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Home My WebLink About20040319Gribble Rebuttal.pdfm f :- ;::CE\VEO , -' !. I':J If 4- -. . ,,. !', ,-' I ,,~J ej \i:t_.J C-, 1::;'.)1,)11 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICE TO ELECTRIC CUSTOMERS IN THE STATEOF IDAHO. CASE NO. IPC-O3- IDAHO POWER COMPANY DIRECT REBUTTAL TESTIMONY DENNIS C. GRIBBLE Please state your name, address and present occupation? My name is Dennis C. Gribble and my business address is 1221 West Idaho Street, Boise, Idaho.I ~ employed by Idaho Power Company as Assistant Treasurer. Are you the same Dennis C. Gribble that has previously presented direct testimony in this proceeding? Yes, I am. Do you have comments concerning the direct testimony of Staff witness Carlock, Staff witness English, and Micron Technology witness Peseau? Yes, but I must point out that due to the press of time, just because I have not addressed an issue raised in their testimony in my rebuttal testimony, should not be taken as agreement with their testimony. Do you agree with Ms. Carlock's and Dr. Peseau s recommended range of common equity for Idaho Power Company in this proceeding? Ms. Carlock's cost of common equityNo. range of 9.5% to 10.5% and Dr. Peseau s range of 8.4% to 10.6%, are both too low in light of current financial market condi tions . Upon what do you base your opinion that Ms. Carlock's and Dr. Peseau ' s recommended cost of equity ranges are too low? GRIBBLE, Di-Reb Idaho Power Company There are a number of reasons that lead me to (1) the direct and rebuttal testimony of themy conclusion: Company s witness Mr. Avera strongly supports a higher cost of equity range; (2) recent regulatory actions in the region support a higher cost of equity range; (3) the unique risks facing Idaho Power support recognition of a higher cost of equi ty range, and (4) capi tal market trends. Are you aware of recent regulatory actions in the region that support your belief that a higher cost of common equity is reasonable in today s regulatory environment? On December 17, 2003, the Utah PublicYes. Service Commission granted $65 million of additional annual revenues to PacifiCorp based upon an all-parties settlement which included a return on common equity of 10.7% (Docket On August 26, 2003, Pacific03-2035-02, January 30, 2004). Power & Light was authorized a 10.5% return on common equity by the Oregon Public Utilities Commission (UE147, August 26, 2003). On March 6, 2003, PacifiCorp was authorized a 10.75% return on common equity in its Wyoming jurisdiction (2000- ER-02-184, March 6, 2003).A recently published report (Exhibit No. 62) for the 12-month period October 2002 through September 2003, for electric and gas rate cases (" Survey of Recent PUC Rulings," PUR Utility Regulatory News, December 26, 2003, pp.5) showed the following results for GRIBBLE, Di - Reb Idaho Power Company 45 rate cases in which a granted rate of return on common equity was identified: Number 0 f Cases Ranqe of ROE 10-10. 11-11. 12-12. I have attached a copy of the PUR survey as Exhibit 62 to my testimony. Although the Company is still recommending a return of common equity of 11.2%, clearly, recent regulatory orders in other jurisdictions indicate justification for a return on common equi ty higher than those recommended by Ms. Carlock or Dr. Peseau. Do you agree with Ms. Carlock's position that the main risk factors for Idaho Power has been and will continue to be primarily due to non-regulated operations? No.Although, non-regulated operations do present a different risk profile than regulated operations, Idaho Power faces a set of unique risk factors that the inves tmen t communi ty watches very closely.First and foremost, the largest risk factor is adequate snow pack and water flow conditions.A primarily hydro-based system does provide for a low-cost source of power, but reliance upon GRIBBLE, Di - Reb Idaho Power Company the vagaries of the weather and water conditions to recover power supply costs is a significant risk to investors. Obviously, the PCA mechanism does mitigate a large portion of this risk, but still ten percent of extra-ordinary power supply costs in the Idaho jurisdiction are at risk.And, although this Commission has shown historical support of extra-ordinary power supply cost recovery through the PCA mechanism, the risk of regulatory under-recovery does add to the investor s risk assessment.Most utilities have some form of fuel cost adjustment clauses similar to the PCA, but they recover 100% of the prudently incurred fuel related As mentioned in my direct testimony, the Companycosts. PCA 10% sharing mechanism in the Idaho jurisdiction had tremendous negative financial impact to Idaho Power during the recent California energy crisis. What other unique risk factors are attributable to Idaho Power? As I have detailed in my direct testimony, other areas of regulated risk unique to Idaho Power are re- licensing of its hydro facilities, environmental laws and regulations, and the risk of actual recovery of costs through the regulatory process. With the wind-down of IDACORP Energy and the intent to primarily focus on the regulated electric utility, in the eyes of the investment community, the primary risks to GRIBBLE, Di - Reb Idaho Power Company IDACORP are now Idaho Power s unique regulatory risks. These unique Idaho Power risks, as seen by investors when evaluating IDACORP as an investment, places the Company as riskier than most electric utilities. Do you agree with Ms. Carlock's assessment that