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HomeMy WebLinkAbout20040803Vol V.pdfORIGINAL BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF) AVISTA CORPORATION FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC AND NATURAL GAS SERVICE TO ELECTRIC AND NATURAL GAS) CUSTOMERS IN THE STATE OF IDAHO. HEARING BEFORE CASE NOS. AVU-04- AVU-04 - . Idaho Public Utilities. ommlsslon Offtoeof the S retary .RECEIV 0 COMMISSIONER PAUL KJELLANDER (Presiding) COMMISSIONER MARSHA H. SMITH COMMISSIONER DENNIS S. HANSEN PLACE:Commission Hearing Room 472 West Washington Street Boise, Idaho DATE:July 21, 2004 VOLUME V - Pages 891 - 1066 COURT REPORTING J'eM'.v tk etIIK/f((Q(I't! &,fU 1978 AUG - 1 POST OFFICE BOX 578 BOISE, IDAHO 83701 208-336-9208 For the Staff:SCOTT WOODBURY , Esq. and LI SA NORDSTROM, Esq.Deputy At torneys General 472 West WashingtonBoise, Idaho 83702 For Avista:DAVID J. MEYER , Esq. Avista Corporation Post Office Box 3727 1411 East Mission Avenue Spokane, Washington 99220-3727 For Potlatch:GIVENS PURSLEY LLP by CONLEY E. WARD , Esq. 601 West Bannock StreetBoise, Idaho 83702 For Coeur Silver Valley:EVANS, KEANE by CHARLES L.A. COX , Esq. Post Office Box 659 III Main StreetKellogg, Idaho 83837 For Community Action:BRAD M. PURDY , Esq. At torney at Law 2019 North Seventeenth Street Boise , Idaho 83702 HEDRICK COURT REPORTING O. BOX 578, BOISE, ID APPEARANCES 83701 WITNESS EXAMINATION BY PAGE Denni s E. Peseau(Potlatch)Mr. Ward (Direct) Prefiled Direct Prefiled Rebuttal Mr. Woodbury (Cross) 891 895 953 966 969 970 972 1027 1036 1037 1044 1055 1060 1065 NUMBER PAGE For Avista: 31.Public Utilities Commission of Nevada Order , Docket Nos. 03-10001 and 03-10002 John S. Thornton(Potlatch)Sworn Mr. Ward (Direct) Prefiled Direct Mr. Meyer (Cross)Mr. Ward (Redirect) Marked 1031Admitted 1037 Premar ked Admitted 1027 PremarkedAdmitted 966 Premar kedAdmitted 966 PremarkedAdmitted 966 Teri Ottens (CAPAI) Mr. Purdy (Direct) Prefiled Direct Larry Stamper (CAPAI) Mr. Purdy (Direct) Prefiled Direct Ms. Nordstrom (Cross) For Potlatch: 201.Overall Rate of Return Recommendation and Range Estimates 202 .(Conf ident ial) 203 .(Conf ident ial) 204.A&G and F&PP Expense HEDRI CK COURT REPORTING P. O. BOX 578 , BOISE , ID 83701 INDEX EXHIBITS 205.Summary of Regression Analysis for Four Factor Test Premar kedAdmitted 966 PremarkedAdmitted 966 Premar kedAdmitted 966 PremarkedAdmitted 966 PremarkedAdmitted 966 PremarkedAdmitted 966 PremarkedAdmitted 966 Premar kedAdmitted 966 Premar kedAdmitted 966 For Communit Action Partnershi Association of Idaho: HEDRICK COURT REPORTING P. O. BOX 578, BOISE , ID 83701 206.Cost of Service BaS1C Summary PremarkedAdmitted 1054 PremarkedAdmitted 1054 Premar ked Admitted 1054 Premarked Admitted 1054 Premarked Admitted 1054 Premarked Admitted 1054 207 .Schedule 7 , Long-Term Firm andShort-Term Firm Point-to-pointTransmisslon Service 208.Update of Computation of DCF Equity Cost Estimates 209.Revised Computation of Dr. Avera' Schedule WEA- 210.Revised Computation of Dr. Avera' Schedule WEA- 211.Summary of Dr. Avera's Estimates 212 .Baa Bond Rates October 2001 to April 2004 213.Cost of Service Basic Summary 401.Curriculum Vitae, Teri L. Ottens 402.Percent of Poverty for States 403 .Poverty Level Calculation 404.State of Idaho Department of Heal and Welfare Energy Assistance Figures 405.Heavy Burden Report 406.April 2003 On the Brink, the Home Energy Affordability Gap in Idaho EXHIBITS BOISE, IDAHO, WEDNESDAY , JULY 21, 2004 , 9:00 A. We'll go back on theCOMMISSIONER KJELLANDER: record, and as we begin today, the order of wi tnesses will be Potlatch's witnesses first, followed by the CAP witnesses and Mr. Purdy, and then we'll move forward with Staff and see how far we get today. So, Mr. Ward, if you'd like to call your first witness , we'll get started. Thank you.We'd call Dennis Peseau toMR. WARD: the stand. DENNI S PESEAU, produced as a witness at the instance of Potlatch , being first duly sworn , was examined and testified as follows: DIRECT EXAMINATION BY MR. WARD: Dr. Peseau, would you please state your name and address for the record? Yes.My name is Dennis Peseau, spelled m with Utility Resources, Inc., at 1500 Liberty Street South , Salem , Oregon. 891 HEDRICK COURT REPORTINGP. O. BOX 578 , BOISE , ID 83701 PESEAU (Di)Potlatch For whom are you appearing today? On behalf of Potlatch. Did you cause to be prepared prefiled direct testimony in this proceeding? I did. And do you have any changes or corrections to that testimony? Yes , I do. Okay.Would you give us the first one, please? Beginning on page 10 -- Okay. - - line 16, the words and numbers " an addi t ional 287 591" should be stricken , and in its place the words " small addi t ional amount," so that that ine now reads:Wi th a small addi tional amount allocated to proj ect development expenses. Same page 10, line 18, the number "41 932 000" should be removed , and in its place, the words "a bit more. Q .Okay. Page 28, line 22 , the number "30,365,240" should be replaced by "29, 742 , 040 . " Also on page 28 , line 23, the number " 30. should be replaced wi th "29. Finally, on page 58, line 21, the reference to "Schedule DEP-4" should be removed , and in its place should be 892 HEDRICK COURT REPORTINGP. O. BOX 578, BOISE , ID 83701 PESEAU (Di)Potlatch the reference "Exhibit No. 211. Q . That concludes my corrections. Did you have one on page 7 , line 7 through Yes.On lines 7 through 9, I have a quotation, a sentence in quotes , and I think to make it clear that it's not a direct quote from the Company, those quotes should be Okay.Thank you.Did you al so , in connect ion removed. wi th your direct testimony, have cause to prepare Exhibi No. 202 through 212? Yes. Okay.And are they true and correct, to the best of your knowledge? They are. All right.If I asked you the questions contained in your direct testimony today, would your answers be They woul d . And did you also prepare rebuttal testimony in Yes , I did. Do you have any corrections to that testimony? No. And if I asked you the questions contained in that testimony today, would your answers be as given? 893 as given? this case? HEDRICK COURT REPORTING P. O. BOX 578 , BOISE, ID 83701 PESEAU (Di)Potlatch Yes. And did I ask you to prepare Exhibit 213 in connection with that rebuttal testimony? I did. All right. MR . WARD:Mr. Chairman , I'd ask that Exhibits 202 through 212 -- excuse me -- 213 be marked for identification , and that Dr. Peseau' s direct and rebuttal testimony be spread on the record as if read. COMMI S S IONER KJELLANDER:Thank you.So without obj ection , we'll spread the testimony of both direct and rebuttal of Mr. Peseau across the record as if read, and introduce Exhibits 202 through 212 and rebuttal Exhibit 213. (The following prefiled direct and rebuttal testimony of Mr. Peseau is spread upon the record. 894 HEDRICK COURT REPORTING P. O. BOX 578, BOISE , ID 83701 PESEAU (Di)Potlatch PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. My name is Dennis E. Peseau. My business address is Suite 250, 1500 Liberty Street , Salem, Oregon 97302. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? I am the President of Utility Resources, Inc. ("URI" ). URI has consulted on a number of economic, financial and engineering matters for various private and public entities for more than twenty years. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND WORK EXPERIENCE. My resume is attached as Exhibit No. 201. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION? Yes, on many occasions. FOR WHOM ARE YOU APPEARING IN THIS CASE? I am appearing on behalf of Potlatch Corporation ("Potlatch" WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY? I have been asked to review A vista s applications in this case and make appropriate recommendations to the Commission. PLEASE PROVIDE A SUMMARY OF YOUR TESTIMONY. My testimony deals with four major issues, all concerning the application for an increase in electric rates. After reviewing the evidence, I conclude that: DIRECT TESTIMONY OF DENNIS E. PESEAU - 2 IPUC Case Nos. A VU-O4-1 and A VU-O4- 895 The Coyote Springs 2 generating plant should be excluded from rate base on several grounds, not the least of which is that the plant is not "used and useful" in providing service to A vista s ratepayers. A vista should not be allowed to recover the cost of natural gas hedges or swaps put on in April and May of 200 1 because they were imprudent and intended to benefit A vista s unregulated activities at the ratepayers' expense. Avista s use of a 2002 test year, adjusted for allegedly known and measurable changes, produces a mismatch of expenses and rate base, on the one hand, and revenues on the other. I offer 3 alternative methods of correcting this mismatch. Avista s inclusion of Potlatch's Lewiston Facility in Schedule 25 for rate design purposes is unreasonable on its face, and A vista s cost of service study overstates the annual cost of serving Potlatch by approximately $1.4 million per year. In addition, John Thornton will present Potlatch's cost of capital testimony and its recommendation for a return on equity for Avista. However, in the recently completed Idaho Power rate case, I offered a critique of Dr. Avera s testimony that showed that updated data and a consistent application of his methodology demonstrate that his cost of equity is overstated, even if one accepts his assumptions. I fear that if I were to not perform a similar analysis in this case, the Commission would draw the unwarranted inference that my critique is no longer valid. To forestall this inference, I have prepared and attached an Appendix to this testimony that once again shows that simple updates to Dr. Avera s data, and the use of internally consistent data employed within his return on equity methods, dramatically lower his return on equity estimate below the 10.40/0 to 11.9% equity cost range (after the addition of flotation costs) he estimates for benchmark DIRECT TESTIMONY OF DENNIS E. PESEAU - 3 IPUC Case Nos. A VU-O4-1 and A VU-O4- 896 electric utilities in the western U. S., and below the 11.5% equity return he endorses for A vista. Coyote Springs 2 WOULD YOU PLEASE EXPLAIN THE ISSUES CONCERNING THE COYOTE SPRINGS 2 GENERATING PLANT? Before I do so, a short preface is in order. The two topics I next discuss in this testimony raise very disturbing issues about the relationship between A vista s regulated and unregulated arms. In order to understand the significance of these issues, the Commission needs to have a clear understanding of A vista s peculiar corporate structure. Consequently, I have reproduced below Scott Morris ' Avista organizational chart from his Exhibit No., page 5 of 5: DIRECT TESTIMONY OF DENNIS E. PESEAU - 4 IPUC Case Nos. AVU-O4-1 and AVU-G-O4- 897 A vista Corporation Company Overview AVISTA CORPORATION Avista Advantage Avista Energy Avista Power . denotes a business entity - denotes an operating division or line ofbusiness Exhibit No. S. Morris Avista Corporation PLEASE DESCRIBE THE ENTITIES AND OPERATING DIVISIONS ON THE CHART. A vista s unregulated enterprises appear on the right hand side of the chart. A vista Capital is a holding company for these enterprises. A vista Advantage provides information services and related business services. N either it nor the operating division labeled "Other" figure in my testimony. The two entities engaged in "Energy Marketing and Resource Management " on the other hand, playa prominent role in the following discussion. Avista Power is Avista Corporation s ill-fated entry into the merchant power business. It was originally designed to build or acquire generating plants and other DffiECT TESTIMONY OF DENNIS E. PESEAU - 5 IPUC Case Nos. AVU-O4-1 and AVU-O4- 898 resources to serve the unregulated wholesale electricity markets. According to A vista testimony it is now inactive, but it was the original owner of the Coyote Springs 2 generating plant and it still owns 49% of the Rathdrum merchant plant. A vista Energy is A vista Corporation s energy trading arm. Its primary purpose is to trade in both the electricity and natural gas markets. In addition, it brokers deals for Avista Utilities, although the Washington Utilities and Transportation Commission recently ordered the termination of this relationship with respect to natural gas purchases. At the peak of its activity it generated revenues far in excess of Avista Corporation regulated public utility sales. YOU EARLIER DESCRIBED A VISTA CORPORATION'S ORGANIZATIONAL CHART AS "PECULIAR.WHAT DID YOU MEAN? The right hand side of the chart is not at all unusual for a utility. Most utilities place unregulated activities in separate entities. The left hand side is quite the opposite. All of the utilities I am familiar with organize the utility function as a separate business entity, which makes its own purchases and business deals separate and apart from the unregulated enterprises. But in Avista s case, there is no separate utility entity, only an operating division. In effect, "A vista Utilities" is simply a name for the residual holder of A vista Corporation assets that are not claimed by one of the unregulated entities. WHAT DIFFERENCE DOES A VISTA'S ORGANIZATION MAKE? It blurs the distinction between regulated and unregulated activities. In the last A vista rate case, I complained, apparently not strenuously enough, that A vista s corporate structure, and its practice of not contemporaneously marking trades to its regulated or non-regulated arm, left it with the latitude to subsequently allocate trades based on their DIRECT TESTIMONY OF DENNIS E. PESEAU - 6 IPUC Case Nos. AVU-O4-1 and AVU-O4- 899 profitability. I characterized this situation as analogous to a stockbroker who makes investments and then, months or even years later, decides whether the purchases were for his own or his customer s account. IS THIS