 14 6 (Tm3fiag:,11)/ PIERA11E V PtERAT10v"./ 93 DIV'D 4 0% ' r4 "t. DQENYSE•DOE PRUE m a 6tedlm:it.o 352 Target Price Range 78dEunss 4tmQ,ed91t4] Hover 17B 11g 136 158 179 209 10.4 1B6 258 205 316 374 2002 2003 2000 SAfEltr 2 Raied ta19192 LEGENDS t6D so - NICIn x Oxdmds $n TECHNICAL 4 Isaac maw dim ay etaes�Rate au�h • ltcbkm R'ce Sh49 a 64 DETA SS (1.00-IUd<d) 3 • s�No ,t§nu _ , - - - - _ - L 40 2002414 P JECTIO Sh,aroema i,dotas rcr ass _ _32 a Arm97oW Nee Gaht Return p y 24 W 6o 't 5Y. f49 Low 45 1-15% 8 L ' 18 Insider Decistons t2 D R O J F Y A Y J ' option o 2 D 0 0 0 0 2 0 Nt rr•'•••' ""' 100 '-•rr=� .• %TOT.REfURN8f49 _ g b o 1 D 0 0 0 0 0 0 •, �") -" tsa9 namnt steer aft Insttlulional Decisions 1yr IDara a0IB1 le1D1 Percent 6A 6.0 SBA 603 3yr 56.4 60.3 - to 8S 75 as snares baSpD� 53 48 67 tradod 7-0 a13. fB 33949 351B7 32604 Syr. 13T6 10n3 199E 1997 1998 1999 20D0 s'VALUEtINEPUB WC 02-04 989 1983 1984 1985 198E 1987 1988 1989 1990 1991 911 199T 1993 1994 1995 1641 18.15 iL05 Revenues per eh 21.90 6102AG 2D 913 887 6.53 8.17 8.10 1228 1467 5.11 1491 15,04 15.75 4.05 15,73 4.68 1536 5.D5 15.69 5,36 5.13 S,SS 5,70 "CashRow"push Los 350 224 2t9 Z23 1.89 IA3 124 135 3.07 1A9 1.61 4D7 178 3.87 1At 199 220 232 240 252 260 3.00 EamingsperehR Dlv d Dec7d eh an 1.70 t78 IAA IAA 1.45 11g t33 13T 1.37 9i BO B1 B7 92 ST 1.03 1.05 1,13 1,22 1 i 130 131 138 152 1.4E }5Y 1.58 per 6 1.T5 fA5 Cap paodingsh 170 256 2 Z28 i 1.41 1 1D5 135 1338 1 f4.00 tA2 1475 127 15A8 t 1627 17.13 18.01 192 19.1E 19BD i&95 Book Valuepash� 2270 1094 10.84 10.91 11.17 112E 1234 72D4 03.01 SO.W1 79. 9.43 79 78.4 7750 7727 71,18 77 1 75.D0 70.00 Common S s Oulsrg 6763 97. 0723 1092 109. 8a.7s 102 99 10.) t13 t2B 102 t16 1 726 Avg Ann rit MOOD 14A twee+ Me '85 7.4 2 7.4 8 58 82 q 58 50 56 39 .68 .77 .74 5B .59 .76 67 J4 .77 .73 RabovePIE We 76 esdrA*S Avg Andl Div d Yield 7 ]% 12.2% 15D% 12.8% 9.7% 9.T% 6.0% 6.3% 62% SA% 5.1% 4.7% 5.6% 5.D% 4.6% 12252 4.6% 12102 4.0% 1269.6 1360 1125 Reveaaes(SmBQ 74D CAPITAL STRUCTURE as Of6f30199 1120.7 Total Debt $1663.6 mill. Due In 5 Yrs S450.0 mf8 1298 11343 f35.7 11995 144,4 ti84.6 15D9 1195.E 144,0 1235,6 1628 12202 1765 179.1 185 9 196 7 2W 210 Net Profit (1m181 lax 2d3 74 OX ITDebt$1271.2mta. LTlnteres16B6.Drrt4 36,8% 343X 41.4 38.9% 425% 373% 35.4% 328% 34D% 339% 3J.No J4.1MR AFUDC%tocome Ne Pm1% AM (LT interest same& 4 2x) 22% 22% 3.0% 32% 1.1% 508 50.6% 471% 45.0% 445% 438X 438% Lang Term Debt Rollo ]2D% Pension Liability No" 54 5% 37.T% 55.9% 375% 54 7% 4D.3% 53.3% 42.0% 619% 43.4% 45.7% 46.9% 45.6% 47.7% 47.1% 48,0% 48.0% CommonE ul fleBo 2770 Total Capital (sedBJ 5AOgX0 Pfd Stock $267.7 mil. Pfd Dhed $16.6 mG 2826.5 2677 9 27571 2788.4 2836.4 27908 2835.3 3054.1 3140.9 3 3149.1 J09D 171611 iSDD 500 Net Plant $in 800 Incl. approx. 8,000,000 shs. 3.75% b 9.00%, all cum, various par values, callable atvsftmPrices . 3D55.D 3046.4 3035.1 71% 7.a% 3015.7 31185 7b% 7% 31395 30602 77% 6.1% 28t15 2- 77% 7D% B.0% 85X 9.OY. RetumoniotelCep7 120% 15.5%. Common Stock 75,618988 rdts. Commo St 72% 10.1% %7% 11.6% 11b% 10.6% 121%�40%5.3% 11.9% 125% 111% 12.0% 1D.8% 113X 11.51G 135% Retain on W. EgaNy 11.6% 12.1% 13.5% 16.eX Return-CamE Das MAT 713 CAP: 528 610ion (fdld Cap 12.DX 3% 5.0X 5.1% 4D% 4,4% 5.6% i,5% e.DX Retained to Com Eq 105% 5B% 66% 57% All Dlr ds W Nei Prol 19% ELECTR� OPERATING STATISTICS 110.t6%11.3% 6% 62% 60% 63% 64% depr. rate: 4 3% Esrd plant age: 9 ym Fuel: coal, 69%; nudanr, 1998 1997 1988 SChn,�RaalSshsO ij +97 3,3 1628 17.0 -3.3 BUSINESS: DOE b 8 mulg41ItlAy dakvery and services company. with ventures and partnerships M the U.S. and Canada DAZE sub• 25%; o8 7%• Fuel costs: 21% of mJs; labor orris l2%. Has 3 9g8 66,270 sikhtdemt� JD D bt. ndmvu(*sR Avp.ndnl8en.pa lilt) 5.81 SAS 5.35 DpjjYYaa)) 2670 2670 2670 sidkuy Duquesne Light Co. produces and distributes elodricBy h an 817•sq.�rd. area, Ind Pith and muniapat0es in west PA employees, Bemslein d Co., 8.1% (Prmcy ). E anpm D"Id PA. Addr: 411 Seventh Ave. P.O. Box iB30, Pglsburgh Peatmd,9lzsePla) 2463 2671 2484 1r9uilmdfaia 61J0 57.1 '7- Area pop.: 1.5 milt Elecbic rev. sources: resid., 32%; cam, 39%; mdust 15%; other, 14%. L95L Indust cusL: USX 1998 canpssia shot Inc_ PA 15230.1930. TeL:412393.6000. Ink+mat www.dge corn• y,tkllgFtddosar�nad) •• +.2 4.1 DQE pre-repoirted a likely earnings DQE's assets should garner $1-$1.5 bil- are earmarked toward Fad Cw.f% 225 191 tell shortfall for the third quarter. A July heat wave throughout its lion. The proceeds stranded cost recovery, share repurchases, l2000ar ANf4UAt RATES Past Past Ea1'd 91 9B otdsnge (parh) 10 Tn. 5Tm to'G!•'0e Revenues 55% t 5% 4.0K prolonged to make service4 and uctions to be finished of new by eas. rly the s 'Cash P4W' 7.5% 55% 5.0% Eamings 6.6% 65% 8.0% Dividends 5.0% 6.0% 4.59: million in high-pricedcompen-market pom,er purchases to satisfy record demand. drain Meanwhile. DQI;'s expanded business lines continue to gather steam, With Book Value 5.0% 5.09E 3.5% Ibis amounts to an $0.18-a-share on earnings. DQE noted. however, that its up to $500 million of new, available DQE Capital should be able to cah ender pUARTfILLYREYENUE51larD1) Dec.3 Mar31 Jat130 Sa 3D Qec31 pug You You expanded business line restructuring will loss. Accordln y, we financing, expedite its aggressive acquisition 199E 300.5 ?93.4 335.4 12252 mitigate much of the have reduced our estimates for the quarter and tegy. AquaSource. DQErs watts and utility, looks to be the compa- 1997 1998 303E 285.9 331.2 29B.5 12192 303.6 285.9 3478 3195 1269.E and the full year by $0.06 and $0.05 a The has wastewater ny's most promising long-term earnings 1999 1099 3261 32B.8 366 34LI 1300 share. respectively- situation been curtailed; the company stated driver. Recent additions are promoting sig through 266 266 366 295 1125 since that it has been a net seller of wholesale wer through the first half of August. nlilcant growth and cost savings increasing economies of scale.. All told" businesses should deliver more than Cab EARNWGSPFRSNAREA Fu0 endar Mar3i Jun-30 Se .30 Doc.31 Year Dafiicult es of this nature should soon these 30% to DQE's total earnings in the coming 1996 1997 55 50 74 553 58 52 75 65 232 240 be a thing of the past for DQE, as its divestiture plan comes quarters, at growth rates that far surpass l998 58 52 80 62 252 eneratin -asset g g closer to fruition The exchange of power those of Its traditional utilittyy business. solid total 1999 2D06 62 55 .77 .60 TO 62 92 .76 260 3.00 plant interests with FirstEnergy has two key approvals; pending final Untimely DQE shares offer returns for a diversified utility. Tf the Cat. QUARTEALYDOfIDEN05PA1Dso pun Yaar received consent, the transaction may be complete company can record a few consecutive of earnings gains commertsurate ender l"a Mar.31 Jun.30 Se .39 oc 31 r', 293 30 30 t 19 by Yearend.. Meanwhile Pennsylvania reg- ulators have okayed DQE's plan to auction quarters with a true growth entity the market may the stock with s richer 199E 1996 32 32 32 34 34 32 32 36 .119 1.38 both its power plants and its customer portfolio, which would effectively eliminate well reward price/earnings multiple. Conry September 10, 1999 1998 .36 36 36 36 iA4 any supply -related risks going forward. Chrls[opher T. 1999 .38 .38 .39 about Aug. 25 Goea ex about Doc 51h. Oivd ppmmnt dates Fast of Jan ,Apr, JUL, lid. 0 detemr:lak value. Rafe a0oqw, corn e0.1n 129%. Rat on avg. I re a 8 fa s10.11 p R. Ckm; &+low Avg. (E) d7 Clock'sompat>�s FTneaelal SlmoOth 100 Pdco Growth Persistence D ++Al EPS Boric Exd discord opeml'82, toss i40; oxbaord gains (bsses): '82, (1' 85, SG; 88, (2ap)'B7, (22{); 97,17¢; BB,15106). Next age rapt due leis Od. (B) Next do d mlg pN'd reinvest pion aver (C) Ind. regufabry assak. In W. 58.771sb. (D) Rate base d kind. Earnings PmdSctablgly 10TO e 1999, Vakrc lam tLbishim, kc N r�'gMs shaved. Fodml r&elial Is msained ham mom be"O to be Whitt and k Pe'ted VA' wacbt k*.nagas tanfts ottryry THE P96USIIra D NOT aESPONSmL£ 70R ANY ERRORS on OfA15570aS 9ERE W. Tea P�fcma� �s�id�'!a rsC�0.,r a a Flan &-Ong r � � • : 1 { l 1 1 + , d k auy to tspmdumd. edrea a 0amrdJed b 50 prines'boosdc a one foma m used im gm nag y p • *Exhibit No. VER-3 Schedule 9 Page 15 of 16 RS9 NEW MEXICONYs>:•PNM PRICE RECEI,T 2� PiE RATID O kel6ng: 881 RELATIVE U tdedian:100 f PiERAT10 0.60 OIVD Y1D 0 ' 4,4 0 ' F0 tc 224 /5 9 15.5 11.6 14 1 13.9 13.6 183 20.5 23.7 11.0 12.1 17.3 15.8 24 8 17A 21 tt 14.8 Target Price Ranga 2002 2003 2004 TB11ElINESS .� Ra cd1121l11 Low. 7.0 tO.B 8.0 7.8 9A 9A 60 SAFETY 3 Lmved2f191B9 LEGENDS „ sb -� 15fis ObmyhaidsRM .55i1 40 32 TECHNICAL 4 tossed 911193 tere t tT Ptkc su�a gpll BETA 30 0M • Maw) He SMdeo °ma i aaa� rnzssbn - - ` 24 8 2002-04 PROJECT-10 7 ,ill .... 11t Total Pelee Gain Return n I r,lur' Rlgfi 25 (+25% 10y: { t, , r rt117,41 12 1D 6 ,a Low 18 -20%� Nit , 'i I, 6 Insider Do laid a S O N O J P M A Y , baby a 0 0 0 0 a a 0 0 orm a t D 0 0 0 a 0 a 0 - %TOT. RETURN 7199 4 _ 3 bfsa 1 0 0 00 0 0 00 v`imr� it " Institutional Decisions sT�t 1 yr -3.4 15A 1011111 401131 101111 Pdmsnt 24.0 Syr 125 T35 is 3Do 754 41 59 shares 16.0 MC a 34119 31805 35483 traded 6A 1993 Syr. Bti.B 128.5 1996 1997 1998 1999 2000 �YALUELiNEPUB WC. 02 -04 1994 1995 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 2718 2615 2155 2795 Revenuespersh JILM 1171 1233 19.T3 1690 16.53 20.15 2191 2334AS 20.47 2052 2D.40 20.92 21.66 19.35 35T 2115 301 396 4.57 4.20 410 "Cash Flove Par A too 378 488 S.t1 4.53 415 3.65 2.46 265 3.14 351 75 121 383 1W 137 i36 2IT 2151 per sh A 2� �il1"Od'dper 12 270 3.11 330 32B 200 1.97 1T3 3Z 32 haw 1.ings 2.81 285 289 292 2.92 1.57 .3B 181 241 255 3813 2 3A7 3A8 1 3IQ Cap Spendingper 2 616 5.5 22 7 1Tt 1 13.29 16.11 15A3 1B.06 20.s 2521 Z529 25.73 2651 25.68 18.01 10.02 17.38 17.69 15.00 err26 10.80 40.80 CoommonSh5Ouisfg IAA 9.8 7.4 B.i 10 152 7.9 7A J4.1 29.1 16.5 9.5 .5 10.6 11.0 10.0 aw R9 mwe Avg m" Md- Vet Relative P1E ROOD .9 83 .69 .66 it 1.02 .66 .59 2 58 186 100 56 49 71 .69 19% a 3.3% .52 3.5% esaaams Ave AnWI Died Ylald 15% 102% 124% 10.6% 8.696 9.6% 12A% 28% 055.1 1572 852D 0739 904 7 808 i 883.4 1t35.3 10924 1125 1 f10 Revenues (;rsBlj 1260 9i6 915.3 CAPITAL STRUCTURE as of 3/31M Total Debt 51008.E m3 Duo in 5 Yrs NO 02.E 23.4 23.0 38.6 57.6 75.7 60.9 72.6 79.3 105.2 83.0 820 Net Profit MO InwmeTaxAak JSOX LTDebt51008.6mN. LTlydoros15713mN 239% 142% 375% 3D.4% 30.9% 36.9% 456% 351% 371% 349% 35.OX 1.0X 35OX f.OX AFUDCy.toNelProQl LOX (LT interest earned:4.1x) 5.8% 14.8% 127% 32% .7% .4% 515% 5Q.5% 482% 46.6% % 532% s25X 51SK Long•7ermDabtRatio 485% Pension Liability Norm 482% 45.3% 480% 44.8% 48.8% 45.9% 561% 38.6% 60.0% 34.8% 432% 48.7% 509% 52.5% 45.4% 47.OX 48.0% Common 11 uli Ratio 5l.5X B i Pad DI 'd S 6 mil /662b 16200 16111 1612A 15864 14605 14445 1481D 15311 1896.4 1905 1950 Total Capital (SmOi) 18 Pro Stock S 12. m v 12B,DD0 she 4 58%. 6100 par w10 mandakry 19319 1914,6 1905.3 1877.1 1703.9 1696.7 l574.A 15527 6.fi% 15732 1593.8 1650 f 705 Nel Plant {m G7% 69% GOX 6OX Relumon7ala1Cap7 redemption. Sinking fund began 211184 7.1% 3.3% 33% 43% 59% lA% 51% 9.6% 28% 28% 5.4% 5.9% 17A 8.5% 9 6% 97% 118% 10% 8.5% Return rm She Equity 95X 8.5y. Realm on core E Wl a Common Stock 40,774,083 shs. as of $11199 9.6% 1.9% 1.6% 49% 9.2% 11.0% 7.9% 9.5% 1fA% 7 9% 7.6% 9.8% 121% 9,0X 4.57. 6,5% 6.4% 55X SOX Retained to Com E9 4.5X MARKET CAP: S625 million (small Cap 7.4% 19% 1.8% 49% 92% 32% 41% 42% 20% 11% 8% B% 21% 34% 31% 40X NX AtIDi+'dstoNatProf 49X ELECTRIC OPEItATiNGSTATISTICS 1996 1997 199B +3.1 BUSINESS: Public Service Company of New Mexico sa0s elecbici- nuclear, 31%; garJ0lt 1%. Fuel costs: 41% of rays ; labor costs 'BB dopmc. ate: 3.3%. Eid d plant age: 12 years Has 2.717 q 0 8 +4,7 pxq. idniBih sitB{ 4016 4287 4330 5.60 5.60 5.64 ) y { wlm (3%) k nodh cenbal New 1Y (76% o! revenues), es 21%), Mexico (popul. 1,30D,OW) Largest customer: Coy of Atbtrquarque 16%. employ eas, 16,390 Stoddroldea Cheiman.,President8 Chief Ea- Inc: Now Maxim. Address: try.hLstRm.Ps j!) Crptdfdlt8 �520t78 1209 j91�3 PukI.W. Jas�o a} Acquired Southern Unions nalunil gas stilly assets, '85. Elect ran breakdown: resid, 30%; comer, 43%; indusL 23%; olber, 4% ecuthe Offiw. Benjamin F. Montoya. 414 Silver Averse, S.W., Albrpuarquk New Mexico 87103. Tele www.pnm.mm• Marilmdrada(% 64D 70.0 667 +2.5 The military estabkhnxmis are major customers. Fuels: coal, 68%; phone: 505.24t-2477.1n1emeL• %ChallpCrsiarm�r+r� +2T +21 Public Service of New Mexico awaits men equity ratio and boost the fixed Moreover, the plowback Findoopcei296 280 290 an electric rate order. Earlier this year, the Supreme Court overtutZTed the charge coverage. of a large percentage of profits to equity is But ANNUAL RATES Past Past Est'd'96•'9B olrtatspomwd4 tOYrs. SYn. to'02-'04 Revenues 3.5% 4A% 35% state $91 million rate reduction mandated by raising the retained earnings account will be low for a while. For 'Cash Flow' •1 A% 6.0% 3.0% Eamings -2A% 2DA 2.5% the old commission and remanded the case the successor commission for further earned returns now, the company merits a below -average Dividends .135% NMF Book Value 2.0% 4.5% 5.5% to proceedings Since that time, PNM has p gs negotiated an agreement with interested Parties for a reduction of $34 million.. Once the cut takes effect, rates would be Frozen until the start of retail competition in New Mexico• beginning in January 200]- Man- Financial Strength rating Of B+. Earnings may decline this year: Post- tives include the elimination of 1998's urt- gs profitable gas trading operations, savcontrols at from the upgrading of emission controls at the San Juan mat -tired station, and a here caM enal- OUARTERLYREYENOESIimOW MQUA QUARTERLY YR Se ES JODI)Dec Foe Year 7896 1997 2419 197.E 21D.8 233.1 29B.8 197.6 210.8 3118 883A t136.3 1993 282.6 23ali 320.4 25B 9 261A 320 270.8 1092.4 1125 agement estimates that the new rates ly 3% increase in energy sales. But these be more than offset by higher 1999 2000 2728 260 259 3" 280 1140 would result in lower revenues of $15 mil- lion In the last two quarters of 1999 and a $22 million reduction in 2000. Because of a pluses will depreciation expense, costs to improve the d a computer system for the year 2000, and Overall, �p EARNINGSPERSt1ARE� INGS Full enaar Mac31 J Sap,30 Dec91 Year dispute with Bernalillo County over, cer- tain of the settlement, a final expected rate reduction. tfmate an 1196 decline in 1999 earnings to 199E 63 32 .47 30 17r 1996 69 33 58 3B 82 44 1.72 226 provisions order on the case may be delayed a few $2.00 a share and fiat results next Year. is an average electric utility 1998 1999 fA 39 .66 .39 .66 .35 200 months to the third quarter of 1999_ improving. In the The stoC]t selection. The year -ahead yield is more 20DO .61 .37 .70 .35 200 Finances are slowly absence of any major building pprogram, through 2003 will than half of a percentage point below the Industry norm But if the regulators ap But Cat. DUARTERLYDNIDFIDSPAID Full ender Mar 1 Jun.30 So 30 Dec31 Year construction outlays average only $120 million yearly. internal- these Px- prove t7te rate which we con- eider likely, the directors would then be 198E 1998 --12 12 12 ••12 36 lY generated funds should exceed and dividend needs by a wide t a position to increase the payout at a rate 1997 1997 17 17 17 17 20 20 20 63 77 penditures merggttn. TT1at will provide cash for debt re• duction, which, in turn, will lift the corn• above the group average. August Z0, 1999 ArthurH 1ldedalle 1995 20 20 (A) EPS base Neil ens repI due into Od '98, 11�. (B) Naxf d va mlg dale eboW Sept 53,621sfi. (Oi In m en. (E1 Ralo base: na1 coin. Comps s PinlabillriciaStrength B�+ '88. Od 28. Div d cost Rek aOovn d in on rekil once ops ; Sloe dce Sksist36 excl aonrettN. gains (losses): '83, 74QQ• 28, Noxt ax dak about pmrd (5481) '90, {SSf); 92. (5342); 93, (6285; dates mid Feb., Mey Aug.. Nov,aDivd�oin 1252X; earned an 98 'B5, '97. 4p; To. flat (2401; vast pall avaR {C) Ind Intang in '98: Regul GMn: Avg avg. system 112X Eeml BsPredctabl11 65 1d4. 11{; rat 350; e 19n. vAm time nrbi-J a'sq, inn At rkpdtixs rrscvd. Famnr matali is Wained ban swan beloved to be sdeUe and is palled x3lrord A irsmus d atry find. r I t • ; I i 1 1 + . ANY ERRORS OR 9ASS10NS HEREar.11is P"baceon is'User la wbsvil+a'a men. nonsamsncal pamul use• Ao pan THE PUBLISHER 6 NOT RESPONSIBLE w e say be npodWxd, swred a bansmaed in en1 Jaime, tkdlan c a alxtl ram a ladd k gtselm g a Ia xetixJ my paled a ex<aais p u adm stmwics a potlud Whibit No.. VER-3 Schedule 9 Page 16 of 16 UNITED ILLUMa NvsE-ua PRICE 5� TrAng:119 R l(0 - J t �Treiiann: i� RBATNE PIE RATIO 0.QC 11 V V DIV'D C Q©%O Di 5.8 I ' TIMELINESS 4 Rd6ed50D9 9 1 24 8 28 9 30.0 341 3B5 28A 29 4 31 1 239 419 38.9Low 20Q2t 2003 2 0�4 SAFETY 2 RhW9R099 L£GENO9 .. -- 0361 oadmds a sn 10 0 0 TECHNICAL .S Loxc d7D099 d'nided by kft sl Rafe .... Rdsbve bysump 04 - •• - - - - •• OETA 50 040 - Mmkd) Onsets: Na hdgks 48 40 02-M PROJECTS NS cdmra mrtttonn ' ' ,' Anal Total Price win Return , nty--s , .•"n•^ „ "n,, s .. 1 32 24 high 55 (+10% BAG Lon 49 -20X 1% p dl-=... 20 t6 '- Insider Decisions 1 O N D J F M A M J b Bur 0a0010110 0 Naa 0 0 0 0 0 000 0 %TOT. Rr URN 8199 in a.0000000 lips xAMIL - e Insulutional Decisions seta emEx S01M1 401Ai Icin Percent 6.0 b aer 45 51 40 shares 4 0 _ 30 1 yr 02 33.3 3 yr 80.1 60.3 Syr. 118J1 f00A b 1.9 34 33 traded 2.0 kld's li4691 4063 4690 INC. 02 1983 1984 1985 1986 1987 1968 1989 1990 1991 199 11993 1994 1995 11111 199649 1997 1998 1499 20D0 dYAL41E 34.66 3794 3753 33.93 35.83 3737 3826 4275 46.33 4755 46,37 46.62 4897 51.49 POrsh 9.45 51A7 4onBB9 4M $too "Cash Five 945 B.99 BBO "Cashper 6.42 6.67 8.15 BA3 9.78 10.68 5.67 5.40 5.82 597 5.99 754 10.25 7.02 798 816 6.11 794 8.19 8Ai 3.00 3.65 531 3-55 322 3AT 313 319 3.64 3.16 32T 3� rSh A LBO Earningssrdper A 3.70 288 Div d Ded d per sh e o 2Bt 3.08 230 20B 232 232 222 1 1114 6 Zia 2.32 732 244 256 266 2,76 2.82 28a 6" 288 288 5.55 451 433 473 6.73 4 421 335 240 271 1 = t15 UP, Spwdingper t. 75 67 13.05 31.48 3180 37.15 40.50 44.02 34.11 26.11 21Z 211.84 30.12 30.06 30.39 3120 31.20 31S 31.74 31.95 3250 BookYaiueperIh a MIS 14.1 14,10 13.91 14A3 14 14.40 C0=710 1st9 14.0 9 3 73. 13.8 13.69 5.3 4,5 3A 13,89 1389 13.83 74.03 14.08 1 . 5.3 B.3 10.6 its 13.6 103 93 11A t0. 163 � Avg pnn1FIE Ratio fib 4.8 29 3A .39 17 28 36 .30 25 .40 .62 .60 .72 M .8 -62 it 82% 8.3% 8.0% .56 .86 Relative PIE Rage .85 8.8% 51% °Sdna1G Avg ARA I Dlv d Yield 6.1% 11.7% 14.6% 10.6% 7A% 85% 10.2% CAPITAL STRUCTURE as of6130199 82% 7.9% 72% 6.6% 62% 5312 5937 673A 6573 M.0 b568 690,4 7260 710.3 6862 710 730 Revenues(IMM) Ito 57.0 Total Debt $573.7m10. DueinbYm.3374.6mB LT Debt $518.2 mill. IT Internal $41.5 mill. B29 64.1 49A 48.6 53.6 482 50.4 43.1 AN 47-2 55.0 50.0 Net Profit Smi 31A% 445% 42.7% 50.1% 382% 4F3% 54.3% 552% 47.4% 56.0% 47.0% 410% Income lax Rate 47.1% MdinvectmenlMSeabrook obigalbnbml&. 789% G.4% 105% 6.7% 75% 72% 5.5% 53% 3.5% 1.1% $0% 3.0% AFUOC%toNelPre6l 3.0% Ind 516.9 mg. capitaRuad lease& (LT Merest earned: 3.6x) 693% 69.0% 68.4% 65.5% 64 9% 60.5% 62BY b0.6% 57 3% 577% 48 5% 48.0% Long Term Dobl Ra90 30.7% 35.7% 32 7% 35.1% 38.0% 37.7% 46.5% 47.0% Common E u RsUc 19. Leases, Uncopltalizad: Ann. rentals 663 mitt Pension UablRlyNow 25.7% 262% 27.3% 302% 140B3 VA79 1470.0 1401.0 1379.4 11989 13462 12542 1154.8 11602 985 995 law Cepitol(1-01 f030 730 Pfd Securitbe 550.0 mitt Pfd Div d S4.8 ors 14021 1337.3 1340.1 1336.0 1361.1 1357.3 1345.7 13M 1273.6 1226A 970 9" Netp ant IM 6.4% 6.6% 6.5% 71% 6.1% 6.1% 6.7% 5.4% 76% 7.5% RalumOnTotdcaje 7.5)G Company-0bigatadmandalaRyredeemabb 91% 7.0% 192% 12.0% to.6% 10.0% 111% 101% 10.1% 8.7% 93% BA% 11.0% 11.0% Return OR Shc Equity 10.0% securities; of aubsidInge Common Stock 14,334,922 star. 202% 119% 11.1% 10M 11.6% 10.4% 11.0% 97% 10.4% 9.4% 11.5% 11.0'i. Return an Core E ui o 10- 4% 25% ZS% RetahledloComEq 25% MARKETCAP:6725mi18on1SmaRCap) 11,3% Ts% 2B% 1.4% 2.0% 3% 12% 50% 69% 77% 82% 77% 88% 02% 95% 89% 96% 78% 80% All DWds to Not Prat 79% ELECTRIC OPERATING STATISTICS 1988 19.7 t996 +7 +1.4 BUSINESS: The United Ilkrminating Company provides cledddly cogener), 10% Fuel costs 29% of revenues; tabor costs, 11% T1B Estimated age: 9 years. Has 1.103 am • %CdanlrRdalSrls(�l� Aq.hydusepM7t1 691 69D 659 1.85 to 312,000 customers In W urban and suburban southern Con, deproc. rate: 3.3% plant �b ers Chairman. C.E.Q. 5 President m resideallal• 42%; commercial, ployaes, 14135 stockhold Revenue d dnbuU40%; Avl.hd nfhraea ) 9.55 1.79 D Gpaohslprakjltr) 1522 1462 1446 1173 1143 necilcul indusldal, 16%; other, 2% Largest Industrial customers: primary Nathaniel D. woodson. Inc: Connecticut. Address 157 Church Sheol, P.O. Box 1564, New Haven, Connecticut Tat: Pratlmd,5n of 1045 N.udls,lFx3o 61A 54.6 572 metaIn taixieated metal produce, transportation equipment. 1990 fuels: oR 46%; anal, 21%; nuclear, 23%; other (gas, hydro, 8 203-0992394.In1emotwww.uMetcom %Chas�Csstm»�jrarrl +3 +•6 r.5 The regulators have granted United next live years (largely for the upkeep of F'sed Cdr.(% 241 218 296 ANNUAL RATES Pant Past Est'd5s 98 ANNUALT Illuminating full recovery of its decision allotted the transmission system), cash flow from operations will exceed capital expenditures fPast Bare t'dW bjpar Revenues 35% t.5% 2 0% Revenues stranded costs. The $559 million for the utility's interest in the and dividend requirements by a wide mar - we have Flour" .1.0% 15% 1.5% 3. Seabrook 7 and the Millstone 3 nuclear by gin. In light of these plusses, the company's Financial Strength DfvrnEdands LID% 23% plants. The figure had been reduced raised $16 million to offset UILs gain on the sale rating a notch to B++ and the stock's Book value -20% 1.0% ZO% of its fossil -fueled generation to Wisconsin Safety rank to 2 (Above Average). Cal. WARTERLYAEYENUES)SmBy pug Energy. The commission also ordered $126 Earnings are on an upward ath Fa- aadar MUM Jun.30 Se .30 Dec31 Year 1996 170.9 168.8 209.2 7711 Tear million recovery of above -market pur- vocable weather conditions to date point to higher energy sales for the full year. Too. 1996 170.9 160.8 196.E 169.E 710,9 used power contracts. (Enron has agreed to buy these contracts at market price and redemptions of long-term debt will reduce 19BI 1675 159.0 195.6 165.3 BB62 1999 168.7 164.5 295 171.8 719 to sell the power to UIL). Finally, the com- interest expense. In addition, last year's prop". $150 million in $0.30-a-share charge for a property tax 2000 170 170 215 175 7" Cal. EARNINGS PER SHARE Full parry will recoup generation -related regulatory assets.. The settlement will be absent this year. total of $835 million, which will be over, noncore subsidiary losses will be less Mar.31 JOn.30 Sop.30 Doc.31 Year award recovered through a nonbypassable trans- than they were in 1998. Thus. despite a 1998 82 85 127 22 316 1957 54 61 t.60 .44 3.27 IN mission charge, eliminates the need for The commission will 596 rate reduction. we estimate a 22% rise In current -year earnings to $3.65 a sham 1998 64 39 10 3.00 1999 70 99 1,48 48 3.65 1.7SPA�.5 165 2000 1.T8 asset write-offs.. determine the timing of the recovery. Finances continue to strengthen. Cash Next year's results will depend largely on the Length of time required to recover .75 .65 .50 Cal QUARTERLY DIVIDENDS Full proceeds from the sale of fossil -fueled gen- stranded costs. The stock is untimely. erating plants earlier this year were ap- The yield is a full percentage point coder Mac31 Jun.30 So .30 Dec,3 Year 705 2.02 plied to a $205 million reduction in long- above rice industry norm But we expel hike for a while because of the 1995 705 705 .705 1996 72 72 72 72 2.88 term debt That will bolster the already above -average fixed charge coverage, no dividend rate reduction. On balance, we rate UIL• 1997 72 72 72 72 286 1993 72 72 72 72 288 What's more, thanks to annual construe- an average electric utility holding. tion outlays of Only $20 million over the Arthur H. Medalle September 10, 1999 1999 72 72 72 !A) EPS basic Exd oroeaa. gains (krssos) Oct. 25. Goes ex about Dec 7. Oiv'd Vay'1 S26.471sh. (D) Role base: orig cost Rale a1 Companys Financial Strength Brr '91. 45(• •92 dalex Jan. t. April 1. Juy 1. Od 1 o gw•tl laved on common equity M'96: tt3% Earned Stock's (rice Stability 125 8B net, ($25I); TO, (S1122j; 590: ,M, (Wr, IN, 10t) 98, 28t, l4exl cgs. reinvest plan avail, On average common equity In •9B: 9.6% Price Growth Persistence 25 report due Isle Od (C) Ind. deferred chgs. 8 Ingot assets. In'BB: I Regul Clem: Avg (E) In mip = Earnings Pmdicialltly 70 1999. Vaba Line Pot. Inc Aa sr'ggHs roe%W- faaml m+rma a anamm emu senses uan•.uu ... �.-...,.++= o,- .. r•...,....._.__.;.'----- - - r s r r • . , r , . . THE PujjUSNER d N01 RE PONSIRLETOR ANY ERRORS OR OMIS90NS IIFREOL Ibis Pddicd'ox a seiGmr 1a suhssnbnrs awn, awntorrmaml,a0ml arc. w pea d e ney be reisedocK sevol a aamoiad In ag Piled. damaic 0 dha ism 0 Usd la 9o`s k9 a imlkeag any pined 0 eledu do pddicaiaa senate a podod Exhibit No. VER-3 Schedule 10 Page 1 of 9 City oryemon. California Indicated Common Equity Cost Rate Through Use of a Risk Premium Model Using an Adjusted Total Market Approach Proxy Group of Four Electric and Proxy Group of Five Combination Electric & Electric and Proxy Group of Four Gas Companies Relied Combination Electric & Electric and Upon by FERC in Gas Companies with Combination Electric & Opinion No. 446 Total 1998 Revenues Gas Companies with Line (Docket No ER97- Greater than S20 Total 1998 Revemres 2355 et. al.) Billion Less than S2.0 Billion i Prospective Yield on Asa Rated Corporate Bonds (1) 700 % 700 % 7 00 % 2 Adjustment to Reflect Yield Spread Between Asa Rated Corporate Bonds and A Rated Public o ity Bonds 0.65 (2) 0.55 (2) 0.55 (2) 3 Adjusted Prospective Yield on A Rated Public Utility Bonds 756 % 756 % 755 % 4 Adjustment to Reflect Bond Rating Difference (0.06) (3) (0.