interest rates are at historical lows and no dramatic increase is expected? I agree that interest rates have trended downward to historical lows over the last several years. fact, the Company s overall cost of capital reflects the prudent management of these capital costs by taking advantage of the low interest rate environment.However, I disagree that no dramatic increase is expected.Federal Reserve Chairman Alan Greenspan indicates that interest rates are too low for long-term economic stability and will have to rise at some point (Wall Street Journal, March Also, Dr. Peseau states in his direct2 004, pg A3) testimony on behalf of Micron "I expect interest rates to increase somewhat in the not too distant future Predicting when interest rates will increase is difficult, but the trend in future interest rates appears upward. Do you agree with the capital structure that Ms. Carlock used to determine Idaho Power s overall cost of capi tal? I am recommending, as detailed inNo. GRIBBLE, Di-Reb Idaho Power Company Exhibi t 63, that the capi tal s truc ture be based upon an actual 2003 year-end capital structure of 51.060% debt, 969% preferred stock and 45.971% common equity for determining the overall cost of capital in these proceedings.This is consistent with the Commission previous order that authorized an actual year-end capital structure at December 31, 1993 for determining the overall rate of return in the Company s last rate proceeding before this Commission (IPC-94-5, Order 25880, pg 19) . Do you agree with PUC Staff witness Donn English's interest rate adjustments for variable rate debt? In a rising interest rate environment,No. Mr. English's recommendation to choose the actual variable rate at year-end 2003 for the variable rate bonds will penalize the Company by setting rates below the actual variable rate costs.By using an appropriate precedent, over time both the shareowner and customer can share in the benefits of lower cost variable rate securities by using an estimated interest rate that is based upon an average of variable interest rates over a historical period of rising and lowering interest. If interest rates are projected to rise, would the rate adjustment proposed in Mr. English' testimony set the Company s variable interest rate levels of recovery below the actual cost of variable interest? GRIBBLE, Di - Reb Idaho Power Company Yes.As Mr. English correctly states in his testimony, "interest rates have been trending downward and are at all-time lows Interest rates are near historical lows, and most economists believe that interest rates will begin rising again, although the timing and rate of the rise are up for debate.The variable rate interest instruments Idaho Power has in its debt portfolio, depending on the security, can reset that security s interest rate daily, weekly or every 35 days.When interest rates begin to rise, the actual cost of the variable rate debt will rise also. Exhibit 64 shows the rate history of IPCo s variable rate debt. How do the actual interest rates for Idaho Power s variable rate debt as of the end of December 2003 compare with the actual rates that these instruments have had in the past? As depicted in Exhibit 65, in all instances, the variable rate at year-end December 2003 is lower than the year-end rates observed for the variable rate bonds in the past. You state that the customer could be penalized in future rate cases if the methodology that staff wi tness English proposes is approved and used as a precedent.Could you please elaborate? As seen in Exhibit 65, the historical year- GRIBBLE, Di-Reb Idaho Power Company end rates have been higher in past years, around 5% as For future rate cases, ifrecently as December 2000. variable interest rates are at higher levels with interest rates moving downward, and the actual year-end variable rate was used for determining the Company s cost of capital, the customer would be penalized.The Company s proposal of using an average rate provides a better sharing of the variable rate benefits to both customers and shareowners and should be continued as the precedent for determining cost of capi tal for this and future rate cases. Has the Commission approved the use of an average rate for variable rate instruments in the past? In Case IPC-94-5, Order 25880, theYes. Commission accepted a five-year historical average for the Company s auction preferred stock (the auction preferred stock variable rate reset every 49 days), instead of using the actual rate as of the end of the 1993 test year.This auction preferred stock issue has been redeemed and therefore is not part of the Company s current cost of capi tal. Why doesn t the Company issue all fixed-rate debt to remove the risk of interest rate volatility? Although variable interest rates on debt instruments change often, over time they provide a less expensive cost of debt than using fixed rate debt. GRIBBLE, Di - Reb Idaho Power Company Exhibi t 66 shows what the debt cost would look like if the Company had issued fixed rate debt at the time of issue, instead of using variable rates for all of the variable rate Assuming the Company had issued fixed-ratebonds. securities rather than variable-rate securities, the Company s proposed cost of debt would have been 6.247% vs. 973% (which assumes the Company s approved 10-year average By undertaking this variable-rate strategy,methodology) . the Company has been able to reduce the customer s annual interest costs by $2,397,700. The Company believes a portion of its debt portfolio