STILL A PROBLEM? In fact, the present case is far worse. In the case of Coyote Springs 2 ("CS2"), the unregulated entity (Avista Power) purchased a plant that subsequently proved to be a disaster. What is the Company s after the fact position? "We (Avista Corporation) ordered that transaction by our unregulated subsidiary (Avista Power) for the 'benefit' of our regulated customers." This is analogous to a broker buying a stock for his own account, and then two years later, when the trade is hopelessly under water, declaring that the trade was really for the customer s account. HOW DID CS2 GET STARTED? The CS2 fiasco began, like many other recent energy debacles in the West, with Enron playing a prominent role. CS2 was originally a Portland General Electric ("PGE" project to be built as a companion to PGE's Coyote Springs 1 generating station located near Boardman, Oregon. PGE was a regulated Enron subsidiary during the entirety of the CS2 saga. DID ENRON PLAY ANY ROLE IN THE DEVELOPMENT OF CS2, OTHER THAN BEING PGE'S PARENT CORPORATION? Yes. On May 4, 1999 Enron ordered the turbine for CS2 from GE at a contract price of $35 889 000. HOW DID A VISTA BECOME INVOLVED WITH CS2? DIRECT TESTIMONY OF DENNIS E. PESEAU - 7 IPUC Case Nos. AVU-O4-1 and AVU-O4- 900 In mid-1999, Enron and PGE decided to sell CS2. On October 4, 1999, Avista Power entered into an "evaluation agreement" with PGE that allowed it to begin its due diligence investigation of the plant. I assume that other potential buyers were also investigating the purchase at about the same time. HOW WAS THE PROPOSED SALE STRUCTURED? By the time it was completed, the deal was classic Enron in its quirkiness. On October 1 1999, three days before A vista Power signed its evaluation agreement, Enron incorporated Coyote Springs 2, LLC ("LLC") as a wholly owned subsidiary. On December 22, 1999, Enron and PGE agreed to transfer CS2 to LLC, contingent upon a subsequent sale to an unidentified third party. The December 22nd agreement also divided up the proceeds of the potential sale as follows-both PGE and Enron would first recover their "cost basis" in CS2 and the turbine, plus their out of pocket and allocated costs of development. Thereafter, the first $10.47 million of profit was allocated to PGE the next $12 million to Enron, and any additional amounts were to be split. DID THIS PGE AND ENRON DEAL CONTEMPLATE A SALE TO A VISTA POWER? Not originally. Apparently it was structured for a sale to an unidentified third party who ultimately backed out. Then A vista Power re-entered the picture. On March 4, 2000 Avista Power signed a Letter of Intent ("LOI") with Enron to buy both CS2 and the turbine. The LOI set the purchase price at $19.5 million for CS2, and $40 million for the turbine. PGE's and Enron s collective cost basis and development costs for CS2 were identified as $ 8 450 000, with the remaining $11 050 000 labeled as a "premium. WHAT DID A VISTA POWER INTEND TO DO WITH THE CS2 PLANT? DIRECT TESTIMONY OF DENNIS E. PESEAU - 8 IPUC Case Nos. A VU-O4-1 and A VU-O4- 901 As in the case of the Rathdrum plant, Avista Power presumably intended to operate CS2 as a merchant plant selling into Western wholesale electricity markets. I base this presumption in part on the plant's location , which is ill suited to serve A vista Utilities load centers that are located far to the east of CS2. DID THE PURCHASE CLOSE AS PLANNED? No. On June 20 2000, the LOI was amended to reallocate the purchase price as $16. million for CS2 and $43 million for the turbine. I cannot find an explanation for this change in any of the discovery documents we received, although I surmise it may have been the result of a reduction in the previous estimate of development costs. An even stranger development took place approximately three weeks later, on July 7, 2000, when Enron assigned its rights to the GE turbine to Avista Power. On the same day, Enron created another subsidiary, LJM2-Coyote ("LJM2"). For a price of 540 000, LJM2 provided Avista Power with a two week "put option" on the turbine. In other words, from July ih through July 21st, A vista Power could require LJM2 to repurchase the turbine for the sum of $39 960 000. This put option was never exercised because, on July 21 , 2000, Enron assigned its interest in LLC to A vista Power, thus giving A vista Power ownership of CS2 as well as the turbine. WHY IS THE LJM2 TRANSACTION STRANGE? I can think of no legitimate business reason for A vista Power to enter into the put option agreement. In the first place, turbines were in short supply at the time, and A vista would have had little difficulty re-selling the turbine if the CS2 deal somehow collapsed. Moreover, it is difficult to understand why, if Avista Power feared the exposure of holding the turbine before it secured the CS2 rights, it didn t simply insist on a DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-O4-1 and AVU-O4- 902 simultaneous transfer of the two components. Instead it allowed Enron to impose a two- week gap on the signing of the two agreements and, in effect, sell it $3.5 million of insurance to cover the minimal exposure that gap created. Finally, why would any reasonable businessperson pay $3.5 million for a two week "insurance policy" issued by an empty corporate shell, with no assets and an operating history of less than a day, even if Enron guaranteed the put? This simply doesn t pass even a minimal smell test particularly when the counter party is named Enron. WHEN ALL WAS SAID AND DONE, WHAT DID A VISTA PAY FOR CS2 AND THE TURBINE? The total purchase price, including the option, was approximately $59.5 million, for a plant that, by my calculations, appeared to have an all-in cost of approximately $42 million. WHAT WAS THE BOOK VALUE OF THE TRANSFERRED ASSETS? The book value of the turbine would have been the same as its purchase price $35 889 000. The Allocation Agreement dated July 21 , 2000 listed CS2's book value as 755,409, with an additional $2 287,591 allocated to project development expenses. Consequently, the book value would have been $39 644 409 without the development expenses, and $41 932 000 if development expenses were capitalized and added to book value. WAS THAT THE END OF AVISTA POWER'S INVOLVEMENT WITH ENRON? Not quite. In April of 2002, CS2's prime contractor, another Enron affiliate, filed for bankruptcy and CS2 lost the benefit of its fixed price construction contract, while at the DIRECT TESTIMONY OF DENNIS E. PESEAU - 10 IPUC Case Nos. AVU-O4-1 and AVU-04- 903 same time incurring the cost of replacing the prime contractor and settling with subcontractors. WAS THAT THE ONLY PROBLEM THAT OCCURRED DURING THE CONSTRUCTION AND OPERATION OF CS2? No. It is fair to say that CS2 has been, and continues to be, an economic and operational nightmare. In May of 2002, approximately a month before the scheduled completion of the plant, a fire destroyed the transformer purchased from a Turkish supplier. This not only prevented the completion of the plant, it also resulted in an environmental incident when water used to douse the fire overran the splash pond built to contain the transformer s contents in the event of an accident. Clean-up costs as of December 31 2003 were approximately $1.7 million, half of which are A vista s responsibility. A replacement transformer arrived at the site in December, 2002, but an inspection revealed it could not be installed because of shipping damage. Repairs to this transformer delayed CS2's commercial operation date for more than a year, to July, 2003. Thereafter, the plant was in service for approximately six months. It then experienced another round of transformer problems that shut it down again. The projected date for a return to service is now August of 2004. YOU JUST DESCRIBED CS2 AS AN ECONOMIC NIGHTMARE. ARE YOU REFERRING TO SOMETHING BEYOND ITS CONSTRUCTION PROBLEMS? Yes. The construction problems have caused the estimated cost of Avista s half of the plant to swell from approximately $94 million to $109 million. In addition, the natural gas swaps I will discuss in detail later in my testimony produced losses in excess of $62 DIRECT TESTIMONY OF DENNIS E. PESEAU - 11 IPUC Case Nos. AVU-04-1 and AVU-04- 904 million. The bottom line is that A vista overpaid for the plant in the original purchase and every turn of the cards since then has only added to the misery. so WHO PAYS FOR ALL THIS?' Under Avista s proposal to rate base the entirety of the plant's cost, Avista ratepayers will pay for all of these problems. If Avista s proposal is accepted, the only entities that walk away from this train wreck unscathed are the plant's original owner, Avista Power and its parent, A vista Corporation. HOW DOES A VISTA POWER ESCAPE ANY RESPONSIBILITY FOR CS2' PROBLEMS? In December of 2000, A vista Corporation announced it would acquire CS2 from A vista Power. But it did not in fact follow through on this announcement. Instead, it vacillated. Internal A vista memos indicate that A vista Power was trying to sell the entire plant to third parties in the summer and fall of 200 1. But A vista Power received only one full price offer from Mirant, and that prospective deal fell apart when Mirant ran into cash flow problems. Ultimately, Avista Power ended up selling 50 percent of the plant to Mirant, and 50 percent to A vista Corporation. WHEN DID THESE SALES OCCUR? Avista Power assigned a 50 percent interest in LLC to Mirant on December 12 2001. But it did not transfer the other 50 percent of the plant to A vista Corporation until January 1 , 2003 , after the close of the test year in this case. GIVEN THIS HISTORY, WHAT IS THE APPROPRIATE RATEMAKING TREATMENT FOR CS2? . DIRECT TESTIMONY OF DENNIS E. PESEAU - 12 IPUC Case Nos. AVU-04-1 and AVU-04- 905 I have two recommendations concerning CS2. The first is that the cost of the plant should not be included in rate base in this case. CS2 is demonstrably not used and useful and its track record does not inspire confidence it will be used and useful in the near future. A vista has had three tries at completing the plant and getting it running on a reliable basis. It has struck out all three times. Given this history, the plant's costs should not be eligible for recovery in regulated rates until it has a demonstrated track record of usefulness and reliability. Furthermore, if and when the plant does become eligible for inclusion in rate base, the rate based costs should be limited to the plant's fair market value , as described below, as of the transfer date of January 1 2003. WHY ARE YOU PROPOSING TO REDUCE THE PLANT'S COST IN THIS MANNER? I am simply applying standard ratemaking precepts to the purchase. A vista Power is an unregulated A vista Corporation subsidiary, and transactions between it and A vista Corporation are clearly not at arms length. I am not an attorney, but I have spent enough years in the regulatory field to state that, in jurisdictions I am familiar with, when a utility purchases goods or services from an unregulated affiliate, the burden is on the utility to prove that the purchase price did not exceed fair market value. In the present case because of all the construction disasters, it is quite clear that transferring CS2 to A vista Corporation at cost creates a purchase price that is well in excess of fair market value. These excess costs should be disallowed. It is patently unjust to ask the ratepayers to relieve A vista Power of the unfortunate consequences of its half ownership of CS2. DIRECT TESTIMONY OF DENNIS E. PESEAU - 13 IPUC Case Nos. A VU-O4-1 and A VU-04- 906 DOES THE FACT THAT A VISTA CORPORATION PREVIOUSLY ANNOUNCED AN INTENTION TO ACQUIRE THE PLANT MAKE ANY DIFFERENCE IN THIS CASE? No. Avista s announced intentions came after Avista Power had already overpaid for the assets it purchased from PGE and Enron, so an adjustment to fair market value would have been in order even then. In addition, even though the boards of directors of the involved companies authorized their executives to proceed with the transaction, the companies never acted on those resolutions. A vista s discovery responses contain no contract, memorandum of understanding, or any other document that would evidence an intention to proceed with the sale. Under those circumstances, A vista Power was under no legal obligation to sell to A vista Corporation, and it in fact tried to sell the plant to third parties months after the announcement. Eventually it did sell half to Mirant. Avista unilaterally chose to purchase CS2 through its unregulated subsidiary, thereby avoiding any regulatory constraints on its use or disposition of the assets. Let us suppose that A vista Power had succeeded in the summer of 2001 in selling the plant at a profit. Would A vista Power have volunteered to share the proceeds with the ratepayers just because at one time it intended to sell the plant to A vista Corporation? This is the same A vista that resisted sharing the Centralia sale proceeds with ratepayers. A vista would have argued that the deal was never consummated, and that ratepayers never acquired an equitable interest in the plant through the payment of depreciation. HOW DO YOU PROPOSE TO DETERMINE THE FAIR MARKET VALUE OF CS2? The Commission could conduct further proceedings for the express purpose of making such a determination, but there is a much easier method readily available. Just two years DIRECT TESTIMONY OF DENNIS E. PESEAU - 14 IPUC Case Nos. AVU-O4-1 and AVU-G-04- 907 ago, the Commission conducted an extensive investigation to determine the cost of a 270 megawatt combined cycle natural gas plant to use as a surrogate avoided resource SAR") for the purpose of calculating avoided cost rates. On August 2, 2002, one month after CS2' s original scheduled completion date, and five months before the transfer of CS2 to A vista Corporation, A vista filed rebuttal