(16) (3) 0.19 (4) 5. Adjusted Prospective Bond Yield 749 749 774 6 Equity Risk Premium (6) 4A4 4.25 4.06 7 Risk Premium Derived Common Equity Cost Rate 11.63 % 11.74 % �1.80 % Range of Indicated Risk Premium Common Equity Cost Rate 11.6315 - 11.80% Midpoint of the Range 11.72% Notes. (1) Derived in Note (3) on page 6 orthls Schedule (2) The average yield spread of A rated public utility bonds over Ass rated corporate bonds of 0 55%. from page 4 of this Schedule (3) One-third of Ore average yield spread of over A at As rated public utility bonds of 017% (1 l 3 x 0 % _ 0 056%, rounded to 0 060/6) from page 4 of this Schedule in order to reflect the average Al Moody's bond rating of the proxy group (4) Two-thirds of the average yield spread of Boo over A rated public utility bonds of 0 2615 (213 x 0 28% 0187%, rounded to 0.191a) from page 4 of this Schedule in order to reflect the average Beal Moodys bond rating of the proxy group. (5) One-third of the average yield spread of over A or As rated public utility bonds of 0.17% (113 x 0 % _ 0.056%. rounded to 0 06%) from page 4 of this Schedule in order to reflect Edison intemalional s Al Moodys bond rating (6) From page 5 of this Schedule, • 0 Exhibit No. VER-3 Schedule 10 Page 2 of 9 Southwest Gas Corporation Comparison or Bond Ratings and Business Position for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No. ER97-2355, et. al.), the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2 0 Billion, the Proxy Group of Four Electric and Combination Electric & Gas Cmmpanies with Total 1998 Revenues Less than S2.0 Billion August 1999 August 1999 Moodys Standard & Poor's Standard & Poor's Bond Rating Bond Rating Business Position (2) Bond Numerical Bond Numerical E11bg Welghlino (11 Egjbg Weighting Ill Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC In Opinion No 445 (Docket No. ER97-2355, eL al.) Constellation Energy Group, Inc (3) A2 60 AA- 4.0 40 Duke Energy Corp. (4) A83 4.0 AA- 4.0 50 PG&E Corp. (5) Al 50 AA- 4.0 50 The Southern Company (6) Al 5.0 AA- 4.0 4.0 Average Average Al 5,0 AA- 4.0 4.5 Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion Aliianl Energy Corp (7) Al 50 AA- 4.0 35 Ameren Corp. (8) As2 I Aa3 35 AA 30 40 Consolidated Edison. Inc. (9) A2 60 A 60 40 Constellation Energy Group. Inc (3) A2 60 AA- 40 40 The Southern Company (6) Al 5.0 AA- 4.0 4.0 Average Al 5.1 AA- 4.2 3.9 Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than S2.0 Billion Central Hudson Gas & Electric Corp. A2 60 A 60 so DOE. Inc. (10) A3 70 BBB+ so 60 Public Service Company of New Mexico Baa3 100 BBB- 100 70 United Illuminating Company Baa3 10.0 BBB+ 8.0 5.0 Average Average Baal 8.3 BBB* 8.0 5.8 Notes: (1) From page 3 or this Exhibit (2) From Standard & Poor s Utilities Perspectives. Global Utilities Ratings Service. Vol 6. No. 36. September 6. (3) Ratings and business position are those of Baltimore Gas & Electric Company (4) Ratings and business position are those of Duke Energy (5) Ratings and business position are those of Pacific Gas & Electric Co. (6) Ratings and business position are a composite of those of Alabama Power Co. Georgia Power Co . Gulf Power Co. Mississippi Power Co. and Savannah Electric & Power Co. (7) Ratings and business position are a composite of those of Ailiant Energy. IES Utilities Inc. and Wisconsin Power & Light Co (8) Ratings and business position are a composite of those of Ameren CIPS and Ameren UE (9) Ratings and business position are a composite of those or Consolidated Edision of New York and Orange & Rockland Utilities (10) Ratings and business position are those or Duquesne tight Co. Source of Information: Moodys Investors Service Standard & Pow's Global Utility Rating Service 0 0 Exhibit No. VER-3 Schedule 10 Page 3 of 9 City of Vernon, California Numerical Assignment for Moody's and Standard & Poor's Bond Ratings Moody's Numerical Standard & Poor's Bond Ratina Bond Weighting Bond Ratina Aaa I AAA Aa1 2 AA+ Aa2 3 AA Aa3 4 AA - All 5 A+ A2 6 A A3 7 A- Baal 8 BBB+ Baal 9 BBB Baa3 10 BBB- Ba1 11 BB+ Bat 12 BB Ba3 13 BB- a > o a m O O O 1- O (O In ao N N N N N N N� jm N 0 0 0 0 O O O .? .Q 7 CL m Q o WE v d ��01.- 0) O 00(OO CL Q o00000 0 riEL o a OR v o U � m m O) ao OR co i- 11 m (a O n 0- D (0 Lio Umuc0iQ(nU.)(n U7 ma o 0000cao d �Q w m (Ga 0) o` U G EM E ' ` • O .+ w >> O o e t IRt o v (� it = Q� � 000doo 0 yl Yii O .O o c a W uO 'D 1A N e G C 2 R to pl:In r�RCR o ((� ((7 1� - NCL N N I- r- t` CO i- M E 90 ID m m � d U 5 `a w v 0: NN-Tr- ) _ Q hhrt`t`t+� OE � U a v QT T� d .�-m(DNONp titi!`I•:tit` CO QO N m N d N m N o � OG� O �(IRG Ntn� (D 3 O Um Q (fl(d 2 Cr Q Ui o 0) C) W O O D •C1 ••+ •.+ E O) O O) 0) O O'1 CL •d.. C N w < im Z o 3 a 0 Exhibit No. VER-3 Schedule 10 Page 4 of 9 0 9 Line No. 1. 2 3. Exhibit No. VER-3 Schedule 10 Page 5 of 9 City of Vernon. California Judgment of Equity Risk Premium for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No ER97-2355, eL ai ), the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2 0 Billion. the Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Proxy Group of Four Electric and Combination Electric & Proxy Group of Five Gas Companies Relied Electric and Proxy Group of Four Upon by FERC in Combination Electric & Electric and Combination Opinion No. 445 Gas Companies with Electric & Gas Companies (Docket No. ER97- Total 1998 Revenues with Total 1998 Revenues 2355, et. al.) Greater than $2.0 Billion Less than $2.0 Billion Calculated equity risk premium based on the total market using the beta approach (1) Mean equity risk premium based on a study using the holding period returns of public utilities with: a A rated bonds (2) b. Bea rated bonds (2) Average equity risk premium Notes: (1) From page 6 of this Schedule. (2) From page 8 of this Schedule. 3.53 % 4.74 4.144 % 3 76 % 4.74 �4.25 % 391 % 4.20 4.06 % 0 n Line No. 1. 4 3. Exhibit No VER-3 Schedule 10 Page 6 of 9 Cily of Vernon. California Derivation of Equity Risk Premium Based on the Total Market Approach Using the Beta for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC In Opinion No. 445 (Docket No. ER97-2355, at at.). the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2 0 Billion. the Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Proxy Group of Four Electric and Combination Proxy Group of Five Proxy Group of Four Electric & Gas Electric and Combination Electric and Combination Companies Relied Upon Electric & Gas Electric & Gas by FERC in Opinion No. Companies with Total Companies with Total 445 (Docket No ER97- 1998 Revenues Greater 1998 Revenues Less 2355, et, at.) than $2.0 Billion than $2.0 Billion Arithmetic mean total return rate on the Standard & Poor's 500 Composite Index - 1926-1998 (1) Arithmetic mean total return rate on the Salomon Brothers Long -Term High -Grade Corporate Bond Index 1926-1998 (1) Historical Equity Risk Premium 4. Forecasted 3-5 year Total Annual Market Return (2) 5. Prospective Yield an Aaa Rated Corporate Bonds (3) S. Forecasted Equity Risk Premium 13.20 % (6.10) 7.10 % 15.23 % (7.00): 8.23 % 13 20 % (6.10) 7.10 % 15.23 % (7.00) 8.23 % 13.20 % (6.10) 7.10 % 15 23 % (7.00) 8.23 % 7. Average of Historical and Forecasted Equity Risk Premium (4) 767 % 7.67 % 7 67 % a. Adjusted Value Line Beta (5) 0.46 0.49 0.51 9. Beta Adjusted Equity Risk Premium 3.53 % 3.76 % 3.91 % Notes: (1) From Stocks, Bonds, Bills and Inflation - 1999 Yearbook - Market Results for 1926-1998, lbbotson Associates, Inc, Chicago, IL, 1999. Income return rate not available on Salomon Brothers Long Term High Grade Corporate Bond Index. (2) From Note 1, page 4 of Schedule 12 of this Exhibit. (3) Average forecast based upon six quarterly estimates of Aaa rated corporate bonds per the consensus of nearly 50 economists reported in Blue Chip Financial Forecasts dated September 1, 1999 (see page 7 of this Schedule) The estimates are detailed below Third Quarter 1999 7.20 % Fourth Quarter 1999 7-10 First Quarter 2000 7.00 Second Quarter 2000 7.00 Third Quarter 20D0 6.80 Fourth Quarter 20M 6.90 Average 7.00 % (4) Average of the Historical Equity Risk Premium of 7.10% from Line No. 3 and the Forecasted Equity Risk Premium of 8.231A from Line No. 6 ((7.10% + 8 23%)12 = 7.665%, rounded to 7.67%. (5) From page 9 of this Schedule Exhibit No. VER-3 _ .... Schedule-10- Page 7 of 9 2 M BLUE CHIP FINANCIAL FORECASTS 1v SEYMMBER 1, 1999 Consensus Forecasts Of U.S. Interest Rates And Key Assumptions' Interest Rates Federal Funds Rate Prime Rate LIBOR, 3-mo. Commercial Paper, 1-mo. Treasury bill, 3-mo. Treasury bill, 6-mo. Treasury bill,1 yr. Treasury note, 2 yr. Treasury note, 5 yr. Treasury note, 10 yr. Treasury bond, 30 yr: Corporate Aaa bond Corporate Ban bond State & Local bonds Home mortgage rate Key Assumptions Major Currency Index Real GDP GDP Chained Price Index Consumer Price Index ---History--- --Avg. For Week Ending --- ---------Month---- Latest Q Aue20 A_ug.13 Aue.6 bUQ July June May 2201999 5.03 499 5.06 5.01 4.99 4.76 4.74 4.75 8.00 8..00 800 8.00 800 7.75 7.75 7.75 5.49 5.47 5 A2 535 5.31 5.16 5.00 5.06 5.20 5,17 5.13 5 D9 5.08 4,96 4.80 4.85 4.81 4.87 4.80 471 469 4.72 4.63 4.59 5.10 5.11 4.99 4,79 4.75 5.03 4.75 4,77 5.20 5.23 5.13 5.07 5.03 5.10 4.85 488 5.68 5.77 364 5.59 5.55 5.62 525 528 5.91 5.97 586 5.75 5.68 5.81 5.44 5.44 5.91 608 5.95 5.86 5.79 5.90 5.54 554 6.03 619 6,12 6 05' 5.98 604 5.81 5.88 7.37 7.53 738 7,29 7.19 723 6.93 6.93 8.14 8.27 8.13 8.04 7.95 8.02 7.72 774 5.65 557 5.49 541 5.36 5.37 5.18 52I 7.93 8.15 789 7.70 763 7.55 7.15 7.21 --- --------------- -History- --- ��._. 3Q 4Q 1Q 2Q 3Q 4Q IQ 2Q 1997 1997 1i98 12L8 1998 1998 1999 1999 915 93.6 95.9 97.3 99.1 93.7 93.0 96.0 4.2 3.0 5.5 1.8 3.7 6.0 4.3 1.8 12 1.1 0.9 0.9 1.0 0.8 1.6 1.5 1.8 2.0 1.0 1.7 1.7 1.7 1.5 3.4 Consensus Forecasts - Quarterly Avg 3Q 4Q IQ 2Q 3Q 4Q 1999 1999 2000 20DO 2000 20 0 5.1 5.3 5.2 5.2 5.2 5.2 8.1 83 8.2 8.2 8.2 8.2 SA 5.5 5.5 5A 5.4 5.5 5.2 5.3 53 53 5.3 5.3 4.8 49 49 49 4.9 4.9 5.0 5.0 5.1 5.0 5.0 5.0 5.1 5.2 5.2 5.2 5.2 5.2 5.6 5.6 5.6 5.5 5.5 5.5 5.8 5.7 5.7 5.6 5.6 5.6 5.9 5.8 5.8 5.8 5.8 5.8 6.0 6.0 5.9 5.9 5.9 5.9 7w 7.1 7.0 7.0 6.8 69 8.0 7.9 7.8 7.8 7.7 7.7 5.5 5.5 5.4 5.4 53 5.3 7.7 7.5 7A 7.4 7.3 7.3 Consensus Forecasts - Quarterly Avg. 3Q 4Q IQ 2Q 3Q 4Q 1999 1999 2000 2000 2000 2000 95.8 95.3 94.5 94.0 93.3 92.8 3.4 3.5 1.7 2.6 17 2.9 1.6 L6 1.7 1.7 1.7 1.9 2.3 2.3 2.2 2.2 2.3 2.3 'Individual panel members' forecasts are on pages 4 through 9 Historical data for interest rates except LIBOR is from Federal Reserve Release (FRSR) H 15 LIBOR quotes avail- - able from 7be Wall Street Journal and Telerate Definitions reported here are same as those in FRSR H.15. All Treasury yields arc reported on a constant maturity basis. Historica data for the U S Federal Reserve Board's Major Currency Index is from FRSR H 10 and G.5 Historical dam for Real GDP and GDP Chained Price Index are from the Bureau of -• Economic Analysis (BEA) Consumer Price Index (CPI) history is from the Department of Lubor's Bureau of Labor Statistics (BLS). 7.0D 6.75 650 625 6 00 R 575 ui 660 525 5.00 4.75 450 U.S. Treasury Yield Curve Week ended August 2D,1999 and Year Ago vs 30 1909 and 40 2000 Consensus 1016 COsts --Year Ago -X- Week ended 620199 -0^-Consensus 40 2000 -1 Consensus 30 1999 675 650 6.25 6.OD 5.75 560 525 Soo 475 450 425 400 3mo 6mo tyr 2yr Syr t0yr 30yr Maturities Corporate Bond Spreads As of week ended August 20.1999 U.S. 3-Mo. T-Sills & 30-Yr. T-Bonds (Ounnerly Average) Blue CMp Hslny Forecasts 8.50 B_00FBondYlaW Conaoneus 7.60 \ 7.im \ 650b00fi6DO4SO 400Consensus35D3•Monthireasury 300Bia Yield 2 60 10 10 10 10 10 10 i0 10 10 1092 1993 100 1995 1996 1997 Mill 1999 2000 U.S. Treasury Yield Curve As of week ended August 20. 1999 30D 3DO 400 275 Bas Corporate Band Yield 276 250 375 250 minus 10 YearT•Bond Yield 225 I 22S 200 Le \ 200 50 250 175 175 225 150 150 200 d _ 125 725 175 160 g a1 100 100 125 75 75 100 50 Aaa Corporale Bond Yield 50 76 25 minus 10-Year T-Bond Yield 25 2255 0 0 0 1994 1995 1996 1997 1998 1999 1994 1995 1996 1997 1998 1999 8 50 8 OD 7 5D 700 6 5D 6 00 5 SD 5.00 450 4.00 350 300 250 400 375 350 Is 300 275 250 225 200 175 150 125 100 75 50 25 0 Exhibit No VER-3 Schedule 10 Page 8 of 9 City of Vernon. California Derivation of Mean Equity Risk Premium Based on a Study Using Holding Period Returns of Public Utilities Over A Rated Over Baa Rated Public Utility Bonds Public Utility Bonds AUS Consultants - AUS Consultants - Line Utility Services Utility Services No Study (1) Study (1) 1 1 Time Period 1928-1998 1928-1998 1. Arithmetic Mean Holding Period Returns (2): Standard & Poor's Public Utility Index 11 29 °% 11 29 °% 2. Salomon Brothers Long -Term High -Grade Corporate Bond Index f6.091 6.09 3. Equity Risk Premium 5.20 520 4 a Adjustment to reflect yield spread between A rated public utility bonds and bonds used in the study M14M (3) b. Adjustment to reflect yield spread between'Baa rated public utility bonds and bonds used in the study fl.go (4) 5. Adjusted Equity Risk Premium 474 °% 4.20 % Notes: (1) S&P Public Utility Index and Long -Term Corporate Bonds (Salomon Brothers Long -Term High -Grade Corporate Bond Index year -by -year total returns 1928-1998 AUS Consultants - Utility Services, 1999 (2) Holding period returns are calculated based upon income received (dividends and interest) plus the relative change in the market value of a security over a one-year holding period (3) Spread calculated as the difference in the arithmetic mean yields on A rated public utility bonds of 6 56 % and Aaa and Aa rated corporate bonds of 6 10°% used as a proxy for the Salomon Brothers Long -Term High - Grade Corporate Bond Index for the years 1928-1998 inclusive, 0 46%. (4) Spread calculated as the difference in the arithmetic mean yields on Baa rated public utility bonds of 7.10°% and Aaa and Aa rated corporate bonds of 6.10°% used as a proxy for the Salomon Brothers Long -Term High - Grade Corporate Bond Index for the years 1928-1998 inclusive, 1.DO%. 0 0 Exhibit No. VER-3 Schedule 10 Page 9 of 9 City of Vernon, California Value Line Adjusted Betas for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No. ER97-2355, et al.), the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion, the Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Value Line Adjusted Beta Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No ER97- 2355, et al.) Constellation Energy Group, Inc. 0.50 Duke Energy Corp. 0.45 PG&E Corp 0.45 The Southern Company 0.45 Average 0.46 Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion Alliant Energy Corp. NMF Ameren Corp 0.50 Consolidated Edison, Inc. 0.50 Constellation Energy Group, Inc. 0.50 The Southern Company 0.45 Average 0.49 Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Central Hudson Gas & Electric Corp 0.50 DQE, Inc. 0.55 Public Service Company of New Mexico 0.50 The United illuminating Company 0.50 Average 0.51 Source of Information: Value Line Investment Survey, (Standard Edition) July 9, August 20, and September 10, 1999 Exhibit No. VER-3 Schedule 11 Page 2 of 6 Map ter 8 The regression is usually performed using monthly data for the most recent five years. The return on the S&P 500, which is a readily available series, is a good proxy for the return on the overall stock market. A good proxy for the riskess asset would be one whose horizon matches the frequency of the portfolio or security data. For example, when using monthly return data, the 30-day U.S. Treasury bill would be an appropriate proxy for the riskless asset. Some analysts adjust the calculated P, towards 1.00 because it is their belief that the betas of most stocks converge to 1.00 over time. Riskless Rate The CAPM implicitly assumes the presence of a single riskless asset, that is, an asset perceived by all investors as having no risk.. Common choices for the nominal riskless rate are the U.S. Treasury bill yield, the yield on intermediate U.S. Treasury bonds, or long-term U.S. Treasury bonds. These obligations are practically default -free because of the ability of the U.S. government to create money to fulfill its debt obligations under virtually any scenario. While interest rate changes cause government obligations to fluctuate in price, investors face essentially no default risk as to either coupon payment or return of principal. Table 8-1 gives 1998 year-end values of the long-term, intermediate -term, and short-term riskless rates. Expected Equity Rr'sk Premium Unlike the yield on a bond, the expected equity risk premium is unobservable in the market and must be estimated, typically by using historical data.t5 It can be calculated by subtracting the long-term average of the income return on the riskless asset from the long-term average stock market return (measured over the same period as for the riskless asset). The maturity (or duration) of the riskless asset from which rf is taken must be the same as that used to estimate ERP. When calculating the equity risk premium, some analysts subtract a long-term Treasury bond's total return —rather than its income return —from the total return on the overall stock market. The income return is the better measure of return to be subtracted from the stock market total return for two reasons: 1. It is the completely riskless portion of the issues' returns (Treasury securities are subject to price risk). 13 it should be noted that from a valuation specialist's point of view, the stock market returns presented in this book are after corporate taxes but before personal taxes, and should be applied to cash flows calculated on the same basis. 154 SBBI 1999 Yearbook *xhibit No. VER-3 Schedule 11 Page 3 of 6 Estimating the Cost of Capital or Discount Rate 2. Bond yields have risen historically, causing capital losses in fixed -income securities (including U.S. Treasury issues). These capital losses caused bonds' total returns to be lower than the returns that investors expected. In other words, had the investor held the bond to maturity, the investor would have realized the yield on the bond as the total return; but in a constant maturity portfolio such as those used to measure bond returns in this book, bonds are sold before maturity (at a capital loss if the market yield has risen since the time of purchase). There is no evidence that investors expect bond capital losses to be repeated in the future (otherwise bond prices would be adjusted accordingly), so that historical total returns are biased downward as indicators of future expectations. Historical income returns, in contrast, are unbiased estimators of the returns that investors expected. Since the market provides a clear measure of what investors in Treasury obligations expected —the bonds' yields or income returns —this information should be used to estimate the riskless rate for the purpose of calculating the expected equity risk premium. As with P. the expected equity risk premium is usually estimated using historical information. Implicit in using history to forecast the future is the assumption that investors' expectations conform to that which is actually realizable. This method assumes that the price of taking on risk changes only slowly, if at all, over time. The "future equals past" assumption is applicable to a random time -series variable. A time -series variable is random if its value in one period is independent of its value in other periods. This is important because empirical research suggests that the yearly difference between the stock market total return and the U.S. Treasury income return in any particular year is random. (The actual, observed difference between the return on the stock market and the riskless rate is known as the realized equity risk premium.) This means that the realized equity risk premium next year will nor be dependent on the realized risk premium from this or any previous year. For example, if this year's difference between the riskless rate and the return on the stock market is higher than last year's, that does not imply that next year's will be higher than this year's. It is as likely to be higher as it is lower.16 The best estimate of the expected value of a variable that has behaved randomly in the past is the average (or arithmetic mean) of its past values. The short -horizon, intermediate -horizon and long -horizon equity risk premia shown in Table 8-1 are computed over the period from 1926 to 1998 (using annual dara). The estimate of the expected risk 16 The serial correlation coefficient for dre total return on the ovenail stock market less long-term government bond income returns over the 73-year period 1926 to 1998 is nearly zero, based on yearly returns. (That is, there is no discernible pattern in the realized risk premium — implying that it is virtually impossible to forecast next years realized risk premium based on the premia in previous years.) This result is powerful evidence in favor of ueating the equity risk premium as a random variable. These results have been independently confirmed by a number of other academic srudies. Ibbotson Associates 155. Exhibit No.. VER-3 Schedule 11 Page 4 of 6 Chapter 8 premium depends on the length of the data series studied. A proper estimate of the expected risk premium requires a long data series, long enough to give a reliable average without being unduly influenced by very good and very poor short-term returns. When calculated using a long data series, the historical risk premium is relatively stable.t7 Furthermore, because an average of the realized equity risk premia is quite volatile when calculated using a short series, using a long series makes it less likely that the analyst can justify any number he or she wants. Some analysts calculate the expected equity risk premium over a shorter, more recent time period on the basis that more recent events are more likely to be repeated in the near future; furthermore, the 1920s, 1930s, and 1940s contain too many unusual events. This view is suspect because all periods contain unusual events. Some of the most "unusual" events of this century took place quite recently. These events include the inflation of the late 1970s and early 1980s, the October 1987 stock market crash, the collapse of the high yield bond market, the major contraction and consolidation of the thrift industry, and the collapse of the Soviet Union —all of which happened in the past 20 years. Without an appreciation of the 1920s and 1930s, no one would believe that such events could happen. More generally, the 73-year period starting with 1926 is representative of what can happen: it includes high and low returns, volatile and quiet markets, war and peace, inflation and deflation, and prosperity and depression. Restricting attention to a shorter historical period underestimates the amount of change that could occur in a long future period. Finally, because historical event -types (not specific events) tend to repeat themselves, long -run capital market return studies can reveal a great deal about the future. Investors probably expect "unusual" events to occur from time to time and their return expectations reflect this. The equity risk premium data presented in this publication are derived from data on publicly traded companies, a majority of whom are minority held. There is no evidence to suggest that the equity risk premium represents a minority interest risk premium. The equity risk premium data make no distinction between majority or minority ownership interests. 17 This asserration is further corroborated by data presented in Global In vesting. 77ie Profenionall Gnfde to :he World Capital Markeu (by Roger G. Ibbotson and Gary P. Brinson and published by McGraw-Hill, New York). Ibbotson and Brinson constructed a stock market total return series bark to 1790. Even with some uncertainty about the accuracy of the data before the mid-19th century, the results are remarkable in that the real (adjusted for inflation) returns that investors received during the three 50-year periods and one 51-year period between 1790 and 1990 did not differ greatly (that is, in a statistically significant amount) from one another, nor did they differ greatly from the overall 201-year average. This finding implies that because real stock market returns have been reasonably consistent over time, investors can use these past returns as reasonable bases for forming their expectations of future remms. 156SBBI 1999 Yearbook *Exhibit No. VER-3 Schedule 11 Page 5 of 6 Estimating the Cost of Capital or Discount Rate Calculating the Expected Equity Risk Premium Arithmetic Versus Geometric Differences For use as the expected equity risk premium in the CAPM, the arithmetic or simple difference of the arithmetic means of stock marker returns and riskless rates is the relevant number. This is because the CAPM is an additive model where the cost of capital is the sum of its parts. Therefore, the CAPM expected equity risk premium must be derived by arithmetic, notgeometric, subtraction. Arithmetic Versus Geometric Means The expected equity risk premium should always be calculated using the arithmetic mean. The arithmetic mean is the rate of return which, when compounded over multiple periods, gives the mean of the probability distribution of ending wealth values. (A simple example given below shows that this is true.) This makes the arithmetic mean return appropriate for computing the cost of capital. The discount rate that equates expected (mean) future values with the present value of an investment is that investments cost of capital. The logic of using the discount rate as the cost of capital is reinforced by noting that investors will discount their expected (mean) ending wealth values from an investment back to'the present using the arithmetic mean, for the reason given above. They will, therefore, require such an expected (mean) return prospectively (that is, in the present looking toward the future) to commit their capital to the investment. For example, assume a stock has an expected return of +10 percent in each year and a standard deviation of 20 percent. Assume further that only two outcomes are possible each year— +30 percent and -10 percent (that is, the mean plus or minus one standard deviation), and that these outcomes are equally likely. (The arithmetic mean of these returns is 10 percent, and the geometric mean is 8.2 percent.) Then the growth of wealth over a two-year period occurs as shown below: $1.70 $1.60 $1.50 $1 40 $1.30 $1.20 $1.10 $1 AO $0.90 $0 80 $0.70 Year $1.69 $1.17 $0.81 Ibbotson Associates 157 Exhibit No. VER-3 Schedule 11 Page 6 of 6 Chapter 8 Note that the median (middle outcome) and mode (most common outcome) are given by the geometric mean, 8.2 percent, which compounds up to 17 percent over a 2-year period (hence a terminal wealth of $1.17). However, the expected value, or probability -weighted average of all possible outcomes, is equal to: (.25 x 1 69) = 04225 + (:50 x 1.17) = 0.585.0 + (.25 x 0 81) TOTAL 1.2100 Now, the rate that must be compounded up to achieve a terminal wealth of $1.21 after 2 years is 10 percent; that is, the expected value of the terminal wealth is given by compounding up the arithmetic, not the geometric mean. Since the arithmetic mean equates the expected future value with the present value, it is the discount rate. Stated another way, the arithmetic mean is correct because an investment with uncertain returns will have a higher expected ending wealth value than an investment that earns, with certainty, its compound or geometric rate of return every year. In the above example, compounding at the rate of 8.2 percent for two years yields a terminal wealth of $1.17, based on $1.00 invested. But holding the uncertain investment, with a possibility of high returns (two +30 percent years in a row) as well as low returns (two -10 percent years in a row), yields a higher expected terminal wealth, $1.21. In other words, more money is gained by higher -than -expected returns than is lost by lower -than -expected returns. Therefore, in the investment markets, where returns are described by a probability distribution, the arithmetic mean is the measure that accounts for uncertainty, and is the appropriate one for estimating discount rates and the cost of capital. Arbitrage Pricing Theory APT is a model of the expected return on a security. It was originated by Stephen A. Ross, and elaborated by Richard Roll. APT treats the expected return on a security (i.:e., its cost of capital) as the sum of the payoffs for an indeterminate number of risk factors, where the amount of each risk factor inherent in a given security is estimated. Like the CAPM, APT is a model that is consistent with equilibrium and does not attempt to outguess the market. APT may be viewed as an extended CAPM with multiple betas" and multiple risk premia. 158 SBBI 1999 Yearbook 0 Line No. 1 2 3. Exhibit No. VER-3 Schedule 12 Page 1 of 4 City of Vernon, California Indicated Common Equity Cost Rate Through Use of the Capital Asset Pricing Model for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No. ER97-2355, et. al.), the Proxy Group of Five Electric and Combination Electric & Gas Companies vVith Total 1998 Revenues Greater than $2.0 Billion, the Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Proxy Group of Four Electric and Proxy Group of Five Combination Electric & Electric and Proxy Group of Four Gas Companies Relied Combination Electric & Electric and Upon by FERC in Gas Companies with Combination Electric & Opinion No. 445 Total 1998 Revenues Gas Companies with (Docket No. ER97- Greater than $2.0 Total 1998 Revenues 2355, et. al.) Billion Less than $2.0 Billion Traditional Capital Asset Pricing Model Risk -Free Rate (1) 5 93 % 5.93% 5.93% Average Company -Specific Market Premium (2) 4.00 4.22 4.44 Capital Asset Pricing Model Derived Company Equity Cost Rate 4 Risk -Free Rate (1) 5 Average Company -Speck Market Premium (2) 6. Capital Asset Pricing Model Derived Company Equity Cost Rate Average of CAPM and 7 ECAPM Cost Rates Range of indicated CAPM Common Equity Cost Rate Midpoint of the Range 9,93 % 10.15 % 10.37 % Empirical Capital Asset Pricing Model 5.93% 5.93% 5.93% 5.16 5.33 5.49 11.09 % Notes: (1) Developed in note 2 of page 4 of this Schedule. (2) Developed on pages 2 and 3 of this Schedule. 