should be kept variable to lower the cost of capital, as long as reasonable rate treatment is received.I f the Commission chooses to set the interest rate for its variable-rate securities at the actual year-end variable rate level, then the Company will have to re-evaluate the use of variable rate debt due to the risk of recovery of those costs. Why does the Company propose using the 10- year Bond Market Association (BMA) index plus a spread instead of the actual historical rate of each bond? The Company chose 10 years as a reasonable period of time to include several interest rate cycles. None of the variable rate bonds outstanding have 10 years of history, so a 10-year BMA index, with an observed Company GRIBBLE, Di-Reb Idaho Power Company spread over or under the index for each individual bond was used.Although a 10-year average is the Company preference, if the Commission determines that 10 years is not the appropriate time period, the Company could support a year average methodology, as long as that methodology is applied consistently in future rate cases.If an average of the 5-year BMA index was deemed appropriate by the Commission, the Company s cost of debt would be 5.908% as reflected in Exhibit 67. Do your same recommendations related to the determination of cost of capital for variable rate interest debt hold true for the calculation of the expense related to the American Falls bonds interest? Yes.The interest cost expense related to the American Falls bonds is based upon a variable interest rate with the interest rate resetting on a weekly basis. Since interest expense related to American Falls is included in the Company s expenses rather than as a portion of the cost of capital, the Company proposed through Ms. Smith direct testimony a known and measurable adjustment that was based upon a 10-year average of the BMA index. Staff witness English recommends the latest variable rate of 2.35% as of January 20, 2004 as the basis for determining the appropriate expense recover.Accepting Mr. English' recommendation, places the Company at risk of not recovering GRIBBLE, Di - Reb Idaho Power Company its actual American Falls interest expense in a rising interest rate environment.Again, the Company recommends the Commission accept the Company s known and measurable expense adjustment for the American Falls interest rate expense reflecting a 10-year historical average of variable interest rates. This methodology provides a consistent equi table sharing in the savings between customers and shareowners in both increasing and decreasing interest cycles.Exhibi t 68 shows the significantly increased annual interest expense requirement for the American Falls bond, had the Company issued a fixed-rate security at the issue date of the American Falls bond.Again, if the Commission determines that 10 years is not the appropriate time period, the Company could support a 5-year average methodology for determining the American Falls interest rate known and measurable expense adjustment. As seen in Exhibit 68, using a 5-year historical average to calculate the American Falls interest related expense yields a known and measurable expense adjustment of $225,308. Both Ms. Carlock and Dr. Peseau make a 2004 adjustment that reflects the Company refinancing its $50 million, 8.0%, First Mortgage Bond, that was due March 15, 2004.Do you agree wi th thi s adj us tmen t ? Wi th interest rates at current low levels, it is economical for the Company to refinance this $50 million, GRIBBLE, Di-Reb Idaho Power Company 0% first mortgage bond.The Company paid-off the $50 million, 8.0% First Mortgage Bond on March 15, 2004 by using proceeds received from issuing short-term commercial paper. The Company is currently in the process of permanently refinancing this obligation and the rates chosen by Ms. Carlock (6.0%) appears reasonable for a new 30-year single A rated first mortgage bond.From a theoretical standpoint, I do not disagree with the adjustment proposed by Ms. Carlock. However, from a ratemaking standpoint, the Commission Staff appears inconsistent in recommending this particular 2004 adjustment but rejecting other 2004 expense adjustments supported by the Company. Does this conclude your direct rebuttal testimony in this case? Yes, it does. GRIBBLE, Di-Reb Idaho Power Company BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-O3- IDAHO POWER COMPANY EXHIBIT NO. 62 D. GRIBBLE Utility Regulatory News -:- '--------------,,---,------------" --------------- Since 1934 THE UTILITY REPORTER SPECIALIZING IN STATE COMMISSION RULINGS AUGUST BLACK OUT CERA Reports on Market Design Lessons ambridge Energy Research Associates has released a new report on the blackout of August 14, which says a nwnber of important reliability safeguards and market design principles have emerged from an analysis of the incident, which already has been found by the U.S. Department of Energy to be avoidable. CERA: Blackout Analysis Reveals Major Structural Flaws finds that when the transmission lines into First Energy from the south began to fail, they were carrying about 300 MWs, but because the failing lines could not carry so much power, the flows had to be reduced to avoid losing additional lines and ultimately causing a widespread blackout. CERA finds that could have been accomplished by redispatch, with genera- tion north of the lines (in Michigan to the north and PJM connected to First Energy in the east) being increased, and generation south of the lines being reduced. It also finds that as a last