testimony identifying the most recent construction cost estimates for the SAR as $604/kilowatt. I see no reason why A vista should not be held to its own contemporaneous estimate of the cost of constructing a plant nearly identical to CS2. This figure, after all, represents the maximum value A vista Corporation was willing to pay for the purchase of resources from unrelated third parties just before it acquired CS2 from Avista Power. Using the $604 figure produces a fair market value for CS2 of $84 560 000 for A vista s share of CS2. The Commission should not allow costs above this amount in rate base at any time. The Natural Gas Hedges WHAT IS THE ISSUE WITH RESPECT TO THE "DEAL A" AND "DEAL B" HEDGE TRANSACTIONS IN THE COMMISSION'S ORDER ON A VISTA'S 2003 PCA FILING? To its credit, the Commission recognized the peculiar nature of both Deal A and Deal B in the 2003 PCA proceeding and deferred a decision on the costs of these deals into the present general rate case. As I explain below, the high costs associated with each deal are the result of imprudent decisions and self-dealing between A vista Corporation and A vista Energy. Avista s actions have resulted in excess natural gas costs of more than $62 million on a system-wide basis. DIRECT TESTIMONY OF DENNIS E. PESEAU - 15 IPUC Case Nos. AVU-04-1 and AVU-04- 908 HAVE MOST OF THE INFORMATION, DATA, AND FACTS NECESSARY TO UNDERSTAND THE NATURE OF DEAL A AND DEAL B BEEN TREATED AS CONFIDENTIAL BY AVISTA? Yes. This is unfortunate, as most of the confidential trading data necessary to understand Deal A and Deal B are public and available on the FERC website as part of the FERC' show-cause proceeding that culminated in its March 2003 P A02-02 report Final Report on Price Manipulation in Western Markets. There is, therefore, no valid reason to continue to treat historical trading data as confidential. WHAT IS THE DIFFERENCE BETWEEN THE NATURAL GAS TRANSACTIONS OF DEAL A AND DEAL B AND NORMAL NATURAL GAS TRANSACTIONS? There are at least three distinct aspects of the Deal A and Deal B transactions that are peculiar. The first distinction is that the Deal A and Deal B trades were financial as opposed to physical transactions. WHAT IS THE DISTINCTION BETWEEN NATURAL GAS FINANCIAL AND PHYSICAL TRANSACTIONS? A physical transaction is the more normal and common purchase of an actual, physical quantity of natural gas at specified pricing, terms and conditions. In physical gas transactions, there are no winners or losers. The buyer receives a specific quantity of gas at agreed upon pricing terms. The seller receives a payment for providing the physical gas to the buyer. A financial natural gas transaction involves no actual exchange of physical gas. Instead, a financial deal is agreed upon by buyer and seller in which the buyer bets that future gas prices will increase, while the seller bets that future gas prices will decrease. DIRECT TESTIMONY OF DENNIS E. PESEAU - 16 IPUC Case Nos. AVU-04-1 and AVU-04- 909 Depending upon the future monthly movement of gas prices, the loser, or the counterparty on the wrong side of the bet writes a monthly check or "settles" with the other party. The FERC report just referenced defines financial gas swaps similar to Deal A and Deal Bas: In a swap, two counterparties execute a trade in which the buyer pays a fixed, known price for some notional quantity of gas and the seller pays a price that will vary with the market price (generally based on some agreed upon price index), which will only be known later. Thus, the buyer in a swap transaction is going long making a bet that the market price will rise - and the seller is betting that prices will fall. (Page II-51) On the four days April 10, April 11 , May 2 and May 10 2001 , Avista Energy entered into the financial swaps, Deal A and Deal B, on behalf of Avista Utilities that were of unprecedented length and lost over $62 million for ratepayers. At no time during the terms of these two deals were these financial trades "in the money," or profitable for A vista Utilities. The deals were extraordinarily profitable for the three seller counterparties. WHO WERE THE COUNTERP ARTIES TO THESE TRANSACTIONS? BP and Mirant were the counterparties on Deal A. Incredible as it may seem, A vista Energy was the counterparty for Deal B. WHY WOULD THE SAME ORGANIZATION SIMULTANEOUSLY TAKE OPPOSITE SIDES OF THE BET ON THE DEAL B SWAP? ISN'T THIS A "ZERO SUM GAME?' The fact that the PCA protected A vista Corporation is the only thing that made this an attractive transaction for A vista Corporation. The PCA insulated the shareholders of the DIRECT TESTIMONY OF DENNIS E. PESEAU - 17 IPUC Case Nos. AVU-04-1 and AVU-O4- 910 parent company by passing through to ratepayers the excess of the locked in hedged natural gas prices over and above the actual market prices that existed at the time. MIGHT THIS BE SIMPLY A CASE OF BAD LUCK FOR A VISTA'S CUSTOMERS? No. The only manner in which a financial swap can be consummated is with a willing buyer and a willing seller. The reason for entering a swap on either side is because one information on market pricing makes the risk of this bet worthwhile. Again, the only possible reason for Avista Utilities to buy the long-term financial swap that it did was because it was predicting gas prices would continue to increase. If future gas prices at the time the swap was entered were expected either to remain at the then high levels, or to decrease then entering the fixed price swap could only harm the buyer. On the other side the seller A vista Energy apparently had information suggesting that future gas prices were not going to rise above the agreed upon price per decatherm over the subsequent 1 7 months, or it would have been foolish to sell the swap. Unless A vista Energy based its action on information that prices would either remain at their high levels or fall, it would have been acting directly against the best interests of its shareholders. If natural gas prices truly were expected to increase over the subsequent 17 months, the best action for both A vista Utilities and A vista Energy would have been for A vista Utilities to buy the fixed-price swap from a less informed counterparty. IS THERE ANYTHING ELSE UNUSUAL ABOUT A VISTA CORPORATION' DECISION TO MAKE THE SWAP? Yes. At the time, A vista Energy brokered all of the natural gas and electric trades made for the benefit of Avista Utilities. Avista s justification for this practice was that Avista Energy s continuous market participation provides it with market insights and knowledge DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-O4-1 and AVU-04- 911 that the utility division doesn t have. A vista Energy s role as a broker for the utility division placed it in a fiduciary position that required it to disclose the fact that it considered Deal B (and by implication, Deal A) to be a bad deal for Avista Utilities. A vista Energy did disclose that fact and the additional fact that it was taking the other side of the swap, it was obviously imprudent for A vista Utilities to proceed with swaps that the party with superior knowledge regarded as foolish. If A vista Energy did not disclose its role, then it violated its fiduciary responsibilities, and that alone would be grounds for disallowing the cost of both deals in rates. WHAT WAS THE RESULT OF THE DEAL B SWAP WITH A VISTA ENERGY? The result was that A vista Utilities immediately began monthly transfers of what turned out to be millions of dollars to Avista Energy. HOW COULD THERE BE AN IMMEDIATE TRANSFER OF CASH? I THOUGHT THE SWAP WAS FOR GAS TO BE DELIVERED IN THE FUTURE. The immediate impact occurred because of the way financial trades such as this are settled. As I stated earlier, swaps like this are literally bets on the direction of prices. Consequently, they settle monthly based on the futures price of gas for the time period covered. In any month in which the futures price is less than the fixed price, the buyer (Avista Utilities) loses his bet and must cut a check to the seller (Avista Energy) for the difference. WHAT IS THE ULTIMATE SIGNIFICANCE OF THE WAY THESE TRADES ARE SETTLED? 1 A vista converted Deal B to a physical purchase at an equivalent fIXed price on June 20, 2002. DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-04-1 and AVU-04- 912 It explains why the Commission really has no choice but to disallow Deal B. Any other decision would provide Idaho utilities that have a PCA or PGA with a blueprint on how to raid ratepayers' pockets for the benefit of shareholders. HOW DOES A VISTA UTILITIES ATTEMPT TO mSTIFY ITS DECISION TO ENTER INTO "BUYS" IN BOTH DEAL A AND DEAL B? Avista witness Mr. Lafferty discusses these two deals (actually four transactions) in pages 29-56 of his testimony. The attempted justification, while sometimes repetitive, is outlined as follows: Deal A and Deal B were made because: 1. A vista was in an electric resource deficit or a "short-position" during the hedge periods. (pp. 31-, 37-, 42-47) 2. The high hedge prices of Deal A and Deal B still compared favorably to forward market prices of electric purchases at the time. (pp.32-36) 3. Electric market prices in January-May 2001 were high, and federal opposition to price caps suggested no relief in market prices. (pp. 40-, 41-42) 4. The 36 month and 17 month duration of Deal A and Deal B were not unusual terms for company hedges of this sort. (pp. 48-52) 5. The company did not expect that forward natural gas prices would decline as they did. (pp. 52-53) 6. The terms of Deal A and Deal B were consistent with market conditions on April 10 and May 10. (pp. 53-54) WOULD THE DEFICIT ELECTRIC RESOURCE POSITION IDENTIFIED BY THE COMPANY mSTIFY BUYING FINANCIAL HEDGES LIKE DEAL A AND DEAL DIRECT TESTIMONY OF DENNIS E. PESEAU - 20 IPUC Case Nos. A VU-O4-1 and A VU-04- 913 No. I first want to make clear that Potlatch does not want in any way to discourage appropriate resource acquisitions to maintain the reliability of service to customers. However, I am quite surprised that the company testimony in this regard suggests that somehow Deal A and Deal B in any way assisted in covering a resource-short position. WHY DO YOU INDICATE THAT DEAL A AND DEAL B DID NOT ASSIST VISTA IN COVERING ANY RESOURCE DEFICIT? Financial fixed-for-floating swaps such as Deal A and Deal B never provide for any physical quantities of natural gas. Again, Deal A and Deal B are strictly the taking of price positions" between two parties, a buyer and seller. For example, if I thought that natural gas prices were going to increase in the near-term, and I could locate a party thinking the opposite, I could buy a natural gas financial swap and reap gains or suffer losses according to my accuracy, and never be involved with actual physical quantities of gas. If I need natural gas to close an electric resource deficit, I would need to enter into distinct physical gas contracts as a buyer. Deal A and Deal B did not entitle Avista to even a molecule of methane. IF A VISTA NEEDED ADDITIONAL NATURAL GAS SUPPLY TO COVER THE PERCEIVED DEFICIT, HOW DID IT ACQUIRE SUCH SUPPLIES? The company on March 13 and March 22 2001 , entered into 36 month and 17 month physical trades for 27 658 and 20 000 decatherms per day at market index-based prices. These two gas contracts alone filled the need to cover the resource deficits discussed by the Company. Deal A and Deal B merely expressed the perceived direction that natural gas prices would take over the ensuing 36 and 1 7 month periods between the betting DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-O4-1 and AVU-O4- 914 parties. The Commission should reject any notion that these financial swaps can be peddled to customers on the basis of enhancing system reliability. WHAT DO YOU MAKE OF MR. LAFFERTY'S DISCUSSION ON PAGES 32-36 OF HIS TESTIMONY THAT SUGGESTS THE DEALS WERE PRUDENT BASED ON THE THEN FOR WARD MARKET PRICES? The analysis at pages 32-36 of Mr. Lafferty s testimony attempts to demonstrate that the variable cost of power produced by Avista s generators would have been below the predicted future market power prices at the gas prices in Deal A and Deal B. That is A vista was predicting that at the Deal A and Deal B fixed swap prices, buying gas for internal generation would be cheaper than buying on the electric markets. This assumes of course, that the existing forward power prices at mid-Columbia represented a good predictor of actual prices in the future. While this analysis is mathematically . correct, it hardly demonstrates that the Deal A and Deal B trades were prudent. PLEASE EXPLAIN. The analysis presented is the starting point for an "arbitrage" trade. An arbitrage is the simultaneous buying and selling of fungible commodities in different markets in order to make an immediate riskless profit. For clarification of the proper use of Mr. Lafferty analysis I refer to the Coyote Springs 2 table at the bottom of page 32 of his testimony. The first row indicates that the Deal B gas fixed price is $6.56 per decatherm and, at the CS2 plants' heat rate , Deal B gas could produce electricity at a variable cost of $46.06/MWh. The forward electric prices, according to Avista, showed power prices at the time of$126.75 and $105.38/MWH. DIRECT TESTIMONY OF DENNIS E. PESEAU - 22 IPUC Case Nos. AVU-O4-1 and AVU-04- 915 A power trader facing these circumstances would, if the market held simultaneous lock in a buy at the $6.56 gas price and a sale at the $126.75 and $105.38/MWh electric prices to insure a riskless profit equal to the difference between these two energy sale prices and the $46.06/MWH the electricity would cost to produce. This would be a rational use of Mr. Lafferty's analysis. DOES THE ANALYSIS PRESENTED BY MR. LAFFERTY DEMONSTRATE THAT DEAL A AND DEAL B WERE PRUDENT AT THE TIME FOR THE PURPOSE OF PROTECTING RATEPAYERS? No. Unlike the