11.26 % 10.71 % 10,51 % - 10.90% 10.71 % 0 Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No. ER97-2355, at. al.) Constellation Energy Group. Inc. Duke Energy Corp. PG&E Corp. The Southern Company Average Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion Anlant Energy Corp Ameren Corp. Consolidated Edison. Inc. Constellation Energy Group. Inc. The Southern Company Average Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion Central Hudson Gas & Electric Corp DQE. Inc Public Service Company of New Mexico The United Illuminating Company Average See page 4 for notes Exhibit No. VER-3 Schedule 12 Page 2 of 4 City of Vernon, California Indicated Common Equity Cost Rate Through Use of the Capital Asset Pricing Model Company -Specific CAPM Result Value Line Risk Premium Including Adjusted Based on Market Risk -Free Beta Premium of 8.65% (1) Rate of 5.93% (2) Traditional Capjtal Asset Pricing Model I3) 050 4.33 % 10 26 % OAS 3B9 9.82 OAS 3.89 9.82 OAS 3.89 9.82 0.46 4.00 % 9.93 % NMF NA % NA % 050 433 1026 0.50 433 1026 0.50 433 10.26 OAS 3.89 9.82 0.49 422 % 10,15 % 050 4.33 % 10 26 % 055 4.76 10.69 050 433 10.26 0.50 4.33 10.26 0.51 _ 4.44 % 10.37 % Exhibit No VER-3 Schedule 12 Page 3 of 4 City of Vernon. Califomia Indicated Common Equity Cost Rate Through Use of the Capital Asset Pricing Model Company -Specific CAPM Result Value Line Risk Premium Including Adjusted Based on Market Risk -Free Beta Premium or 8.65% (1) Rate of 5.93% (2) Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No 445 (Docket No. ER97-2355, at. al.) Constellation Energy Group, Inc Duke Energy Corp PG&E Corp The Southern Company Average Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.O Billion Alliant Energy Corp Ameren Corp Consolidated Edison. Inc. Constellation Energy Group. Inc The Southern Company Average Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0Billion Central Hudson Gas & Electric Corp. DOE. Inc. Public Service Company of New Mexico The United Illuminating Company Average See page 4 for notes Empirical Capital Asset Pficinn Model (61 O50 SA1 % 11.34 % 0.45 5.08 11.01 0.45 5.08 11.01 0.45 5.08 11.01 0.46 16 % 11.09 % NMF NA % NA % 050 5.41 1134 050 541 11.34 050 541 1134 OAS 5.08 11.01 OA9 5.33_ % 11.26 % 050 541 % 11.34 % 0.55 5.73 11.66 050 5.41 11.34 0.50 5.41 11.34 0.51 c 5.49% 11A2% • 0 Notes: Exhibit No. VER-3 Schedule 12 Page 4 of 4 City of Vemon. California Development of the Market -Required Rate of Return on Common Equity Using the Capital Asset Pricing Model for the Proxy Group of Four Electric and Combination Electric and Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No. ER97-2355, at al.), the Proxy Group of Fire Electric and Combination Electric and Gas Companies with Total 1998 Revenues Greater than $2.0 Billion, and the Proxy Group of Four Electric and Combination Companies with Total 1998 Revenues Less than $2 0 Billion Adjusted to Reflect a Forecasted Risk -Free Rate and Market Return (1) From the six previous month -end (Mar. '99 - Aug. '99), as well as a recently available (Sep.. 10, 1999). Value Line Summary & Index, a forecasted 3-5 year total annual market return of 1523% can bederived by averaging the March through August 1999, and spot forecasted total 3-5 year total appreciation, converting it into an annual market appreciation and adding the Value Line average forecasted annual dividend yield. The 3-5 year aye rage total market appreciation of 65%, produces a four-year average annual return of 13..34% ((1.65 -1). When the average annual forecasted dividend yield of 1.89% is added, a total average market return of 15 23% (1.89% + 13.34%) is derived. The March through August 1999, and spot forecasted total market return of 15.23% minusthe risk - free rate of 5.93% (developed in Note 2) is 9.30% (15.23%- 5.93%). The Ibbotson Associates calculated market premium of 8.00% for the period 1926-1998 results from a total market return of 13.20% less the average income return on long-term U.S. Government Securities of 5.20% (13.20% - 5.20% = 8.00%). This is then averaged with the 8.65% Value Line market premium resulting in an 8.65% market premium. The 8.65% market premium is then multiplied by the beta in column t of pages 2 and 3 of this Exhibit (2) Average forecast based upon six quartedy estimates of 30-year Treasury Bond yields pertheconsensus of nearly 50 economists reported in the Blue Chip Financial Forecasts dated September 1,1999 (seepage 7 of Schedule 10 of this Exhibit). The estimates are detai below: Third Quarter 1999 Fourth Quarter 1999 First Quarter 1999 Second Quarter 1999 Third Quarter 2000 Fourth Quarter 2000 Average 30-Year Treasury Bond Yield - 6..00% 6..00 5..90 5.90 5.90 5.90 5-93% (3) The traditional Capital Asset Pricing Model (CAPM) is applied using the following formula: Rs = RF + R (RM - RF) Where Rs = Return rate of common stock RF = Risk Free Rate p = Value Line Adjusted Beta RM = Return on the market as a whole (4) The empirical CAPM is applied using the following formula: Rs = RF + .25 (RM - RF ) + .75 P (Ra - RF ) Where Rs = Return rate of common stock RF _= Risk -Free Rate gg Value tine Adjusted Beta RM = Return on the market as a whole Source of Information: Value Line Summe & Index (Standard Edition) Blue Chip F�nanc,a Forecasts. September 1, 1999 Value Line Investment Survey (Standard Edition), July 9, August 20, and September 10, 1999 Stocks Bonds Bills and Inflation -1999 Yearbook Market Results for 1926-1998 lbbotson Associates, Inc., Chicago, IL I Exhibit No. VER-3 Schedule 13 Page 1 of 6 City of Vernon, California Indicated Common Equity Cost Rate Through Use of a Comparable Earnings Analysis Indicated Comparable Earnings Analysis Return Rate Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No. ER97-2355, et. al.) 14.00% (1) Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion 14.00% (2) Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion 13.50% (3) Range of Indicated Risk Premium Common Equity Cost Rate 13.50% _ 14.00% Mid -Point of the Range 13.75% Notes: (1) From page 2 of this Schedule. (2) From page 3 of this Schedule. (3) From page 4 of this Schedule. City of Vernon. California Comparable Earnings Analysis for a Proxy Group of Seven Non -Utility Companies Comparable to the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No 445 (Docket No ER97-2355, et al) (1) Proxy Group of Seven Non -Utility Companies Comparable to the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No. 445 (Docket No. ER97-2355, et. al.) (1) Buckeye Partners L.P Inrl Aluminum National Presto Ind. Network Assoc. Regis Corp Washington R.E.I.T_ West Pharmac. Svcs Average for the Non -Utility Group Average for the Proxy Group of Four Electric and Combination Electric & Gas Companies Relied Upon by FERC in Opinion No 445 (Docket No ER97-2355, et al) Mean Conservative Conclusion (5) See pages 5 - 6 for notes Exhibit No. VER-3 Schedule 13 Page 2of6 5-Year Projected Rate of Return on Standard Net Worth, Equity, or Partners' Error Capital (2) Adj Unadj of the Sludenrs Beta Beta Regression Percent T Test 0.50 019 23140 2350 % 1.79 0.55 0.31 2.5853 11.50 (0 85) 0.55 0.25 2.3965 9.D0 (1.40) 046 0.11 2.4507 1550 0.03 0.50 0.23 2.2886 1650 025 0.60 0.38 2.6669 1500 (0.08) 0.50 0.24 2.6422 1650 0.25 0.52 0.24 2.4777 0.49 0.17 (3) 2.4227 (4) 15.36 % 14.00 % Exhibit No. VER 3 Schedule 13 Page 3of6 City of Vernon. Califomia Comparable Eamings Analysis for a Proxy Group of Ten Non -Utility Companies Comparable to the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion (6) 5-Year Projected Rate of Retum on Proxy Group of Ten Non -Utility Companies Standard Net Worth, Equity or Partners' Comparable to the Proxy Group of Five Electric Error Capital (2) and Combination Gas & Distribution Companies Adj. Unadj. of the Student's with Total 1998 Revenues Greater than $2.0 Billion (6) Seta Beta Regression Percent T-Test Anheuser-Busch 0.65 0.46 2.3081 33.50 % 2.13 Buckeye Partners L.P 0.50 0.19 23140 23.50 0.87 Int'I Aluminum 0.55 031 25853 11.50 (0 64) National Presto Ind. 055 025 23965 9.00 (0.96) Network Assoc 045 0.11 24507 15.50 (0,14) Penn. R. E IT 065 0.43 2.6374 20.00 0.43 Regis Corp 050 0.23 2.2886 16.50 (0.01) United Dominion R'Ity 065 0.43 2.4714 5.00 (1 A6) Washington RE IT 060 0.38 2.6669 15.00 (020) West Pharmac. Svcs 0.50 0.24 2.6422 1650 (0.01) Average for the Non -Utility Group 0.56 0,30 2.4761 Average for the Proxy Group of Five Electric and Combination Electric & Gas Companies with Total 1998 Revenues Greater than $2.0 Billion 0.51 0.22 (7) 2.3855 (8) Mean 16.60 % Conservative Conclusion (5) KOO % See pages 5 - 6 for notes. Exhibit No. VER-3 Schedule 13 Page 4 of 6 City of Vernon, California Comparable Earnings Analysis for a Proxy Group of Twelve Non -Utility Companies Comparable to the Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2.0 Billion (91 5-Year Projected Rate of Return on Proxy Group of Twelve Non -Utility Companies Standard Net Worth, Equity or Partners' Comparable to the Proxy Group of Four Electric Error Capital (2) and Combination Gas & Distribution Companies Adj Unadj. of the Students with Total 1998 Revenues Less than $2.0 Billion (9) Beta Beta Regression Percent T Test Anheuser-Busch 0.65 0.46 2.3081 3350 % (113) 239 BRE Properties 070 0.48 2.5812 1150 (0 ST Buckeye Partners L. P 0.50 0.19 2.3140 23 50 1.04 Duke Realty Corp 070 0.51 2.3876 12.50 (0.45) Inrl Aluminum 0.55 0.31 2.5853 11.50 (0 59) National Presto Ind. 055 0.25 2.3965 9 00 (0 92) Network Assoc 045 0.11 2.45D7 1550 (0 04) Penn RE -IT 065 0.43 2.6374 20.00 056 Regis Corp 0.50 0.23 22886 1650 009 United Dominion R'tty 0.65 0.43 2.4714 5 0D (1 46) WashingtonR.E.I_T. G60 0.38 2.6569 1500 (0.11) West Pharmac. Svcs. 0.50 0.24 2.6422 1650 009 Average for the Non -Utility Group 0.58 0.34 2.4775 Average for the Proxy Group of Four Electric and Combination Electric & Gas Companies with Total 1998 Revenues Less than $2 0 Billion 0.54 0.26 (11) 2.3810 (12) Mean JAM % Conservative Conclusion (5) g3.5D% See pages 5 - 6 for notes. Notes: Exhibit No. VER-3 Schedule 13 Page 5 of 6 City of Vernon, California Comparable Earnings Analysis (1) The criteria for selection of the proxy group of seven non -utility companies was that the non -utility companies be domestic and have a meaningful projected 2002 —2004 rate of return on net worth or partners' capital as reported in Value Line Investment Survey (Standard Edition). The proxy group of seven non -utility companies was selected based upon the proxy group of four electric and combination electric & gas companies relied upon by FERC in Opinion No.. 445 (Docket No_ ER97-2355, et. al.) unadjusted beta range of (0.08) — 0.42 and standard error of the regression range of 2.1035 — 2.7419 These ranges are based upon plus or minus three standard deviations of the unadjusted beta and standard error of the regression as detailed in Mr.. Hanley's accompanying direct testimony. Plus or minus three standard deviations captures 99.73% of the distribution of unadjusted betas and standard errors of the regression. (2) 2002-2004. (3) The standard deviation of the proxy group of four electric and combination electric & gas companies relied upon by FERC in Opinion No. 445 (Docket No.. ER97-2355, et. al..) unadjusted beta is 0.0833_ (4) The standard deviation of the proxy group of four electric and combination electric & gas companies relied upon by FERC in Opinion No. 445 (Docket No. ER97-2355, et. al.) standard error of the regression is 0.1064. The standard deviation of the standard error of the regression is calculated as follows: Standard Deviation of the Standard Error of the Regression W Standard Error of the Regression /2N where: N = number of observations. Since Value Line betas are derived from weekly price change observations over a period of five years, N = 259 Thus, 0.1064 = 2.4227 = 2.4227 /518 22.7596 (5) Average of 5-year projected rates of return excluding those above 20% and below the prospective yield of 7.55% on A rated Moody's public utility bonds (from page 1 of Schedule 10 of this Exhibit). (6) The criteria for selection of the proxy group of ten non -utility companies was that the non -utility companies be domestic and have a meaningful projected 2002-2004 rate of return on net worth or partners' capital as reported in Value Line Investment Survey (Standard Edition).. The proxy group often non -utility companies was selected based upon the proxy group of five electric and combination electric & gas companies with total 2002 revenues greater than $2.0 billion's unadjusted beta range of (0.03) — 0.47 and standard error of the regression range of 2.0711 — 2.6999.. Exhibit No. VER-3 Schedule 13 Page 6 of 6 City of Vernon, California Comparable Eamings Analysis These ranges are based upon plus or minus three standard deviations of the unadjusted beta and standard error of the regression as detailed in Mr.. Hanley's accompanying direct testimony. Plus or minus three standard deviations captures 99.73% of the distribution of unadjusted betas and standard errors of the regression. (7) The standard deviation of the proxy group of five electric and combination electric & gas companies with total 2002 revenues greater than $2.0 billion's unadjusted beta is 0.0820. (8) The standard deviation of the proxy group of five electric and combination electric & gas companies with total 2002 revenues greater than $2.0 billion's standard error of the regression is 0.1048 (2.3855 _ 223596). (9) The criteria for selection of the proxy group of twelve non -utility companies was that the non -utility companies be domestic and have a meaningful projected 2002 — 2004 rate of return on net worth or partners' capital as reported in Value Line Investment Survey (Standard Edition). The proxy group of twelve non -utility companies was selected based upon the proxy group of four electric and combination electric & gas companies with total 2002 revenues less than $2.0 billion's unadjusted beta range of 0.01 — 0.51 and standard error of the regression range of 2..0672— 2.6948.. These ranges are based upon plus or minus three standard deviations of the unadjusted beta and standard error of the regression as detailed in Mr. Hanley's accompanying direct testimony. Plus or minus three standard deviations captures 99.73% of the distribution of unadjusted betas and standard errors of the regression. (10) The Student's T-statistic associated with this projected return exceeds 2.201 at the 95% level of confidence with eleven degrees of freedom (11 = 12 observations —1). Therefore, it has been excluded, as an outlier, to arrive at a proper mean projected return as fully explained in the accompanying direct testimony. (11) The standard deviation of the proxy group of four electric and combination electric & gas companies with total 2002 revenues less than $2..0 billion's unadjusted beta is 0.0819. (12) The standard deviation of the proxy group of four electric and combination electric & gas companies with total 2002 revenues less than $2.0 billion's standard error of the regression is 0.1046 (2..3810 T 223596). Source of Information: Value Line, Inc., June 15, 1999 Value Line Investment Survey (Standard Edition) EXHIBIT 14 Exhibit No. VER-7 Page 1 of 40 1 2 UNITED STATES OF AMERICA 3 BEFORE THE 4 FEDERAL ENERGY REGULATORY COMMISSION 5 6 City of Vernon, California ) Docket No. EL00-105-007 7 ) 8 California Independent System ) Docket No. ER00-2019-007 9 Operator Corporation ) 10 11 PREPARED INITIAL 12 TESTIMONY OF BAKER G. CLAY 13 ON BEHALF OF THE CITY OF VERNON, CALIFORNIA 14 15 I. QUALIFICATIONS AND SCOPE OF TESTIMONY 16 17 A. Qualifications 18 19 Q. What is your name and business address? 20 A. My name is Baker G. Clay, and my business address is: Baker G. Clay 21 Associates, Inc., 1592 Lancaster Green, Annapolis, Maryland 21401. 22 Q. By whom are you employed? 23 A. I am president of the firm of Baker G. Clay Associates, Inc., which is a public 24 utilities consulting firm. 25 Q. On whose behalf are you presenting testimony in this proceeding? 26 A. I am presenting testimony on behalf of the City of Vernon, California 27 ("Vernon"). 28 Q. Describe your occupational history, education and qualifications to present 29 this testimony. 30 A. I graduated from West Virginia University in 1958 with a Bachelor of Science 31 degree in Mining Engineering -Petroleum Engineering Option, and in 1975 I 32 received a Masters Degree in Energy Resources from the School of Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 2 of 40 1 Engineering at the University of Pittsburgh. I am licensed as a professional 2 Engineer in the States of Pennsylvania and Maryland. 3 Upon graduation from West Virginia University in 1958, I was employed by 4 Commonwealth Natural Gas Corporation for one year as an Engineer Trainee 5 assigned to the maintenance and construction of transmission system 6 properties. 7 In 1959, I accepted the position of General Engineer in the pipeline rate 8 division of the Bureau of Rates and Certificates of the Federal Power 9 Commission ("FPC"), which later became the Office of Pipeline and Producer 10 Regulation of the Federal Energy Regulatory Commission ("Commission" or 11 "FERC"). My duties with the FPC consisted of analyzing and preparing 12 reports and memoranda on proposed changes in tariffs, rate schedules, and 13 contracts filed with the FPC by natural gas pipeline companies. I assisted in 14 the preparation of rates and related aspects of the rate making process for use 15 in pipeline rate proceedings and rate settlement conferences, and provided 16 technical assistance on the rate aspects of certificate proceedings for the 17 construction of pipeline facilities subject to FPC jurisdiction. 18 In 1962, I joined the Service Company of the Consolidated Natural Gas 19 system. My duties with Consolidated encompassed practically all aspects of 20 natural gas regulation. One of my primary responsibilities was to perform 21 cost allocation and rate design studies of the Consolidated System and of the 22 pipeline suppliers of Consolidated. In addition, I participated in many studies 23 involving Consolidated's operating companies, including studies of the 24 economics of proposed projects and the rate structures of those companies 25 involving both transmission and distribution operations. I participated in the Docket Nos. EL00-105, et. al.. Exhibit No. VER-7 Page 3 of 40 1 preparation of cost allocation and rate design evidence presented in the rate 2 proceedings of those companies before both state commissions and the FPC. 3 I also represented Consolidated in rate, certificate, and curtailment cases of 4 the company's pipeline suppliers at the FPC. 5 I joined the firm of Hess and Lim, Inc. in 1976 and, during my employment 6 with this firm, I continued to perform cost allocation and rate design studies, 7 as well as curtailment studies, and presented such studies as evidence in 8 proceedings before the FPC, the FERC, and various state commissions and 9 courts. In May, 1980 I formed the firm of Baker G. Clay & Associates, Inc. 10 Q. Have you presented testimony before federal and state commissions? I I A. Yes. I have presented testimony before the FPC and the FERC in gas, 12 electric, and oil pipeline proceedings and before the state regulatory agencies 13 in California, Virginia, Idaho, Pennsylvania, Maryland, West Virginia, 14 Colorado, and the District of Columbia. 15 Q. Have you presented testimony before any courts? 16 A. Yes. I presented testimony before the United States District Court for the 17 Western District of North Carolina, before the United States District Court for 18 the Northern District of New York, before the United States District Court for 19 the Western District of Louisiana, Shreveport Division, and before the United 20 States District Court for the Eastern District of Pennsylvania. 21 Q. Have you had prior experience in Vernon's dealings with Southern California 22 SCE Company ("Vernon" or "SCE")? 23 A. Yes. I have been Vernon's principal witness in all of SCE's rate increase 24 proceedings at the Commission subsequent to 1979, including SCE's rate 25 increase filings in Docket Nos. ER79-150, ER81-177, ER82-427, ER84-75 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 4 of 40 1 and ER88-83. I have also participated in other SCE proceedings, including 2 the price squeeze phase of Docket No. ER79-150, the 1986 rate case that was 3 settled (Docket No. ER87-365), Vernon's complaint case against SCE that 4 resulted in SCE's filing rate schedules for transportation of Vernon's interest 5 in Palo Verde in Docket No. ER86-316, Phase II of Docket No. ER81-177 to 6 determine the justness and reasonableness of the Integrated Operations 7 Agreements under which wholesale customers of SCE obtain supplies of 8 capacity and energy from sources other than SCE, Phase II of Docket No. 9 ER84-75 on the reasonableness of SCE's proposed wheeling of Vernon's 10 capacity and energy entitlement in the Hoover hydroelectric project, SCE's 11 applications to the Commission and the California Public Utilities 12 Commission ("CPUC") for its proposed merger with San Diego Gas & 13 Electric Company in Docket No. EC89-5 and Application No. 88-12-035, 14 respectively, and in the California -Oregon Transmission Project application at 15 the Commission. I presented testimony on Vernon's behalf in connection 16 with the CPUC's order instituting investigation to develop a policy of 17 nondiscriminatory access to electricity transmission services for nonutility 18 power producers in I.90-09-050. I participated in Vernon's various contract 19 negotiations with SCE and in Vernon's antitrust case against SCE. I 20 presented testimony in SCE's filing in Docket No. ER97-2355-000 regarding 21 credits for Vernon's transmission facilities and in the consolidated 22 proceedings in Docket Nos. ER97-2358-002, ER97-2355-002, and ER97- 23 2364 regarding SCE's wholesale distribution tariff. 24 Some of the more significant issues that I addressed are the issue with 25 respect to separate rate class treatment for Vernon, issues with respect to the 0 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 5 of 40 1 terms and conditions of the integrated operations agreement, time -varying 2 energy charges under SCE's partial requirements rate schedule, the 3 availability of interruptible rate schedules to resale customers, the contract 4 terms in SCE's proffered contracts for transportation of Vernon's interest in 5 the Hoover hydroelectric project, contract terms in SCE's proffered contracts 6 for the transportation of Vernon's interest in Palo Verde, various issues 7 related to SCE's applications at the Commission and at the CPUC on SCE's 8 proposal to merge with SDG&E, and numerous revenue requirements and 9 cost allocation and rate design issues in the rate cases. Of particular 10 relevance, here, as noted above, I presented testimony on credits for customer 11 owned facilities in SCE's Docket No. ER97-2355-000. Numerous issues, 12 other than some of the revenue requirements issues, involved undue 13 discrimination or some form of anticompetitive effect. 14 Q. Have you had prior experience in Vernon's dealings with Vernon's retail 15 service? 16 A. Yes. I have prepared reports dealing with Vernon's retail rates and have met 17 with Vernon's retail customers and potential customers to discuss rate and 18 service matters. 19 Q. Have you had prior experience dealing with Vernon's energy supply and 20 requirements? 21 A. Yes. I have participated with Vernon's management in exploring various 22 alternatives to supplies of electricity from sources other than SCE, and in 23 negotiating transmission contracts with SCE, including transmission 24 associated with the Mead -Phoenix, Mead-Adelanto, California -Oregon 25 Transmission Projects, and transmission from the Hoover hydroelectric i 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 6 of 40 1 project. 2 Q. Have you had prior experience in Vernon's dealings with the California 3 Independent System Operator Corporation ("CAISO" or "ISO")? 4 A. Yes. I testified on Vernon's behalf in the so-called California refund 5 proceedings in Docket Nos. EL00-95, et al., and in the aforementioned SCE 6 Docket No. ER97-23 5 5-000, which involved, among other things, SCE's 7 Transmission Revenue Requirement ("TRR") upon SCE becoming a 8 Participating Transmission Owner ("PTO"). I also prepared an affidavit and 9 schedules in support of Vernon's protest of the ISO's March 31, 2000 filing 10 of Amendment No. 27 in Docket No. ER00-2019. Vernon's protest 11 concerned the ISO proposed "buy down" provision, which was supported by, 12 among others, SCE and PG&E. The "buy down" provision would have 13 artificially limited New PTOs' recovery of their TRRs. The Commission 14 rejected the "buy down" provision in its May 31, 2000 order.' That ruling, 15 and other Commission rulings in the May 31, 2000 order, enabled Vernon to 16 apply for PTO status on June 30, 2000, and to submit its August 30, 2000 17 petition for declaratory order regarding its TRR for its transmission facilities 18 turned over to ISO operational control. 19 B. Scope of Testimony 20 Q. What is the purpose of this testimony? 21 A. The purpose of my testimony is to present Vernon's TRR, which Vernon first 22 submitted to the Commission as a part of Vernon's August 30, 2000 petition 23 for declaratory order. Conditioned upon certain changes, the Commission ' California Independent System Operator Corp., 91 FERC ¶ 61,205 at p. 61,723 (2000), reh g denied in relevant part, 104 FERC ¶ 61,062, P. 47 (2003). Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 7 of 40 1 approved Vernon's TRR. See Exhibit No. VER-8. That Commission 2 approval is now on remand from the D.C. Circuit Court of Appeals. 3 Among other things, with certain exceptions, I adopt the testimony submitted 4 by Albert Clark to the Vernon City Council when it approved the Vernon 5 TRR, which testimony was submitted to the Commission as a part of 6 Vernon's August 30, 2000 petition for declaratory order. Regarding the 7 exceptions, I make alternative recommendations to Mr. Clark's development 8 of Net Plant and make a correction to the aggregation of the A&G Expenses. 9 Also, Mr. Frank Hanley makes a recommendation as to rate of return, and Mr. 10 Edward Feinstein makes a recommendation as to depreciation. I II. VERNON'S RELATIONSHIP WITH SCE 12 AND THE CAISO 13 A. The City of Vernon 14 Q. Describe the City of Vernon. 15 A. The City of Vernon was incorporated on September 16, 1905 as 16 California's first industrial city. Vernon was planned from its 17 inception as an industrial city. It currently occupies an area of 5.06 18 square miles (3,238 acres). It has common boundaries with the City of 19 Los Angeles, Los Angeles County, and the Cities of Huntington Park, 20 Maywood, Bell, and Commerce. It is located approximately 5 miles 21 from "downtown" Los Angeles. Vernon has a small resident 22 population but provides jobs for a daily working population of 23 approximately 44,000 employees of businesses located within the City 24 of Vernon. 25 Q. Describe Vernon's electric utility operations. 