resort, load within First Energy could have been shed. The reliability lessons learned concern both structure and process. CERA believes all highly interconnected areas such as Michigan, Ohio and Indiana should have a single reliability authority with sufficient information, adequate breadth of (See page NATURAL GAS RATES VA Rejects LDC Gas Cost Incentive hile reviewing a series of changes to transportation and large-user service rules proposed by a natural gas local distribution company, the Virginia State Corporation Commission rejected a new gas cost incentive mechanism (GCIM) proposed by the LDC. According to the SCC, Colwnbia Gas of Virginia, Inc. states that its proposed GCIM would change its traditional purchased gas adjustment clause to a more competitive market model, while maintaining the advantages of a regulated company serving the role of a gas supplier of last resort. The company asserts that the GCIM will foster innovative portfolio man- agement with the goals of: (1) acquiring gas supplies for Colwnbia s gas supply customers at prices that are below recognized purchasing benchmarks; and (2) developing skills and products related to upstream markets. The SCC said that the mechanism represents a major change in the way gas costs are allocated and, for the company to improve its gas procurement perfor- mance, it would have to engage in off-system sales, options, and hedging. The SCC also noted that the hearing examiner assigned to review the evidence in the case had expressed concern about inter-company sales between affiliate NiSource (See page Exhibit No. 62 Case No. IPC-O3- D. Gribble, (PCo Page 1 of 5 ~~~g~~~ AUGUST BLACKOUT (Continued from page view and necessary authority to recog- nize and resolve transmission problems before they get out of control. It also makes a strong case that mandatory national reliability standards should be established and enforced by a federal agency. CERA points out that both PJM and MISO, which are jointly responsible for reliability in the Midwest, had the breadth of vision to see the enonnity of the problem. Specifically, PJM did not have the infonnation required to see the severity of the problem, and neither P JM nor MISO had the authority to take the direct actions required. However, American Electric Power (AEP) was able to understand what was happening better than MISO and FirstEnergy, but communication among the parties apparently was inadequate. CERA finds important market design lessons involve both how the market should be designed and what should be done in the interim to pre- vent such enonnous blackouts from happening again. The lessons include: . MISO presently is not functioning as do the longer running indepen- dent system operators in the east such as PJM, New York ISO and ISO New England. PJMhas effec- tive design control over generator outputs through its transmission control centers, enabling it to re-dis- patch quickly when a problem occurs. MISO does not currently have direct control over generation although it plans to in the future. . MISO manages a system of flow gates and transmission loading relief (TLR) requests to avoid overloading the transmission system. MISO schedules transmission flows such that these flow gates are not over- loaded and then requests TLRs to reduce flows on certain lines when a problem occurs. The TLR system is not automatic and takes precious time. A PJM-type market design appears to be the best approach, and the Midwest has plans to implement VIRGINIA NATURAL GAS RATES (Continued from page (which owns Colwnbia and other means of offsetting commodity costs. local distribution companies) to The SCC explained that under the create artificial profits. The Examiner GCIM, the company would share in had stated that off-system sales cur- the benefits of off-system sales, rently provide a direct benefit to the thereby providing a new source of Colwnbia gas sales customers as a revenue for Columbia. In addition RETURN ON EQUITY A Survey of Recent PUC Rulings The following survey was collected utility commissions during the period I from regulators and utility finan- Oct. 1 2002, through Sept. 31 2003 cial officials, as augmented from pub- including traditional rate cases, peri- licly available documents. It covers odic earnings reviews, perfonnance- detenninations of allowances for cost based ratemaking plans, and special of equity capital issued by state public proceedings to detennine revenue such a market design. But until then, if the TLRprocess is the only means MISO has to ensure reliabil- ity, then the flow gates should be set more conservatively so that the cwnbersome TLR process has times to solve a problem. . Merchant generators have no finan- cial incentives to comply with MISO re-dispatch requests. This problem does not exist in P JM, which uses locational marginal prices (LMPs). In PJM, when a transmission con- straint occurs that requires re-dis- patch, generators that need to reduce output will be earning low LMPs and will be pleased to reduce gener- ation to avoid losing money. Conversely, generators that need to increase output will do so in order to earn very high LMPs. Further, PJM has a "no-harm" principle, under which any economic harm to gener- ators resulting from an emergency situation will be equitably redressed when the situation is over. ratepayers would be responsible for at least part of the cost of hedging and other risk-taking actions by the Company. Re Columbia Gas of Vlrginia, Inc., Case No. PUE-2001- 00587, Oct. 31, 2003 (Va.c.c.). requirement for restructured, electric delivery-only" utility operations. Explanatory notes accompany most entries. Parallel citations are provided for orders published in Public Utilities Reports, Fourth Series (PUR4th). Public Utilities Reports, Inc. Phillip S. Cross, Editor One year of weekly service: 8229 Boone Boulevard Dcross(ii)our.com $549 Call: 800-368-5001Suite 400 Lori A. Burkhart, Managing Editor For e-mail address changes Vienna, VA 22182 lab((jipur.com or other information. contact Phone: 703-847-7720 Jean Cole, Editorial Assistant icfark(gJ,pur.com 800-368-5001 ico/efg)pur.com or 80~368-500/, :: - n__ ;;;;-;:---- $;;:~~~ Y:~ ;::i ::. 