arbitrage case where a certain outcome (the riskless profit) is locked in by a conscious decision to forego possible upside and avoid all downside, the open hedges conducted by A vista did the opposite. A vista s hedges in essence locked in the downside - by fixing gas prices at near record levels for up to 36 months - and precluded the ratepayers getting any upside if gas prices returned to more normal historic levels. WOULD A VISTA ENERGY HAVE ENTERED THE SELL SIDE OF THESE HEDGES IF IT EXPECTED NATURAL GAS PRICES TO CONTINUE UPWARD? Absolutely not. Doing so would have been a direct contradiction of management' fiduciary responsibility to shareholders. A vista Energy made a calculated bet that the very high natural gas market prices could not be sustained. By selling Deal B to the utility for prices that exceeded $6.00/decatherm it stood to reap all the profit from falling prices. If prices simply remained at the then high levels, A vista Energy stood to lose nothing. Only if gas prices increased further from these high levels, did it risk losing money. The end result is that Avista Energy made an obvious bet and reaped more than $18 million in benefits from its parent utility. DIRECT TESTIMONY OF DENNIS E. PESEAU - 23 IPUC Case Nos. AVU-04-1 and AVU-O4- 916 PLEASE ADDRESS MR. LAFFERTY'S DISCUSSION ON PAGES 40- REGARDING THE PRUDENCE OF THESE TRANSACTIONS. Beginning on line 17 of his page 40, Mr. Lafferty suggests that a prudent person would have viewed the high winter prices of2000-2001 , and the federal government's position against the implementation of price caps, as reasons to "go long" with the natural gas hedges. I have just two short comments on this point. First, the prudent man at A vista who was buying the fixed-price hedge on behalf of the utility was the same man who was selling it on behalf of Avista Energy. Taking simultaneous and opposite positions on the same transaction cannot each be deemed prudent. The same market observation of high prices and price caps could not have led a single individual or committee to opposite conclusions regarding the future near-term trend in gas prices. Second, other utilities and market participants in the western U.S. observed the same market phenomena discussed by Mr. Lafferty and did not take long-term price positions that anticipated further gas price increases. PLEASE DISCUSS MR. LAFFERTY'S TESTIMONY ON PAGES 48-52 THAT SUGGESTS THAT THE 36 MONTH AND 17 MONTH HEDGES ARE COMMONLY MADE BY THE UTILITY. Mr. Lafferty s discussion here involves only physical resource acquisitions, not financial hedges. I certainly agree with him that any resource portfolio should have various short medium, and long-term resources. In this light, I do not challenge or take issue with Avista s entering into its March 13 and March 22 long-term physical gas purchase contracts, as I previously noted. DIRECT TESTIMONY OF DENNIS E. PESEAU - 24 IPUC Case Nos. AVU-O4-1 and AVU-04- 91 7 The issue here, of course, is that A vista took an unprecedented long-term price view in the form of financial hedges and, in combination with its subsidiary A vista Energy, Avista Corporation took both sides of the transaction. Mr. Lafferty is silent on these points. HAS A VISTA EVER, TO YOUR KNOWLEDGE, ENTERED INTO FINANCIAL HEDGES AS LONG AS THE 36 MONTH AND 17 MONTH TERMS OF DEAL A AND DEAL B? No. In response to Potlatch's data requests, Avista provided a list of all recent financial hedges and fixed price contracts. Of the 67 fixed-price transactions provided, the overwhelming majority of the contracts were for terms of 1-3 months, with a few with terms of one year. Only the Deal A and Deal B transactions were for such long periods. I conclude that it is not Avista s normal business practice to enter into long-term price hedges. HAVE YOU REVIEWED OTHER DATABASES FOR INFORMATION TO DETERMINE WHETHER THE 36 AND 17 MONTH TERMS OF DEAL A AND DEAL B ARE COMMONPLACE IN THE INDUSTRY? Yes. In conjunction with its investigation of electric and natural gas price manipulation in western U.S. markets, the FERC compiled massive databases regarding both physical and financial natural gas trades. As a check on the frequency of long-term financial hedges, I reviewed the FERC data file for all natural gas financial hedges that were entered into during May 2001 , the same period as Deal A and Deal B. According to the data base file, there were 37 472 such transactions during May 2001. The huge preponderance of these financial hedges was for the immediate month or DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-04-1 and AVU-04- 918 15' quarter ahead, although some were for quarterly periods ending as late as December 2002. I found no other financial trades that extended as long as the 36 and 17 month terms contained in Deal A and Deal B. PLEASE ADDRESS MR. LAFFERTY'S TESTIMONY THAT THE DECLINE IN NATURAL GAS PRICES WAS UNFORESEEABLE. Mr. Lafferty s testimony on pages 52-53 states that "the Company" did not expect that forward natural gas prices would decline, as of course they did (Page 52, lines 3-6). I cannot from the context of the statement ascertain just what "the Company" is. Certainly, A vista Energy expected a decline in natural gas prices, or it would not have sold the fixed prIce swap. Further, Mr. Lafferty s explanation does not justify the utility buying the swap. As I explained earlier, buying the fixed-price swap only gave the utility protection from further increases in gas prices, not from the then existing level of high prices. Mr. Lafferty explains only that" . . . the Company expected the price for natural gas would remain high for some time into the future. . . " (page 52, lines 5-6). He does not make the argument that the Company expected gas prices to continue to increase, which would be the only legitimate reason for the swaps. WERE THE TERMS OF DEAL A AND DEAL B CONSISTENT WITH MARKET CONDITIONS ON APRIL 10 AND MAY 10 2001 , AS MR. LAFFERTY ARGUES? As I have previously indicated, there were apparently no other natural gas hedge transactions occurring that were comparable to Deal A and Deal B. The references Mr. Lafferty makes to forward price curves at that time certainly is no indication of what an DIRECT TESTIMONY OF DENNIS E. PESEAU - 26 IPUC Case Nos. AVU-O4-1 and AVU-O4- 919 arms-length buyer and seller might agree upon for financial hedges of up to 36 months in length. WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE FINANCIAL LOSSES CLAIMED BY THE UTILITY IN CONJUNCTION WITH DEAL A AND DEAL B? The financial losses incurred by the utility in Deal A and Deal B are summarized in my Exhibit No. 202. As of March 31 , 2004, the cumulative losses to the utility on the hedges were $62,446 000. These losses represent the difference between what the utility would have paid for natural gas on the market (absent the hedges) and the high fixed gas price that it agreed to pay by virtue of the hedges. The market prices for gas are shown for the Malin receipt point, and are compared to the weighted average price of the hedges labeled "Average $/dt." For Deal A, the cumulative financial loss was $44 175 600. For Deal B, the cumulative loss was $18 270,400. Since Deal B involves self-dealing and a direct transfer of the utility s losses to shareholder profits, the entire $18.3 million must be disallowed, adjusted of course for the Idaho jurisdictional share and for the PCA test period. Deal A did not involve self dealing, but it was certainly imprudent and it is further suspect due to the unprecedented term of 36 months and the high locked in prices. I believe it should likewise be disallowed. But if the Commission for some reason rejects this proposal, I propose, in the alternative, a lesser adjustment based on a more normal hedging strategy. PLEASE EXPLAIN THE LATTER RECOMMENDATION. Deal A represents two hedge contracts of 10 000 decatherms each for a period of 36 months. The named counter parties to these Deal A contracts are private entities with no DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-O4-1 and AVU-G-O4- 920 apparent legal connection to Avista. According to the Company s response to Potlatch' data requests, A vista did not have either of these entities "sleeve " (conduct the trade for A vista Energy s benefit) the transaction. Thus, there was no apparent enrichment of Avista s shareholders. But Deal A was nevertheless an imprudent $44.2 million hedge given its duration and the fact that it was put on contrary to A vista Energy s position. I base my adjustment on A vista s normal hedge strategies for all its other fixed price gas purchases. As I stated earlier, Avista normally hedges for gas deliveries in ensuing seasons and occasionally for periods as long as one year. If A vista had followed its normal hedging strategy it would have avoided the disastrous 36 month Deal A fixed price of $6.45/decatherm. HOW IS THIS INFORMATION USED TO CALCULATE AN ADJUSTMENT FOR DEAL A? My review of Avista s confidential information on other hedges reveals that Avista normal hedges were established approximately six months prior to a season (November- March or April-October). I therefore used the Malin natural gas contract prices in effect six months prior to each upcoming season as a base price. F or example, May 1 , 2001 prices were used for the November 2001-March 2002 season. These prices are then subtracted from the Deal A prices. The results are summarized in my Exhibit No. 203. WHAT DOES EXHIBIT NO. 203 SHOW? That exhibit indicates that, if A vista had not entered into Deal A and instead hedged in the same manner that it was hedging other natural gas purchases in the same time frame gas costs would have been $30 365 240 lower. I alternatively propose that, should the Commission not disallow the entirety of the Deal A costs, it should disallow $30.4 DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-04-1 and AVU-04- 921 million of Deal A costs, adjusted for both the Idaho jurisdiction as well as the PCA test period. The Test Year Mismatch YOU EARLIER STATED THAT A VISTA'S CASE CONTAINS A MISMATCH OF REVENUES AND EXPENSES. PLEASE EXPLAIN WHAT YOU MEAN BY THE WORD "MISMATCH. Avista calculates its test year revenues in a straightforward manner. Test year revenues consist of 2002 actual figures, "normalized" for weather and other standard Commission approved adjustments. On the other side of the ledger, however, expenses and rate base are treated in a much different manner. A vista pro forms increases in selected expense items, such as pension, insurance, and labor costs, to 2004 levels. A vista also includes in rate base a number of projects that were placed in service after the test year, as well as construction work in progress that is scheduled for completion in 2004. These adjustments produce operating and maintenance increases of approximately $5.4 million rate base additions of $54 million, and associated depreciation increases of $2.3 million. The net effect is a mismatch of 2002 revenues against year-end 2004 expenses and rate base. IS THIS AN ACCEPTABLE RA TEMAKING PROCEDURE? No. For unknown reasons, Avista chose a 2002 test year, rather than 2003. Having made that choice, it should not be allowed to unilaterally alter the test year relationship between revenues, expenses and rate base. It is a fundamental principle of regulation that a utility s rate base and expenses should be matched against revenues for the same period. A vista s pro forma results clearly violate this principle. DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. AVU-04-1 and AVU-O4- 922 ARE YOU SUGGESTING PRO FORMA CHANGES TO A TEST YEAR BASE CASE SHOULD BE REJECTED OUT OF HAND? No. Adding known and measurable changes to a test year base case is a legitimate regulatory tool, but it must be used with extreme caution because of the high potential for abuse. In a rate case, utilities have every incentive to identify changes that increase the revenue requirement, but no incentive at all to find revenue enhancing changes. Consequently, it comes as no surprise that all of Avista s proposed known and measurable changes produce an increase in revenue requirement. These changes should either be rejected or accompanied by a corresponding adjustment to revenues. CAN YOU PROVIDE AN EXAMPLE OF THE TYPE OF KNOWN AND MEASURABLE CHANGE THAT SHOULD BE ACCEPTED? The classic example is a post-test year change in tax rates. Plugging the new tax rates into the revenue requirement calculation does not disturb the relationship between test revenues and expenses and is obviously equitable. WHAT RULES SHOULD BE APPLIED TO POST-TEST YEAR KNOWN AND MEASURABLE CHANGES? Post-test year expense and rate base adjustments should only be accepted when they are in fact truly known and measurable. In order to qualify, a proposed adjustment must be virtually certain to occur, and its revenue requirement impact must be precisely and reliably quantifiable. Furthermore, there must be some limit on the time interval between the test year and pro forma adjustments. ARE A VISTA'S PRO FORMA ADJUSTMENTS CONSISTENT WITH THE RULES YOU HAVE JUST DESCRIBED? DIRECT TESTIMONY OF DENNIS E. PESEAU - 30 IPUC Case Nos. A VU-04-1 and A VU-O4- 923 No. In the case of its pro forma expense adjustments, the time lag between the 2002 test year and adjustments based on 2004 data or projections makes these adjustments inequitable. WHY IS THE TIME LAG IMPORTANT? For most utilities, expenses tend to increase every year, but this is offset in whole or in part by efficiency improvements and load growth. If this were not so, utilities would automatically file rate cases every year. Avista s own rate case history nicely illustrates this point. Its last rate case occurred in 1998, and the one before that was several years earlier. Avista s pro forma expense adjustments for items like increased labor, insurance and similar costs are