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 8 of 40 1 A. Vernon owns and operates its own distribution system from which it serves its 2 industrial and commercial customers, and small resident population. Vernon 3 owns within its municipal boundaries some 28.5 MW of generating capacity 4 in diesel and gas turbine units. Vernon has an entitlement of 22 MW of 5 peaking capacity and associated energy through a federal agency from Hoover 6 Dam and an 11 MW entitlement in the Palo Verde nuclear generating station 7 through Southern California Public Power Authority. In recent years up to 8 the present time, Vernon has purchased firm capacity and energy and non- 9 firm energy from several western utilities. 10 Vernon has a 121 MW ownership interest in the California -Oregon 11 Transmission Project ("COTP") and has exchanged Vernon COTP 12 transmission service to Pacific Gas & Electric Company ("PG&E") for 13 transmission service by PG&E in the magnitude of 93 MW on the Pacific 14 Intertie, which is functionally parallel with the COTP. Vernon is also a 15 participant in the Mead -Phoenix Project ("MPP"), which connects the 16 Westwing Substation near Phoenix with the Westwing Substation through 17 Mead Substation (near Hoover Dam in southern Nevada) and the Mead- 18 Adelanto Project ("MAP") that connects the Los Angeles Department of 19 Water and Power ("LADWP") with Marketplace Substation. Vernon has 20 turned its transmission facilities and entitlements over to CAISO operational 21 control. 22 Vernon's annual peak load is approximately 190 MW. 23 B. Vernon's Relationship with SCE 24 Q. Discuss Vernon's relationship with SCE. 25 A. Before April 1, 1998 SCE operated a fully integrated electric utility company • 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 9 of 40 1 with a service area that included primarily the Los Angeles Basin. SCE made 2 retail sales that were subject to the regulation of the CPUC. SCE also 3 rendered Commission jurisdictional wholesale service to Vernon and other 4 municipal utilities. 5 Q. What were the sources of SCE's electricity? 6 A. SCE maintained highly diversified sources of electricity, including gas, oil, 7 and coal -fueled thermal plants, as well as significant production from nuclear, 8 hydro, wind, and solar, and purchases from other utilities. SCE acquired a 9 significant portion of its requirements from Qualifying Facilities ("QFs"). 10 SCE obtained an indispensable portion of its requirements from generation 11 located outside its service area. 12 Q. Describe SCE's certificated service area, and SCE and Resale Cities', 13 including Vernon's transmission facilities bringing electricity into SCE's 14 service area. 15 A. Page 1 of Exhibit No. VER-9, a 1989 map prepared by the California Energy 16 Commission, shows SCE's certificated service area. Note that all of the Resale 17 Cities, Vernon, Anaheim, Azusa, Banning, Colton, and Riverside, are 18 included in SCE's certificated service area. Page 2 of Exhibit No. VER-9, a 19 1983 map, also shows SCE's service area, but in addition also shows the 20 major transmission lines supplying SCE's service area as they existed at that 21 time. Note that the page 2 map shows that SCE's 1983 sources of energy from 22 outside its service area amounted to 10,773 GWH from the northwest and 23 11,238 GWH from the south-west. Those were, and are, the major sources of 24 energy from outside the Los Angeles basin. At that time Vernon had no 25 access to such energy on either a firm basis or non -firm basis. Vernon's 0 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 10 of 40 1 investigations revealed that it could realize major savings in its cost of 2 electricity if it could gain access to potential suppliers in the northwest and 3 the southwest. But Vernon also came to realize that SCE would not sell firm 4 transmission service to Vernon, and that if Vernon were able to engage in 5 firm purchases to reduce its demand charges it would have to participate on 6 an ownership basis in new transmission lines to bring new sources of capacity 7 and energy into the Los Angeles basin. Those new lines generally parallel the 8 Pacific Intertie to the north and the "West of the River System" and the "East 9 of the River System" both to the east. 10 Q. Describe the transmission system connecting SCE's service area to supplies of 11 energy to the north in the Pacific Northwest. 12 A. The transmission system connecting SCE's service area to supplies of energy 13 to the north, in the Pacific Northwest, is known as the Pacific Intertie. The 14 Pacific Intertie is composed of three 500 kV lines. Page 2 of the exhibit shows 15 two 500 kV lines from John Day through Midway and into SCE's certificated 16 service area through the Vincent Substation and terminating at the Lugo 17 Substation. Page 2 of the exhibit also shows a 500 kV line from Celio 18 terminating at Sylmar. While the lines are not shown on the map on page 2 of 19 Exhibit No. VER-9, 230 kV lines connect Sylmar with the Vincent 20 Substation, and then to the Lugo Substation. Page 3 of the exhibit (Figure 2 21 from Exhibit A to the California Companies Pacific Intertie Agreement) 22 shows the 500 kV AC lines entering California at the California -Oregon 23 Border and the 500 kV line entering Nevada at the Nevada -Oregon Border 24 extending through western Nevada and entering California at the California- 25 Nevada Border. Pages 4, 5, and 6 of the exhibit show the same facts in greater 0 • Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 11 of 40 1 detail, and page 6 also shows the COTP. 2 Q. Does SCE have an ownership interest in the 500 kV DC lines? 3 A. Yes. SCE has an undivided interest in Los Angeles' DC transmission circuit 4 between the Nevada -Oregon border and Sylmar, approximately 586 miles. 5 Q. You testified above that Vernon constructed facilities that complement SCE's 6 facilities that import electricity into its service area. What Vernon facilities 7 complement the Pacific Intertie facilities that were constructed and are owned 8 by SCE? 9 A. Vernon participates on an ownership basis in the COTP. The COTP 10 transmission facilities parallel the Pacific Intertie, including both the portion 11 of the AC Intertie constructed and owned by SCE and in the DC line in which 12 SCE has an undivided interest. The COTP transmission facilities perform the 13 same functions as those of the Pacific Intertie and contribute to SCE's ability 14 to serve its utility obligations just as SCE's own Pacific Intertie transmission 15 facilities do. 16 Q. Do you contend that Vernon's imports of capacity and energy over the COTP 17 are integrated with SCE's system? 18 A. Yes. Vernon's imports of capacity and energy over the COTP, whether over 19 the COTP or over the 1000 kV DC line (originally, it was 500 kV), are 20 commingled with, and delivered to the same network as, SCE's own imports 21 or capacity and energy. Such capacity and energy imports in addition to those 22 through the MAP and MPP displace capacity and energy that SCE would 23 otherwise be required to import into its service area, and reduces the 24 investment in facilities that SCE otherwise would be required to construct. 25 Such imports are scheduled and dispatched by SCE. Vernon's imports of 0 • Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 12 of 40 1 capacity and energy are thus integrated with SCE's system in every sense of 2 the word. 3 Q. Do Vernon and other Resale Cities own or have long-term entitlement to 4 generation resources in states to the east of SCE's service area? 5 A. Yes. With reference to page 2 of Exhibit No. VER-9, Vernon has an 11 MW 6 interest in the Palo Verde Nuclear Generating station in Arizona through 7 Southern California Public Power Authority ("SCPPA") and a 22 MW 8 interest in the Hoover Power Project in Nevada through Western Area Power 9 Administration. Vernon has also purchased firm capacity for credit under 10 Special Condition 12 and purchased and integrated non -firm energy produced 11 in the states to the east. 12 Q. How has Vernon historically imported its capacity and energy from the east 13 into its service area? 14 A. Vernon historically imported its capacity and energy from the east into its 15 service area through transmission systems known as the "West -of -the -River" 16 ("WOR") and "East -of -the -River" ("EOR") systems. With respect to page 2 of 17 Exhibit No. VER-9, the transmission lines from Palo Verde (in Arizona) to 18 Devers (in California), in SCE's service area are referred to as being in the 19 "Southern WOR" system. The transmission lines entering Adelanto 20 Substation from IPP and Victorville Substation from McCullough Substation 21 belong to Los Angeles DWP. SCE owns the transmission lines from the 22 Eldorado Substation and Mohave Substation into Lugo. Those transmission 23 lines entering Adelanto, Victorville, and Lugo Substations are referred to as 24 the Northern WOR system. LADWP's McCullough Substation connects with 25 SCE's Eldorado Substation through 500 kV lines in the east. Other 500 kV 0 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 13 of 40 1 transmission lines, known as the Victorville-Lugo line, connect LADWP's 2 Adelanto and Victorville Substations to SCE's Lugo Substation. Vernon and 3 the other Resale Cities have entered into agreements with SCE and third 4 parties for transmission service over the 500 kV transmission lines making up 5 the Northern WOR system into SCE's Lugo Substation, the gateway to SCE's 6 220 kV network. SCE then provides transmission service for such capacity 7 and energy to the city gates under rates developed using the Rate Schedule 8 TN methodology. 9 Q. What contract path has Vernon's capacity and energy resources used to enter 10 into SCE's Lugo Substation? 11 A. SCE has denied long-term firm transmission service to Vernon over its Palo 12 Verde-Devers transmission line and, with one exception, has denied long- 13 term firm transmission service to Vernon over its Northern WOR system 14 transmission facilities into Lugo. With respect to their entitlements to Palo 15 Verde capacity and energy in Arizona, Vernon and the other Resale Cities, as 16 part of the SCPPA, entered into complicated transmission/exchange 17 agreements with third parties under which they import their Palo Verde 18 entitlements. 19 Q In what instance did SCE agree to provide long-term firm transmission 20 service to the Resale Cities? 21 A. SCE agreed to provide long-term firm transmission service to Vernon and 22 other Resale Cities for their entitlements to capacity and energy from the 23 Hoover Power Plant at the Hoover Dam. 24 Q. Why did SCE agree to provide long-term firm transmission service to Resale 25 Cities from Mead to their city gates? Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 14 of 40 1 A. The Hoover power plant provides particular benefits to the SCE system 2 because of the ability of Hoover to provide automatic generation control. 3 Q. Have additional facilities been constructed and included in the WOR system 4 since 1983? 5 A. Yes. Vernon and other Resale Cities participated with others in constructing 6 two 500 kV transmission lines. One is a line known as the Mead -Phoenix line 7 and the other is known as the Mead-Adelanto line. These parties also 8 constructed a substation known as "Marketplace" near Mead. The 9 Marketplace Substation at the eastern end of the Mead-Adelanto line connects 10 with the McCullough, Mead, Mohave, and Eldorado substations, and the 11 Adelanto Substation connects with the Victorville and Lugo substations at the 12 western end. The three sets of lines, the Mead-Adelanto line, LADWP's 13 McCullough/Hoover-Victorville line and SCE's Eldorado/Mohave-Lugo line 14 now form the northern WOR system. 15 Q. Generally discuss the northern WOR system as it now exists, including the 16 Mead-Adelanto transmission line. 17 A. There are essentially three series of lines that make up the northern WOR 18 system, as shown by the schematic diagram attached as page 7 of Exhibit No. 19 VER-9. One consists of SCE's lines from Mohave and the Eldorado 20 Substation into the Lugo Substation. Another consists of the LADWP lines 21 from McCullough/Mead to Victorville. The third is the transmission line 22 constructed by Vernon, other Resale Cities; and others, from Marketplace 23 Substation to Adelanto Substation. Those three series of lines are connected 24 at the eastern end by 500 kV lines tying Mead, Marketplace, McCullough, 25 Eldorado, and Mohave substations. The three series of lines are connected at Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 15 of 40 1 the western end by 500 kV lines tying Adelanto, Victorville, and Lugo 2 Substations. 3 Q. Do you have additional reasons for concluding that Vernon's interests in the 4 COTP and Vernon's interests in the MPP /MAP facilities are integrated with 5 SCE's transmission facilities? 6 A. Yes. Vernon's interests in the COTP and Vernon's interests in the MPP/MAP 7 facilities are irrevocably linked to and integrated with SCE's transmission 8 facilities. In fact, such facilities are linked to and integrated with the electric 9 grid serving the entire Southern California market area. 10 C. Vernon's Relationship with the CAISO 11 Q. Discuss Vernon's relationship with the CAISO. 12 A. Vernon is a municipal utility within the CAISO control area. Vernon 13 schedules all its resources and transmission pursuant to the CAISO tariff. 14 Vernon had transmission rights which it transferred to the CAISO on January 15 1, 2001. Vernon schedules its entire load with and procures its ancillary 16 service requirements from the CAISO. Vernon is a Scheduling Coordinator 17 ("SC"), a Utility Distribution Company ("UDC"), and a PTO as defined in the 18 CAISO tariff. As a Scheduling Coordinator, Vernon provides schedules of its 19 supply and requirements to the CAISO. Vernon receives credits from the 20 CAISO that are associated with its transmission rights, SC functions 21 (uninstructed and instructed energy and ancillary services) and various 22 revenues associated with being a PTO (wheeling, congestion, and TRR). 23 Q. Please explain how Vernon became a PTO? 24 A. On March 31, 2000, the ISO filed Amendment No. 27 in Docket No. ER00- 25 2019. The ISO included in its filing a "buy down" provision that would have Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 16 of 40 1 required New PTOs to reduce the rate bases of their transmission by certain 2 amounts of the disbursements of Transmission Access Charge ("TAC") 3 revenues they received from the ISO for the ISO's use and operational control 4 of the New PTOs' transmission facilities. Vernon protested the "buy down" 5 provision. My affidavit in support of that protest showed that under the "buy 6 down" provision New PTOs would not receive their full TRRs. The 7 Commission summarily rejected the "buy down."2 8 Under the ISO tariff, notice of intent to become a PTO may be filed only on 9 January 1 or July 1 in any year, to be effective on the following July 1 or 10 January l respectively. Vernon submitted its notice of intent on June 30, 11 2000, and submitted its formal application to the ISO on August 1, 2000. On 12 August 3, 2000, the ISO made a compliance filing that allowed 13 nonjurisdictional New PTOs to submit their TRRs directly to the 14 Commission. 15 Vernon's City Council is the rate -making body for the City. Therefore, the 16 City Council scheduled a public hearing during which it considered the 17 appropriate TRR for Vernon. After considering the evidence, including the 18 testimony of a rate consultant, Albert Clark, on August 29, 2000, the Vernon 19 City Council established Vernon's TRR. 20 Vernon filed its petition for declaratory order to the Commission on August 2 California Independent System Operator Corp., 91 FERC ¶ 61,205 at p. 61, 723 (2000), reh'g denied in relevantpart, 104 FERC ¶ 61,062, P. 47 (2003). Vernon also objected to "cost shift" caps the ISO proposed to impose on New PTOs' TRR recovery. Those caps were recently struck down in Administrative Law Judge McCartney's March 10, 2004 Initial Decision in Docket Nos. ER00-2019, et al., 106 FERC ¶ 63,026, PP. 143-50. Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 17 of 40 1 30, 2000. The Commission accepted Vernon's TRR with certain adjustments 2 and made it effective as of January 1, 2001. The City Council considered the 3 Commission's rulings at another public hearing on November 7, 2000, and 4 decided to accept the changes. Vernon then made a compliance filing, which 5 was approved by the Commission on March 28, 2001 as to Vernon's revised 6 TRR. 94 FERC ¶ 61,344. 7 Along with filing its petition for declaratory order, Vernon undertook all of 8 the other tasks necessary for it to become a PTO by January 1, 2001. Among 9 other things, Vernon executed the Transmission Control Agreement ("TCA") 10 with the ISO, which governs many aspects of PTO status and operations, 11 including the ISO's acquisition of operational control. The Commission 12 approved the Vernon TCA on February 21, 2001. 94 FERC ¶ 61,141 (2001). 13 The ISO also filed in Docket No. ECO1-14 under Section 203 of the Federal 14 Power Act ("FPA") for authority for the transfer of the Vernon transmission 15 to ISO operational control. In that filing the CAISO established that the 16 transfer of such assets was in the public interest and was beneficial to the ISO. 17 The Commission approved the ISO's Section 203 filing on January 9, 2001. 18 California Independent System Operator Corp., 94 FERC ¶ 62,016 (2001). 19 III. VERNON'S TRANSMISSION REVENUE REQUIREMENTS 20 Q. What is the nature of Vernon's TRR? 21 A. Vernon turned over its interests in the COTP, MPP, and MAP and its rights to 22 certain transmission service agreements, to the CAISO for operational control 23 effective January 1, 2001. In return, the ISO is to compensate Vernon for the 24 TRR of those facilities and the costs incurred under the transmission service 25 agreements. Vernon's TRR includes the ownership costs, such as return, 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 LON FA Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 18 of 40 depreciation, operating expenses, Administrative and General costs, and transmission service payments to others for transmission entitlements. Describe the segments of transmission facilities that comprise the MPP and MAP facilities. The circuit distances between the locations are approximately as follows: • Vernon's own facilities, Westwing Substation (near Palo Verde) to Marketplace Substation: 243 miles. • Vernon's own facilities, Marketplace Substation to LADWP's Adelanto Substation: 215 miles. Describe the COTP. The California -Oregon Transmission Project is a project constructed to increase the transfer capability between the Pacific Northwest and central California by approximately 1,600 MW. The COTP consists of a 500 kV AC transmission line running between the California -Oregon border ("COB") and central California. Where does the COTP terminate? The COTP terminates at a point just south of PG&E's Tesla/Tracy substations, in PG&E's service area, in central -western California near San Francisco. When did the COTP become operational? The COTP became operational on March 26, 1993. See 63 FERC 63,018 at p. 65,067, n. 7. What is Vernon's entitlement to the COTP? Vernon initially had an entitlement to 121 MW of COTP capacity delivered at the terminus of the COTP. However, Vernon entered into an agreement with 0 • Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 19 of 40 1 PG&E under which it traded 121 MW of Vernon COTP transmission service 2 for 93 MW of PG&E transmission service over the 500 kV DC Intertie for 3 delivery at Midway. 4 Q. Have you developed Vernon's TRR on the facilities and transmission service 5 Vernon has turned over to the ISO for operational control? 6 A. Yes. I have developed Vernon's TRR on the facilities and transmission 7 service Vernon turned over to the ISO for operational control as set forth on 8 Exhibit No. VER-8. Vernon's TRR, including the transmission services of 9 $1,431,162, amounts to $12,253,797 annually based on a test period ending 10 June 30, 1999. Schedule 1 of Exhibit No. VER-8 shows the components of 11 the TRR of the facilities. The TRR on the facilities and contracts Vernon 12 turned over to the ISO for operational control represents the cost of owning 13 and operating these facilities, including the return requirements on Vernon's 14 investment in facilities and the annual cost of the transmission service 15 contracts. I computed the return component of Vernon's TRR by applying an 16 overall rate of return of 9.29 percent, including the weighted average cost of 17 debt and cost of equity, to a rate base represented by the original cost of 18 facilities less accumulated depreciation. 19 Q. Explain how you developed your rate base and return requirements. 20 A. I developed a rate base composed of average Gross Plant in service during the 21 test period, less accumulated depreciation, and applied a rate of return to that 22 rate base to compute return requirements as one of the components of 23 Vernon's TRR. Line 1 of Schedule 1 shows the Gross Plant for the three 24 projects Vernon turned over to the ISO for operational control. Column B 25 shows the Gross Plant for the COTP, Column C shows the Gross Plant of the 9 • Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 20 of 40 1 MAP and MPP, and Column D shows the total of all three projects. 2 Q. Explain how you developed Gross Plant. 3 A. I computed the Gross Plant as the sum of the monthly "Cash Calls" on the 4 respective projects and the Allowance for Funds Used During Construction 5 ("AFUDC") on each Project. I added Administrative and General Plant 6 associated with each transmission project to the sum of the monthly Gross 7 Plants. I develop Gross Plant on the three projects during the development 8 and construction period in Schedule 3 of Exhibit No. VER-8. Part 1 of 9 Schedule 3 shows the development, by month, of Gross Plant for the COTP 10 and Part 2 shows the development of Gross Plant for MAP and MPP. Note 11 that AFUDC in Gross Plant can be analogized with "return on investment," or 12 recompense for the cost of having money "tied up" in the project before the 13 project has economic utility. 14 The Cash Calls on each of the projects are from the records of the City of 15 Vernon, and represent the amounts Vernon contributed to the respective 16 projects each month. 17 Schedule 3 also shows the crediting of $487,786 to Gross Plant to reflect the 18 value of Vernon's firm transmission in 1993, 1994, and 1995, on the COTP 19 and $ $270,415.60 to reflect the value of non -firm transmission prior to the 20 time I began depreciating the facility. 21 Schedule 3 also shows Administrative and General Plant allocated to the 22 COTP and MPP/MAP Part 1 shows an allocation of $1,430,443 to the COTP 23 and Part 2 shows an allocation of $1,229,470 to MPP and MAP. 24 Q. What makes up the Administrative and General Plant that is a part of Gross 25 Plant? Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 21 of 40 1 A. The Administrative and General Plant is composed of costs that are not paid 2 out to the construction manager of the projects but rather cost incurred 3 internal to Vernon that has been identified assignable to the transmission 4 project. 5 Q. How were these costs identified? 6 A. City Attorney office costs identified in Vernon's records as relating to Project 7 90010 were assigned to the transmission projects. Other legal and consultants 8 cost charged to various project numbers were assigned to their appropriate 9 transmission projects. Further, certain Vernon staff cost was assigned to the 10 transmission facilities based on estimated time spent on project matters. See 11 Workpapers AM, AN, AO, AP, AQ, AR, AS, AT, AU, and AV. 12 Q. Explain how you computed AFUDC. 13 A. I computed AFUDC on each project for each month during the development 14 and construction period prior to the time the respective project became 15 commercially operable. I ceased accruing AFUDC at that time and began 16 depreciating the project. The AFUDC period on the MPP extended from 17 January 1992 until April 15, 1996 and MAP extended from February 1988 18 until April 15, 1996. The beginning dates for those two projects are the dates 19 the project manager began issuing Cash Calls. The ending dates for those two 20 projects are the dates the project manager declared those two projects as being 21 available for commercial operation. However, while the project manager 22 declared the COTP commercially operable as of March 26, 1993, I did not 23 begin depreciating the COTP until January 1, 1996. I accrued AFUDC on the 24 COTP for the period January 1985-December 1995 for purposes of 25 developing the TRR herein. I explain the rationale for the accrual of AFUDC CJ I and the depreciation of the COTP below. Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 22 of 40 2 I recommend the following two bookkeeping actions to reflect the above 3 described treatment of COTP depreciation: 4 1. Vernon's records currently reflect depreciation of the COTP beginning 5 in 1993. Upon approval by the Commission of TRR reflecting 6 depreciation of the COTP beginning December 31, 1995, Vernon 7 would make changes to its records to reflect that change in the 8 beginning of depreciation. 9 2. As noted above, Vernon currently does not accrue AFUDC on its 10 records. Vernon must maintain records to reflect the accrual and 11 depreciation of AFUDC on the three projects sufficient to maintain 12 continuity in any future proceeding to compute Vernon's TRR. 13 Q. Why did you not begin to compute depreciation on the COTP until January 1, 14 1996 even though the project manager declared the COTP commercially 15 operable as of March, 1993? 16 A. I did not begin to compute depreciation on the COTP as of March, 1993 17 because Vernon was constrained from making economic use of the facility 18 prior to January 1, 1996. The usefulness to Vernon of the COTP depended 19 upon Vernon being able to obtain permission from SCE to use the COTP to 20 reduce its billing demands from SCE, and the ability to obtain transmission 21 service from the terminus of the COTP/Nevada-Oregon Border ("NOB") to 22 Vernon. The usefulness to Vernon of the COTP also depended on Vernon 23 being able to enter into contracts for the purchase of capacity and associated 24 energy from Pacific Northwest suppliers of electricity given the above 25 described constraints. For various reasons, including the fact that Vernon had 0 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 23 of 40 1 entered into contracts for adequate supply from other sources, Vernon made 2 limited use of the COTP in 1995. 3 Q. Why did Vernon need approval from SCE to purchase capacity and associated 4 energy for transmission over Vernon's entitlements in the COTP/NOB? 5 A. Vernon needed SCE's approval for Vernon's purchase of capacity and 6 associated energy for transmission over Vernon's entitlements in the COTP 7 because of the contractual relationship between SCE and Vernon. Vernon 8 purchased capacity and energy from SCE in 1993 under a so-called Partial 9 Requirements Rate Schedule. That rate schedule provided that Vernon had 10 the right to purchase capacity and energy from third parties, with certain 11 constraints, and to look to SCE for the remainder of its requirements. That 12 right, embodied in Special Condition 12 ("SC 12") of SCE's Partial 13 Requirements Rate Schedule, allowed customers to add capacity sources and 14 reduce their billing demands to the extent the sources provided capacity at the 15 time of their respective monthly peak requirements from SCE. That approach 16 was described as "running against the meter" and the resources used were 17 referred to as "Non -Integrated Sources" or "SC 12 Sources." SC 12 is 18 attached as Exhibit No. VER-10. 