0....." whm, ~ PUR Utility Regulatory News December 26, 2003 2 C ~ I No.jpC-O3- D. Gribble, IPCo Page 2 of 5 ILiTY GULATORY EWS ~~~~ ANNUAL SURVEY OF ELECTRIC AND GAS UTILITIES AUTHORIZED RATE OF RETURN ON COMMON EQUITY Rale of Rebm on Increase Increase Common Equi1;y (Decrease)(Decrease)Previously NewlyJurisdiction and Type of Service Case. Docket,Application Order Test.year Requested Granted AuIhorized Au1horized Company Name (Electric or Gas)or Decision No.Date Dale End Dale ($Minion)(SMiDion)Rale (%)Rale(%) ARIZONA UniSource Energy Corp.Gas E-O132C-OO- 0751 8/6/02 413/03 12/31/01 10.11.001 ARKANSAS Arkansas Western Gas Co,Gas 02-227-11/8/02 9117103 6/30102 11.00 CAUFORNIA Pacific Gas & Electric Co.Electric 02-11-O272 5/8/02 11m02 12131/03 133.11,11. 227 PUR4th 507 Pacific Gas & Electric Co,Gas 02-11-O27 5/8/02 11m02 12131/03 23.11.2 11.2 San Diego Gas & Electric Co,Electric 02-11-O27 5/8/02 11m02 12131/03 24,10,10, San Diego Gas & Electric Co,Gas 02-11-027 5/8102 11m02 12131/03 10.10. Sierra Pacific Power Co.Electric 02-11-O27 5/8/02 11m02 12131/03 362 10.10. Southern California Edison Co,Electric 02-11-O27 128 11.6 11. COLORADO Aquila. Inc.Electric C03-O697 10115/02 6/12103 6/30102 15.10.75 226 PUR4th 445 Public Service Co. 01 Colorado Electric 02S-315EG 5/31/02 6/26103 12131/01 74.10.2)3 11.10.75 Public Service Co, 01 Colorado Gas 02S-315EG 5/31/02 6/26/03 12131/01 133.11.25 11. 226 PUR41h 380 CONNECTICUT United Illuminating Co.Electric 01-10-10 11/15/01 9/26102 12131/00 130.11.50 10. DISTRICT OF COLUMBIA Washington Gas Light Co.Gas 989 6/19/01 10129102 12131/00 16.15.10. Order No. 12589 227 PUR4th FLORIDA Peoples Gas System Gas PSC-O3-OO38-FOF-6/24/02 1/6103 12131/03 22.12.11.25 222 PUR41h 476 ILLINOIS Commonwealth Edison Co.Electric4 01-0423 6/1/01 3/28103 12131/00 787 1.508 10.11.72 224 PUR4fh 357 IOWA Aquila Gas RPU-02-6/3/02 2/18103 12131/01 12. Interstate Power & Ught Co.Electric RPU-O2-3/29102 4/1 5JO3 12131/01 25.11.1165 225 PUR4fh 165 Interstate Power & Ugh! Co.Gas RPU-02-7/15102 5/15103 12131/01 20.13.11.011' MidAmerican Energy Co,Gas RPU-02-3/15/02 11/8/02 12131/01 26.17.10.75 KANSAS Empire Distrid Electric Co.Electric EPDE-488-RTS 12128/01 6/27/02 6130101 11. Kansas City Power & light Co.Elecbic 02-KCPE-840-RTS 4/24/02 5/24/02 12/31/01 112-131 112. KENTUCKY Kentucky Power Co.Electric 2002-00169 9130102 3/31/03 11.11.00 Rate case decision was resuI of a settlement. No adversarial PUC determination of ROE. 1 Result of setIIement a~ Ihat included the pll'Chase of Citizens ' Gas 8IId Electric assets by UniSource Energy. 60140 debtlequily hypothetical cap stnJctiIe. 2 Amual cost of capital proceedi1g. Interim order establishing ROE lor electric 8IId gas d'1StJibution public utilities lor 2003 test year. 3 F9Ire shown does not include fuel clause revenues. 4 Revenue requiement lor deIiveIy service only. 5 F1gUIe rellects double leverage calculation with ROE of 11.15 percent. 6 Figure reflects double leverage calculation with ROE of 11.05 percent. 7 Envirorunental sUltharge proceeding, . . ~ PUR Utility Regulatory News, December 26, 2003 Exhibit No. 62 Case No. IPC-O3- D. Gribble, IPCo Page 3 of 5 . . ./- !;_'~if~t1,I;~; ~~~~;ij11I\1i,lt~~i rtH,F~t1r"Ed~~~~~nldJ~' / . (We ; .. ANNUAL SURVEY OF ELECTRIC AND GAS UTILITIES AUTHORIZED RATE OF RETURN ON COMMON EQUITY (CONTINUED) Rate of Rebm on Increase Increase Common Equity (Decrease)(Decrease)Previously NewlyJurisdiction and Type of Service Case. Docket,Application Order Test-year Requested Granted Authorized AuthorizedCompany Name (Electric or Gas)or Decision No.Date Date End Date ($Million)($MiDion)Rate (%)Rate(%) LOUISIANA CIeco Power LLC Electric 21496F 5/9/03 9130/02 12.25 12.25 Entergy Gulf States. Inc.Electric 22491. et ai,1/8103 12/31/00 (22.1)11.11. Evangeline Natural Gas Co.Gas 25402 11/13/00 9127/02 4/30101 238 104 10.50 MARYLAND Washington Gas Light Co.Gas 8920 3/28/02 9/27/02 12/31/01 31.4 9.79 MAINE Maine Public Service Co.Electric 2003-085 3/6103 9/3/03 12/31/02 1.27 10.7()9 10.259 MICHIGAN Consumers Energy Co.Gas 13000 6/29/01 11nt02 12/31/02 140 11.6 11. 227 PUR41h 270 MISSOURI Empire District Electric Co,ElectJic ER20D0-424 3/8/02 11/4/02 12/31/01 19.11. laclede Gas Co,Gas GR-2oo2.356 1/25/02 11/8/02 11/30/01 36.14.10. NEW HAMPSHIRE Norther Utilities Gas DG"()1.182 11/15/00 10128/02 6/30/01 11, NEW JERSEY Elizabethtown Gas Gas GR"()2040245 4/16/03 11/22/03 5/31/03 28.142 14.10. Jersey ~ntral Power & Ught Electric ER02080506 8/1/02 8/1/03 12/31/02 (41)(223)10 12.2 511 Public Service Electric & Gas Electric ER02050303 5/24fO2 7/31/03 2/31/02 250 159.12. Rockland Electric Co.ElectJic GR0200724 8/1/03 7/31/03 4130103 (7.12.00 NEW YORK New York State Electric & Gas Corp,Gas 01-1668 11/20102 9/30/02 22.10.11.11.512 222 PUR41h 378 Orange & Rockland Utilities. Inc.Electric 03-E"()797 7/1/03 10/03 12/31/02 10.12.7512 Orange & Rockland Utilities, Inc,Gas 02-G-1553 11/1/03 10103 6/30/02 27.17.11.65 11.0012 NORTH DAKOTA Montana-Dakota Utilities Co.Gas PUR-399-02-183 4/12102 12/18/02 12/31/03 2.8 11.329 222 PUR41h OKlAHOMA Empire District Electric Co.Electric PUD.2003-121 3/4/03 7/31/03 11130102 11. OREGON Northwest Natural Gas Gas UG152 11/29/02 8/22/03 9130/04 38.6213 10.10. Pacific Power & Light Electric UE147 3/18/03 8/26103 3/31/04 57.10.75 10. RHODE ISLAND New England Gas Co.Gas 17381 11/1/01 2/28/03 6130/03 (3.9)14 11.2515 11.2515 225 PUR41h 407 Rate case decision was resut 01 a settlement. No adversarial PUC detennination or ROE. 