simply 2004 budget estimates. It is absolutely inappropriate to match these expenses against 2002 revenues because normal load growth will recoup some or all of these costs. The Commission should either reject the 2004 adjustments or impute revenue increases to the 2002 test year to correct this mismatch. ARE A VISTA'S PRO FORMA ADDITIONS TO RATE BASE SUBJECT TO THE SAME OBJECTIONS? Only in part. Additions to A vista s generating capacity were added to the power supply model, and this presumably adds revenues or decreases expenses as a result of the pro forma plant additions. I have not attempted to confirm that this modeling change was properly implemented, but I assume Staff will do so. If the implementation was correctly done, I have no objection to these pro forma adjustments as such, although I have proposed the removal of Coyote Springs 2 on other grounds, as discussed above. DIRECT TESTIMONY OF DENNIS E. PESEAU - 31 IPUC Case Nos. A VU-O4-1 and A VU-04- 924 But there is no similar revenue adjustment for the $26 300 000 in 2003 and 2004 transmission projects Avista pro forms into the rate base, even though these additions will also produce either additional revenues or operational savings. Like other businesses utilities generally do not make additional investments or increase their expenses unless they can generate additional revenues and profits, either by serving additional customers or by cutting costs or increasing margins. There is no reason to assume this is not the case here. The projected expenditures Avista has identified must be presumed to generate additional revenues or other benefits that would offset their costs, in whole or in part. A vista has made no attempt to identify these offsetting benefits. As the Commission pointed out in its recent order in the Idaho Power rate case: Generally speaking, the Commission expects all utilities to attempt to identify expense saving and revenue producing effects when proposing rate base adjustments for major plant additions. It is unfair to ratepayers to assume that the investment in these plants will not increase Company revenues or decrease Company expenses in the future. Further, it is unreasonable to expect the Commission to allow full recovery of plant investment as if the plant had been in operation the full year without a corresponding adjustment to revenues and expenses. Order No. 29505 , p. 7. HOW SHOULD THIS MISMATCH BE CORRECTED? There are basically three alternative remedies available to correct this rate base mismatch. The first would be to reverse the pro forma entries and properly match test year averages on both sides of the ledger. The second alternative is to update revenues to the 2004 level in the same manner as rate base and expenses. Finally, the third alternative is to employ the rate base adjustments the Commission adopted in the Idaho Power rate case. DO YOU HAVE A PREFERENCE BETWEEN THESE THREE AL TERNA TIVES? DIRECT TESTIMONY OF DENNIS E. PESEAU - 32 IPUC Case Nos. A VU-04-1 and A VU-04- 925 1.5 As I have stated in other cases, I think annualizing revenues to 2004 year-end levels is the preferable course for two reasons. First, it is much simpler to annualize revenues than to back out pro forma adjustments from numerous expense and rate base categories. Moreover, adjusting revenues produces a more forward-looking result than reversing the expense and rate base annualizations. I recognize, however, that the Commission adopted a third course of action to correct similar mismatches in the recent Idaho Power rate case. In that case, the Commission adopted a proxy for increased revenues and reduced expenses. While the Commission stated that it did not necessarily regard that adjustment as precedent for future cases, the circumstances in this case are very similar to the Idaho Power case. lack the precise data to calculate a similar remedy of the mismatch in this case, but I note that in the recent Idaho Power decision the Commission adjusted total revenues on the order of 5 percent of the rate base additions. Cost of Service Issues HAVE YOU REVIEWED AVISTA'S COST OF SERVICE STUDY AND THE RESULTING RATE DESIGN? Yes. The study sponsored by Ms. Tara Knox generally follows the methods approved in the past, with a major exception described below. I recommend two improvements to allocators contained in the Company s study. Avista s Proposed "Four Factor" Allocator for Common Costs DOES WITNESS TARA KNOX PROPOSE A CHANGE FROM THE PREVIOUS APPROVED COST OF SERVICE METHODOLOGY USED IN CASE NO. WWP- 98-11 ? DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. A VU-O4-1 and A VU-04- 926 Yes. As noted on Pages 6-7 of her direct testimony, the Company proposes to allocate common costs" on the basis of four factors: direct O&M expenses, direct labor, net direct plant, and number of customers. Previously, Avista had allocated these common costs to customer groups with a 60% customer/40% energy allocation factor. WHAT ARE "COMMON COSTS?" Common costs are typically defined as those costs necessary for the utility to function but which are left over after most directly assignable costs have been identified and functionalized" to production, transmission, distribution or customer accounts. These remaining common costs include general and common plant investment costs and administrative and general expenses. Office buildings, furniture, transportation equipment, certain inventories, computer costs and a portion of management salaries typically comprise common costs. ARE THE SPECIFIC FOUR FACTORS USED BY MS. KNOX TO ALLOCATE COMMON COSTS P ARTIALL Y VALID? Yes and no. Yes, the four factors, if correctly defined, are legitimate bases upon which to allocate common costs. However, the method Ms. Knox uses to calculate the actual weights of the four-factor allocations has a serious flaw, one that renders her calculations highly volatile and incorrect. PLEASE EXPLAIN. In order to better explain this issue, I list the proposed four factors chosen for the common cost allocations: Direct O&M Expenses Direct Labor Expenses Net Direct Plant Expenses Number of Customers DIRECT TESTIMONY OF DENNIS E. PESEAU - 34 IPUC Case Nos. A VU-04-1 and A VU-04- 927 The issue I raise involves only one of the four factors - Direct O&M Expenses. Simply put, Ms. Knox fails to remove a portion of these direct O&M expenses, an adjustment that is necessary for the proper allocation of common costs. WHAT ARE DIRECT O&M EXPENSES? Direct O&M expenses in Avista s cost of service study are listed as FERC Accounts 500- 916 on pages 4-10 in Ms. Knox s Exhibit 16, Schedule 2. For reference, the sum of the expenses in these O&M accounts is $97 699 000 (Line 369, Page 10 of 59, Exhibit 16 Schedule 2). By using the sum of all the dollars in all of the O&M accounts, and their allocators (energy, demand, customer) as one of the four factors used, Avista and Ms. Knox are suggesting that common costs are caused in a fashion similar to the cause of the O&M costs. Properly defined, O&M expenses form a reasonable means with which to allocate common costs, but Avista s O&M expense definition fails in this regard. WHAT IS THE BASIS FOR YOUR STATEMENT THAT A VISTA HAS IMPROPERL Y DEFINED ITS DIRECT O&M EXPENSES AS ONE OF THE FOUR- ACTORS TO ALLOCATE COMMON COSTS? Three distinct reasons support my conclusion that Avista s first factor, the Direct O&M Expense, incorrectly allocates common costs: Avista s O&M expense allocator is extremely volatile from year to year and common costs are not volatile. A vista s annual common costs from 1998-2003 are actually inversely related to its definition of O&M expenses. DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. A VU-04-1 and A VU-04- 928 A statistical regression analysis supports the conclusion that the common cost allocator using Avista s Direct O&M Expenses is valid if, and only if variable fuel and purchased power expenses are removed. Avista s Volatile Direct Expense Definition WHAT IS THE ISSUE WITH RESPECT TO THE VOLATILITY OF USING A VISTA'S DEFINITION OF DIRECT O&M EXPENSE TO ALLOCATE COMMON COSTS? Simply put, A vista s definition of O&M expenses includes fuel and purchased power costs as an element from which the relatively fixed common costs are allocated. I offer clear evidence below that common costs simply do not vary in any relation to changes in fuel and purchased power costs. APART FROM ACCOUNTING AND STATISTICAL DATA, IS THERE A COMMON SENSE EXPLANATION AS TO WHY COMMON COSTS SHOULD NOT BE ALLOCATED ON THE BASIS OF FUEL AND PURCHASED POWER COSTS? Yes. As we are all aware, fuel and purchased power prices have risen, fallen, and again risen by as much as several hundred percent on a year-to-year basis. If we assume, as A vista has done, that common costs are caused by changes in fuel and purchased power costs, then we will be changing the common cost allocator by as much as several hundred percent year-by-year. Another way of stating the misapplication is that A vista is implying that its expenditures on office buildings, furniture, parts inventories, vehicles, computers, office supplies, employee pension and benefits, rents and general plant maintenance can be expected to vary directly with the recent huge swings, both up and down, in fuel and DIRECT TESTIMONY OF DENNIS E. PESEAU - 36 IPUC Case Nos. A VU-04-1 and A VU-04- 929 purchased power prices. (See Exhibit 16, Schedule 2, Pages 10-11 for complete list of common (A&G) cost items. DOES THIS DISTORT THE COST OF SERVICE RESULTS? The distortion is huge, because fuel and purchased expenses from year to year comprise the overwhelming majority of Direct O&M expenses. For example, of the total test year O&M expenses of$97.7 million (Exhibit 16, Schedule 2, Page 10, Line 369) $66. million, or 68 percent of the total is fuel and purchased power expenses. The effect on customers of allocating relatively fixed common costs on volatile fuel and purchased power prices is to cause huge swings in the levels of common costs allocated to each customer class. These swings have nothing to do with the common costs of serving these customer classes. IS THERE AN EASY, COST-BASED FIX TO A VISTA'S VOLATILE AND INACCURATE COMMON COST ALLOCATOR? Yes, apart from the inclusion of fuel and purchased power expenses, the remaining Direct O&M Expense factor is fairly indicative of, and related to the need to incur, common costs. The easy fix is to simply remove the fuel and purchased power expenses and use the remaining non-fuel and purchased power O&M expenses as one of the four-factors for common cost allocator proposed by A vista. A vista s Historical Common Costs are Inversely Related to Fuel and Purchased Power Expenses OTHER THAN YOUR COMMON SENSE DISCUSSION, HAVE YOU ATTEMPTED TO ESTABLISH EMPIRICALLY THAT A VISTA'S EXPENDITURES FOR FUEL AND PURCHASED POWER DO NOT DIRECTLY RELATE TO, OR CAUSE A VISTA'S COMMON COSTS? DIRECT TESTIMONY OF DENNIS E. PESEAU - 37 IPUC Case Nos. A VU-04-1 and A VU-04- 930 Yes. My Exhibit No. 204 is a graph of the recent history of Avista s annual variations in total fuel and purchased power expenses comparing them with Avista s actual A&G (common) costs, 1998-2003. WHAT DOES EXHIBIT NO. 204 SHOW? Exhibit No. 204 confirms what we know to be true - that Avista s fuel and purchased power costs have varied tremendously on a year-to-year basis since 1998. The exhibit also confirms the point I was making above, that A vista s common (A&G) costs have been virtually constant since 1998. Use of the fuel and purchased power expense component within A vista s Direct O&M factor would therefore generate widely fluctuating allocations of common costs to different customer classes, distorting the intent of a common cost allocator. Statistical Relationship Between O&M and Common Costs WHAT STATISTICAL VERIFICATION DO YOU HAVE THAT INDICATES THAT A VISTA'S INCLUSION OF FUEL AND PURCHASED POWER EXPENSES IN ITS COMMON COST ALLOCATOR IS INCORRECT? The use of formal statistical analysis to prove that volatile, variable costs for fuel and purchased power are not correlated with fixed common costs may be overkill , but I nevertheless offer a statistical regression analysis supporting my arguments. The statistical tests or "hypotheses" I review also indicate that fuel and purchased power costs should be excluded from the allocator used to allocate common costs. PLEASE EXPLAIN. The regression analysis I performed simply answers the question of whether A vista incurrence of common costs is fundamentally related to a definition of O&M expenses DIRECT TESTIMONY OF DENNIS E. PESEAU - 38 IPUC Case Nos. A VU-04-1 and A VU-04- 931 that includes or does not include fuel and purchased power expenses. As our goal in the cost of service study is to identify the causative factors of common costs, we search statistically for the accounts making up O&M expenses that do, and those that do not cause A vista to incur common costs. Then, in the allocation of common costs to customer classes, we use only those O&M accounts that do relate to, or "cause" common costs. WHAT DOES YOUR STATISTICAL REGRESSION ANALYSIS SHOW? The analysis shows that common costs are much more related to, or "correlated with O&M expenses that have had fuel and purchased power expenses removed. The regression analysis was conducted for two different equations: Common Costs related to (O&M minus F&PP expenses); and Common Costs related to (O&M with F&PP expenses) where F&PP refers to fuel and purchased power. Exhibit No. 205 summarizes the results of regressions for these two equations. For completeness, common cost data were developed two ways: first measured as A&G costs; second, as dollar levels of A vista s general plant accounts. HOW WERE THE DATA DERIVED? All data were taken from the 2003 FERC Form Is, for Avista and the five other western electric utilities listed in Exhibit No. 205. The other five utilities