19 Q. Were there provisions in SC 12 that imposed major constraints to the early 20 use of the COTP? 21 A. Yes. A major constraint to note about SC 12 in the context of this issue is that 22 it required Vernon to provide SC 12 notices sufficiently in advance to allow 23 SCE to adjust its supply portfolio to reflect Vernon's reduced requirements 24 from SCE. Specifically, SC 12 required Vernon to provide notice prior to 25 July 1 of odd -numbered years, by source, of Non -Integrated Sources to be 0 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 24 of 40 1 added during the 24-month period commencing 18 months after said July 1. 2 That notice requirement was particularly onerous to Vernon in the early years 3 after the COTP was declared commercially operable. Although Vernon now 4 has a 121 MW interest in the COTP, its initial interest was only 27 MW. It 5 obtained the additional interest in the COTP in November 1991 when SCE's 6 other municipal customers decided not to participate in the COTP. Vernon 7 claimed the interest of SCE's other municipal customers on behalf of the SCE 8 Control Area. But Vernon did not obtain that increased interest in the COTP 9 until after the July 1, 1991 cut-off date for noticing purchases and could not 10 use the increase in COTP entitlements to provide notice to SCE prior to July 11 1, 1993 to purchase increased capacity beginning January 1, 1995. 12 Q. Are you saying that the SC 12 noticing provision precluded Vernon from 13 using more than 27 MW of the COTP/NOB capacity prior to January 1, 1995? 14 A. Yes. However, SCE allowed Vernon to round the 27 MW up to 30 MW. 15 Even though Vernon had a 121 MW interest in the COTP (traded for 93 MW 16 of PG&E's interest in the NOB to Sylmar 500 kV DC line), and bore the cost 17 of the full 121 MW, it owned entitlements of only 27 MW prior to the July 1, 18 1991 cut-off date and, because of the 18 month notice requirement of SC 12, 19 could not schedule more than the noticed amount on the COTP prior to 20 January 1, 1995. 21 Q. What use did Vernon actually make of its COTP/NOB entitlements in the 22 1993-1994 time period? 23 A. Vernon was able to contract for and schedule 21 MW in the summer months 24 of 1993 for replacement capacity while its diesels were undergoing 25 maintenance. Vernon scheduled 30 MW of capacity in July 1994 and 20 MW Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 25 of 40 1 in August and September 1994, in addition to various non -firm energy 2 purchases. Vernon purchased only 20 MW of capacity under firm contracts 3 under each of the months of May and June 1995 for transmission over the 4 COTP. 5 Q. What do you conclude with respect to the availability of Vernon's 6 entitlements in the COTP for the period 1993-1994? 7 A. Vernon did not know as of June 30, 1991, the cut-off date for giving SCE 8 notice of its SC 12 capacity additions, that it would purchase the Cities' 9 interests in the COTP. The additional capacity was thus not available to 10 Vernon until January 1, 1995, eighteen months from the July 1, 1993 cut-off 11 date. Further, the unsettled nature of transmission from the terminus of the 12 COTP to Vernon constrained Vernon from entering into contracts to make 13 full use of the 27 MW of capacity it had as of June 30, 1991. The COTP thus 14 was not "commercially available" to Vernon until January 1, 1995. As 15 discussed below, the COTP was not economically useful to Vernon for the 16 year 1995 also. 17 Q. Why did Vernon purchase a large interest in the COTP? 18 A. Vernon believed that it would be necessary to obtain generation supplies in 19 the Pacific Northwest and desert southwest, and had been trying throughout 20 the 1980's, with limited success, to purchase transmission entitlements from 21 SCE. Vernon had been negotiating and litigating with SCE to obtain those 22 transmission rights. Therefore, Vernon purchased the additional capacity of 23 SCE's other municipal customers (approximately 96 MW) when that capacity 24 became available. Vernon intended from the beginning that it would use any 25 capacity in the COTP in excess of its market requirements to render Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 26 of 40 1 transmission or sales services to other utilities. Vernon believed that even if 2 the capacity were greater than Vernon's requirements at the time, there would 3 soon be a ready market for the transmission. Vernon was willing to risk 4 underutilization of the COTP in the early years in exchange for the valuable 5 service the line could render in later years. 6 Q. Has the Commission recognized that in some instances it is appropriate to 7 declare a commercial operation date different from the in-service date? 8 A. Yes. The Commission recognized with respect to SCE's SONGS 2 9 generating station that in some instances it is appropriate to declare a 10 commercial operation date different from the in-service date. There, SCE met 11 its in-service criterion in November, 1982 by producing test energy at the 50 12 percent power level, but did not declare SONGS 2 commercially operable 13 until August 8, 1983. SCE argued that its voluntary deferral of the effective 14 date for the increased rates resulting from SONGS 2, ensured that ratepayers 15 would not bear any of the costs associated with SONGS 2 prior to it becoming 16 commercially operable. The Commission allowed SCE to continue to accrue 17 AFUDC through August 8, 1983. 53 FERC ¶ 61,408 at pp. 62,415, 62,418. 18 Vernon's situation is analogous to SCE's SONGS 2 situation. In both 19 instances it is inappropriate for customers to begin paying for facilities that 20 will be lightly used in the present but more fully used later. Also see 21 SunShine Interstate Transmission Company ("SITCO'), where SITCO strived 22 to reduce its initial rates by three methods, each of which had the effect of 23 deferring recovery of costs. 67 FERC ¶ 61,229 at pp. 61,704-06. There, the 24 Commission approved SITCO's deferred recovery mechanism, noting that 25 under the non-traditional ratemaking approach it would not be able to fully Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 27 of 40 1 utilize the capacity of its facilities during the first four years of operation, and 2 the deferred recovery rate was a means for SITCO's potential shippers to 3 offer it an incentive to construct a pipeline system that is adequately sized to 4 serve the potential market. 5 Q. Does fairness and equity support your proposal to defer depreciating the 6 COTP until the facility becomes useful to Vernon and its customers? 7 A. Yes. I have pointed out above that contractual and rate schedule constraints 8 prevented the facility from becoming used and useful to Vernon even though 9 the facility itself was commercially operable. Vernon entered into the 10 contracts to purchase interests in the COTP very much aware that it would be 11 unable to obtain economic benefit from those projects in the near term. But 12 Vernon realized that those facilities would be needed by the SCE control area 13 in the long term. Vernon therefore financed the project with the intention that 14 it would provide sales and/or transmission service to third parties at a profit. 15 While Vernon was aware of the contractual constraints, Vernon was also 16 aware that the entitlements to the capacity in the COTP were valuable and 17 economically feasible in the long term. 18 Q. What use did Vernon make of the COTP in 1995? 19 A. For various reasons, including the fact that Vernon had entered into contracts 20 for adequate supplies from other sources, Vernon made little use of the COTP 21 in 1995. Vernon's only purchases under firm contracts for transmission over 22 the COTP were for 20 MW from Bonneville Power Administration in each of 23 the months of May and June. Vernon's use of the COTP for transmission of 24 non -firm energy in 1995 was also very limited. I have credited the value of 25 the transmission of both firm and non -firm energy over the COTP during Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 28 of 40 1 1993, 1994, and 1995 to the Gross Plant to be included in the rate base herein. 2 Q. Did Vernon have discretion to make use of the COTP/NOB in 1995? 3 A. Yes. Vernon could have provided notice to SCE prior to July 1, 1993 of the 4 sources of its capacity purchases for the 24 months beginning January 1, 5 1995, including purchases that would utilize the COTP/NOB facilities, and 6 Vernon did so. Exhibit No. VER-11 contains June 29, 1993 letters from 7 Vernon to SCE noticing the 20 MW SC 12 purchase from BPA and an 80 8 MW SC 12 purchase from SCE, both to begin January 1, 1995. Note that in 9 both letters Vernon reserves the right under the notices to sell the capacity and 10 associated energy to other utilities. Note also, that both letters make reference 11 to an ongoing dispute between SCE and Vernon about notices under SC 12. 12 SCE insisted that when Vernon gave notice for capacity from a specific 13 source, Vernon could not later replace that capacity or energy with purchases 14 from a different source. Of particular relevance here is the fact that that SCE 15 was willing to sell 80 MW of capacity to Vernon under SC 12 in competition 16 with its sales under its Partial Requirements Rate Schedule R 7.4. That sale 17 indicates (1) Vernon's participation in the COTP had the commendable effect 18 of providing competition that resulted in reduced rates in SCE's service area; 19 and, (2) capacity and associated energy imported from outside SCE's service 20 area was, in fact, available at costs lower than costs under SCE's Partial 21 Requirements rate schedule. 22 Q. Given that Vernon had the discretion to notice in 1993, and make greater use 23 of the COTP/NOB in 1995, why is it appropriate to continue to accrue 24 AFUDC on the project after December 31, 1994? 25 A. Commission precedent is that the accrual of AFUDC should cease when the Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 29 of 40 1 facility is declared to be commercially operable. That precedent is designed 2 to prevent a utility from earning a return on the portion of its rate base 3 financed by its customers through AFUDC. Vernon and its retail customer 4 got very little use of the COTP/NOB in 1995, and to the extent they did utilize 5 the line, I credited the value of the transmission service to the Gross Plant. As 6 of December 31, 1995, Vernon and its retail customers have not been 7 compensated, in terms of service or rates, for their investment in the 8 COTP/NOB. I have accrued AFUDC on the COTP to allow them to earn a 9 fair return on their investor -contributed capital, whenever the opportunity to 10 do so arises. 11 Q. How do you justify establishing rates here to recoverl995 COTP costs? 12 A. My accrual of AFUDC costs in 1995 is consistent with widely used pricing 13 practices in the business world. Most businesses other than utilities do not 14 expect to recover their costs of facilities in the period in which they are 15 incurred. It may take many years for a market to develop to recover the costs 16 of designing and manufacturing new products. In fact, the natural gas 17 industry recovers the up -front cost of exploration and development of gas 18 wells by depleting their costs over the productive life of the wells. Here, 19 Vernon was aware that the market for service over the COTP would not 20 support the investment in the near term, but believed the project would be 21 economically feasible in the long term. It would be inappropriate for Vernon 22 and its retail customers to bear the burden of the investment in the near term, 23 but then turn the project over to the ISO at cut-rate prices at a time when 24 Vernon could otherwise begin to realize revenues that would offset that loss. 25 That is particularly true given that the ISO would incur substantially greater 7 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 30 of 40 1 costs to construct alternative comparable facilities. Further, the term 2 "depreciation" as defined in Part 101 of the Uniform System of Accounts, 3 considers "changes in demands and requirements" as causes to be given 4 consideration. The term "amortization" considers the period over which the 5 anticipated benefit will be realized. 6 Q. What is your recommendation given your above testimony? 7 A. I have determined that the COTP was not commercially available to Vernon 8 until January 1, 1996, at which time I ceased accruing AFUDC on the COTP 9 and began depreciating the facilities. 10 Q. Is your recommendation consistent with Commission precedent? 11 A. I believe that my recommendation is consistent with the logic behind 12 Commission precedent. Commission precedent generally supports the 13 proposition that once a facility becomes commercially operable, AFUDC 14 ceases. That precedent follows from the logical conclusion that a utility is not 15 entitled to earn a return on that portion of its rate base financed by its 16 customers. Canadian River Gas Co., 3 FPC 32 (1942). Here, Vernon and its 17 retail customers advanced funds for the COTP prior to it becoming used and 18 useful to them, in full knowledge that their gratification for the use of those 19 funds would be deferred. They have a right to earn a fair return on that 20 investor -contributed capital, whenever the opportunity to do so arises. 21 Q. Explain your computation of AFUDC. 22 A. My computation of AFUDC is set forth in Schedule 3 of Exhibit No. VER-8. 23 That schedule shows that I applied a 12.65 percent AFUDC rate to the 24 cumulative Cash Calls and AFUDC each month. 25 Q. Have you reflected in your Gross Plant the value of the service Vernon received Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 31 of 40 1 from transmission on the COTP prior to your beginning to depreciate the COTP? 2 A. Yes. As I stated above, I show on Schedule 3 the crediting of the value of 3 transmission service Vernon received prior to beginning to depreciate the facility. 4 Q. Why did you use and AFUDC rate of 12.65 percent? 5 A. I used an AFUDC rate of 12.65 percent because that was the overall rate of return 6 last approved by the Vernon City Council for Vernon's electric operations prior to 7 the month I ceased accruing AFUDC. The practice before any rate reviewing 8 regulatory body, whether it is the state Public Utility Commission, the Federal 9 Energy Regulatory Commission, or a Municipal City Council, is that rates, 10 including formulary rate making procedures such as Energy Cost Adjustment 11 Clauses, remain in effect until changed by the rate reviewing body. The 12.65 12 percent rate of return is the Rate of Return I recommended to the City Council in 13, my December 1983 and May 1984 Rate Reports to this City Council, and is the last 14 overall rate of return the Vernon City Council has approved for Vernon's electric 15 operations prior to the month I ceased accruing AFUDC. That overall rate of return 16 last approved by the rate reviewing body applies to AFUDC as well as to plant in 17 service. My use of the last overall rate of return approved by the Vernon City 18 Council is consistent with the FERC's prescribed method of computing AFUDC. 19 The Commission's Electric Plant Instruction No. 3(A)(17) generally provides that 20 the AFUDC rate is to be computed as the weighted average cost of money used to 21 finance the construction. The overall rate of return approved by the Vernon City 22 Council is the best proxy available for Vernon's average cost of money used to 23 finance the projects. That conclusion is consistent with the FERC's Electric Plant 24 instruction No. 3(A)(17)(b), which provides that the cost rate for common equity 25 shall be the rate granted common equity in the last rate proceeding before the 26 ratemaking body having primary rate jurisdiction. 27 Q. Explain the rate studies that form the basis. for the use of a 12.65 percent AFUDC 0 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 32 of 40 1 rate. 2 A. I presented to the Vernon City Council in December 1983 a study of Vernon's retail 3 rates, rate design, and rate schedules. I recommended in that study a cost of service 4 for Vernon's retail sales and recommended changes in Vernon's rates that were 5 necessary to track changes SCE proposed to make in its wholesale rates in its rate 6 increase filing in FERC Docket No. ER84-75. I recommended at Page 8 of that 7 December 1983 Report a 12.65 percent rate of return. I prepared and presented to 8 the City Council a supplement to that report in May 1984 to track further changes in 9 SCE's rate increase filing in its FERC Docket No. ER84-75. I did not propose 10 changes to the 12.65 percent rate of return in the May 1984 Report, and the City 11 Council adopted the May 1984 Report without change by Resolution No. 5076 on 12 May 15, 1984. 13 Q. What was the basis for your recommendation of a 12.65 percent rate of return? 14 A. I explain at page 8 of the December 1983 Report that the 12.65 percent was based 15 on SCE's cost of capital as determined by the CPUC because Vernon's experience 16 with financing was too limited to use as a measure of the cost of capital and that a 17 more appropriate measure of Vernon's cost of capital is the requirements of a utility 18 that makes frequent transactions in the bond and stock markets. Further, to my 19 knowledge, Vernon has been in intense competition with SCE for the attraction of 20 industry into their respective service areas beginning at least as early as 1980. The 21 leadership of the City of Vernon has been acutely aware that Vernon's rates must 22 not only be competitive with SCE's rates, but if possible, lower, because Vernon is 23 an industrial city. Vernon thus had no captive customers, at least in the sense that 24 other municipal utilities had residential and commercial customers whose 25 requirements were presumably price inelastic. I personally met with industrial 26 entities to discuss comparisons of Vernon's rates with SCE's rates. It was thus 27 necessary that the return component of Vernon's rates not be so high as to make • 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 33 of 40 1 Vernon's rates noncompetitive with SCE's rates. However, the return component 2 needed to be high enough to generate cash flow from which to fund projects to 3 facilitate the introduction of electricity that might be cheaper than alternative 4 purchases from SCE. Vernon's return requirements thus needed to reflect return 5 sufficient to help fund future construction requirements. Establishing a rate of 6 return at the level of SCE's rate of return seemed to accommodate both objectives, 7 (generating capital while remaining competitive) particularly because Vernon 8 believed it could obtain capacity and energy at costs below the costs that Vernon 9 would incur in purchasing from SCE. 10 Q. Has Vernon utilized internally generated funds to acquire generation and 11 transmission facilities? 12 A. Yes. In addition to the transmission facilities Vernon turned over to the ISO 13 for operational control, and improvements in the distribution system, Vernon 14 has renovated its diesel generation facilities, constructed a gas turbine 15 generating facility, and funded an interest in the output of the Hoover 16 hydroelectric project, all with internally generated funds. Thus, Vernon has 17 utilized funds generated by cash flow to fund projects to acquire capacity and 18 energy from sources other than SCE, for the benefit of Vernon's customers. 19 These projects have provided economical alternatives to purchases from SCE 20 and have enabled Vernon to remain competitive with SCE. 21 Q. Does Vernon currently carry AFUDC on its records? 22 A. No. Vernon does not carry AFUDC in its records as a component of Gross 23 Plant and I therefore had to compute AFUDC for the purpose of computing 24 Vernon's transmission revenue requirements. However, it will be appropriate 25 to maintain records so that Vernon may establish rates in future proceedings 26 at the Commission that reflect Vernon's ratemaking here. That is, Vernon Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 34 of 40 1 must maintain records to reflect in future Commission proceedings the 2 amounts of AFUDC capitalized in the computations of TRR here, and the 3 depreciation of the AFUDC in future years based on depreciation rates 4 established herein. 5 Q. Explain Line 2 of Exhibit No. VER-8. 6 A. Line 2 of Exhibit No. VER-8 shows the accumulated depreciation on the 7 subject facilities. Schedule 2 shows the computation of depreciation, by 8 month, subsequent to time when I ceased accruing AFUDC and began 9 depreciating the plant through June 1999, the end of the test period used 10 herein. Part 1 of Schedule 2 shows the calculation of depreciation for the 11 COTP, and Part 2 of Schedule 2 shows the calculation of depreciation of 12 MAP and MPP. Vernon developed a depreciation rate of 2.857 percent per 13 year using a 35 year life to compute the annual depreciation for book 14 purposes, and I applied that rate to the total Gross Plant computed on 15 Schedule 3, including the AFUDC component. 16 Q. Explain Line 3 of Schedule 1. 17 A. Line 3 of Schedule 1 shows the Net Plant, or Rate Base, which represents 18 Vernon's investment, on which it should earn a return. 19 Q. Explain Line 4 of Schedule 1. 20 A. Line 4 of Schedule 1 shows the Rate of Return, which represents the rate to 21 apply to the rate base to compute Vernon's return requirements on the 22 facilities it turned over to the ISO for operational control. Mr. Hanley 23 supports a Rate of Return of 9.51 percent, which he has determined to be 24 conservative. However, the Vernon City Council has in the past approved a 25 rate of return tied to SCE's rate of return, which is the same approach as • 0 Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 35 of 40 1 approved by the Commission in its October 17, 2000 order. Partly for 2 competitive reasons, Vernon traditionally has not set a target Rate of Return 3 higher than SCE's requested Rate of Return. I therefore have retained the 4 9.29 percent Rate of Return adopted by the City Council. 5 Q. Explain Line 5 of Schedule 1. 6 A. Line 5 of Schedule 1 shows the dollar amount of return on rate base Vernon is 7 entitled to, computed by multiplying the Net Plant on Line 4 by the Rate of 8 Return on Line 5. 9 Q. Explain Line 6 of Schedule 1. 10 A. Line 6 of Schedule 1 shows the annual depreciation expense to be included in 11 the TRR, using a depreciation rate of 3.14 percent. That depreciation rate was 12 supplied by Mr. Feinstein. 13 Q. Please explain how Vernon's Operation and Maintenance expenses were 14 derived on Line 7 of Schedule 1. 15 A. Vernon has ownership entitlements in COTP, MAP, and MPP. The 16 transmission projects are operated by third parties under operation 17 agreements. The non -capital related charges billed to Vernon under these 18 agreements are reflected in Vernon's TRR as "O&M expense (owned 19 projects). The expenses reflected are fiscal year ending 1999 amounts. 20 Q. Please explain how the Administrative and General expenses were developed 21 on Line 8 of Schedule 1. 22 A. Vernon's Administrative and General Expenses were developed based on 23 costs allocated to the resource planning division (Department 9200) from the 24 Administrative Division (Department 9000) and allocated within the 25 Department 9200 to the transmission function. The costs include the Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 36 of 40 1 following: 2 1. A portion of the Department 9000 costs were allocated to Department 3 9200 based on the number of full time employees in Department 9200 4 to the total number of employees in the Light and Power Department 5 (see Workpaper AH 1 of 7). 6 2. Salaries for directly involved employees were allocated to the 7 transmission function based on the time allocation factors. 8 3. Employee's benefits associated with the above assignments were 9 allocated based budget figures. 10 4. The assigned cost from Department 9000 to Department 9200 plus 11 other general expenses of 9200 were allocated by a labor factor to 12 transmission. The labor factor was based on ratio of salary assigned to 13 transmission to the total salary of department 9200. The ratio result 14 was 24%. 15 The Administrative and General Expenses allocation results in $137,997 in 16 salary and benefits assigned to transmission from Department 9200 plus 17 $40,753 from expenses assigned from Department 9000 to Department 9200 18 plus general expenses from Department 9200. The $40,753 was inadvertently 19 omitted from Mr. Clark's August 2000 testimony. 20 Q. Please explain the derivation of property taxes shown on Line 9 Schedule 1 in 21 the TRR. 22 A. Vernon pays property taxes directly to the States of Nevada and Arizona for 23 Vernon's share of MAP and MPP. Property taxes directly billed to Vernon in 24 the test year by the States of Nevada and Arizona related to MAP and MPP 25 are reflected in the TRR as "Property tax". Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 37 of 40 1 Q. Please explain how the Regulatory Expenses were derived on line 10 of 2 Schedule 1. 3 A. While Vernon's actual fiscal year 1999 regulatory expenses amounted to 4 $597,361, Vernon estimated a more normal expense would be $350,000. 5 Q. Explain Line 11 of Schedule 1. 6 A. Line 11 of Schedule 1 shows the TRR of the facilities turned over to CAISO 7 operational control (excluding transmission services) to be $10,822,635. 8 Q Please explain how Vernon's transmission service expenses were derived on 9 Line 12 of Schedule 1. 10 A. Transmission service expenses include Vernon's cost for transmission service 11 under bills it receives from SCE and the Los Angeles Department of Water 12 and Power under existing transmission service contracts that continue to 13 remain in effect. Vernon places its contract transmission entitlements under 14 the CAISO operational control. Service under a portion of one of these 15 contracts was discontinued in 1999 until December 31, 2007. The cost of this 16 contract has thus been excluded from the TRR. The costs to Vernon under 17 these agreements are reflected in Vernon's TRR as "Transmission service." 18 In the case of the transmission service received from SCE, these costs simply 19 represent a pass through by Vernon of charges by SCE that have been 20 previously approved by the Commission as jurisdictional service under the 21 FPA. 22 Q. Please explain Line 13 of Schedule 1. 23 A. Line 13 includes the portion of Vernon's TRR related to Vernon's facilities of 24 $10,822,635 plus the portion of Vernon's TRR related to transmission service 25 from Line 12 of $1,431,162, for a total recommended Vernon TRR of Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 38 of 40 1 $12,253,797. 2 Q. What are your conclusions regarding the TRR on the facilities Vernon turned 3 over to the CAISO for operational control? 4 A. I have computed TRR on the facilities Vernon turned over to the CAISO for 5 operational control using revenue requirements principles consistent with 6 principles long used by the Commission, as adapted to the particular situation 7 here, and believe the $10.8 million TRR to be fair and reasonable. The 8 Commission noted that the Court rejected an argument that Vernon's TRR 9 must be independently subjected to the just and reasonable standard of 10 Section 205 of the FPA. Further, the Commission's February 17, 2004 order 11 establishing this proceeding establishes a hearing to ascertain whether 12 Vernon's TRR results in a just and reasonable rate for the CAISO. 13 Q. Have you tested to determine whether Vernon's TRR of $10.8 million on the 14 facilities it turned over to the CAISO for operational control results in a just 15 and reasonable rate for the CAISO? 