'Annual earnings review. 9SetUement with ROE specified. 111Jnc1uded $4 miIion revenue reduction resulting from a penalty of 25 basis points against ROE to reIIect poor service reiabirlty, I1BPU wiH review selVice quaity performance in Phase II proceeding, Upon satisfactoty review utility may request ROE increase to 9.75 percent. Negative review to resu. in 9.25 perceIt ROE.l~year rate agreements. ROE shown is ttreshoId for earnings sharing mechanism, 13$62 mBflOR inaease elfective Sept. 1. 2003. OveraU inaease wiD rise to $13.9 with 2004 new construction in-service date.14Post-merger rate setllement. Rate reduction to be foUowed by J.year rate Ireeze, 15FIgIII'e shown is tiI'eshokI for earnings sharing mechanism. xhibit No, 62 ~ PUR Utility Regulatory News, December 26, 2003 Case No. IPC-O3- D. Gribble, IPCo Page 4 of 5 " ~ , (~_I_1f_Jjf~~i~~!F~~rfllt~~~:t;iJ~1~~~~:i ANNUAL SURVEY OF ELECTRIC AND GAS UTILITIES AUTHORIZED RATE OF RETURN ON COMMON EQUITY (CONTINUED) Rate of Return on Increase Increase Conunon Equity Type of Service (Decreasel (Decrease)Previously NewlyJurisdiction and Case, Docket,Application Order Test-year Requested Granted AIdhorized AuIhorized Company Name (Elec:lric or Gas)or Decision No.Dale Date End Date ($Minion)($Mimon)Rate ('110)Rate(%) SOUTH CAROUNA Piedmont Na1lIaI Gas Co,Gas 2002-6J.G 5f.W2 11n102 1/31/02 15.8.38 12.6 2002-761 223 PUR4th 497 South Carolina Electric.Electric 2OO2-223-8/6/02 1/31/03 3/31/02 104.7 70.7 12.12.45 & Gas Co,2003-38 225 PUR4th 440 UTAH Questar Gas Co.Gas 02-057-02 5/3102 12/30/02 12/31/02 23.017 11.163 11.11.2 VERMONT Central Vermont Public Electric 6460 1119/00 6/26/01 6/30/00 19.852 11.00 11. Service Corp, WISCONSIN Madison Gas & Electric Co,Electric 3270-UR-111 5/1/02 2/28/03 12/31/03 14.20.12.12. Madison Gas & Electric Co,Gas 3270-UR-111 5/1/02 2/28/03 12/31/03 12,12. WYOMING PaciliCorp Electric 2ooO-ER-o2-184 5n102 3/6103 9/30102 30.716 11,10. 224 PUR4th Rate case decision was resutt or a seWement No adversarial PUC detenninalion or ROE. 16The utility had requested a rate increase totalling $121.7 million, consisting 01 a 30.7 million general base rate increase. a $60.3 million surcharge to IaSlIlvee years to coIlectOexcessO wholesale power costs and an additional $30.7 million 3-year surcharge to recover excess replacement power costs, The PSC rejected \he sur- charge requests, ~ PUR Utility Regulatory News December 26, 2003 Exhibit No, 62 Case No. IPC-O3- D. Gribble, IPCo Page 5 of 5 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-O3- IDAHO POWER COMPANY EXHIBIT NO. 63 D. GRIBBLE Capital Structu re Analysis ID A H O P O W E R C O M P A N Y Ca p i t a l S t r u c t u r e A n a l y s i s CO M P O S I T E C O S T O F C A P I T A L AT P R O P O S E D R A T E O F R E T U R N - 1 2 / 3 1 / 2 0 0 3 (1 ) (2 ) (3 ) (4 ) (5 ) Li n e Ca p i t a l i z a t i o n S t r u c t u r e Em b e d d e d We i g h t e d Am o u n t Pe r c e n t Co s t Co s t Lo n g - te r m D e b t 90 1 , 56 5 00 0 51 . 06 0 % 97 3 % 05 0 % Pr e f e r r e d S t o c k 52 , 4 2 9 , 4 0 0 96 9 % 53 9 % 19 4 % Co m m o n E q u i t y : 81 1 69 8 91 5 45 . 97 1 % 11 . 20 0 % 14 9 % To t a l C a p i t a l i z a t i o n 76 5 , 69 3 31 5 10 0 . 00 0 % 39 3 % NO T E : * U S I N G 1 1 . 2% F O R C O S T O F E Q U I T Y V A L U E Ex h i b i t N o . 6 3 CA S E N O . I P C - O3 - D. G R I B B L E , I P C o Pa g e 1 o f 1 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-O3- IDAHO POWER COMPANY EXHIBIT NO. 64 D. GRIBBLE Variable Rate Hsitory (:)'#. 8/29/1996 11/29/1996 2/28/1997 5/29/1997 8/29/1997 11/29/1997 2/28/1998 5/29/1998 8/29/1998 11/29/1998 2/28/1999 5/29/1999 8/29/1999 11/29/1999 2/29/2000 III5/29/2000 8/29/2000 11/29/2000 2/28/2001 5/29/2001 8/29/2001 11/29/2001 2/28/2002 5/29/2002 8/29/2002 11/29/2002 2/28/2003 ):05/29/2003 (J) Q m m8/29/2003 2;!z ):0009:1:QOO-(ij11/29/2003 mr-c-ma-l ..... - - m Z 0 -c I 0 II a ~ ..... V).,... Reset Rates .....'#. !'V '#.'#.'!'-'#.'#.....(:) '#. '#. '"tI c::: .., (I) (I) :E: (I) -to (I) I !-c ):0 (J) (J) 0 3 ~ ~ 1 ;::1. CD CD 0 II CD CD ,...a. s: en ~ ~ '..... ..... .. .."...- -~-.. '--~.""'-"~"--'-"'-""--"""-'.......-......_......_... BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-O3- IDAHO POWER COMPANY EXHIBIT NO. 65 D. GRIBBLE Year-End Rates for Variable Rate Debt IPCO ACTUAL YEAR-END RATES FOR VARIABLE RATE DEBT Sweetwater Sweetwater Line No Date Series B Series C American Falls Port of Morrow 12/31/1996 90%00% 12/31/1997 20%10% 12/31/1998 20%20% 12/31/1999 00%80% 12/31/2000 05%90%20%05% 12/31/2001 90%00%75%75% 12/31/2002 85%80%05%65% 12/31/2003 33%40%55%15% EXHIBIT NO. CASE NO. IPC-03- D. GRIBBLE, IPCO PAGE 1 OF 1 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-O3- DAHO POWER COM P ANY EXHIBIT NO. 66 D. GRIBBLE Long-Term Debt (2 ) ID A H O P O W E R C O M P A N Y EF F E C T I V E E M B E D D E D C O S T O F LO N G - TE R M D E B T - U P D A T E D T H R O U G H 1 2 / 3 1 / 2 0 0 3 CO M P O S I T E C O S T O F C A P I T A L 2 0 0 3 ($ O O O ' (6 ) (4 ) (5 ) (1 0 ) (1 1 ) (1 2 ) (1 3 ) (( 4 ) + ( 6 ) - ( 7 ) - ( 8 ) - ( 9 ) ) (( 4 ) ' ( 1 1 ) ) (( 1 2 ) / ( 1 0 ) ) Ne t An n u a l Un d e r w r i t e r E x p e n s e Pr o c e e d s In t e r e s t Ef f e c t i v e Pr e m i u m Di s c o u n t Co m m i s s i o n o f Is s u e Re c e i v e d Ra t e Re q u i r e m e n t s Co s t 40 6 , 9 4 76 5 , 0 1 3 68 5 , 6 7 0 9 , 14 2 , 5 4 4 65 7 , 0 6 , 29 7 % (7 ) (8 ) (9 ) (1 ) (3 ) Li n e Cl a s s a n d S er i e s To t a l F i r s t M o r t g a g e B o n d s Da t e o f Is s u e Pr i n c i o a l A m o u n t Is s u e d Ou t s t a n d i n g 73 0 , 00 0 7 3 0 , 00 0 Pr i c e Po l l u t i o n C o n t r o l R e v e n u e B o n d s : 05 % S e r i e s 1 9 9 6 A , d u e 2 0 2 6 7/ 2 5 / 1 9 9 6 68 , 10 0 10 0 99 , 30 8 47 1 , 44 2 , 40 3 , 78 2 , 05 0 % 12 0 , 46 0 Va r , R a t e S e r i e s 1 9 9 6 B , d u e 2 0 2 6 . . , (a ) 7/ 2 5 / 1 9 9 6 20 0 24 , 20 0 10 0 , 00 0 78 , 16 5 , 23 , 95 6 , 97 0 % 71 8 , 00 0 Va r , R a t e S e r i e s 1 9 9 6 C , d u e 2 0 2 6 . . , (b ) 7/ 2 5 / 1 9 9 6 24 , 00 0 00 0 10 0 , 00 0 78 , 22 2 , 23 , 69 9 , 92 0 % 70 0 , 95 7 Po r t o f M o r r o w V R C , d u e 2 0 2 7 . . . . . . . . . . (c ) 5n 1 2 0 0 0 36 0 36 0 10 0 , 00 0 50 , 72 , 23 7 , 98 0 % 17 3 , 09 5 Va r , R a t e R e f i n a n c e d H u m b o l d t S e r i e s , d u e 2 0 2 4 . . (1 1 2 / 2 0 / 1 9 8 4 49 , 80 0 49 , 80 0 10 0 , 00 0 24 9 , 17 6 , 48 , 37 4 , 65 0 % 81 7 , 75 8 To t a l P o l l u t i o n C o n t r o l R e v e n u e B o n d s 17 0 , 46 0 17 0 , 46 0 47 1 , 89 8 . 3 03 9 , 16 4 , 05 1 , 53 0 , 59 1 Pr a i r e P o w e r R E A N o t e s (d ) va r i o u s 10 5 , 10 5 , 36 , 26 7 TO T A L D E B T C A P I T A L . . . . . . . . . . , $9 0 0 , 46 0 $9 0 1 56 5 , 87 8 , $5 , 66 3 , $1 8 , 72 4 , $8 7 4 29 8 , $5 2 22 3 , 97 3 % ID A H O P O W E R C O M P A N Y EF F E C T I V E E M B E D D E D C O S T O F LO N G - TE R M D E B T - U P D A T E D S C E N A R I O I F Al l P C BO N D R A T E S H A D B E E N F I X E D A T T I M E O F I S S U E - U P D A T E D T H R O U G H 2 0 0 3 ($ O O O ' (6 ) (2 ) (3 ) (4 ) (5 ) (7 ) (8 ) (9 ) (1 0 ) (( 4 ) + ( 6 ) - ( 7 ) - ( 8 ) - ( 9 ) ) Ne t Pr o c e e d s Re c e i v e d 70 9 , 14 2 , (1 1 ) (1 2 ) (1 3 ) (( 4 ) ' ( 1 1 ) ) (( 1 2 ) / ( 1 0 ) ) An n u a l In t e r e s t Ef f e c t i v e Ra t e Re q u i r e m e n t s Co s t 44 , 65 7 , 29 7 % (1 ) Li n e Cl a s s a n d S er i e s To t a l F i r s t M o r t g a g e B o n d s Da t e o f Is s u e Pr i n c i o a l A m o u n t Is s u e d Ou t s t a n d l n 73 0 , 00 0 7 3 0 , 00 0 Pr i c e Pr e m i u m Un d e r w r i t e r Di s co u n t Co m m i s s i o n 40 6 , 9 4 , 76 5 , Ex p e n s e of I s s u e 13 , 68 5 , Po l l u t i o n C o n t r o l R e v e n u e B o n d s : 05 % S e r i e s 1 9 9 6 A . d u e 2 0 2 6 7/ 2 5 / 1 9 9 6 10 0 10 0 99 , 30 8 47 1 , 44 2 , 3, 4 0 3 , 63 , 78 2 , 05 0 % 12 0 , 46 0 Va r , R a t e S e r i e s 1 9 9 6 B , d u e 2 0 2 6 . . , (a ) 7/ 2 5 / 1 9 9 6 20 0 20 0 10 0 , 00 0 78 , 16 5 , 23 , 95 6 , 95 0 % 43 9 , 01 1 Va r , R a t e S e r i e s 1 9 9 6 C , d u e 2 0 2 6 . . , (b ) 7/ 2 5 / 1 9 9 6 00 0 00 0 10 0 , 00 0 78 . 0 22 2 , 23 , 69 9 , 95 0 % 1, 4 2 8 , 02 5 Po r t o f M o r r o w V R C , d u e 2 0 2 7 . . . . . . . . . . (c ) 5f 7 1 2 0 0 0 36 0 36 0 10 0 , 00 0 50 , 72 , 23 7 , 88 0 % 25 6 , 05 0 Va r , R a t e R e f i n a n c e d H u m b o l d t S e r i e s , d u e 2 0 2 4 . . (1 1 2 / 2 0 / 1 9 8 4 49 , 80 0 49 , 80 0 10 0 , 00 0 24 9 , 17 6 , 48 , 37 4 , 39 0 % 68 4 , 54 9 16 T o t a l Po l l u t i o n C o n t r o l R e v e n u e B o n d s 17 0 , 4 6 0 17 0 , 46 0 47 1 , 89 8 . 3 03 9 , 16 4 05 1 , 92 8 , 05 2 Pr a i r e P o w e r R E A N o t e s (d ) va r i o u s 10 5 , 10 5 , 36 , 26 7 18 T O T A L D E B T C A P I T A L .. . . , . . " . . $9 0 0 , 4 6 0 $9 0 1 , 56 5 , $2 , 87 8 , $5 , 66 3 , $1 8 72 4 , $8 7 4 , 29 8 , $5 4 , 62 1 , 24 7 % (a ) - F i x e d R a t e F a i r M a r k e t Y i e l d c u r v e i f I n t e r e s t f o r U t i l i t y A - 3 0 y e a r m u n i c i p l e d e b t a s o f 8 / 2 9 / 9 6 - S o u r c e - B l o o m b e r g (b ) - F i x e d R a t e F a i r M a r k e t Y i e l d c u r v e i f I n t e r e s t f o r U t i l i t y A - 3 0 y e a r m u n i c i p l e d e b t a s o f 8 / 2 9 / 9 6 - S o u r c e - B l o o m b e r g (c ) - F i x e d R a t e F a i r M a r k e t Y i e l d c u r v e i f I n t e r e s t f o r U t i l i t y A - 3 0 y e a r m u n i c i p l e d e b t a s o f 4 / 2 6 / 0 0 - S o u r c e - B l o o m b e r g (d ) - I n c l u d e s v a r i o u s d a t e s o f i s s u e a n d m a t u r i t y - s o m e a t 2 , 0% t h a t m a t u r e q u a r t e r l y a n d s o m e a t 5 , 0% t h a t m a t u r e m o n t h l y (e ) - F i x e d R a t e F a i r M a r k e t Y i e l d c u r v e i f I n t e r e s t f o r U t i l i t y A - 2 0 y e a r m u n i c i p l e d e b t a s o f 1 0 / 2 2 / 0 3 - S o u r c e . B l o o m b e r g NO T E : A m e r i c a n F a l l s D a m B o n d a n d M i l n e r D a m N o t e a r e g u a r a n t e e s , T h e s e i n s t r u m e n t s a r e e x c l u d e d i n r a t e m a k i n g c a l c u l a t i o n s a n d t h e r e f o r e a r e o m i t t e d f r o m t h i s s c h e d u l e , An n u a l I n t e r e s t S a v i n g s I 2 , 39 7 , 7 I EX H I B I T N O , 6 6 CA S E N O . IP C - 03 - D, G R I B B L E , I P C O PA G E 1 O F 1 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-O3- IDAHO POWER COMPANY EXHIBIT NO. 67 D. GRIBBLE Long-Term Debt - BMA Average (1 ) ID A H O P O W E R C O M P A N Y EF F E C