provide a representational cross section of similarly situated electric utilities. PLEASE SUMMARIZE THE QUANTITATIVE FINDINGS. Regardless of whether A&G expenses or general plant is used as the measure of common costs, the regression results strongly indicate that O&M expenses less fuel and purchased DIRECT TESTIMONY OF DENNIS E. PESEAU - 39 IPUC Case Nos. A VU-04-1 and A VU-04- 932 power expenses is a superior allocator, compared with Avista s proposed change of including fuel and purchased power expenses. This analysis supports the common sense reasoning and graphic evidence presented earlier, and it demonstrates that Avista proposed change in these proceedings to include fuel and purchased power expenses to allocate common costs should be rejected. HOW SHOULD COMMON COSTS BE ALLOCATED IN THESE PROCEEDINGS? I believe that the Commission is left with two reasonable alternatives. First, the Commission could adopt in principle Avista s four-factor common cost allocator concept but simply order the Company to remove fuel and purchased power expenses from the one factor, Direct O&M Expense. In this way, each of the factors in the four-factor method would closely track common costs. I have participated in cost of service studies in the past where FERC has similarly removed fuel and purchased power expenses from the Direct O&M Expense accounts. Alternatively, the Commission could order Avista to continue to use the previously approved common cost allocator, where costs were allocated 40% on energy and 60% on customer counts. The allocations resulting from the two alternatives are similar in this case. My Exhibit No. 205 reflects the cost of service results from the four- factor "Direct O&M less F &PP expenses" method. My recommendation to the Commission is to use the four-factor Direct O&M less F &PP expenses method. Avista s Transmission Cost Allocator DOES A VISTA'S COST OF SERVICE STUDY CORRECTLY ALLOCATE ITS TRANSMISSION COSTS? DIRECT TESTIMONY OF DENNIS E. PESEAU - 40 IPUC Case Nos. A VU-04-1 and A VU-04- 933 Transmission costs are incurred to meet peak demands, and are therefore appropriately allocated to customer classes on the basis of demand (capacity) allocators. Avista proposed cost-of-service study allocates a significant amount of transmission costs, not on demand, but on an energy basis. This is no longer defensible. DID A VISTA'S COST OF SERVICE STUDY IN WWP-98-AA ALLOCATE TRANSMISSION COSTS SIMILARLY ON A DEMAND AND ENERGY BASIS? Yes. Unlike the previous issue on the four-factor method, the transmission allocation issue I raise here clearly would require the Commission to modify its position in the previous rate case, and adopt the same methodology it recently approved in the Idaho Power rate case. But I believe the evidence supporting this change is compelling. PLEASE EXPLAIN. My proposal to allocate transmission costs strictly on a demand basis is based on three distinct propositions: A vista s and virtually all other transmission systems are planned, sized and built to meet maximum instantaneous, or peak demands. A vista s proposed demand/energy transmission allocator is inconsistent with, and contradictory to, the same transmission system rates it has had approved, and indeed charges, to wholesale customers through its Open Access Transmission Tariff ("OA TT" The Commission has just weeks ago approved the demand allocator for transmission costs that I propose here in the recently completed Idaho Power general rate case. DIRECT TESTIMONY OF DENNIS E. PESEAU - 41 IPUC Case Nos. A VU-04-1 and A VU-04- 934 WHAT IS THE BASIS FOR YOUR CONCLUSION THAT A VISTA' TRANSMISSION SYSTEM IS CONSTRUCTED TO MEET ITS PEAK DEMAND REQUIREMENTS? Our firm has examined system planning methods and models for many years. For generation systems, a hydro-electric dam being a good example, construction costs can be incurred to meet both demand and energy considerations. In the Pacific Northwest, for example, we know that hydro generation costs are incurred or "caused" not only by peak demand requirements, but also by the need to store energy. Generation costs are routinely allocated to both demand and energy. Transmission systems, while they obviously transmit energy, are planned for, and the cost is caused by, the need to meet peak demands. Once the costs are incurred and the facilities constructed, no additional costs are incurred to transmit energy. Thus, the principle of cost-causation leads us to allocate transmission on the basis of demand (capacity) usage only. HOW IS A VISTA'S PROPOSED DEMAND/ENERGY TRANSMISSION ALLOCATOR INCONSISTENT WITH THE TRANSMISSION COST ALLOCATION AND RESULTING RATES IT HAS IN PLACE FOR WHOLESALE TRANSMISSION USERS? The open access policies implemented by FERC some years ago, as we know, require A vista and other utilities to file and maintain OA TTs, the rates of which must be based on cost of service. I have reviewed the current A vista OA TT and determined that the Company allocates its transmission system costs (the same system contained in its present transmission cost of service) not on the basis of the demand/energy allocator DIRECT TESTIMONY OF DENNIS E. PESEAU - 42 IPUC Case Nos. A VU-04-1 and A VU-04- 935 proposed in this general retail rate case, but rather on the same demand basis that I am proposing here. There is no reasonable justification to have two different sets of transmission costs and rates for the same identical system. HOW DO YOU KNOW THAT THE APPROVED OA TT RATE IS BASED ON A DEMAND-ONL Y ALLOCATOR? In my Exhibit No. 207 I attach a copy of the relevant pages of Avista s present OATT. The rates posted there are derived strictly on a "per kW" or demand basis. This indicates that the OA TT rates and the transmission costs contained therein are based solely on a demand allocator. DO PROBLEMS ARISE FROM ALLOCATING THE SAME TRANSMISSION COSTS OF SERVICE ON THE BASIS OF TWO DIFFERENT ALLOCA TORS , AS VISTA IS PROPOSING? Yes, obviously so. First, the demand method is correct and the demand/energy is not. Therefore, one set of rates is correct and the latter is not. There is no sound reason why identical retail or wholesale transmission customers should have their respective cost allocations and therefore their rates differ for the same usage. This is disparity is not only illogical; it is also potentially discriminatory. WHAT TRANSMISSION COST ALLOCATION METHOD DID THIS COMMISSION ADOPT IN THE RECENT IDAHO POWER GENERAL RATE CASE NO. IPC-03-13? The Commission based its rate design on Idaho Power s basic cost of service study, which allocated the Company s transmission costs on the basis of demand only. Idaho Power s approved OA TT rates are also based on demand-only transmission cost allocators. DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. A VU-04-1 and A VU-04- 936 HAVE YOU PREPARED A COST OF SERVICE STUDY THAT INCORPORATES THE CHANGES YOU RECOMMEND? Yes. Exhibit 206 is a summary of the results of my cost of service study incorporating the proper 4-factor and transmission capacity allocator. While the changes to the allocations to the various customer classes are not dramatic, they are significant and necessary to properly capture cost of service. WHAT DOES YOUR COST OF SERVICE STUDY SHOW WITH RESPECT TO THE PRESENT CONTRIBUTIONS THAT DIFFERENT CUSTOMER CLASSES ARE MAKING TOWARD RESPECTIVE COSTS OF SERVICE? The summary results indicate, consistent with the conclusions of A vista s cost of service study, that residential customers, Schedule 1 , and large general service customers Schedule 25, are receiving substantial subsidies from all remaining customer classes including Potlatch. Page 1 of Exhibit 206 shows that the residential and general service customer classes' rates generate rates of return that are significantly below the system average rate of return, thus indicating that other classes' rates are set too high in order to make up the shortfall. HOW SHOULD THE COMMISSION DEAL WITH THE ELIMINATION OF THESE SUBSIDIES? In the recent Idaho Power general rate case I testified that a huge subsidy, in that case to the irrigation pumping class, needed to be systematically and unequivocally reduced to zero, necessitating a large increase to the irrigators. The same principles apply here although the levels of subsidies to the residential and general service customers are not so large as in the Idaho Power case. In principle, I believe these subsidies should be DIRECT TESTIMONY OF DENNIS E. PESEAU - 44 IPUC Case Nos. A VU-04-1 and A VU-04- 937 eliminated immediately. However, I am also aware the Commission has expressed concerns about the "rate shock" that could result from very steep increases for a particular customer class. Accordingly, I propose in these proceedings that, if the overall approved increase is ten percent or less, all customer classes should be moved to full cost of service. If the increase is greater than ten percent, the Commission order should order residential and large general service rates moved at least halfway toward rate ofretum parity, with two annual automatic adjustments thereafter to close the remaining cost of service gap. Under the latter alternative, the other customer classes (Schedules 11-, Schedules 21- , and Potlatch) would continue to pay a subsidy in the near term, but would receive assurances that the remaining subsidy would be eliminated over the next two years. This , I believe, more than fair to the subsidized customer classes. Rate Design Issues DO YOU HAVE ANY COMMENTS ON A VISTA'S RATE DESIGN PROPOSALS? Yes. My first observation is that Avista s proposal to include Potlatch's Lewiston Facility ("Facility ) in Tariff Schedule 25 should be rejected. Because of the huge disparity in size between the Facility and the other Schedule 25 customers, it makes no sense to include the Facility in that schedule. For customers the size of the Facility, the Commission has always used separate tariffs for each special contract customer, and it should do so in this case as well. The Facility is approximately three times the size of all the entire Schedule 25 class. IS THE FACILITY IN FACT A SPECIAL CONTRACT CUSTOMER? DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. A VU-04-1 and A VU-04- 938 Yes. The Avista and Potlatch power supply agreement ("Agreement") is a unique contract that governs Avista s service to only one customer- the Facility. In that Agreement, the parties agreed to the temporary use of Schedule 25 rates for service to the Facility, pending the next rate case. But Potlatch did not agree to become a Schedule 25 customer The Facility has always been a "special contract customer" in the past, and the Agreement clearly contemplates that this status will continue in the future. IS IT DIFFICULT TO SEPARATE THE FACILITY'S COST OF SERVICE FROM SCHEDULE 25? No. The A vista cost of service study, and my own, already compute all cost of service elements for the Facility on a stand-alone basis, in recognition of the fact that the Facility is indeed a customer class unto itself. Given this, the Commission should require A vista to preserve these cost elements treating the Facility as the customer class that it is. makes no sense to subsequently meld the Facility with the much smaller Schedule 25 class. In order to set rates for the Facility within the Schedule 25 class, A vista in this case had to resort to major rate design changes in order to properly assure that Potlatch would not be overcharged. Creating a stand-alone rate schedule for the Facility will not affect the Facility cost of service or rates. It is simply a preventive measure. The concern is that in the future this distinction could be blurred in a subsequent study in a manner that causes the Facility to pay costs for which it should not be accountable. The distinction between the Facility and the Schedule 25 customers should be clarified by placing the Facility in a separate rate schedule. DOES THIS COMPLETE YOUR TESTIMONY? DIRECT TESTIMONY OF DENNIS E. PESEAU - 46 IPUC Case Nos. A VU-04-1 and A VU-04- 939 Yes, it does. DIRECT TESTIMONY OF DENNIS E. PESEAU - 47 IPUC Case Nos. A VU-04-1 and A VU-04- 940 Appendix A-Update to Dr. Avera s Analysis WHAT IS THE CORRECT RETURN ON EQUITY RANGE USING DR. AVERA' METHODS FOR ESTIMATING EQUITY RETURNS? I conclude that consistent application of the discounted cash flow (DCF) and risk premium methods used by Dr. Avera reduces his recommendations as follows: ROE Method Avera Estimate- Peseau U date DCF 10.4% Risk Premium I 11.4 10. Risk Premium II 10.9.2% to 10.1 % CAPM 11.9 10. - nJ includes flotation costs of 20 basis points. Updates that are consistent with the methods Dr. Avera utilizes do not support his range of 10.4% to 11.9% and certainly do not support a recommended ROE of 11.5%. See Exhibit No. 211. WHAT GENERAL COMMENTS DO YOU HAVE REGARDING THE TESTIMONY AND ANALYSES OFFERED BY DR. AVERA? Dr. Avera offers 70 pages of testimony covering a number of topics. Twenty-four of these pages cover discussion of flotation costs and the quantitative equity return methods and estimates commonly considered by this Commission. The rest of the testimony is concerned with general and fundamental economic and financial topics that are normally and efficiently taken into account by investors when bidding on and purchasing common stock and other assets. Financial institutions and investors know the financial and operational characteristics of A vista every bit as well as Dr. A vera and use this information to make formal investment decisions. A well-known financial principle is that investors are not normally, nor do they expect to be, compensated for nonmarket or DIRECT TESTIMONY OF DENNIS E. PESEAU - 48 IPUC Case Nos. A VU-04-1 and A VU-04- 941 company-specific risks that are not systematic. These risks are diversifiable and do not and should not form the basis of rate of return "adders." The methods