16 A. Yes. I have tested my calculation of Vernon's TRR against a calculation of 17 those revenue requirements assuming the facilities were owned by SCE. 18 Exhibit No. VER-12. I changed the calculation of AFUDC on the three 19 Vernon projects, the COTP, MPP, and MAP, by using SCE's rate of return as 20 a capitalization rate and beginning depreciation of the COTP as of the official 21 date of commercial operations, March 1993, and computed a Net Plant (Rate 22 Base) of $56.2 million. That $56.2 million represents: (1) the cost of Plant 23 (Cash Calls) as they were billed to Vernon, plus (2) AFUDC computed using 24 SCE's capitalization rate applied over the period from the beginning of the 25 development until the commercially operable date, plus (3) Administrative Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 39 of 40 1 and General Plant, less (4) accumulated depreciation computed assuming a 42 2 year life and a 33 percent negative salvage value. From Sheet 1 of SCE's 3 Period II Statement BK,3 SCE's total CAISO Revenue Requirements 4 amounted to $209,277,000, and its Rate Base amounted to $1,056,252,000. 5 SCE's Revenue Requirements thus amount to 19.81 percent of Rate Base. 6 The revenue requirements on Vernon's facilities, if owned by SCE, would 7 thus be $56,160,442 * .1981, or $11,125,384. That SCE ownership cost of 8 $11.1 million compares with Vernon's ownership cost of $10.8 million. 9 Thus, Vernon's TRR on those facilities is approximately the same as, plus or 10 minus a small increment, what the TRR would be if the facilities were owned 11 by SCE. 12 Q. What are the implications of your conclusions that Vernon's TRR is 13 approximately the same as, plus or minus a small increment, what the TRR 14 would be if those facilities were owned by SCE? 15 A. I conclude that the inclusion of Vernon's TRR for its facilities and 16 transmission service of $12,253,797 in the CAISO does not make the CAISO 17 rates unjust and unreasonable. From my testimony above, Vernon's 18 transmission facilities are designed to import energy into SCE's control area, 19 and perform a service identical to the service performed by SCE's high 20 voltage import transmission facilities. I presented extensive testimony in 21 Docket No. ER97-2355 describing Vernon's transmission facilities and 22 comparing those facilities and their functions in serving SCE's control area 23 with SCE's facilities. Based upon that testimony, Presiding Administrative 3 Attached as VER-13 is SCE's response to a Vernon data request and the Statement BK sheets therein referred to. Docket Nos. EL00-105, et. al. Exhibit No. VER-7 Page 40 of 40 1 Law Judge Michel Levant in his March 31, 1999 Initial Decision, 86 FERC ¶ 2 63,014, reversed in non -relevant part, 92 FERC T 61,170 (2000), presents 3 extensive discussion of that testimony at pp. 65,159-65, and citing my direct 4 testimony in that proceeding (Exhibit No. V-8), finds that Vernon's 5 transmission facilities were planned, constructed, and operated to serve the 6 total load of the SCE system. He states, for instance, 86 FERC p. 65,170: 7 The record establishes that Resale Cities' transmission facilities which 8 were integral to meeting SCE loads, continue to contribute to the 9 capability and reliability needs of the overall system. [Citations 10 omitted. ] It is also clear from the record that the ISO control area and 11 all customers of the ISO receive reliability benefits from the 12 transmission facilities in which Vernon and Cities hold various 13 entitlements/rights .... 14 15 Moreover, the history of the relationship between SCE and the Resale 16 Cities shows that Vernon's and the Cities transmission facilities were 17 planned, constructed and operated to serve the total load of the SCE 18 Central area. [Citations omitted. ] This is highly relevant to a finding of 19 integration in this case. 20 21 22 Q. What is your overall conclusion? 23 A. I conclude that Vernon's total annual TRR should be $12,253,797, before 24 Transmission Revenue Balancing Account Adjustments ("TRBA"). 25 Q. Does this complete your testimony at this time? 26 A. Yes. • Exhibit No. VER-8 Schedule 1 of 3 City of Vernon, California Transmission Revenue Requirements Year Ended June 30, 1999 MAP Line & No. Description COTP MPP TOTAL A B C D -_ 1 iAverage Gross Plant in Service_ $56,005,429 $27,299,043 $83,304,472 2 rAccumulated Depreciation 4,798,1881 2,108,488 6,906,676 3 Net Plant $51,207,2411 $25,190,555 $76,397,797 4 - Rate of Return 9.29% ° o 9.29/oi 9.29/0 5 — Return on Rate Base_ $4,757,153 $2,340,203 $7,097,355 6 7 lAnnual Depreciation Expense— O&M Expense Owned roects p ( p 1 ) $1,758,570 --- 328,707 $857,190 $2,615,760 _ - --- — -- 117,114, 445,821 8 A&G Expenses 178,750 9 Property Tax 134,948 10 Regulatory Expenses 35 0000 11 12 j Facilities TRR Transmission Service Expenses $10,822,635 $1,431,162 13 Total TRR $12,253,797 Sources: Lines 1 and 2, Col. B: Attachment A. Schedule 2, Part 1. Lines 1 and 2, Col. C: Attachment A. Schedule 2, Part 2. Line 3: Line 1 Less Line 2. Line 4: Rate of Return on rate base of 9.29%. Line 5: Line 3 " Line 4. Line 6: Depreciation of Line 1 at 3.14 % per Mr. Feinstein. Line 7: Amount paid to operators per agreements. Line 8: Vernon A&G expenses allocated on labor ratio. Line 9: Amount paid to taxing authorities. Line 10: Estimated annual regulatory expenses. Line 11: Total TRR on facilities turned over to CAISO. Line 12: Cost under transmission service contracts turned over to CAISO. Line 13: Vernon's total TRR. E*No. VER-8 Schedule 2 of 3 Part 1 of 2 CITY OF VERNON Net Plant and Depreciation Test Period - Fiscal Year June 30, 1999 California -Oregon Transmission Project Service Life (Years) 35.00 Depreciation Rate 2.8571% Monthly Depreciation Rate 0.2381% California -Oregon Transmission Project Month Cash Calls A End of Month Gross Plant B Average Gross Plant C Depreciation D Accumulated Depreciation E Dec 95 Jan 96 + 0.00 55,972,396.87 55,972,396.87 55,972,3_96.87 133,267.61 133,267.61 Feb _ f 0.00 55,972,396.87 55,972,396.87 133,267.61 266,535.22 March 0.00 55,972,396.87 55,972,396.87 133,267.61 399,802.83 April 0.00 55,972,396.87 55,972,396.87 _ 133,267.61 533,070.45 May 0.00 55,972,396.87 55,972,396.87 133,267.61 666,338.06 June 0.00 55,972,396.87 55,972,396.87 133,267.61 799,605.67 July 0.00, 55,972,396.87 55,972,396.87 133,267.61 932,873.28 Aug 0.00 55,972,396.87 55,972,396.87 133,267.61 1,066,140.89 Sept woOj 55,972,396.87 55,972,396.87 133,267.61 1,199,408.50 OCT 692.00 ___55,9_7_3,088.87 55,972,742.87 133,268.44 1,332,676.94 NOV_ 0.00 55,973,088.87 ! 55,973,088.87 j 133,269.26 1,465,946.20 DEC 768.00 55,973,856.87 j 55,97_3,472.8_7 133,270.1 1,599,216.37 _ JAN 97 636.00 55,974,492.87' 65,974,174.87 ! 133,271.84 1,732,488.22 FEB - 589.00 55,975,081.87 55,974,787.37 133,273.30 1,865,761.52 MARCH --_0. 0.00 55,975,081.87 55,975,081.87 _� 133,274.00 1,999,035.53 APRIL 0.00 55,975,081.87 55,975,081.87 133,274.00 2,132,309.53 MAY 0.00 55,975,081.87 55,975,081.87 133,274.00 2,265,583.53 JUNE 966.00 55,976,047.87 55,975,564.87 133,275.15 2,398,858.69 JULY % 0.00 55,976,047.87 55,976,047.87 133,276.30 2,532,134.99 _ AUG 2,693.00 55,978,740.87 55,977,394.37 133,279.51 2,665,414.50 SEPT_ 0.00 55,978,740.87 55,978,740.87 133,282.72 2,798,697.22 OCT 0.00 55,978,740.87 55,978,740.87 133,282.72 2,931,979.94 NOV 0.00 55,978,740.87 55,978,740.87 133,282.72 3,065,262.65 DEC 0.00 55,978,740.87 55,978,740.87 133,282.72 3,198,545.37 JAN 98 0.00 55,978,740.87 55,978,740.87 133,282.72 3,331,828.09 FEB 0.00, 55,978,740.87 133,282.72 3,465,110.80 MARCH 0.00 55,978,740.87 __55,97_8,740.87 55,978,740.87 133,282.72 3,598,393.52 APRIL 0.00! 55,978,740.87 55,978,740.87 133,282.72 3,731,676.23 MAY 0.001 55,978,740.87 55,978,740.87 133,282.72 3,864,958.95 J_UN_E 0.00 55,978,740.87 55,978,740.87 133,282.72 3,998,241.67 JULY 1,669.00 55,980,409.87 55,979,575.37 133,284.70 4,131,526.37 AUG 1,121.00 55,981,530.87 55,980,970.37 133,288.02 4,264,814.39 SEPT 1,826.00 55,983,356.87i 55,982,443.87 133,291.53 4,398,105.93 OCT_ 1,033.00 55,984,389.87 ! 55,983,873.37 133,294.94 4,531,400.86 NOV 0.00 55,984,389.87! 55,984,389.87 4,664,697.03 DEC 39,842.00 56,024,231.87 56,004,310.87 ___133,296.17 133,343.60 4,798,040.63 JAN 99 0.00 56,024,231.87 ! 56,024,2_31.87 133,391.03 4,931,431.66 FEB �+ 0.00 56,024,231.87 56,024,231.87 133,391.03 5,064,822.68 MARCH - 6,407.00 56,030,638.87 1 56,027,435.37 133,3_98.66 5,198,221.34 APRIL 3,382.00 56,034,020.87' 56,032,329.87 133,410.31 5,331,631.65 _ MAY 0.00 56,034,020.87 ! 56,034,020.87 133,414 34 5,465,045.99 JUNE 0.00 56,034,020.87' S6,034,020.87 133,414.34 5,598,460.32 Average June 1998 - June 1999 56,005,428.87 4,798,187.73 Sources: Column A: Cash Calls from January 1996-June 1999 from WPs F to I. Column B: December Gross Plant from Schedule 3, Part 1. Columm E: Annual depreciation of Gross Plant at 2.8571 Percent (.2381 Percent per Month). Page 2 of 9 Aft. VER-8 Schedule 2 of 3 Part 2 of 2 CITY OF VERNON Net Plant and Depreciation Test Period - Fiscal Year June 30, 1999 Mead-Adelanto and Mead Phoenix Projects Service Life (Years) 35.00 Depreciation Rate 2.8571% Monthly Depreciation Rate 0.2381% Mead-Adelanto and Mead Phoenix Projects Month MPP Cash Calls A MAP Additions B End of Month Gross Plant C Average Gross Plant D Depreciation E Accumulated Depreciation F Apr-96 27,036,381.45 27,036,381.45 32,186.17 32,186.17 May 12,135.58 0.00 27,048,517.03 27,042,449.24 64,386.78 96,572.95 June 23,046.13 0.001 27, 71,563 16 27,060,040.10 64,428.67 161,001.62 July 45,482.00 33,972.36[ 27,151,017.52 27,111,290.34 64,550.69 225,552.31 Aug 13,271.83 2,867.01 27,167,156.84 27,159,087.18 64,664.49 290,216.80 Sept 6,352.91 1,477.691 27,174,987.44 27,171,072.14 _ 64,693.03 354,909.83 O_CT 10,896.44 6,151.401 27,192,035.28 27,183,5 11.36 64,722.65 419,632.48 NOV 1,689.25 406.12 27,194,130.65 27,193,082.97 64,745.44 484,377.91 _ DEC 1,127.07 2,588.811 27,197,846.53 27,195,988-59 64,752.35 549,130.27 JAN 97 18,091.92 _ 60,346.09 ! 27,276,284.54 27,237,065.54 64,850.1_6 613,98_0.42 FEB 0.00 453.431 27,276,737.97 27,276,_511._26 64,944.07 678,924.50 MARCH 0.00 __ 618.811 27,277,356.78 27,277,047.38 64,945.35 743,869.85 APRIL 581.53 -4,829.96i 27,273,_108.35 27,275,232.57 64,941.03 808,810.88 MAY 58.50 532.42 27,273,699.27 27,273,403.81 64,936.68 873,747.56 JUNE 0.00 1,515.52 27,275,214.79 27,274,457.03 64,939.18 938,686.74 JU_LY 0.00 27,275,214.79 27,275,214.79 64,940.99 1,003,627.73 AUG_ 10,095.20 27,285,309.99 27,280,262.39 44,953.0-1 1,068,580.73 SEPT 2153.80 27,287,463.79 27,286,386.89 64,967.59 1,133,548.32 _ CT O 14:215.08 27,301,678.87 27,294,571.33 64,987.07 1,198,535.39 NOV 27,301,678.87 27,301,678.87 65,004.00 1,263,539.39 DEC 5,384.501 27,296,294.37 27,298,986.62 64,997.59 1,328,536.98 JAN 98 T 27,296,294.37 27,296,294.37 64,991.18 1,393,528.16 FEB 27,296,294.37 27,296,294.37 64,991.18 1,458,519.33 MARCH 530.711 27,296,825.08 2_7,296,559.73 64,_991.81 1,523,511.14 APRIL 2,218.41I 27,299,043.49 27,297,934.29 64,995.08 1,588,506.22 MAY 27,299,043.49 27,299,043.49 4-,997.72 1,6- 53,503.95 JUNE _ - --------- 27,299,043.49 27,299,043.49 -6- 64,997.72 1,718,501.67 JULY 27,299,043.49 27,299,043.49l 64,997.72 1,783,499.39 AUG 27,299,043.49 27,299,043.49 64,997.72 1,848,497.11 SEPT_ 27,299,043.49 27,299,043.49 64,997.72 1,913,494.84 OCT _ 27,299,043.49 27,299,043.49 64,997.72 1,978,492.56 NOV_ 27,299,043.49 27,299,043.49 64,997.72 2,043,490.28 DEC 27,299,043.49 27,299,043.4 4 7.72 2,108,488.00 JAN99 27,299,043.49 27,299,043.49; 64,997.72 2,173,485.73 FEB 27,299,043.49 27,299,043.4 4 69 997.72 2,238,483.45 MARCH_ 27,299,043.49 27,299,043.49 64,997.72 2,303,481.17 APRIL 27,299,043.49 27,299,043.49 i 64,997.721i 2,368,478.90 MAY JUNE ---- 27,299,043.49 27,299,043.49 --- - 27,299,04 4 --- 27,299,043.49 __64,997.72 64,997.72 2,433,476.62 2,498,474.34 Average June 1998 - June 1999 27,299,043.49 27,299,043.49 2,108,488.00 Sources: Column A: MPP Cash Calls from W/Ps T, U and V. Column B: MAP Cash Calls from W/P AE. Column C: December Gross Plant from Schedule 3, Part 2. Column D: Cumulative Gross Plant. Columm E: Annual depreciation of Gross Plant at 2.8571 Percent (.2381 Percent per Month). Page 3 of 9 Exhihil N -8 Schedule Part 1 of 2 CITY OF VERNON Gross Plant -Cash Calls and AFUDC May 1985-December 1996 California -Oregon Transmission Project COTP AFUDC Rate Date Cash Call A AFUDC B Gross Plant C MAY 85 9,400.00 99.09 9,499.09 _12.65% 12.65% I JUNE 0.00 100.14 9,599.23 12.659). 1 JULY _ 2,632.00 128.94 12,360.17 12.651/b 'IAUG 0.00 130.30 12,490.46 12.65% _ ISEPT 1,598.00 148.52 14,236.98 12.65% jOCT - 13,272.80 290.00 27,799.78 12.65% NOV 1,297.20 306.73 29,403.71 12.65% DEC 0.00 309.96 29,713.67 12.65% ------ JAN 86 ------ 14,776.80 -- 469.00 -- 44,959.48 12.65% !FEB j 8,873.60 567.49 54,400.57 12.65% MARCH 14,636.21 727.76 69,764.54 12.65% APRIL 10_,400.31 845.07 81,009.92 12.65% MAY 29,906.47 1,169.24 112,085.63 12.65% JUNE 18,916.24 1,380.98 132,382.85 12.65% DULY 5,182.03 1,450.16 139,015.04 12.65% AUG 13,444.30 1,607.18 154,066.52 12.65% SEPT_____ 22,866.18 1,865.17 178,797.87 _ 12.65% OCT 17,358.00 2,067.81 198,223.68 12.65% NOV , 12,24_8.44 2,218.73 212,690.84 12.65% _ DEC 38,720.30 2,650.29 254,061.43 _ 12.65% JAN 87 10,400.31 2,787.87 267,249.61 12.65% FEB ------ j 12,465.87 - -- 2,948.67 282,664.15 12.65% MARCH 16,017.20 3,148.60 301,829.95 12.65% _' APRIL 12,520.23 3,313.77 317,663.95 12.65% ------- MAY _ -- 16,361.46 --- 3,521.18 -- 337,546.60 12.65% JUNE I, 14,531.44 3,711.49 355,789.53 12.65% JULY 15,129.37 3,910.10 374,829.00 12.65% AUG 4,910.25 4,003.08 383,742.34 12.65% SEPT 21,3U_3_0 4,270.48 409,375.11 12.65% OCT 1,503.88 4,331.35 415,210.34 12.65% NOV 11,306.26 4,496.20 431,012.80 _1_2.65% DEC _ 11,795.47 4,667.94 447,476.21 12.65% JAN 88_ 6,287.29 4,783.42 458,546.92 12.65% FEB 3,750.63 4,873.39 467,170.94 12.65% MARCH 6,685.91 4,995.24 478,852.09 12.65% APRIL _ 6,957.70 5,121.24 490,931.03 12.65% MAY 9,186.33 5,272.07 505,389.43 12.65% 9458121 5,427.35 520,274.90 12.65% (JUNE IJULY -� 8:099:19 _ 5,569.94 533,944.04 12.65% JAUG 6,486.60 5,697.04 546,127.68 12.65% iSEPT 6,2_32.94! 5,822.80 558,183.42 12.65% iOCT 6,758.391 5,955.43 570,897.24 12.65% jNOV 5,308.871 6,074.17 582,280.28 12.65% DEC 12,900.73 6,274.20 601,455.21 12.65% JAN 89 4,167.37 6,384.27i 612,006.85 12.65% IFEB 12,230.33 6,580.50 630,817.68 12.65% (,MARCH_________ 9,729.90 6,752.44 647,300.02 _ 12.6512.65%APRIL 6,468.48 6,8 19 81 660,660.31 12.65% MAY _ 851.59 6,973.441 668,485.34 12.650/ jJUNE i 4,656.58 7,096.04I, 680,237.95 12.65% !JULY_ j 0.00 687,408.80 12.65% IA 0.00 ___7,170.841, 7,246.431 694,655.23 12.65% 1SEPT 688.52 7,330.081 702,673.83 37704 7,421.87 711,472.74 L26 0.007,500.11! 718,972.8590/ EC 06 7,580.13' 726,643.58 Page 4 of 9 0 Exhibit N -8 Schedule Part 1 of 2 CITY OF VERNON Gross Plant -Cash Calls and AFUDC May 1985-December 1996 California -Oregon Transmission Project COTP AFUDC Rate Date Cash Call A AFUDC B Gross Plant C 12.65% JAN 90 0.00 7,660.03 i 734,303.61 FEB 0.00 7,740.78 742,044.40 _12.65% 12.65% MARCH 0.00 7,822.38 749,866.78 12.650/. APRIL 0.00 7,904.85 757,771.63 12.65% MAY 0.00 _ 7,988.18 765,759.80 12.65% DUNE 1,286.45 8,085.95 775,132.20 12.65% JULY 0.00 8,171.19 783,303.38 12.65% AUG 1,811.90 8,276.42 793,391.71 12.65% _ SEPT 0.00 8,363.67 801,755.38 12.65% OCT_ 0.001 _ 8,451.84 810,207.22 12.650/. iNOV 0.001 8,540.93 818,748.15 12.65% iDEC -- - _ 0.00 8,630.97 827,379.12 12.65% 'JAN 91 0.00� 8,721.95 836,101.08 12.65% !FEB 0.001 8,813.90 844,914.98 12.65% MARCH 0.00 8,906.81 853,821.79 12.65% JAPRIL 0.00; 9,000.70 862,822.49 12.65% MAY 0.001 9,095.59 871,918.08 12.65% JUNE ----0.00 -- - 9,191.47 881,109.55 12.65% JULY 0.00 9,288.36 890,397.91 12.65% AUG 0.00 _ 9,386.28 899,784.19 12.65% SEPT 0.00 9,485.22 _ 909,269.41 12.65% OCT 4,001,297.00 51,765.55 4,962,331.97 12.65% NOV 215,707.00 54,585.16 5,232,624.13 12.6501. DEC 131,090.00 56,542.49 5,420,256.62 12.65% JAN 92 15,966,040.00 225,447.21 21,611,743.83 12.65% FEB 1,319,374.00 241,732.201 ___ 23,172,850.03 12.65% MARCH 1,021,464.00 255,048.39 24,449,362.42 12.65% APRIL 696,055.02 265,074.61 25,410,492.05 12.65% MAY _ _ 334,881.00 271,399.141 26,016,772.19 12.65% JUNE 1,084,315.00 285,690.631 27,386,777.82 12.65% jJULY 615,823.00 295,194.081, 28,297,794.90 12.65% ;AUG 586,161.00 304,485.04; 12.65% 639,324.00 314,434.36! _29,188,440.94 30,142,199.29 _;SEPT 12.65% iOCT 852,418.00 326,734.921 31,321,352.22 12.65% NOV _ 565,876.00 336,144.53 32,223,372.75 12.65% tDEC 1,030,153.00 350,547.58' 33,604,073.33 12.65% JAN 93 322,519.00 357,642.831 34,284,235.16 12.65%_ FEB_ 754,771.00 369,369.52 i 35,408,375.68 12.65% MARCH 478,835.00 378,311.01 5,521.69 12.65% APRIL_ 1,126,342.001 394,172.561 37,786,036.26 12.65% MAY 161,833.0_0 400,033.79 8 47,903.05 12.65% JUNE 296,077.00 _ 407,371.96 39,051,352.00 12.65% JULY 1 180,026.001 413,564.11 39,644,942.11 12.65% AUG 169,981.00 419,715.65' 40,234,638.76 12.65% _ SEPT 0.001 424,140.15i 40,658,778.91 12.65% OCT -- - -- O.00r-- -- 428,611.29i 41,087,390.20 12.65% NOV 000i 433,129.57! 41,520,519.78 12.65% DEC 0.0W 437,695.48i 41,958,215.25 12.65% JAN 94 0.00 442,309.521 42,400,524.77 12.65% FEB 0.00i 446,972.201 42,847,496.97 12.W/. MARCH 0.001 451,684.031 43,299,181.00 12.65% APRIL IL_ _ 0.001 456,445.531 43,755,626.54 12.65% 12.65% MAY JUNE 0.00 0.00 461,257.23 466,119.65 44,21644,216,883.77 44,683,003.42 12.65% JULY 0.00 471,033.33 45,154,036.74 12.65% AUG 667,859.00 483,039.15 46,304,934.89 12.65% SEPT 76,238.00 488,934.86 46,870,107.76 12.65% OCT 90,514.00 495,043.22 47,455,664.98 12.65% NOV 10,566.00 500,373.18 47,966,604.16 12.65% DEC 13,546.00 505,790.75 48,485,940.91 Page 5of9 Exhibit N -8 Scheduie3 Part 1 of 2 CITY OF VERNON Gross Plant -Cash Calls and AFUDC May 1985-December 1996 Califomia-Oregon Transmission Project COTP AFUDC Rate Date Cash Call A AFUDC B Gross . Plant C 12.65% 1JAN 95 64,072.001 511,798.05 49,061,810.97 12.65% jFEB 6,861.001 517,265.58 49,585,937.55 12.65% !MARCH 16,444.00_L__ _ 522,891.77 50,125,273.32 12.65% IAPRIL 0.001 528,403.92 50,653,677.25 12.65% ;MAY 199,600.00 536,078.30 51,389,355.54 12.65% IJUNE _ 0.001 _ 541,729.46I 51,931,085.00 12.65% iJULY 12.65% !AUG 0.001 0.001 547,440.199 553,211.12, 52,47�8,525.19 53,031,736.31 ------- ----- 12.65% ISEPT 0.001 _ 559,042.89 53,590,779.19 12.65% IOCT 0.001 564,936.13 54,155,715.32 _ 12.65% NOV 0.00 570,891.50 54,726,606.82 12. 550% lDEC 0.001 576,909.65 55,303,516.47 total $34,211,366.40 $21,092,150.07 $55,3U3,516.4/ Less Value of Firm Transmission (1) -$487,786.00 Less Value of Nonfirm Transmission (2) -$270,415.60 Non -firm Transmission service -$3,361.00 A&G Plant $1,430,443.00 Total Plant $55,972,396.87 Sources: AFUDC Rate: City of Vernon Report on Rate Design. Cash Call May 1985 - February 93: W/P A. Cash Call Feb 93 - June 93: W/P C. Cash Call July 93-June 94: W/P D. Cash Call July 94-June 95: W/P E. Cash Call July 95-Dec 95: W/P F. A&G Plant from W/P AM (1) 2.6 $/MWH' 730 hours/month' 257 MW Month 487,786.00 (2) t MWH MWH t $0.00260 22,656,000 58,905.60 $0.00260 23,147,000 60,182.20 $0.00260 58,203,000 151,327.80 $0.00260 104,006,000 270,415.60 Page 6 of 9 9 Exhibit No. VER-8 Schedule 3 of 3 Part 2 of 2 CITY OF VERNON Gross Plant, Cash Calls and AFUDC January 1988 -April 1996 Mead-Adelanto and Mead Phoenix Projects AFUDC Rate Date MAP Cash Call A MPP Cash Call B Total Cash Call C AFUDC D Total Gross Plant E 12.65% 12.65% ' JAN 88 i FEB 0.00 125.55 0.00 0.00 - 0.00 125.55 0.001 1.32 0.00 126.87 12.65% MARCH 187.06 0.00 187.06 3.311 317.24 12.65% .APRIL ( 0.00 0.00 0.00 _ 3.341 320.59 12.65% MAY 1,005.41 0.00 1,005.41 13.9811 1,339.98 12.65% !JUNE 67.84 0.00 67.84 14.84 j 1,422.66 12.65% (JULY 0.00 0.00 0.00 15.00 1,437.65 12.65% !AUG 1,161.08 0.00 1,161.08 27.39; 2,626.13 12.659/6 1 SEPT 254.69 0.00 254.69 303'71 2,911.19 12.65% 12.650io 1OCT i NOV 0.00 0.00 0.00 0.00 0.00 0.00 30.691 31.01 2,941.88 2,972.89 12.65% DEC 0.00 0.00 0.00 31.34 3,004.23 12.65% JAN 89 0.00 0.00 0.00 31.67 3,035.90 12.65% ! FEB 28.60 0.00 28.60 32.30 3,096.80 12.65% j MARCH 22.27 _ 0.00 22.27 32.88 3,151.95 12.65% ,APRIL 18.82 0.00 18.82 33.43 3,204.20 12.65% 12.65% MAY !JUNE 56.96 209.46 0.00 0.00 56.96 209.46 34.38 36.95 3,295.54 3,541.94 12.65% 'JULY 391.58 0.00 391.58 41.47� 3,974.99 12.65% 12.65% ,AUG ISEPT 1,055.24 725.09 0.00 0.00 1,055.24 725.09 53.03 61.23 _ 5,083.26 5,869.58 12.65% OCT 1,143.72 _ 0.00 11143.72 73.93 j 7,087.23 12.65% NOV 1,131.39 0.00 1,131.39 86.641_ 8,305.26 12.65% DEC 0.00 0.00 0.00 87.5511 8,392.61 12.65% _ JAN 90 1,493.83 0.00 1,493.83 104.221 9,990.86 12.65% FEB 2,274.55 0.00 2,274.55 129.30! 12,394.71 12.65% MARCH 1,676.42 0.00 11676.42 148.331 14,219.46 12.650/ APR IL 1,623.69 0.6 1,623.69 167.011 16,010.16 12.65% MAY 2,036.66 0.00 2,036.66 190.24 18,237.07 12.65% JUNE 9,670.69 0.00 9,670.69 294.19! 28,201.95 12.65% JULY 0.00 0.00 0.00 297.3011 28,499.25 12.650/6 AUG 0.00 0.00 0.00 300.43 28,799.68 12.65% SEPT 98.001 0.00 98.00 304.631 29,202.31 12.650/6 OCT 69,315.10 0.00 69,315.10 1,038.54' 99,555.94 12.65% NOV 10,955.231 0.00 10,955.23 1,164.97, 111,676.15 12.65% DEC 0.00�_ 0.00 0.00 1,177.251 112,853.40 12.65% JAN 91 0.00' 0.00 0.00 1,189.661 114,043.06 12.650/6 FEB 0.00 0.00 0.00 1,202.20 115,245.26 12.65% MARCH_ 0.00 0.00 0.00 1,214.88 116,460.14 12.65% APRIL _ 5,923.00I 0.00 5,923.00 1,290.12 123,673.26 1_2 65% MAY 12,926.76 0.00 12,926.76 1,439.99 138,040.02 12.65% _ JUNE 22,698.131 _ 0.00 22,698.13 1,694.451 162,432.59 12.6516 JULY 0.00' 0.00 0.00 1,712.311, 164,144.90 12.65% AUG 0.00 0.00 0.00 1,730.36 165,875.27 12.65% SEPT 0.00! _ 0.00 0.00 1,748.60 167,623.87 12.65% OCT 0.00 0.00 0.00 1,767.03 169,390.90 _ 12.65% ---- NOV --- 4,905.001 ---- 0.00 -- 4,905.00 1,837.37 176,133.27 12.65% 1 DEC 1 378,925.001 0.00 378,925.001; 5,851.24 560,909.51 Page 7 of 9 Exhibit No. VER-8 Schedule 3 of 3 Part 2 of 2 CITY OF VERNON Gross Plant, Cash Calls and AFUDC January 1988 - April 1996 Mead-Adelanto and Mead Phoenix Projects AFUDC Rate Date MAP Cash Call A MPP Cash Call B Total Cash Call C AFUDC D Total Gross Plant E 'JAN 92 110,666.88 47,056.00 157,722.88 7,575.58 12.65% _ 726,207.97 12.65% , FEB 47,480.27 16,855.00 64,335.27 8,333.64' 798,876.89 12.65% MARCH 39,030.01 23,530.00 62,560.01 9,080.981 870,517.88 12.65% APRIL 0.00 13, 308.00 13, 308.00 9,317.001i 893,142.88 12.65% MAY 124,096.73 17,548.00 141,644.73 10,908.39 1,045,695.99 _ 12.65% IJUNE 30,116.18 1,730.00 _ 31,846.18 11,359.09 1,088,901.26 12.65% !JULY 0.00 0.00 0.00 11,478.83 1,100,3_80.10 12.65% _ ;AUG 0.00 0.00 _ 0.00 11,599.84 1,111,979.94 12.65% SEPT 307,562.42 60,742.00 368,304.42 15,604.66 1,495,889,02 12.65% OCT 181,847.00 80,712.00 262,559.00 18,536.97 1,776,984.99 12.65% 1N_O_V 40,080.24 22,274.00 19,389.70 1,858,728.93 12.65% 1DEC 0.00 28,691.00 _62,354.24 28,691.00 19,896.55 1,907,316.49 12.65% 1 JAN 93 23,713.00 19,336.00 43,049.00 20,560.10 1,970,925.59 12.65% !FEB 81,974.00 19,727.00 101,701.00 21,848.94 2,094,475.53 12.65% !MARCH 29,343.00 21,482.00 50,825.00 22,615.04 21167,915.57 12.65% !APRIL 113,682.00 38,105.00 151,787.00 24,453.53 2,344,156.10 12.65% 1 MAY 80,686.81 14,464.00 95,150.81 25,714.36 2,465,021.27 12.65% IJUNE 176,457.00 8,030.00 184,487.00', 27,930.23 2,677,438.51 12.65% IJULY 216,389.00 23,251.00 239,640.001 30,750.87 2,947,829.37 12.65% 'AUG 203,436.00 31,458.00 234,894.00 33,551.21 3,216,274.58 12.65% LSEPT 333,741.00 17,431.00 351,172.00 37,606.83 3,605,053.42 12.65% OCT 423,430.00 26,823.00 4.50,253.00, 42,749.69 4,098,056.10 12.65% ;NOV 242,152.00 193,824.00 435,976.00 47,796.26 4,581,828.36 12.65% ! DEC_ 204,984.00 180,573.00 385,557.001 52,364.52 5,019,749.88 12.65% rJAN 94 837,446.93 136,707.11 974,154.041 63,185.74 6,057,089.66 12.65% !FEB 480,881.19 347,046.14 82 2 12.65% 1 MARCH 377,968.43 246,589.39 _ 624,557.82 79,928.54 7,662,082.91 12.65% !APRIL 458,530.44 112,291.12 570,821.56' 86,788.53 8,319,693.00 12.65% 1MAY 291,291.68 183,124.67 474,416.35! 92,704.57 8,886,813.92 12.65% JUNE 536,873.75 231,942.54 768,816.29 101,786.44 9,757,416.64 12.65% IJULY 611,444.07 208,654.34 820,098.41 111,504.64 10,689,019.69 12.65% IAUG 278,493.82 369,646.45 648, 2014 7 119,512.56 11,456,672.52 2.65% ISEPT 105,956.63 90,230.07 196,186.70I 122,840.56 11,775,699.78 .65% ri1 iOCT 1,007,930.40 367.92 1,008,298.32' 134,764.65 12,918,762.75 2.65% NOV 1,120,257.14 127,809.03 1,248,066.17! 149,341.99 14,316,170.91 12.65% iDEC 967,172.41 572,912.17 1,540,084.58;, 167,151.36 16,023,406.85 12.65% _ JAN 95 528,281.06 578,843.10 1,107,124.16 180,584.35 17,311,115.35 12.65% ;FEB 455,333.62 302,693.54 758,7.16! 02 190,478.88 18,259,621.39 12.65% 12.65% ;MARCH !APRIL 141,744.06 469,204.19 308,788.89 103,123.59 450,532.95' 572,327.78 197,236.21 205,348.70 18,907,390.55 19,685,067.03 12.65% ,MAY 891,092.881 45,128.30 936,221.18 217,382.75 20,838,670.96 12.65% _ 1 J U NIE 230,452.061 452,341.85 682,793.91 % 226,872.11 21,748,336.97 12.65% iJUL Y 325,138.75 261,710.20 586,848.95 235,450.08 22,570;636.01 12.65% AUG 294,644.07 48,427.66 343,071.73I 241,548.67 23,155,256.41 12.65% __ _ SEPT 25,986.45 25,986.45 244,368.94 23,425,611.79 12.650/6 OCT 6,972.72 6,972.72 247,018.50 23,679,603.01 12.65% NOV 138,245.21 138,245.21 -- 251,079.82 -- 24,068,928.03 ------- 12.65% DEC ---------- ------ 158,644.77 158,644.77 255,399.00 24,482,971.80 Page 8 of 9 Exhibit No. VER-8 Schedule 3 of 3 Part 2 of 2 CITY OF VERNON Gross Plant, Cash Calls and AFUDC January 1988 -April 1996 Mead-Adelanto and Mead Phoenix Projects AFUDC MAP MPP Total Total Rate Date Cash Call Cash Call Cash Call AFUDC Gross Plant A B C D E 12.65% JAN 96 19,353.64 19,353.64 258,2951.35 2427 30,620.79_ 12.65% FEB 157,560.71 157,560.71 2621- .16 25,180,860.66 12.65% MARCH _ 222,316.29 222,316.29 267,791.82; 25,670,968.78 12.65% APR (.5) 631.95 631.951 135,310.73 25,806,911.45 Total $13,953,111.94 $6,365,039.82 $20,318,151.76 $5,488,759.69 $25,806,911.45 A&G Plant $614,735.00 $614,735.00 $1,229,470.00 $1,229,470.00 Total MAP & MI $14,567,846.94 $6,979,774.82 $21,547,621.76 $5,488,759.69 $27,036,381.45 Sources: AFUDC Rate: City of Vernon Report on Rate Design Col. A, MAP Cash Call: W/P Tab AC. Cola B, MPP Cash Call: W/P Tabs R and T. A&G Plant: W/P Tab AM. Page 9 of 9 -' NTA --r-.GTUOLUMNE s I _ MM�ss W �� meµsn, Governor ERGY COMMISSION echt, Chairman j, Vice Chair mare, Commissloner Ir, Commisslormr Commbslornr 'IES SITING DIVISION herkemn. Chief Gaya, Cartographer d Marcti, IW9 • Exhibit No. V€ft=9--- Page 1 of 7 $PP ................ Sierra Pacific Power SCW................ Southern California Water TID.................. Turlock Irrigation District IID of Utility Exhibit NO VER 9"— Page 2 of 7 0 CL E 0 L) c: 0 W W CV) CD cc) 0 < O CO (D cu U . .. ....... ... ... .... 0 ........ .. - o . .......... U- . . . . . . . . . . . . LL ... .............. tL 0 3:(.) LLI X Z w < 4W z 0 N C2) xhibit No. VER-9 _ age 3 of 7 a 0 yOYTM 1 •����• ..Flrh.w�ChM �_......0ftc..W.~ TAO(f Yrv. own,,, r I ! A i...I.Ir.. r E O sI.«,►I..I aroN • 4"�4ee rest d . O f r 7 . cos SAAVs `\ o r�OwAr ''�td �• a; 9t , ., SAN O/W ARE %. PACIFIC INTERTIE AC i DC LINES FIGURE 2 Exii. Exhibit No. VER-9 Page 4 of 7 EASTOF-THE-COLORADO-RIVER TRANSMISSION SYSTEM DI hibit No. VER-9 ge5of7 WEST -OF -THE COLORADO-RMP. TRANSMISSION SYSTEM MMOR SIMMER PKLWANT �, YAIOR 6uBbTATIONgN • Inc Exhibit No. VER-9 Page 6 of 7 PACIFIC NORTHWEST -PACIFIC SOUTHWEST MTERT E cm J" DAY MARM AWEY ORECON CAPTAIN JACK W LJN lmum wm C PACI PD CI TARK PAN NEVADA VAG IM TAACY W6 0AMM uw"�0owa MCA so MImw OWID CANYpI CALIFORNIA Vau=T LEGEND snMAh tu00 �'� u_aaewx ofkvAC �.J Exhibit No. VER-9_. *age 7 of 7 EDISON'S CERTIFICATED SERVICE AREA t Ekhibit No. VER-10 Page 1 of l f=_!V Southern California Edison 22" Wak" Grow Avema. RawraW. CaMono 91 M Schedule R-7.S 1'IME-OF-USE RESALE SERVICE (Continued) SPECIAL CONDITIONS (Continued) 9. Fuel Cost Adjustment: (Continued) When the revenue resulting from Paragraph g (2) is compared with the estimated Adjustment Factor revenue previously billed for the same month, any net difference shall be the amount of synchronizing revenue to be added to or subtracted from the first subsequent billing after determination of the synchronizing revenue. h. The base period fuel cost Fb is 1.767t/kith. Sb 10. Notice of Termination: Service under this schedule, or any superseding schedule, may not be terminated by the customer except on written notice to the Company of not less than 36 months. 