T I V E E M B E D D E D C O S T O F LO N G - TE R M D E B T - U P D A T E D T H R O U G H 1 2 / 3 1 / 2 0 0 3 - ( U S I N G 5 Y E A R B M A A V E R A G E ) CO M P O S I T E C O S T O F C A P I T A L 2 0 0 3 ($ O O O ' (6 ) (3 ) (4 ) (5 ) (1 0 ) (1 1 ) (1 2 ) (1 3 ) (( 4 ) + ( 6 ) - ( 7 ) - ( 8 ) - ( 9 ) ) (( 4 ) - ( 1 1 ) ) (( 1 2 ) / ( 1 0 ) ) Ne t An n u a l Un d e r w r i t e r E x p e n s e Pr o c e e d s In t e r e s t Ef f e c t i v e Pr e m iu m Di s c o u n t Co m m i s s i o n 01 I s s u e Re c e i v e d Ra t e Re q u i r e m e n t s Co s t 2, 4 0 6 , 9 4 76 5 , 0 1 3 68 5 , 6 7 0 9 14 2 , 5 4 4 65 7 , 0 6 , 29 7 % (7 ) (8 ) (9 ) (2 ) Li n e Cl a s s a n d S er i e s To t a l F i r s t M o r t g a g e B o n d s Da t e 0 1 Is s u e Pr i n c i D a l A m o u n t Is s u e d Ou t s t a n d i n g 73 0 , 00 0 7 3 0 00 0 Pr i c e Po l l u t i o n C o n t r o l R e v e n u e B o n d s : 05 % S e r i e s 1 9 9 6 A , d u e 2 0 2 6 7/ 2 5 / 1 9 9 6 10 0 68 , 10 0 99 , 30 8 47 1 . 44 2 , 3,4 0 3 , 63 , 78 2 , 05 0 % 12 0 , 46 0 Va r , R a t e S e r i e s 1 9 9 6 B , d u e 2 0 2 6 . . , (a ) 7/ 2 5 / 1 9 9 6 20 0 24 , 20 0 10 0 , 00 0 78 . 7 16 5 , 23 , 95 6 , 41 0 % 58 3 , 43 5 Va r . R a t e S e r i e s 1 9 9 6 C , d u e 2 0 2 6 . . , (b ) 7/ 2 5 / 1 9 9 6 24 , 00 0 00 0 10 0 , 00 0 78 . 0 22 2 , 23 , 69 9 , 36 0 % 56 6 , 39 0 Po r t o f M o r r o w V R C , d u e 2 0 2 7 . . . . . . . . . . (c ) 5n t 2 0 0 0 36 0 36 0 10 0 , 00 0 50 , 72 , 23 7 , 42 0 % 14 9 , 51 9 Va r , R a t e R e f i n a n c e d H u m b o l d t S e r i e s , d u e 2 0 2 4 . . (1 12 1 2 0 / 1 9 8 4 80 0 49 , 80 0 10 0 , 00 0 24 9 , 17 6 , 48 , 37 4 , 09 0 % 53 8 , 18 1 To t a l P o l l u t i o n C o n t r o l R e v e n u e B o n d s 17 0 , 46 0 17 0 , 46 0 47 1 , 89 8 , 03 9 , 16 4 05 1 , 95 7 , 24 1 Pr a i r e P o w e r R E A N o t e s (d ) va r i o u s 10 5 , 10 5 , 36 , 26 7 TO T A L D E B T C A P I T A L . . . . . . . . . . , $9 0 0 , 46 0 $9 0 1 56 5 , $2 , 87 8 , $5 , 66 3 , $1 8 , 72 4 , $8 7 4 29 8 , $5 1 65 0 , 90 8 % (a ) - In t e r e s t f o r S w e e t w a t e r 1 9 9 6 B B o n d w a s e s t a b l i s h e d b y t a k i n g t h e a v e r a g a g e s p r e a d o v e r t h e B M A i n d e x o n t h e l i f e 0 1 t h e b o n d p l u s a v e r a g e o f t h e 5 y e a r B M A i n d e x ( - 07 + 2 , 48 = 2 , 41 ) (b ) - In t e r e s t f o r S w e e t w a t e r 1 9 9 6 C B o n d w a s e s t a b l i s h e d b y t a k i n g t h e a v e r a g a g e s p r e a d o v e r t h e B M A i n d e x o n t h e l i f e o f t h e b o n d p l u s a v e r a g e 0 1 t h e 5 y e a r B M A i n d e x ( - 12 + 2 , 48 = 2 , 36 ) (c ) - I n t e r e s t f o r P o r t 0 1 M o r r o w B o n d w a s e s t a b l i s h e d b y t a k i n g t h e a v e r a g a g e s p r e a d o v e r t h e B M A i n d e x o n t h e l i f e o f t h e b o n d p l u s a v e r a g e o f t h e 1 0 y e a r B M A I n d e x ( 0 , 94 + 2 . 4 8 = 3 , 42 ) (d ) - I n c l u d e s v a r i o u s d a t e s o f i s s u e a n d m a t u r i t y - s o m e a t 2 , 0% t h a t m a t u r e q u a r t e r l y a n d s o m e a t 5 , 0% t h a t m a t u r e m o n t h l y (e ) - I n t e r e s t f o r H u m b o l d t B o n d w a s e s t i t m a t e d b y t a k i n g t h e a v e r a g a g e s p r e a d o v e r t h e B M A i n d e x o n t h e l i f e o f t h e b o n d p l u s a v e r a g e o f t h e B M A i n d e x ( 0 , 61 + 2 . 4 8 = 3 , 09 ) NO T E : A m e r i c a n F a l l s D a m B o n d a n d M i l n e r D a m N o t e a r e g u a r a n t e e s , T h e s e i n s t r u m e n t s a r e e x c l u d e d i n r a t e m a k i n g c a l c u l a t i o n s a n d t h e r e f o r e a r e o m i t t e d f r o m t h i s s c h e d u l e , EX H I B I T N O , 6 7 CA S E N O , I P C - 03 - D, G R I B B L E , I P C O PA G E 1 O F 1 "" U )= - "" " " "" U (" ) S) ) :: : D "" U S) ) :: : D :: : D (" ) "" " " "" U .. . . . . . I\ ) -c : : AM E R I C A N F A L L S S E R I E S 2 0 0 0 $1 9 , 88 5 , 00 0 Li n e N o l() ) Y e a t A V G . A iN D E X An n u a l I n t e r e s t Ex p e n s e 20 0 3 5 0 4 50 4 . 29 (1 ) 20 0 4 8 0 1 94 0 . 51 (2 ) Ad j u s t m e n t 2 9 7 , 4 3 6 . 5Y e a r A V G ~ M A . IN D E X " . " An n u a l I n t e r e s t Ex p e n s e 50 4 50 4 . 29 (1 ) 72 9 , 81 2 . 64 (3 ) 22 5 , 30 8 . Fix e d . Ra t e An n u a l I n t e r e s t Ex p e n s e 50 4 , 50 4 . 29 (1 ) 18 8 , 72 5 . 30 (4 ) 68 4 , 22 1 . NO T E S : 1) I n t e r e s t f o r J u l - 03 - D e c - 03 w a s c a l c u l a t e d b y f o r e c a s t i n g i n t e r e s t r a t e s f r o m 0 7 - 22 - 03 t o e n d o f y e a r 2 0 0 3 . - I n t e r e s t r a t e s w e r e c a l c u l a t e d u s i n g a t r e n d l i n e d e v e l o p e d b y a r e g r e s s i o n e q u a t i o n u s i n g ac t u a l d a t a f r o m 1 - 01 - 03 - 0 7 - 22 - 03 . 2) I n t e r e s t f o r 2 0 0 4 w a s c a l c u l a t e d b y u s i n g t h e 1 0 y e a r a v e r a g e o f t h e B M A i n d e x p l u s t h e A m e r i c a n F a l l s hi s t o r i c a l s p r e a d o v e r t h a t i n d e x ( 3 . 04 + 1 . 08 = 4 . 12 ) . 3) I n t e r e s t f o r 2 0 0 4 w a s c a l c u l a t e d b y u s i n g t h e 5 y e a r a v e r a g e o f t h e B M A i n d e x p l u s t h e A m e r i c a n F a l l s hi s t o r i c a l s p r e a d o v e r t h a t i n d e x ( 2 . 4 8 + 1 . 08 = 3 . 56 ) . 4) I n t e r e s t f o r 2 0 0 4 w a s c a l c u l a t e d b y u s i n g t h e F i x e d r a t e s i n g l e A u t i l i t y o n B l o o m b e r g o n 4 / 2 6 / 2 0 0 0 = 5 . 88 % EX H I B I T N O . 6 8 CA S E N O . I P C - 03 - D. G R I B B L E , I P C o Pa g e 1 o f 1