of determining cost of equity used by Dr. Avera and others in this case measure returns that are commensurate with similar risk-adjusted investments and should not be adjusted for exogenous risks. PLEASE SUMMARIZE DR. AVERA'S ESTIMATES. Dr. Avera presents four quantitative analyses of the cost of equity for a "benchmark" group of western electric utilities from which he derives a 10.2% to 11.7% equity cost range. He presents a discounted cash flow ("DCF") analysis for a benchmark group of electric utilities in the western U. S., two risk premium approaches, and an estimate based on the capital asset pricing model ("CAPM" ). From his DCF analysis, he estimates that a benchmark sample of western electric utilities requires a return on equity of 10.2% (page 45). Based on two risk premium models, he concludes that the cost of equity for the respective reference samples of electric utilities is 11.2% (page 49) and 10.6% (page 50). And, from his CAPM approach, he derives a cost of equity estimate for the western electric utilities of 11.7% (page 51). Based on that information, and an adder of 20 basis points for flotation costs and additional premiums he argues are required for risk specific to Avista, he endorses an ROE of 11.5%. HOW DOES HE REACH THE CONCLUSION THAT A VISTA SHOULD BE AUTHORIZED AN EQUITY RETURN IN EXCESS OF 11.5%? Dr. Avera presents lengthy discussions of company-specific risks that he contends are faced by Avista and should be recognized in setting the authorized return. That analysis of unique risks is the basis for his contention that the Company requires an equity return DIRECT TESTIMONY OF DENNIS E. PESEAU - 49 IPUC Case Nos. A VU-04-1 and A VU-04- 942 near the top of his estimate of the equity cost range for other western electric utilities. But as I just explained, these company specific risks are incorporated into his results, and a subjective adder for such risks is unwarranted. Update to Dr. Avera s DCF Approaches DO YOU HAVE ANY COMMENTS ABOUT HIS DCF ANALYSIS? Yes. Recall that the DCF method under standard financial assumptions reduces to the equation: ROE = DI/Po + g where ROE required equity return first period dividend rate today s stock price growth rate Dr. Avera s estimate of a 10.2% return results from his estimate of the DCF components: 10.2% = 4.2% (yield) + 6.0% (growth) I update the 6.0% growth rate and his dividend yield. The growth rate g is growth that expected in the future by investors. It is by nature forward looking. But I note that on Dr. Avera s Schedule WEA-, he used not only the typical benchmark for expected growth, as reported by the investor institutions IBES, Value Line, First Call and Multex Investor, but also historical rates of earnings growth for both five and ten year past periods: DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. A VU-04-1 and A VU-04- 943 Dr. Avera s Ex ected Growth Rates Value First Past Past IBES Line Call Multex 10 Yr.5 Yr. Average Expected Growth Rate 5.1 2.4 5.4 7.3 8.1 While the simple average of these growth rates is 5., Dr. Avera inexplicably uses a 0% figure to develop his 10.2% return. IN YOUR OPINION, IS DR. AVERA'S USE OF THE HISTORICAL GROWTH RATES IN HIS AVERAGE AN APPROPRIATE BASIS FOR ESTIMATING THE DCF REQUIRED FUTURE EXPECTED GROWTH RATE? No. To the extent that past growth might be of any importance to investors, the analysts forecasts Dr. Avera reports for IBES, Value Line, First Call and Multex have already taken that information into account. David A. Gordon, Myron 1. Gordon and Lawrence I. Gould , " Choice Among Methods of Estimating Share Yield Journal of Portfolio Management pp. 50-55 (Spring 1989), did a study that found analysts' forecasts of growth provide a better explanation of stock prices than three backward-looking measures of growth. They explain that their findings make sense because analysts would take into account past growth as well as any new information when they form their forecasts. Roger Morin reports the results of other empirical studies and concludes analysts ' forecasts "are more accurate than forecasts based on historical growth. Regulatory Finance: Utilities Cost of Capital page 154. My restatement of Dr. Avera DCF analysis recognizes four of the growth forecasts Dr. Avera relied upon, but gives no weight to the measures of past growth Dr. Avera reported. DIRECT TESTIMONY OF DENNIS E. PESEAU - 51 IPUC Case Nos. A VU-O4-1 and A VU-04- 944 HOW HAVE YOU MODIFIED DR. AVERA'S DCF EXPECTED GROWTH RATE VARIABLE TO REMOVE THE EFFECTS OF HISTORICAL GROWTH? My Exhibit No. 208 shows those results. To determine an updated and consistent estimate for the DCF expected growth rate for each of the utilities in Dr. Avera s sample I updated his reported estimates of investor institution projections in Schedule WEA-2 as well as his estimate of sustainable growth in his Schedule WEA-3. Exhibit No. 208 shows an average of four growth forecasts; the current estimates reported by IBES, First Call and Reuters (formerly Multex) and the higher of the two forecasts made with Value Line data. Exhibit No. 208 shows that the correct average for the projected or expected growth rate is 5.1 %, close to the bottom of the 5% to 7% range adopted by Dr. Avera. DID YOU UPDATE DR. AVERA'S DIVIDEND YIELDS? Yes. I used data published by Value Line, dated June 4, 2004, and the method Dr. Avera used to compute dividend yields to make that update. These updated dividend yields are also reported in Exhibit No. 208. BASED ON YOUR UPDATES AND UTILIZATION OF ONLY THE FORWARD- LOOKING GROWTH RATES REPORTED BY DR. AVERA, WHAT IS YOUR RESTATEMENT OF DR. AVERA'S DCF RESULTS? Based on his sample and the restatements discussed above, the indicated average cost of equity for the western electric utilities is 9.3% (4.% dividend yield and 5.1 % growth after rounding), 90 basis points less than the 10.2% estimated by Dr. Avera. DO YOU HAVE OTHER CONCERNS WITH DR. AVERA'S DCF ANALYSIS? Yes. The DCF method he proposes is incorrect. At page 32, Dr. Avera presents the general form of the DCF model. It clearly shows that expected dividends per share DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. A VU-04-1 and A VU-04- 945 (DPS) are the cash flows that are of interest to investors. He adopts Value Line forecasts of dividends for the next year but ignores Value Line ~ forecasts of dividends for other future years. His DCF approach is incorrect because it does not incorporate all of the information on dividend growth that investors consider when they price the shares of common stock in his sample. Had Dr. Avera made his DCF estimates with a multi-stage DCF model that recognized that dividend growth is expected to be less than half as rapid as forecasted earnings and sustainable growth for the period 2004 to 2008, the DCF equity cost estimate would be less than 9.3 %. But because I limit my testimony to a restatement of the methods Dr. Avera has relied upon, I have not presented such an analysis. Update to Dr. Avera s Risk Premium Approaches PLEASE DESCRIBE THE RISK PREMIUM APPROACH TO ESTIMATING A UTILITY'S REQUIRED RETURN ON EQUITY. Whereas the DCF method adds estimates of dividend yield to expected growth rate to get equity cost estimates, risk premium methods recognize that over time common stock is riskier than most debt securities (bonds) and therefore requires a premium, or adder, over and above the return on bonds. This adder is often termed a risk premium. As yields on bonds are generally directly observable and measurable, equity cost estimates may be derived if reliable risk premiums can be determined. HOW DOES DR. AVERA UTILIZE THE RISK PREMIUM METHOD? Dr. Avera uses a risk premium method based on authorized equity returns, another based on actual or realized returns and, finally, the more academically rigorous risk premium method, the Capital Asset Pricing Model (CAPM). DIRECT TESTIMONY OF DENNIS E. PESEAU - 53 IPUC Case Nos. A VU-04-1 and A VU-04- 946 WHAT EQUITY RETURN DOES DR. AVERA ESTIMATE USING HIS AUTHORIZED RETURN RISK PREMIUM METHOD? 11.2%. He derives this by adding a December 2003 bond yield of 6.61 % to a risk premium estimate of 4.58% that is derived in his Schedule WEA-4. Schedule WEA- uses regression analysis to attempt to determine the historical relationship between allowed equity returns and bond yields, and the difference between the two, to establish the risk premium. The theory is that if the regression analysis can determine the relationship between the bond yield and the appropriate risk premium, then one can observe today s bond yield, add to it the estimate of risk premium appropriate for the bond yield and add the two to get an equity return estimate. From Schedule WEA-, Dr. Avera estimates the relationship as: (ROE - Bond Yield) = . 073 + (-.435 x Bond Yield) While I have no quarrel with the basic methodology, Dr. Avera uses interest rates or bond yields that are internally inconsistent in his method. PLEASE EXPLAIN. Dr. Avera uses a low yield bond to compute his historical risk premium. Use of this low bond yield when subtracted from allowed equity returns, produces an exaggerated or higher risk premium than if a consistent bond rate is used. The bond yield used by Dr. Avera, shown on Schedule WEA-4 is an average of AAA, AA, A and BBB rated bonds. Since the highly rated bonds AAA, AA and A will have the lowest interest rates, the composite rate Dr. A vera uses is low. Subtracting a low interest rate from an authorized return yields an artificially high risk premium. Then, on Page 49, Line 10, he adds this high risk premium to the highest bond yield, that of a triple-B bond. This mixing of DIRECT TESTIMONY OF DENNIS E. PESEAU - 54 IPUC Case Nos. A VU-04-1 and A VU-04- 947 different bonds for the regression analysis and for computing the equity return biases upward Dr. Avera s estimate of an equity return. HAVE YOU ATTEMPTED TO REMOVE DR. AVERA'S INCONSISTENCY? Yes. An appropriate calculation would use the same measure of bond rating in the regression analysis as in the recommended equity return. In making my restatement, I have used A-rated utility bonds to compute the risk premiums, to run the regressions and to estimate the equity cost. I ~hose the A-rated utility bond rates because Dr. Avera relies on A-rated bonds in Schedule WEA-5. Also, current quotations for A-rated utility bond rates are widely available and published by Value Line every week. I also used triple- rates, as a second approach in another regression as well, because that is what Dr. Avera uses on his Page 49. The results of the revised analysis are shown in my Exhibit No. 209, pages 1 and 2. Combining the revised regression result with a June 4, 2004 Value Line quotation of 08% for A-rated utility bond rates gives an indicated cost of equity for the benchmark electric utilities of 10.40 basis points lower than Dr. Avera s estimate of 11.2%. Using the triple-B regressions with the current triple-B rate of 6.56% reported June 4 2004 gives a cost of equity estimate of 10.9%. DO YOU HAVE ANY COMMENTS ABOUT DR. AVERA'S RISK PREMIUM APPROACH BASED ON THE REALIZED-RA TE-OF -RETURN APPROACH THAT HE PRESENTED IN SCHEDULE WEA- Yes. First, as he did with his other risk premium approach, Dr. Avera used one type of bond to determine the average risk premium and then incorrectly added that risk premium to a triple-B public utility bond rate. In this analysis the risk premium was established as DIRECT TESTIMONY OF DENNIS E. PESEAU - 55 IPUC Case Nos. A VU-04-1 and A VU-04- 948 the average difference between annual returns on stocks and A-rated bonds and thus the risk premium will be larger than if the premium were established for triple-B bonds. To make Dr. Avera s approach internally consistent, I added the current A-rated bond to the premium for A-rated bonds. This change alone reduces Dr. Avera s equity cost estimate to 10. %. See Exhibit No. 210. My other observation is that Dr. Avera s approach assumes that investors typically have holding periods of only one year, when investors probably expect to hold shares of utility stocks for longer periods. If investors have very long holding periods, a risk premium based on differences in geometric average returns would be the appropriate risk premium. If, for example, investors have 57-year holding periods, the correct estimate of the risk premium would be 3.11 % instead of 4.01 %. See Exhibit No. 210. I expect that investors typically have holding periods longer than one-year but much shorter than 57 years. In such a case this approach would indicate the cost of equity would be between 9.2% and 10.1% but closer to 10.1%. DO YOU HAVE ANY COMMENTS ABOUT DR. AVERA'S CAPITAL ASSET PRICING MODEL EQUITY COST ESTIMATE? Yes. Although the CAPM's derivation is steeped in a good deal of financial theory and mathematical determination, the final specification, like the DCF method, is fairly straightforward: Equity Cost = Risk Free Rate + Beta x Market Risk Premium There are a number of different ways the CAPM can be implemented and a number of ways that estimates of the risk free rate and market risk premium can be derived. I limit DIRECT TESTIMONY OF DENNIS E. PESEAU - 56 IPUC Case Nos. A VU-04-1 and A VU-04- 949 my comments to an update of Dr. Avera s risk free rate and his estimate of the market risk premium (MRP). I will not contest his measure of market risk , " beta. WHAT IS THE RISK-FREE RATE USED BY DR. AVERA? Dr. Avera uses as a measure of the risk-free rate the average yield on long-term government bonds. He indicates that this measure of the risk-free rate as of December 2003 was 5.2%. WHAT IS THE RECENT YIELD ON LONG-TERM GOVERNMENT BONDS? The yield reported by Value Line at June 4 2004 is 5.32%. I use that value in my update of Dr. Avera s CAPM estimate. HOW DOES DR. AVERA ESTIMATE THE MARKET RISK PREMIUM ("MRP" While I do not agree with his method of estimating the