11. Integrated Sources: Where a part or all of the electrical requirements of the customer can be supplied from a source or sources other than Company, and where all such sources are integrated with the Company's system in accordance with an integrated operations agreement, between the customer and the Company, this rate schedule shall incorporate by reference the provisions of such agreement, and where there are differences between the provisions in such agreement and in this rate schedule, the provisions in the agreement shall be determinative. 12. Non -Integrated Sources: Where customer proposes to provide a part of its electrical requirements from Non -Integrated Sources, customer shall notify Company in writing, by July 1 of each odd -numbered year, of customer's proposed Non - Integrated Source to be added during .the 24-month period commencing 18 months after said July 1. In the event customer's installed capacity exceeds the capacity for which notice was provided, the amount of such excess capacity expressed in kilowatts must be noticed, as set forth above, before customer shall receive billing demand credits for such excess capacity. Acceptance by Company of Non -Integrated Sources shall be dependent upon installation of metering equipment, by Company at customer's expense, capable of measuring and ionitoring the output of the customer's Non -Integrated Source and arrangement by customer for transmission service from the Non -Integrated Source to the Point of Delivery, if necessary. (Continued) Settlement Rate Effective January 1, 1995 X920410.01 T"T'd SZbl 928 222:01 E6E26178OTV :WOJd TT:20 17002-92-Ndd CITY COUNCIL LEONIS C. MALBURG Mayor THOMAS A. YBARRA Mayor Pro-Tem Wm. "BILL" DAVIS Councilman H. "LARRY" GONZALES Councilman W. MICHAEL McCORMICK Councilman BRUCE V. MALKENHORST City Administrator/City Clerk FAX: (213) 581-7924 HAND DELIVERED CITY HALL Exhibit NO. VEk 11 Page 1 of 6 DAVID B. BREARLEY City Attorney FAX: (818) 330-5818 VICTOR H. VAITS Director of Community Services & Wa FAX: (213) 588-2761 KENNETH J. DeDAR10 Director of Light & Power FAX: (213) 583-1983 LARRYSPADT Fire Chief FAX: (213) 581-1385 LOUIS ROSENKRANTZ Police Chief FAX: (213) 581-1178 4305 SANTA FE AVENUE, VERNON, CALIFORNIA 90058 TELEPHONE (213) 583-8811 June 29, 1993 Mr. Vikram Budhraja Vice President Southern California Edison Company 2244 Walnut Grove Avenue Rosemead, CA 91770 In Reply Refer to: Re: Notice of Generation Addition - Special Condition 12 Bonneville Power Administration Dear Mr. Budhraja: PLEASE TAKE NOTICE that, in accordance with Speeding rate Condition 12 in Tariff Schedule R-7.4, or any p the schedule filed with the Federal Energy Regulatory Commission, City of Vernon ("Vernon") hereby gives notice tthat he Vern n will purchase capacity and associated energy from e power Administration ("BPA") pursuant to a Power Sale Agreement and schedule and dispatch such capacity and energy as a Vernon nonintegrated source as that term is used Condition such Special Condition 12. Vernon intends to purchase from BPA a maximum of 20 MW of MW of capacity and capacity and associated energy. The said 20 period and associated energy will be supplied during the summer p no capacity and associated energy will be supplied during the winter period as such periods are defined in the tariff schedule. This notice provides for an increase in demand from Vernon's customers. Vernon anticipates experiencing increases in demand from its customers during the noticed period. In the event such increases in demand do not materialize, then Vernon other the right to sell such capacity and associated energy utilities or to reduce the amount of capacity and associated energy purchased pursuant to the Power Sale Agreement. Said capacity and energy is to be delivered at the Vernon city (aorder for the period from January 1, 1995 to December 31, 1 period of three years). Exhibit No. VER-11 I Page 2 of 6 Mr. Vikram Budhraja Page 2 June 29, 1993 Furthermore, Vernon has indicated to Edison on several occasions that Vernon's position is that whenever Vernon gives a Special Condition 12 notice of the acquisition of nonintegrated source of capacity and/or energy such notice includes notice of an intent to obtain replacement capacity and energy from other sources when the nonintegrated source is not available because of causes such as scheduled or unscheduled outages. Edison personnel have disagreed with this position and have refused to provide Edison transmission service to permit Vernon to acquire replacement capacity and/or energy. without acceding to the position expressed by those Edison personnel, in an effort to avoid the problem in connection with this nonintegrated source, Vernon hereby gives notice that it intends to obtain replacement capacity and/or energy from other sources to replace capacity and/or energy that is not available to Vernon from BPA due to unforeseen circumstances. The combination of BPA capacity and energy and replacement capacity and energy will not exceed the level of Vernon's notice herein of 20 MW of capacity and energy during the summer period and nothing during the winter period. This notice shall be effective for power deliveries.starting on January 1, 1995. Vernon's notice herein includes the right to use this capacity with other capacity in an interchangeable manner so as to replace the output of other noticed resources when such resources are not scheduled or dispatched for economic reasons, scheduled maintenance, or unscheduled outages. Vernon's notice herein with regard to replacement capacity and/or energy is not to be construed as an acquiescence with Edison's position or a waiver of Vernon's right to contest. Edison's position at the present time but is simply an attempt to accommodate Edison's interpretation from January 1, 1995 forward. Further, if this power source does not become available to the City as expected (such as Vernon's inability to complete the final details of the Power Sale Agreement or because of BPA's inability to deliver the power to Vernon and the unavailability of alternate transmission arrangements), the City will substitute power from another source. If you have any questions concerning this notice or the matters stated herein, please call me. Very truly yours, l \ / David B. Brearley City Attorney DBB:j1 Exhibit NO. VER-11 Page 3 of 6 Mr. Vikram Budhraja Page 3 June 29, 1993 cc: Mr. Bruce V. Malkenhorst Mr. Arnold Fieldman Mr. Bob Clay Mr. Ken DeDario Mr. Steve Pickett Mr. Gil Tam CITY COUNCIL LEONIS C. MALBURG Mayor THOMAS A. YBARRA Mayor Pro-Tem Wrn. "BILL" DAVIS Councilman H. "LARRY" GONZALES Councilman W. MICHAEL McCORMICK Councilman BRUCE V. MALKENHORST City Administrator/City Clerk FAX: (213) 581-7924 4305 SANTA FE AVENUE, VERNON, CALIFORNIA 90058 TELEPHONE (213) 583-8811 June 29, 1993 HAND DELIVERED CITY HALL Mr. Vikram.Budhraja Vice President Southern California Edison Company 2244 Walnut Grove Avenue Rosemead, CA 91770 Exhibit No. VER-11 Page 4 of 6 DAVID B. BREARLEY City Attorney FAX: (818) 330-5818 VICTOR H. VAITS Director of Community Services & Water FAX: (213) 588-2761 KENNETH J. DeDARIO Director of Light & Power FAX: (213) 583-1983 LARRYSPADT Fire Chief FAX: (213) 581-1385 LOUIS ROSENKRANTZ Police Chief FAX: (213) 581-1178 /n Reply Refer to: Re: Notice of Generation Addition - Special Condition 12 - Southern California Edison Company Dear Mr. Budhraja: PLEASE TAKE NOTICE that, in accordance with Special Condition 12 in Tariff Schedule R-7.4, or any superseding rate schedule filed with the Federal Energy Regulatory Commission, the City of Vernon ("Vernon") hereby gives notice that Vernon will purchase capacity and associated energy from the Southern California Edison Company ("Edison") pursuant to a Power Sale Agreement and schedule and dispatch such capacity and energy as a Vernon nonintegrated source as that term is used in such Special Condition 12. Vernon intends to purchase from Edison a maximum of 80 MW of capacity and associated energy. The said 80 MW of capacity and associated energy will be supplied during the summer period and 60 MW of capacity and associated energy will be supplied during the winter period as such periods are defined in the tariff schedule. This notice provides for a 20 MW increase in demand from Vernon's customers. Vernon anticipates experiencing increases in demand from its customers during the noticed period. In the event such increases in demand do not materialize, then Vernon reserves the right to sell such capacity and associated energy to other utilities or to reduce the amount of capacity and associated energy purchased pursuant to the Power Sale Agreement. Said capacity and energy is to be delivered at the Vernon city border for the period from January 1, 1995 to December -31, 1996 (a period of two years). Exhibit No. VER-11 Page 5 of 6 Mr. Vikram Budhraja Page 2 June 29, 1993 Furthermore, Vernon has indicated to Edison on several occasions that Vernon's position is that whenever Vernon gives a Special Condition 12 notice of the. acquisition of nonintegrated source of capacity and/or energy such notice includes notice of an intent to obtain replacement capacity and energy from other sources when the nonintegrated source is not available because of causes such as scheduled or unscheduled outages. Edison personnel have disagreed with this position and have refused to provide Edison transmission service to permit Vernon to acquire replacement capacity and/or energy. without acceding to the position expressed by those Edison personnel, in an effort to avoid the problem in connection with this nonintegrated source, Vernon hereby gives notice that it intends to obtain replacement capacity and/or energy from other sources to replace capacity and/or energy that is not available to Vernon from Edison due to unforeseen circumstances. The combination of Edison capacity and energy and replacement capacity and energy will not exceed the level of Vernon's notice herein of 80 MW of capacity and energy during the summer period and 60 NW during the winter period. This notice shall be effective for power deliveries starting on January 1, 1995. Vernon's notice herein includes the right to use this capacity with other capacity in an interchangeable manner so as to replace the output of other noticed resources when such resources are not scheduled or dispatched for economic reasons, scheduled maintenance, or unscheduled outages. Vernon's notice herein with regard to replacement capacity and/or energy is not to be construed as an acquiescence with Edison's position or a waiver of Vernon's right to contest. Edison's position at the present time but is simply an attempt to accommodate Edison's interpretation from January 1, 1995 forward. Further, if this power source does not become available to the City as expected (such as Vernon's inability to complete the final details of the Power Sale Agreement or because of Edison's inability to deliver the power to Vernon), the City will substitute power from another source. If you have any questions concerning this notice or the matters stated herein, please call me. Very truly yours, D dl,J 1 l t VD/l-� David B. Brearley City Attorney DBB: j 1 0 i Exhibit No. VER -1� �` Page 6 of 6 Mr. Vikram Budhraja Page 3 June 29, 1993 cc: Mr. Bruce V. Malkenhorst Mr. Arnold Fieldman Mr. Bob Clay Mr. Ken DeDario Mr. Steve Pickett Mr. Gil Tam 0 Exhibit No. VER-12 Schedule 1 of 3 EDISON Transmission Revenue Requirements Year Ended June 30, 1999 Line No. Description A MAP & COTP MPP B C TOTAL D 1 Average Gross Plant in Service $39,747,913 $25,787,261 $65,535,174 2 Accumulated Depreciation 7,167,481 2,207,251 9,374,732 3 Net Plant $32,580,432 $23,580,010 $56,160,442 19.81% $11,125,384 Exhibit No. VER-12 Schedule 2 of 3 Part 1 of 2 EDISON Net Plant and Depreciation Test Period - Fiscal Year June 30, 1999 California -Oregon Transmission Project California -Oregon Transmission Project Month Cash Call A End of Month Gross Plant B Average Gross Plant C Depreciation D Accumulated Depreciation E Mar-93 $36,634,922.11 $0.00 APRIL $1,126,342.00 $37,761,264.11 $37,198,093.11 j $98,161.63 $98,161.63 MAY - JUNE $161,833.00 $296,077.00 $37,923,097.11 $38,219,174.11 $37,842,180.61 $38,071,135.61 $99,861.31 $ 0,465.50 $198,022.94 $298,488.44 JULY �- $180,026.00 $38,399,200.11 j $38,309,187.11 $101,093.691 $399,582.13 AUG SEPT $169,981.00 $0.00 $38,569,181.11 $38,569,181.11 $38,484,190.61 $38,569,181.11 $101,555.50 $101,779.78 $501,137.63 $602,917.42 OCT -� $0.00 $38,569,181.11 $38,569,181.11 $101,779.78 $704,697.20 NOV_ — - $0.00 $38,569,181.111 $38,569,181.11 $101,779.781 $806,476.98 DEC $0.00 $38,569,181.11 $38,569,181.11 $101,779.78 $908,256.77 JAN 94 $0.00 $38,569,181.11 $38,569,181.11 $101,779.78 $1,010,036.55 FEB MARCH _ 00 $0.00j $38,569,181.11 $38,569,181.11 $38,569,181.11 $38,569,181.11 $101,779.78 $101,779.78 $1,111,816.33 $1,213,596.12 APRIL $0.001 $38,569,181.11 $38,569,181.11 $101,779.78 $1,315,375.90 MAY $0.00 $38,569,181.11 $38,569,181.11 $101,779.78 $1,417,155.68 JUNE $0.00 $38,569,181.11 $38,569,181.11 $101,779.78 $1,518,935.47 JULY = $0.00 $38,569,181.11 $38,569,181.11 $101,779.78 $1,620,715.25 AUG $667,859.00 $39,237,040.11 $38,903,110.61 $102,660.99 $1,723,376.24 SEPT $76,238.00 $39,313,278.11 $39,275,159.11 $103,642.78 $1,827,019.02 OCT $90,514.00 $39,403,792.11 $39,358,535.111 $103,862.80; $1,930,881.82 NOV $10,566.00 $39,414,358.11 $39,409,075.11 $103,996.17; $2,034,877.99 DEC_ $13,546.00 $39,427,904.11I $39,421,131.11 $104,027.98 $2,138,905.97 JAN 95 $64,072.00 $39,491,976.11 1 $39,459,940.11 $104,130.40 $2,243,036.37 FEB $6,861.00 $39,498,837.11 $39,495,406 04,223.99 $2,347,260.36 MARCH $16,444.00 $39,515,281.11 $39,507,059.11I $104,2 754 41 $2,451,515.10 APRIL $0.00 $39,515,281.11 $39,515,281.11 $104,276.44 j $2,555,791.54 MAY $199,600.001 $39,714,881.11 $39,615,081.11� $104,539.80 $2,660,331.33 JUNE $39,714,881.11 $39,714,881.11 $104,803.16 $2,765,134.49 JULY _$0.00) $0.00; $39,714,881.11 $39,714,881.11 $104,803.16 $2,869,937.65 AUG $0.00 $39,714,881.11 $39,714,881.11 $104,803.16 $2,974,740.81 SEPT L $0.00 $39,714,881.11 $39,714,881.11 $104,803.16 $3,079,543.97 OCT ! $0.00 $39,714,881.111 $39,714,881.11 $104,803.16 $3,184,347.13 Page 2 of 10 Exhibit No. VER-12 Schedule 2 of 3 Part 1 of 2 EDISON Net Plant and Depreciation Test Period - Fiscal Year June 30, 1999 California -Oregon Transmission Project California -Oregon Transmission Project Month Cash Call A End of Month Gross Plant B Average Gross Plant C Depreciation D Accumulated Depreciation E NOV $0.001 $39,714,881.11 $39,714,881.11 $104,803.16 $3,289,150.29 DEC �— Jan 96 $0.00 $0.001 -- j $39,714,881.11 $39,714,881.11 - $39,714,881.11 $39,714,88 1 $104,803.16 $104,803.16 $3,393,953.44 $3,498,756.60 Feb $0.00 $39,714,881.11 $39,714,881.11 1 $104,803.16 $3,603,559.76 March $0.00 $39,714,881.11 $39,714,881.11 ! $104,803.16 $3,708,362.92 April $0.00 $39,714,881.11 $39,714,881.11 } $104,803.16 $3,813,166.08 --- May ---- $0.00 $39,714,881.11 $39,714,88 11 1 -- $104,803.16 ------- $3,917,969.24 June July _ Aug $0.00 $0.00 - $0.00 $39,714,881.11 $39,714,881.11 $39,714,881.11 $39,714,881.11 $39,714,881.11 ---- $39,714,881.11 $104,803.16 - i $104,803.16 1 $104,803.16 $4,022,772.39 ---- $4,127,575.55 $4,232,378.71 Sept $0.00 $39,714,881.11 $39,714,881.11 $104,803.16 $4,337,181.87 OCT $692.00 $39,715,573.11 $39,715,227.11 $104,804.07 $4,441,985.94 NOV - ---- $0.00 $39,715,573.11 --- $39,715,573.11 --- $104,804.98 --- - $4,546,790.93 DEC JAN 97 FEB $768.00 $636.00 $39,716,341.11 $39,716,977.11 $39,717,566.11 $39,715,957.11 $39,716,659.11 $39,717,271.61I, $104,806.00 $104,807.85 $104,809.47 $4,651,596.92 $_4,756,404.77 $4,861,214.24 MARCH APRIL_ MAY _$589.00 $0.00 $0.00 $0.00 $39,717,566.11 $39,717,566.11 $39,717,566.11 $39,717,566.11 $39,717,566.11 $39,717,566.11 i1 $104,810.24 $104,810.24 $104,810.24 $4,966,024.49 $5,070,834.73 $5,175,644.97 JUNE $966.00 $39,718,532.11 $39,718,049.11 $104,811.52 $5,280,456.49 JULY AUG _ $0.00 $21693.00 $39,718,532.11 $39,721,225.11 $39,718,532.11 $39,719,878.61 $104,812.79 $104,816.35 $5,385,269-28 $5,490,085.63 SEPT $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $5,594,905.53 OCT $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $5,699,725.43 NOV $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $5,804,545.33 --------------- -- DEC --- $0.00 $39,721,225.11 $39,721,225.11 - $104,819.90 $5,909,365.23 JAN 98 $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $6,014,185.13 FEB $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $6,119,005.03 MARCH ___ $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $6,223,824.93 APRIL $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $6,328,644.83 MAY $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $6,433,464.73 JUNE $0.00 $39,721,225.11 $39,721,225.11 $104,819.90 $6,538,284.63 Page 3 of 10 • 0 Exhibit No. VER-12 Schedule 2 of 3 Part 1 of 2 EDISON Net Plant and Depreciation Test Period - Fiscal Year June 30, 1999 California -Oregon Transmission Project California -Oregon Transmission Project Month Cash Call A End of Month Gross Plant B Average Gross Plant C Depreciation D Accumulated Depreciation E JULY_ $1,669.00 $39,722,894.11 $39,722,059.61 $104,822.10 $6,643,106.73 AUG j $1,121.00 $39,724,015.11 $39,723,454.61 $104,825.78 $6,747,932.51 SEPT $1,826.00 $39,725,841.11 $39,724,928.11 $104,829.67 $6,852,_762.18 OCT $1,033.00 $39,726,874.11 $39,726,357.61 $104,833.44 $6,957,595.63 NOV $0.00 $39,726,874.11 $39,726,874.11 $104,834.81 $7,062,430.43 DEC JAN 99 FEB MARCH APRIL MAY JUNE $39,842.00 $0.00 $0.00 $6,407.00 $3,382.00 $0.00 $0.00 $39,766,716.11 $39,766,716.11 $39,766,716.11 $39,773,123.11I, $39,776,505.11 $39,776,505.11 1 $39,776,505.11 $39,746,795.11 $39,766,716.11 t $39,766,716.11 $39,769,919.61 $39,774,814.11 _$39,776,505.11 $39,776,505.11 $1041887.38 $104,939.95 $104,939.95I $104,948.40 $104,961.321 L $104,965.781 $104,965.78 $7,167,317.81 $7,272,257.75 $7,377,197.70 $7,482,146.10 $7,587,107.41 $7,692,073.19 i - $7,797,038.97 I Average June 1998 - June 1999 $39,747,913.11 $7,167,480.85 Sources: Column A: Cash Calls from April 1993-June 1999 from W/Ps F to I. Column B: March 1993 Gross Plant from Schedule 3, Part 1. Column C: Cumulative Gross Plant. Service Life (Years) 42.00 Plant plus Neg. Salvage Value 133.0000% Depreciation Rate 3.1667% Monthly Depreciation Rate 0.2639% Page 4 of 10 0 Exhibit No. VER-12 Schedule 2 of 3 Part 2of2 EDISON Net Plant and Depreciation Test Period - Fiscal Year June 30, 1999 Mead-Adelanto and Mead Phoenix Projects Mead-Adelanto and Mead Phoenix Projects Month MPP Cash Call A MAP Cash Call B End of Month —F--Average Gross Plant C Gross Plant D Depreciation E Accumulated Depreciation F Jan 96 Feb March -- - -- — -- - April _---- $25,524,599.251 25,524,599.251 $33,678.29 May $12,135.58 $0.00 $25,536,734.83 ( $25,530,667.04 $67,372.59 _$33,678.29 $101,050.88 June 96 _ $23,046.13 ___ $0.00 $25,559,780.96 — -- i$25,548,257.90 � $67,419.01 $168,469.90 July _ $45,482.00 $33,972.36 $25,639,235.32 $25,599,508.14 $67,554.26 $236,024.16 Aug $13,271.83 - $25,655,374.641 --- $25,6_4.7,304.98 - $67,680.39 $303,704.54 Sept $6,352.91 —$2,867.49 $1,477.69 $25,663,205.24 $25,659,289.94 $67,712.02 $371,416.56 OCT ---- $10,896.44 $6,151.40 $25,680,253.08 $25,671,729.16 $67,744.84 i $439,161.40 NOV -- - $1,689.25 - $406.12 --- $25,682,348.4_ 5� $25,681,300.77 j $67,770.10 - -- ---- --- $506,931.50 ------------- DEC $1,127.07 $2,588.81 $25,686,064.33_ $25,684,206.39 $67,777.77 $574,709,27 JAN 97 - $18,091.92 $60,346.09 $25,764,502.34 $25,725,283.34 $67,886.16 $642,595.43 FEB $0.00 $453.43 $25,764,955.77 $25,764,729.06 $_67,990.26 — 1 $710,585.69 MARCH $0.00 $618.81 $25,765,574.58 $25,765,265.18 $67,991.67 $778,577.36 APRIL $581.53 -$4,829.96 $25,761,326.15 $25,763,450.37 $67,986.88! $846,564.24 MAY $58.50 $532.42 1 $25,761,917.07 $25,761,621.61 $67,982.06 $914,546.30 JUNE $0.00 $1,515 52 $25,763,432.59 $25,762,674.83 $67,964.84 $_982,531.14 JULY $25,763,432.59 $25,763,432.59 $67,986.84 $1,050,517.97 AUG $10,095.20 $25,773,527.79 $25,768,480.19 $68,000.16 $1,118,518.13 SEPT $2,153.80 _ $25,775,681.59 $25,774,604.69 _ $68,016.32 $1,186,534.45 OCT $14,215.08 $25,789,896.67 $25,782,789.13 $68,037.92 $1,254,572.36 NOV $25,789,896.67 $25,789,896.67 $68,056.67 $1,322,629.03 DEC -$5,384.50 $25,784,512.17 $25,787,204.42 $68,049.57 $1,390,678.60 JAN 98 $25,784,512.17 $25,784,512.17 $68,042.46 $1,458,721.06 FEB -- $25,784,512.17 $25,784,512.17 $68,042.46 $1,526,763.53 MARCH $530.7_1 $25,785,042.88 $25,784,777.53 $68,043.16 $1,594,806.69 APRIL $2,218.41{ $25,787,261.29 $25,786,152.09 $68,04_6.79 $1,662,853.48 MAY --- $25,787,261.29 $25,787,261.29 $68,049.72 $1,730,903.20 JUNE $25,787,261.29 $25,787,261.29 $68,049.72 $1,798,952.91 JULY _ 1 $25,787,261.29 $25,767,261.29 $68,049.72 $1,867,002.63 AUG -- $2578726129 ,,. $6804972 ._ SEPT - $25,787261.29 ___$25,787,261.29, $25,787,26129 $68,049.72 _$_1,935,05_2.35 $2,003,102.07 OCT— — "- $25,787,261.29 $25,787,261.29 $68,049.72 $2,071,151.78 NOV -_--- - $25,787,261.29 $25,787,261.29 --- $68,049.72 _ $2,139,201.50 DEC - $25,787,261.29 $25,787,261.29 $68,049.72 $2,207,251.22 JAN 99 - $25,787,261.29 $25,787,261.29 1 $68,049.72 $2,275,300.94 _ FEB $25,787,2_61.29 $25,787,261.29� $68,049.72 $2,343,350.65_ MARCH $25,787,261.29 $25,787,261.291 $68,049.721 $2,411,400.37 APRIL ��— MAY - $25,787,261.29 $25,787,261.29 $25,787,261.29 $25,787,261.29 .721 j $68,049.72 $2.479,450.09 $2,547,499.80 JUNE - $25,787,261.29 $25,787,261.29 086 49.7_2I $2,615,549.52 I i Average June 1998 - June 1999 $25,787,261.29 $25,787,261.29 $2,207,251.22 Sources: Column A: MPP Cash Calls from W/Ps U and V. Column B: MAP Cash Calls from W/P AE. Column C: April Gross Plant from Schedule 3, Part 2. Column D: Cumulative Gross Plant. Service Life (Years) 42.00 Plant plus Neg. Salvage Value 133.0000% Depreciation Rate 3.1667% Monthly Depreciation Rate 0.2639% Page 5 of 10 Exhibit No. VER-12 Schedule 3 of 3 Part 1 of 2 EDISON Gross Plant -Cash Calls and AFUDC May 1985-March 1993 California -Oregon Transmission Project COTP AFUDC Rate Date Cash Call A AFUDC B Gross Plant C 12.70% !MAY 85 _ $9,400.00 $99.48 _ $9,499.48 12.70% iJUNE $0.00 $100.54 $9,600.02 -- _ 11.86% - IJULY _- -- $2,632.00 $120.89 ----$_12,352.91 _ 11.86% iAUG $0.00 $122.09 _-_ $12,475.00 _ 11.86% SEPT $1,598.00 $139.09 $14,212.09 11.86% OCT _ $13,272.80 $271.64 _ $27,756.53 11.86% -- NOV_ ---------- $1,297.20 $287.15 $29,340.88 11.86% DEC $0.00 $289.99 $29,630.86 11.86% JAN 86 $14,776.80 $438.90 _ _ $44,846.56 11.86% FEB $8,873.60 $530.93 $54,251.09 _ 11.86% MARCH $14,636.21 _ $680.84 $69,568.14 11.86% APRIL $10,400.31 $790.35 $80,758.81 11.86% MAY $29,906.47 $1,093.74 $111,759.02 _ - $18,916_24 $1,291.51 $131,966.76 11.24% JULY $5,182.03 $1,284.63 $138,433.42 11.24% AUG $13,444.30 $1,422.59 $153,300.31 11.24% SEPT $22,866.18 $1,650.09 $177,816.58 11.24% _ OCT $17,358.00 $1,828.14 $197,002.72 11.24% NOV $12,248.44 $1,959.99 $211,211.14 11.24% DEC $38,720.30 $2,341.02 $252,272.47 11.24% JAN 87 $10,400.31 $2,460.37 $265,133.15 11.24% FEB $12,465.87 _ $2,600.18 $280,199.19 11.24% MARCH $16,017.20 $2,774.56 $298,990.95 11.24% APRIL $12,520.23 $2,917.82 $314,429.01 11.24% MAY $16,361.46 $3,098.40 $333,888.87 - 11.24% JUNE $14,531.44 $3,263.54 $351,683.85 10.75% JULY ---- ---- $15,129.37 $3,286.04 $370,099.25 10.75% AUG $4,910.25 $3,359.46 $378,368.96 10.75% SEPT $21,362.30 $3,580.93 $403,312.19 10.75% OCT $3,626.48 $408,442.54 10.75% NOV _$1,503.88 $11,306.26 $3,760.25 $423,509.05 10.75% DEC $11,795.47 $3,899.60 $439,204.13 10.75% 1JAN 88 --- $6,287.29 $3,990.86 _ $449,482.28 10.75% FEB $3,750.63 $4,060.21 $457,293.12 10.75% 10.75% 10.75% 10.75% MARCH APRIL MAY JUNE $6,685.91 _ $6,957.70 $9,186.33 $9,458.12 $4,156.48 $4,256.04 $4,376.46 $4,500.40 $468,135.51 $479,349.25 $492,912.05 _ $506,870.57 10.91% JULY $8,099.19 $4,681.93 $519,651.69 10.91% AUG $6,486.60 $4,783.47 _$530,92_1.76 10.91% SEPT $6,232.94 _ $4,883.63 $542,038.33 10.91% ;OCT ----- _ $6,758.39 $4,989.48 $553,786.20 10.91 % NOV $5,308.87 $5,083.11 _$564,178.18 Page 6 of 10 Exhibit No. VER-12 Schedule 3 of 3 Part 1 of 2 EDISON Gross Plant -Cash Calls and AFUDC May 1985-March 1993 California -Oregon Transmission Project COTP AFUDC Rate Date Cash Call A Gross AFUDC Plant B C 10.91% DEC $12,900.73 $5,246.61 $582,325.52 10.91% JAN 89 $4,167.37 $5, 332.20 $591,825.08 10.91% FEB $12,230.33 $5,491.87 $609,547.28 10.91% MARCH $9,729.90 $5,630.26 $624,907.45 10.91% APRIL $6,468.48 $5,740.26 $637,116.19 10.91% MAY $851.59_ $5,800.191 $643,767.97 10.91% JUNE_ $4,656.58 $5,895.261 $654,319.81 10.70% IJULY $0.00 $5,834.351 $660,154.16 10.70% AUG $0.00 $5,886.37 $666,040.53 10.70% SEPT_ $688.52 $5,945.001 $672,674.05 10.70% OCT $1,377.04 $6,010.29! $680,061.38 10.70% NOV _ $0.00 $6,063.88! $686,125.26 10.70% DEC $90.60 $6,118.76 1 $692,334.62 10.70%JAN 90_ $0.00$6,173.32 $698,507.94 j 10.70% FEB $0.00 $6,228.361 $704,736.30 10.70% MARCH $0.00 $6,283.90 $711,020.20 - - -- 10.70% 10.70% APRIL -- MAY ------ ___ $0.00 $0.00 ---- -- $6,339.93$717,360.13 $6,396.461 $723,756.59 10.70% _ JUNE $1,286.45 $6,464.971 $731,508.01 - -- -- 10.71% JULY_ $0.00 $6,528,711 - - $738,036.72 10.71% _ AUG_ _ $1,811.90 $6,603.15 j $746,451.76 10.71% SEPT_ $0.00 $6,662.081 $753,113.85 10.71% OCT $0.00 $6,721.541 $759,835.39 10.71% NOV _ $0.00 $6,781.531 $766,616.92 10.71% DEC $0.00 $6,842.061 $773,458.97 10.71% JAN 91 $0.00 $6,903.12 __ $780,362.10 10.71% FEB _ $0.00 $6,964.73 $787,326.83 10.71% MARCH _ $0.00 $7,026.89 $794,353.72 10.71% APRIL $0.00 $7,089.611 $801,443.33 10.71% MAY $0.00 $7,152.881 $808,596.21 10.71% JUNE $0.00 $7,216.721 $815,812.93 -- 10.59% JULY -- $0.00 $7,199 55 $823,012.48 10.59% AUG $0.00 $7,263.09 $830,275.56 10.59% SEPT $0.00 $7,327.18 $837,602.75 -- 10.59% _ OCT $4,001,297.00 $42,703.29 $4,881,603.04 - ------------ ----- -- 10.59% NOV -- - $215,707.00 - $44,983.761 $5,142,293.80 10.59% DEC $131,090.00 _ $46,537.611 $5,319,921.41 10.59% JAN 92 $15,966,040.00 $187,848.61 1 $21,473,810.02 10.59% FEB $1,319,374.00 $201,149.851 $22,994,333.87 -- 10.59% _. - _ MARCH $1,021,464.00 -. $211,939.42' $24,227,737.28 10.59% APRIL_ $696,055.02 $219,952.471 $25,143,744.77 10.59% MAY - $334,881.00 $224,848.871 $25,703,474.64 10.59% JUNE $1,084,315.00 $236,402.241 $27,024,191.89 Page 7 of 10 • 0 EDISON Gross Plant -Cash Calls and AFUDC May 1985-March 1993 California -Oregon Transmission Project Exhibit No. VER-12 Schedule 3 of 3 Part 1 of 2 COTP AFUDC Rate Date Cash Call A AFUDC B Gross Plant C 9.94% tJULY $615,823.00 $228,951.46 $27,868,966.34 _ 9.94% AUG $586,161.00 $235,703.30 $28,690,830.65 9.94% SEPT $639,324.00 $242,951.45 _ $29,573,106.10 —9.94% OCT _ $852,418.00 $252,024.76 $30,677,548.85 9.94% NOV $565,876.00 $258,799.70 $31,502,224.56 9.94% ,DEC $1,030,153.00 $269,476.53 $32,801,854.08 9.94% JAN 93 $322,519.00 $274,380.22 $33,398,753.31 9.94% ;FEB $754,771.00 $282,905.03 $34,436,429.33 9.94% MAR $478,835.00 $289,214.77 $3 5,204,479.11 Total $31,131,407.40 $4,073,071.71 $35,204,479.11 A&G $1,430,443.00 Total Plant $36,634,922.11 Sources AFUDC Rate: 'W/P Tab AJ. Cash Call May 1985 - February 93: W/P A. Cash Call March 93: W/P C. A&G Plant from W/P AM Independent Variables Service Life (Years) Plant plus Neg. Salvage Value 42.00 133.00% Page 8 of 10 • Exhibit No. VER-12 Schedule 3 of 3 Part 2 of 2 EDISON Gross Plant, Cash Calls and AFUDC January 1988 - April 1996 Mead-Adelanto and Mead Phoenix Projects AFUDC Rate Date MAP Cash Call A MPP Cash Call B Total Cash Call C AFUDC D Total Gross Plant E 10.75% JAN 88 $0.00 $0.00 $0.00 $0.000 --- 10.75% --- FEB $125.55 - $0.00 --- $12_5.55 --- $1.12' $126.67 10.75% MARCH - $187.06 $0.00 $187.06 $2.81 $316.55 10.75% APRIL $0.00 $0.00 $0.00 $2.841 $319.38 10.75% MAY $0.00 $1,005.41 $11.87, $1,336.66 10.75% 10.91% JUNE_ JULY _ _$1,005.41 $67.84 $0.00 - $0.001 $0.001 $67.84 $0.00 $12.58 $12.88 $1,417.08 $1,429.96 10.91% AUG $1,161.08 $0.00 i $1,161.08 $23.56 _ $2,614.60 10.91% SEPT $254.69 $0 0000 $254.69 $26.09 $2,895.38 10.91% OCT $0.00 $0.00 $0.00 $26.32 $2,921.70 10.91 % I NOV $0.001 _ $0.00 $0.00 $26.56 $2,948.26 10.91% 1 DEC $0.00 _ $0_0_0 $0.00 $26.80 $2,975.07 10.91% ! JAN 89 $0.00 _ i $0.00 $0:00 $27.05 $3,002.12 10.91% _ FEB $28.601 _ $0.00 $28.601 $27.55 $3,058.27 10.91% MARCH $22.27I $0.00 $22.27 j $28.01 $3,108.5_5 10.91% jAPRIL $18.82 $0.00 $18.82T $28.43 $3,155.80 10.91% MAY $56.96 $0.00 $56.961 $29.21 $3,241.97 10.91% JUNE _ $209.46 $0.00 $209., 6i $31.38 $3,482.81 ---------- 10.70% JULY $391 _58 $0.00 $391.58i $34.55 $3,908.94 10.70% AUG _ $1,055.24 $0.00 $1,055.24i _ $44.26 $5,008.44 10.70% SEPT _ $725.09 $0.00 $72 9 $51.12 $5,784.66 10.7061 OCT I $1,143.72 $0.00 $1,143.72 $61.78 $6,990.15 10.70% NOV $1,131.39 $0.00 $1,131.39 $72.42 - -_--$8,193.96 10.70% DEC $0.00 $0.00 $0.00 $73.06 $8,267.02 10.700/6 JAN 90 $1,493.83 $0.00 $1,493.83 _ $87.03 $9,847.89 10.70% FEB $2,274.55 $0.00 $2,274.55 $108.09 $12,230.53 10.70% MARCH $1,676.42 $0.00 $1,676.42 $124.001 $14,030.95 10.70% APRIL $1,623.69 $0.00, $1,623.69 $139.591 $15,794.23 10.70% MAY $2,036.66 $-O 001 $2,036.66 $15�- $17,989.88 10.70%° JUNE $9,670.69 $0.00! $9,670.69 $246.641 $27,907.21 10.71% JULY $0.00 j $0.00 $249.07 $28,156.28 10.71% AUG _$0.00 $0.00 $0.001 $0.00 $251.29 i $28,407.58 10.71% SEPT $98.00 $0.00 1 $98.00 $254.41 ' $28,759.99 10.71% OCT $69,315.10 $0.00 $69,315.10 $875.32 $98,950.41 10.71% NOV $10,955.23 $0.00 $10,955.23 $980.91 j $110,886.55 10.71% DEC $0.00� $0.00 $0.00 �- $989.66i -- $111,876.21 -------- _ 10.71% JAN 91 $0.001 $0.00 $0.00 $998.501 $112,874.71 10.71% FEB $0.00! $0.00 $0.00 _ $1,007.41I $113,882.11 10.71% MARCH $0.001 $0.00 $0.00 $1,016.40 $114,898.51 10.71% APRIL $5,923.001 $0.00 $5,923._00 $1,078.33 $121,899.84 10.71% MAY $12,926.761 $0.00 $12,926.76 $1,203.33 $136,029.93 10.71% 10.59% iJUNE JULY - $22,698.13 $0.00 $0.00 $0.00 $22,698.13 $O.00i $1,416.65 $1,413.28 $160,144.71 $161,557.99 -- 10.59% AUG- $0.00 $0.00 $0.001 $1,425.75 ____ $162,983.74 10.59% SEPT _ $0.00 00..0000 $1,438.33 $164,422.07 .__ OCT $0.00 --- - -_-$$ _$0.00i $0.001 - $1,451.02 $165,83.0910.59% 0_% NOV $4,905.00 $0.00 $4,905.00 $1,507.12 _ $172,285.21 10.59% DEC 1 $378,925.00 $0.00 $3781925.00 $556,074.64 10.59% 1 JAN 92 $110,666.88 $47,056.00 $157,722.88 _$4,864.43 1 $6,299.26 $720,096.78 10.59% iFEB $47,480.27 $16,855.00 $64,335.271 $6,922.61 $791,354.66 10.59% i MARCH $39,030.01 - $23,530.00 $62,560.01 $7,535.80 $861,450.47 10.59% ----------- IAPRILi $0.00 $13,308.00 $13,308.001 $7,719.74 $882,478.22 10.59% IMAY $124,096.73 $17,548.00 $141,644.731 $9,03_7.88 $1,033,160.83 10.59°/ J _ E $30,116.18 $1,730.00 $31,846.18, $9,398.69 $1,074,405.70 Page 9 of 10 Exhibit No. VER-12 Schedule 3 of 3 Part 2 of 2 EDISON Gross Plant, Cash Calls and AFUDC January 1988 -April 1996 Mead-Adelanto and Mead Phoenix Projects AFUDC Rate Date MAP Cash Call A MPP Cash Call B Total Cash Call C AFUDC D Total Gross Plant E 9.94% JULY $0.00 $0.00 $0.00i I $8,899.66 $1,083,305.36 9.94% AUG - $0.00 $0.00 $0.00; $8,973.38 $1,092,278.74 SEPT $307,562.42 $60,742.00 $368,304.421 $12,098.50 $1,472,681.65 9.94% OCT $181,847.001 - -- -- $80,712.00 $262,559.00; $14,373.58 -- $1,749,614.23 9.94% 9.94% NOV DEC $40,080.24i $0.00 $22,274.00 1 $28,691.00 $62,354.241 $28,691.001 $15,009.14 $15,371.12 $1,826,977.61 $1,871,039.73 9.94% JAN 93 $23,713.001 $19,336.001 $43,049.00 $15,855.03 $1,929,943.77 9.94% FEB $81974.00'i , $19,727.001 $101,701.00 $16,828.79 $2,048,473.56 9.94% MARCH $29,343.001 $21,482.001 $50,825.00 $17,389. 99 $2,116,687.75 9.94% APRIL _ $113,682.00i _$38,105.00� $151,787.00 $18,790.53 $2,287,265.28 9.94% MAY $80,686.811 $14,464.001 $95,150.81 $19,734.35 $2,402,150.44 9.94% JUNE $176,457.001 $8,030.00I $184,487.00 $21,425.98 $_2,608,063.42 9.17% JULY $216,389.001 $23,251.00 $239,640.00 $21,761.20 $2,869,464.62 9.17% 'IAUG $203,436.001 $31,458.00 $234,894.00 $23,722.47 $3,128,081.09 9.17% (SEPT $333,741.1 $17,431.00 $351,1 22.00 $26,587.29 $3,505,840.38 9.17% OCT $423,430.00� $26,823.00 $450,253.00 $30,231.15 $3,986,324.53 _ _ 9.17% NOV $242,152.00' $193,824.00 $33,793.75 $4,456,094.28 9.17% 'DEC $204,984.00 $180,573.00 _$435,976.00 $385,557.00 $36,998.29 $4,878,649.56 9.17% !JAN 94 $837,446.93 $136,707.11 $974,154.04 $44,725.17 $5,897,528.78 9.17% FEB $480,881.19 $347,046.14 $827,927.33 $51,393.69 $6,776,849.80 9.17% !MARCH $377,968.43 $246,589.39 $624,557.82 $56,559.09 $7,457,966.71 9.17% 'APRIL $458,530.44 1.12 $112,29_ 82 $570,1.56 $612353.32 $809_0,14_1.59 9.17% MAY $291,291.68 $183,124.67 $474,416.35-- $65,447.50 $8,630,005.44 - ----- -- ------------- 9.17% ----- JUNE $536,873.75 $231,942.54 $768,816.29 - -- $71,822.66 $9,470,644.39 _ 9.80% JULY _ $611,444.07 $208,654.34 $820,098.41 $84,041.07 $10,374,783.87 9.800/6 _ AUG_ _ $278,493.82 $369,646.45 $648,140.27 $90,020.55 $11,112,944.69 9.80% SEPT $105,956.63 $_9_0,230.07 $196,186_.70 $92,357.91 $11,401,489.29 9.80% _ OCT $1,007,930.40 $367.92 $1,008,298.32 $101,346.60 $12,511,134.21 9.80% NOV_ $1,120,257.14 $127,809.03 $1,248,066.17 $112,366.80 $13,871,567.18 9.80% DEC $967,172.41 $572,912.17 $1,540,084.58 $125,861.82 $15,537,513.59 9.80% JAN 95 $528,281.06 $578,843.10 $1,107,124.16 $135,931.21 $16,780,568.95 -- 68.9 9.80% FEB $455,333.62 $302,693.54 $758,027.16 $143,231.87 $17,681,827.98 9.80% MARCH $141,744.06 $308,788.89 $450,532.95 $148,080.95 $18,280,441.88 9.80% APRIL $469,204.19 $103,123.59 $572,327.78 $153,964.29 $16,006,733.95 9.80% MAY $891,092.88 $45,128.30 $936,221.18 $162,867.47 $20,105,822.59 9.80% JUN_E $230,452.06 $452,341.85 $682,793.91 _ $169,773._70 $20,958,390.20 9.27% JULY $325,138.75 $261,710.20 $586,848.95 $166,436.97 $21,711,676.13 9.27% AUG $294,644.07 $48,427.66 $3431071. 33 $170,372.93 $22,225,120.78 9.27% SEPT $25,986.45 $25,986.45 $171,889.80 22 $22,4,997.04 9.27% OCT - -- $6,972.72 $6,972.72 $173,M152 $22,603,241.27 9.27% NOV 1 $138,245.21 $138,245.21 $175,677.98 - $22,917,164.47 - -- 9.27% DEC - $158,644.77 --- $158,644.77 - $178,260.63 $23,254,069.86 _ 9.27% JAN 96 $19,353.641 $19,353.64 $179,787.20 $23,453,210.70 9.27% FEB $157,560.711 $157,560_71 $182,393.21 $23,793,164.62 9.27% MARCH $222,316.291 $222,316.29 $185,519.59 $24,201,000.50 9.27% APRIL (0.5) + _ $631.951 - $631.95 $93,478.81 $24,295,111.25 Total $13,953,111.94 $6,365,039.82 A&G Plant $614,735.00 $614,753.00 Total MAP & MPP Plant $14,567,846.94 $6,979,792.82 Sources: AFUDC Rate: 'W/P Tab AJ. Col. A, MAP Cash Call: W/P Tab AC. Col. B, MPP Cash Call: W/P Tabs R and T. $20,318,151.76 $3,976,959.49 $24,295,111.25 $1,229,488.00 $1,229,488.00 $21,547,639.76 $3,976,959.49 $25,524,599.25 Page 10 of 10 souneiw cwwaHa EDISON Exhibit No. VER-13 Page 1 of 1 Period II STATEMENT BK A R. Escamilla As [vtsoi' /NTLUM770NA4 c�r�x Sheet 1 of 2 SOUTHERN CALIFORNIA EDISON COMPANY ALLOCATED COST OF SERVICE 1998 ESTIMATED AT PROPOSED RATES (THOUSANDS OF DOLLARS) 1 Total Operating Revenue 6.753,989 209,277 6,W.712 2 Operating Expense 3 Total Production Expense 4,905,699 0 4,905,699 4 Total Transmission Expense 82,458 16,779 65,679 5 Total Distribution Expense 204,306 445 203,861 6 Total Customer Accounts Expense 179,691 0 179,691 7 Total C S& I Expense 139,744 0 139,744 8 Total Admin & General Expense 650,797 22,358 528,439 9 Total Electric O & M Expense 6,062,695 39,582 6,023,113 10 Total Depreciation Expense 898,882 53,421 845,461 11 Total Other Taxes • 170,623 14.510 156,113 12 Total Revenue Credits (1,770,252) (42,215) (1,728.037) 13 Total Taxes - Income 432,524 44,373 388,150 14 Total Operating Expense 5,794,472 109,671 5,684,800 15 Total Operating Income 959,517 99,605 859,912 16 Total Rate Base 10,175,143 1,056,252 9,118,891 17 Rate of Return % 9.43% _ 9.43% 9.43% 11 Reflects the revenue requirement associated with those facilities that will be under the operational control of the Independent System Operator. TOTAL ALL LINE NO. DESCRIPTION SYSTEM ISO 11 OTHER SUPPORTING DOCUMENTS AFFIDAVIT OF POSTING STATE OF CALIFORNIA ) COUNTY OF LOS ANGELES) ss CITY OF VERNON ) I, Sharon Johnson, Deputy City Treasurer, of the City of Vernon do hereby certify that I did, on the 12th of April 2004, post two (2) copies of: Notice of Public Hearing - To consider evidence to provide additional support and/or to establish Vernon's Transmission Revenue Requirements for its high voltage (over 200 kV) transmission facilities and entitlements (all located outside the City) for the purpose of Vernon's status as a Participating Transmission Owner with the California Independent System Operator. On each of the following places, to wit: at the northwest corner of 38th Street and Santa Fe Avenue and the northeast corner of Leonis Blvd., and Pacific Blvd., all in said City, there being no newspaper of general circulation printed and published in the City of Vernon. Date: 4ZA!a* Sharon Jo n—s-81h Deputy City Treasurer State of California ) ) ss County of Los Angeles) Onbefore me, Pd">d4 Notary Public personally appeared � ::)44 m Jdh,0 Personally known to me ( a is -- �) to be the person(.$) whose name(-) is/awe subscribed to the within instrument and acknowledged to me that he/she/.4-- r executed the same in lyre/her/ter authorized capacity, and that by-h-irs/her/tom signature(-91 on the instrument the person(4), or the entity upon behalf of which the persons-) acted, executed the instrument. WITNESS my hand and official seal MANUELA GIRON Commission 8 1328374 z@My Notary Public - California y zol Los Angeles County Comm. Expires Nov 4, 20Q5 AFFIDAVIT OF POSTING STATE OF CALIFORNIA ) COUNTY OF LOS ANGELES) ss CITY OF VERNON ) I, Gloria Molleda, Deputy City Clerk, of the City of Vernon do hereby certify that I had, on the 12th of April 2004, posted one (1) copy of: Notice of Public Hearing - To consider evidence to provide additional support and/or to establish Vernon's Transmission Revenue Requirements for its high voltage (over 200 kV) transmission facilities and entitlements (all located outside the City) for the purpose of Vernon's status as a Participating Transmission Owner with the California Independent System Operator. At the following place, to wit: on the bulletin board in the lobby of the City Hall of the City of Vernon located at 4305 Santa Fe Avenue, in said City, there being no newspaper of general circulation printed and published in the City of Vernon. '' ++ �( Date: "I I-- 1- "2" Gloria Molleda Deputy City Clerk State of California ) ) ss County of Los Angeles) � / !" C.lot4t e L4 � lYdyt On 6�,, ��, � i" before me, Notary Public personally appeared �//� d{ i74 Z,1 Personally known to me ( --- -e) to be the person(-&) whose name (s) is/a-r-� subscribed to the within instrument and acknowledged to me that4;i-e/sheer, executed the same in irrs/her/ i-r authorized capacity, and that by h±s/her/ signature(-s) on the instrument the person(-e), or the entity upon behalf of which the person{- acted, executed the instrument. ITNESS my hand and official seal MANUELAGIRON Commission S 1328374 Z z Notary Public • California z Los Angeles County My Comm. Expires Nov 4, 2005 r DECLARATION OF PUBLICATION STATE OF CALIFORNIA COUNTY OF LOS ANGELES NOTICE OF PUBLIC HEARING The City of Vernon will conduct a Public CITY OF VERNON Hearing, which you may attend. PLACE: Vernon City Hall, City Council LEGAL DEPT Chambers, 4305 Santa Fe Avenue, Vernon, 4305 SANTA FE AVE CA 90058 DATE & TIME: Wednesday, May 5, VERNON CA 90058 2004, at 5:00 p.m. (or as soon thereafter as the matter can be heard) APPLICANT: Southern California NOTICE Edison Company, its successors and assigns PURPOSE: To obtain testimony from affected and/or interested persons regarding application by Southern California Edison for EDISON a franchise in the City of Vernon. The public is HEARING/CLOSE/SALE DATE: 05/05/04 also invited to submit written comments regarding the request prior to the hearing. REQUEST: Grant a franchise to use and to construct and use poles, wires, conduits and appurtenances, including communication circuits necessary or proper therefor, in, along, across, upon, over and under the public streets, The undersigned says: ways, alleys and places within the City of Vemon for the purpose of transmitting or distributing electricity through .the City of Vernon, but not to serve retail, wholesale, I am over the age of 18 years and a citizen of the resale or other electric customers located United States. I am not a party to and have no interest in within the City of Vemon. southern California Edison Company this matter. I am a principal clerk of the METROPOLI- franchise, pay during on, city NEWS-ENTERPRISE, a newspaper of general cir- o annuauy, em California Edison's gross annual receipts culation in the City of Los Angeles, the Judicial District arising from the use, operation, or possession of the franchise, from the date of the granting of Los Angeles the County of Los Angeles and the State > > of the franchise. In the event such payment is not made, the franchise will be forfeited The of California, as adjudicated in Los Angeles Superior kan��will beIEWermindiagrams Court Case No. 601165. The notice, a printed copy of and any supporting information are available in the which appears hereon, was published on the following office of the City Clerk, Vernon City Hall, 4305 Santa Fe Avenue, between the hours of date(s): Apr 12, 2004 77:15am. and 5:15 p.m. Monday through Thursday. If you challenge the adoption of this I declare under penalty of perjury that the foregoing is franchise or any provision thereof in court, you may be limited to raising only those issues you true and correct. Executed at Los Angeles, California on someone else raised at the hearing described 04/ 12/04. n this notice or in written correspondence in delivered to the City of Vernon at, or prior to, the meeting. Dated: April 8, 2004 - BRUCE V. MALKENHORST City Administrator/City Clerk CN703295 EDISON Apr 12, 2004 signa r Metropolitan N s-Enterprise P.O. Box 60859 Los Angeles, Ca 90060 Phone: (213) 346-0033 Fax: (213) 687-3886 Cust. Num.: 011501 Control Num.: 703295 Cust. Ref Num.: EDISON 1111111111111111111111111111111111111111 Page 1 of I NOTICE OF PUBLIC HEARING The City of Vernon will conduct a Public Hearing which you may attend. PLACE: Vernon City Hall City Council Chambers 4305 Santa Fe Avenue Vernon, CA 90058 DATE AND TIME: Wednesday, April 21, 2004, at 5:00 p.m., or as soon thereafter as the matter may be heard PURPOSE: To consider evidence to provide additional support and/or to establish Vernon's Transmission Revenue Requirements for its high voltage (over 200 kV) transmission facilities and entitlements (all located outside the City) for the purpose of Vernon's status as a Participating Transmission Owner with the California Independent System Operator Any interested person may attend and may make an oral presentation to the City Council at the time of the hearing, or may present written comments prior to the hearing. If you challenge the approval of the establishment of Vernon's Transmission Revenue Requirements or any provision thereof in court, you may be limited to raising only those issues you or someone else raised at the hearing described in this notice or in written correspondence delivered to the City of Vernon at, or prior to, the meeting. Information may be obtained by contacting the office of the City Clerk at the above address. The hearing may be continued or adjourned to a stated time and place without further notice of a public hearing. Dated: April 12, 2004 BRUCE V. MALKENHORST, City Administrator/City Clerk SUPPORTING DOCUMENTS CITY OF VERNON LIGHT & POWER DEPARTMENT STAFF REPORT REGARDING CITY COUNCIL REVIEW OF VERNON'S TRANSMISSION REVENUE REQUIREMENT April 26, 2004 The City of Vernon established its Transmission Revenue Requirement ("TRR") associated with Vernon's high voltage transmission facilities and entitlements that were turned over to the operational control of the California Independent System Operator ("CAISO") when Vernon became a Participating Transmission Owner ("PTO") on January 1, 2001. Vernon established its TRR pursuant to Resolution Nos. 7608 and 7659 adopted on August 29, 2000 and November 7, 2000, respectively. Based upon the October 15, 2002, decision by the District Court for the District of Columbia, and the FERC's order on remand, the City has hired ratemaking, rate of return and depreciation experts that have determined that the City Council should revise its TRR. BACKGROUND In 1996, the California State Legislature adopted AB 1890, which created the CAISO. AB 1890 required the CAISO to file a Transmission Access Charge ("TAC") tariff with the Federal Energy Regulatory Commission ("FERC") that would establish TACs for high voltage transmission service within the State of California. On May 31, 2000, FERC accepted CAISO's proposed TAC tariff for filing and ordered the CAISO to make a compliance filing in accordance with its order. - 1 - On June 30, 2000, in accordance with the CAISO TAC tariff, the City of Vernon provided its notice of intent to become a PTO. Vernon, a municipal utility, was the first utility that was not subject to FERC's jurisdiction under the Federal Power Act ("FPA"), to apply to become a PTO. In order to become a PTO, pursuant to the TAC tariff, Vernon was required to turn over operational control of Vernon's transmission facilities and entitlements to the CAISO. In return, the CAISO was required to reimburse Vernon its TRR relating to such transmission facilities and entitlements. Vernon undertook all of the tasks necessary for it to become a PTO by January 1, 2001. Among other things, Vernon executed the Transmission Control Agreement ("TCA") with the CAISO, which governs many aspects of PTO status and operations, including the CAISO's acquisition of operational control of Vernon's transmission facilities and entitlements. On February 21, 2001, FERC approved the TCA (94 FERC 1 61,141 (2001)). On August 29, 2000, the City Council held a duly noticed public hearing, during which it considered the appropriate TRR for Vernon. After considering the evidence, including the testimony of expert rate consultant, Albert Clark, the City Council established Vernon's TRR. Among other things, based upon the testimony of Mr. Clark, the City Council determined that it was appropriate to use Southern California Edison ("SCE") as a proxy for Vernon in establishing the rate of return and depreciation for Vernon's TRR. As Mr. Clark noted, SCE and Vernon should not be treated differently in connection with the transmission facilities that both entities turned over to the CAISO`s operational control. Additionally, as Mr. Clark noted, because of the relationship - 2 - between Vernon and SCE, it was rational and proper for Vernon to use SCE as a proxy. On August 30, 2000, Vernon filed a petition for declaratory order with FERC, in which it requested that FERC accept the TRR established by the Vernon City Council. On October 27, 2000, FERC accepted Vernon's TRR, with certain adjustments, and made it effective as of January 1, 2001. Among other things, FERC indicated that if Vernon was going to use SCE as a proxy, although Vernon had not incurred debt when it invested in its transmission facilities, SCE's capital structure should be imputed on Vernon for purposes of FERC's review of the TRR. On November 7, 2000, the Vernon City Council held another duly noticed public hearing during which it considered FERC's rulings. After considering the evidence submitted at that public hearing, the City Council decided to accept the adjustments requested by FERC. Therefore, pursuant to Resolution No. 7659, the City Council approved a revised TRR. Pursuant to Section 203 of the FPA, the CAISO filed for approval of the transfer of Vernon's transmission facilities and entitlements to the CAISO's operational control. (FERC Docket No. EC01-14). In that filing, the CAISO established that the transfer of Vernon's transmission assets was in the public interest and was beneficial to the CAISO. On January 9, 2001, FERC approved the CAISO's Section 203 filing. (California Independent System Operator Corp., 94 FERC (1 62,016 (2001)). On March 28, 2001, FERC approved Vernon's compliance filing as to Vernon's revised TRR (94 FERC 1 61,344). - 3 - THE APPEAL TO THE DISTRICT COURT FOR THE DISTRICT OF COLUMBIA AND FERC'S ORDER ON REMAND Pacific Gas and Electric ("PG&E") appealed FERC's October 2000 and February 2001 orders to the Circuit Court for the District of Columbia. On October 15, 2002, the Court remanded to FERC the question of whether the review conducted by FERC of the TRR for a non - jurisdictional entity - Vernon - that is part of the jurisdictional CAISO, was sufficient to ensure that the CAISO's rates will be just and reasonable under section 205 of the FPA. Among other things, the Court determined that: • No hearing was required under section 205 of the FPA; • PG&E's challenge to the administrative and general expenses that Vernon had approved as part of its TRR was rejected; • Although FERC did not have jurisdiction over Vernon, FERC had jurisdiction over the CAISO's TAC rate. Therefore, FERC needed to assure that when Vernon's rate was included, the CAISO's rate remained just and reasonable; • FERC had failed to articulate the standard that it was applying in order to make sure that when Vernon's TRR was plugged into the CAISO rate, the rate remained just and reasonable; • FERC's determination that SCE was a proper proxy for Vernon was not supported by substantial evidence in the record. Therefore, FERC's determination that Vernon 4 - could use SCE as a proxy for Vernon's own rate of return and depreciation, was not supported. On February 17, 2004, in response to the Court's order on remand, FERC ordered that a hearing be held to explore the appropriate TRR for Vernon that will ensure that the CAISO's rates, after the inclusion of Vernon's TRR, are just and reasonable. The D.C. Court's order on remand made it clear that FERC had properly determined that Vernon was not subject to jurisdiction under section 205 of the FPA. FERC recognized this same point in its order on remand. FERC then indicated that it would hold a hearing on Vernon's rate of return and depreciation, and that all aspects of Vernon's TRR would be considered at the hearing. In response to FERC's order, on April 12, 2004, Vernon posted Notice of Public Hearing, notifying all interested parties that the City Council would hold a public hearing to consider additional evidence in support of Vernon's TRR. The hearing was opened on April 21, 2004, and continued to April 26, 2004. SUMMARY OF TESTIMONY PRESENTED IN SUPPORT OF VERNON'S TRR Staff believes that FERC could have articulated the rationale for use of SCE as a proxy based upon the evidence that was contained in the testimony of Albert Clark. For the reasons stated in that testimony, Vernon needed to use a proxy to determine its rate of return and depreciation. Because of the relationship between SCE and Vernon, the use of SCE as a proxy appeared to be reasonable and proper. Nevertheless, in order to address the concerns raised by the Court and to address FERC's order on remand, Vernon has hired several experienced utility experts in order to provide additional evidence in the record to allow the City Council to review and determine the - 5 - appropriate TRR for the transmission facilities and entitlements that the City turned over to CAISO's operational control on January 1, 2001. That same evidence, as well as the final determination by the City Council, will need to be submitted to FERC in order to allow FERC to review Vernon's TRR and assure that when Vernon's TRR is included in the CAISO rate, the CAISO rate remains just and reasonable. The following expert witness testimony is being submitted to the City Council: Baker G. Clay of Baker G. Clay and Associates; Edward H. Feinstein of Brown, Williams, Moorhead & Quinn, Inc.; and Frank J. Hanley, CRRA, of AUS Consultants -Utility Services. These experts have recommended that the Vernon City Council revise its TRR. Among other things, the experts have determined the following: • the use of SCE as a proxy was reasonable and appropriate. However, the experts have provided additional analysis and have refined Vernon's TRR. • The City Council should adopt, for ratemaking purposes, a depreciation composite rate of 3.14 percent (Edward H. Feinstein). • the City's reliance on SCE as a proxy for the required rate of return of 9.29%, was very conservative and proper. Frank Hanley has concluded, for the reasons set forth in his testimony, that a rate of return of 9.51% would have been more appropriate for Vernon. • Vernon was constrained from making economic use of the California -Oregon Transportation Project ("COTP") facility until January 1, 1996. Therefore, it is appropriate for Vernon to not begin depreciation on the COTP until January 1, 1996, when the facility became - 6 - useful to Vernon and its customers. As such, the accrual of the allowance on funds used during construction ("AFUDC") on the COTP until January 1, 1996, is necessary and fair in order to allow Vernon to earn a fair return on its investment. • although Mr. Hanley has determined that a 9.51% rate of return for Vernon is proper, because the City Council has historically attempted to maintain a competitive balance with SCE, Mr. Clay recommends that the City take a conservative approach and maintain the 9.29% rate of return that was approved by the City Council in Resolution No. 7659 and previously accepted by FERC. • the aggregation of A&G expenses in Vernon's TRR needs to be corrected. • as set forth in his testimony, Mr. Clay has determined that Vernon's total TRR for the transmission facilities and entitlements that it turned over to the CAISO's operational control when Vernon became a PTO, should be revised and established by the City Council at Twelve Million Two Hundred Fifty Three Thousand Seven Hundred Ninety Seven Dollars ($12,253,797.00). RECOMMENDATIONS Based upon the testimony of the experts, it is recommended that the City Council: 1. Amend Resolution Nos. 7608 and 7659, in order to amend and revise the TRR for Vernon's transmission facilities and - 7 - entitlements that were turned over to the operational control of the CAISO on January 1, 2001, when Vernon became a PTO. 2. Approve the revised recommended total TRR for Vernon's transmission facilities and entitlements of Twelve Million Two Hundred Fifty Three Thousand Seven Hundred Ninety Seven Dollars ($12,253,797.00), that has been recommended in the written testimony of Baker G. Clay. 3. Delay any amendment to Vernon's TO Tariff to reflect the revised TRR until FERC determines that when Vernon's TRR is included in the CAISO rate, the CAISO's rate will remain just and reasonable. 4. Approve the written testimony of consultants, Baker G. Clay, Edward H. Feinstein and Frank J. Hanley, and authorize Vernon's staff and Legal Counsel to file such testimony, as well as the Resolution that the City Council adopts herein, with FERC for purposes of FERC's review and determinations relating to the TRR required to be paid to Vernon for the transmission facilities and entitlements that have been turned over by Vernon to the CAISO's operational control. - 8 -