MRP, I use his method here with a simple update. Dr. Avera derives a forecast of the total average market return for the stock market of 13., then, to estimate the market premium he subtracts his risk free rate of 5.2%, which results in an 8.5% MRP. WHA T UPDATE HAVE YOU MADE TO DR. AVERA'S MRP? Whereas the long-term government bond rate is directly observable and is set in competitive markets, the other component of the risk premium approach used by Dr. Avera, the projected market return, is not directly observable or measurable. The projected market return is simply the opinion about the future made by different investor institutions and can change frequently. Use of a projected market return of 13., as of a single point in time, therefore makes the prediction of total market return highly variable as I now show. For reference, the long-term average market risk premium during the DIRECT TESTIMONY OF DENNIS E. PESEAU - IPUC Case Nos. A VU-04-1 and A VU-04- 950 period 1926 to 2003 is 7.2%, not the 8.5% used by Dr. Avera. Investors that use CAPM would undoubtedly give weight to that long-term average market risk premium. Dr. Avera s total market return estimate was made prior to recent stock market activity that has occurred since December 2003. Investors now understand that a short- term gain as large as 13.7% is no longer realistic. For example, the Value Line forward- looking total market return for the 1700 stocks it follows, as of June 4, 2004, was 12.55%, not the 13.7% used by Dr. Avera. This huge potential for variation in these current" MRP estimates makes rate of return setting for regulatory purposes difficult. Nevertheless, using the updated market return forecast of 12.55%, the implied MRP is 23% (12.55% - 5.32%), not the 8.5% used by Dr. Avera. At this time, the indicated current" market risk premium and the long-term average market risk premium are both 7.2%. If investors consider either indicator of the market risk premium, an update of Dr. Avera s CAPM equity cost estimate is 10.9% as shown below: Equity cost RF + beta x MRP Equity cost = 5.32% + .77 x 7.2% = 10. PLEASE SUMMARIZE YOUR UPDATES AND RESTATEMENTS OF DR. AVERA'S QUANTITATIVE ESTIMATES OF THE COST OF EQUITY FOR BENCHMARK ELECTRIC UTILITIES. I conclude my straightforward updates of Dr. Avera s estimates of the cost of equity do not support a recommended ROE range of 10.4% to 11.9% and certainly do not support an equity return for A vista of 11.5%. My summary Schedule DEP-4 shows that a simple average of the updated equity cost estimates is 140 basis points below the 11.5% ROE that Dr. Avera recommends for A vista. DIRECT TESTIMONY OF DENNIS E. PESEAU - 58 IPUC Case Nos. A VU-04-1 and A VU-04- 951 DO THE DIRECTIONS IN TRENDS OF FINANCIAL MARKETS SUPPORT YOUR RECOMMENDATIONS? Yes. My Exhibit No. 212 shows monthly interest rate data for 10-year Treasury bonds and for Baa corporate bonds for the period October 2001 through April 2004, as reported by the Federal Reserve. Generally, rates for government bonds and Baa corporate bonds have decreased by 145 basis points since October 2001. I conclude that, given the drop in capital costs, A vista s cost of equity is well below its 1998 cost. DIRECT TESTIMONY OF DENNIS E. PESEAU - 59 IPUC Case Nos. A VU-04-1 and A VU-04- 952 ARE YOU THE SAME DENNIS PESEAU WHO PREVIOUSLY FILED DIRECT TESTIMONY IN THIS CASE? Yes. WHA T IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY? I have five areas of brief rebuttal: Staff witness Hessing should not have accepted the Deal A excess gas costs because his compelling arguments to disallow Deal B gas costs apply to Deal A as well. Staff witnesses overlooked the significant change in cost of service methods proposed by A vista witness Knox. Staff witnesses Schunke s and Hessing s proposal to nlove various rate schedules only 20% of the way to cost of service will perpetuate the longstanding subsidies between custolner classes. Coeur Silver Valley witness Yankel' s proposal to directly assign primary costs to Schedule 25 class has merit. Staffs proposal to change the method of computing PCA rates should be rejected or modified. Deal A and Deal B Financial Transactions WHA T ARE THE PRIMARY ISSUES YOU ADDRESS IN YOUR REBUTTAL TESTIMONY OF MR. HESSING REGARDING DEAL A AND DEAL B? In a nutshell, I agree wholeheartedly with Mr. Hessing s recommendation to exclude all the excess financial costs of the so-called Deal B. In fact, his approach is quite similar to and parallels, the rationale I provide for excluding Deal B in my direct testimony. There REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 2 of 16 Case Nos. A VU-04-1 and A VU-04- 953 is no need to elaborate on our similar approaches and our identical conclusions with respect to Deal B, other than to point out that our statements of the amounts in dispute differ, primarily because I used system numbers while Mr. Hessing s figures are for the Idaho jurisdiction and test year only. My issue with Mr. Hessing s testi111ony is that the very compelling cirCulllstances and facts that lead Mr. Hessing to appropriately deny A vist~ recovery of Deal B costs, with one exception, should have also compelled him to recommend disallowance of Deal A costs. My testimony recommends the disallowance of the costs of both Deal A and Deal WHA T IS THE ONE EXCEPTION TO THE SIMILARITY OF CIRCUMSTANCES SURROUNDING BOTH DEAL A AND DEAL B? The one dissimilar circumstance is that A vista Energy was the counterparty to Deal B. Deal A the apparent counterparties were Mirant and BP. Thus, the Deal A counterparties that profited so greatly were not pal1 of Avista Corporation s corporate structure. But in all other respects both Mr. Hessing s and my observations and criticisms regarding the impropriety and imprudence of Deal A and Deal B are the same for both deals. IS THE FACT THAT A VISTA CORPORATION ITSELF DID NOT PROFIT FROM DEAL A SUFFICIENT TO JUSTIFY RECOVERY OF THE DEAL'S EXCESS GAS COSTS IN THE PCA? No. Mr. Hessing s other compelling arguments for denying recovery of Deal B costs on the basis of imprudence also hold for Deal A. Both Mr. Hessing s direct testimony and my own explain at length the numerous peculiarities and irregularities of both Deal A and Deal B that lead to the conclusion that each of these deals was imprudent. In fact, the REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 3 of Case Nos. A VU-04-1 and A VU-04-954 6 - extended period of 3 Y2 years for the Deal A swap actually makes the bet the utility made on Deal A prices far more speculative and imprudent than Deal B. HOW DOES MR. HESSING EXPLAIN HIS PROPOSAL TO DISALLOW DEAL B BUT ACCEPT DEAL A? On pages 15-16 of his direct testimony, Mr. Hessing offers two reasons for not disallowing Deal A. First, as explained above, the counterpaliies to Deal A were not A vista affiliates. Second, Mr. Hessing opines that Deal A did not put A vista over "the long limit contained in its Risk Policy. YOU HAVE ALREADY EXPLAINED YOUR POSITION ON DEAL A COUNTERP ARTIES NOT BEING A VISTA AFFILIATES. WHAT IS YOUR RESPONSE TO MR. HESSING ALLOWING DEAL A BECAUSE IT WAS STILL UNDER THE "LONG LIMIT?" As I discussed in more detail in my direct testimony, Deal A and Deal B were both financial trades, not physical transactions. In other words, Deal A and Deal B did not purchase any natural gas. On page 5 , lines 14-24 of his testimony, Mr. Hessing describes both the physical index-priced gas purchases and the subsequent financial transactions as if they were all parts of Deal A and Deal B. But the proposed Deal A and Deal B cost adjustments are strictly related only to the financial imprudence of these transactions, and not in any way to the procurelnent of the physical natural gas. Therefore, I find it irrelevant that the physical purchases were, or were not, over some designated volumetric or long limit. Neither of the Deal A and Deal B financial trades was prudent on behalf of the utility s customers for reasons explained in Mr. Hessing s and my testimony. I urge REBUTT AL TESTIMONY OF DENNIS E. PESEAU - Page 4 of 16 Case Nos. A VU-04-1 and A VU-04- 955 PAGE IS CONFIDENTIAL 956 other reckless and unprecedented features of both deals that Mr. Hessing and I identify in our direct testimony, compels the conclusion that both should be excluded from rates on the grounds that their costs were imprudently incurred. Staff Fails to Acknowledge the Importance of Avista s Incorrect 4-Factor Allocator WHAT IS YOUR RESPONSE TO STAFF'S ADOPTION OF A VISTA'S COST OF SERVICE METHODOLOGY? Both Mr. Hessing and I testify that Avista s cost of service methodology generally follows that ordered in prior Commission orders. However, I point out that there is a significant change in Avista s newly proposed "factor" allocator for common costs. While I indicate that a 4- factor allocator is not objectionable on its face, the manner in which A vista witness Knox constructs this allocator is incorrect and unacceptable. My issue here is with Mr. Hessing s characterization of Avista s study as consistent with that used in its last general rate case "with minor modifications" (Hessing, page 4. lines 1-2). What I want to make clear, and demonstrate quantitatively, is that his characterization of "minor modifications" holds only if the newly proposed 4-factor method of allocating common (overhead) costs is corrected as I propose on pages 33- of my direct testimony. As I show below, the corrected 4-factor allocator I developed represents a less extreme departure from the previously adopted allocator. In the case of Potlatch's Lewiston Facility, the prior method and my corrected 4-factor allocator should and in fact do, produce similar cost allocations, both of which differ significantly from the A vista results. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 6 of 16 Case Nos. A VU-04-1 and A VU-04- 957 HOW DO YOU PROPOSE TO DEMONSTRATE THAT THE INCORRECT ALLOCATOR PROPOSED BY A VISTA IS NOT, AS MR. HESSING STATES, A MINOR MODIFICATION" Below I list three columns summarizing the rate schedule rates of return from 1) the 40% energy/60% customer" used and adopted in prior proceedings, 2) A vista s newly proposed but incorrect 4- factor allocator and 3) my corrected A vista s 4-actor allocator 1 : Class Schedule General Service Large General Service Schedule 25 Potlatch Lewiston Pumping Lighting AVERAGE 400/0/600 Method 1. 04 % 35% 26% 07% 61% 79% 52% 710 Potlatch Factor 84% 52% 16% 1.28% 60% 22% 4.15% 71 % Avista Factor 1.97% 70% 8.120/0 1.1 7% 24% 240/0 550/0 71 % PLEASE EXPLAIN THIS TABLE. My intent here is to show that Avista s incorrect 4-factor allocator is much more than a lninor lnodification." As I discussed in my direct testimony, Avista s results are skewed by its inappropriate inclusion of variable fuel and purchase power expenses in the definition of O&M. By including these energy costs in an allocator meant to allocate fixed common costs, A vista ilnproperly shifts costs to higher load factor customers. While the percentage shift is relatively small, the effect in absolute terms is not. Avista flawed cost of service change increases Potlatch Lewiston s cost of service by approximately $1 000 000 per year. A shift of this magnitude in common costs defies common sense. 1 The Potlatch-calculated returns differ from those in my direct testimony because, in order to make accurate comparisons, I do not here change the transmission allocator, as I recommend in my direct testimony. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 7 of Case Nos. A VU-04-1 and A VU-04- 958 Correcting A vista s mistaken inclusion of fuel and purchased power expenses, as I show in the column headed "Potlatch 4-Factor " produces final allocations that are less prejudicial to high load factor customers and more consistent with prior orders than Avista s approach. My rebuttal Exhibit 213 summarizes the derivation of the Potlatch 4- Factor lnethod. The other columns are developed fron1 A vista Exhibit 16, Schedules 2 and 3. HOW DO YOU RECOMMEND THAT THE COMMISSION RESOLVE THESE DISPARATE COST OF SERVICE RESULTS? I recommend that the Commission either stick with its previously adopted "40%/60%" n1ethod, or adopt the corrected 4- factor method that I propose. Staff's Proposed 200/0 Movement to Cost of Service is Inadequate WHAT IS THE ISSUE WITH RESPECT TO STAFF'S PROPOSAL TO MOVE EACH RATE SCHEDULE 20% TOWARD COST OF SERVICE? Both Staff witnesses Messrs. Hessing and Schunke proposed to lilnit the movement of each customer class s rates to 20% of the discrepancy with cost of service, with the remaining revenue requirement deficiency being made up by spreading the deficiency on the basis of an equal percentage to each rate class. My issue here is that the Staff proposal once again blunts any meaningful movement to cost of service, thereby continuing indefinitely the longstanding inter-class rate subsidies. The concurrent PCA reduction lnakes this an ideal time to finally make some progress toward rate parity. PLEASE EXPLAIN. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 8 of 16 Case Nos. A VU-04-1 and A VU-04- 959 Staff justifies its proposal to make minimal progress toward cost of service on the basis of avoiding rate shock. The unfortunate consequence of limiting rate increases of customer classes currently being subsidized is that it generates a corresponding rate shock to rate classes that are already paying well in excess of cost of service (Potlatch' Lewiston Facility). For example, staff proposes an overall average rate increase of 15.8%. As my chart on page 7 of this testimony points out, the residential class s rates currently generate roughly 20% to 400/0 of the average rate of return, no matter which cost of service n1ethod is adopted. Yet staff proposes to limit the increase to the residential class to 18.8%. On the other hand, Potlatch's current rates generate returns well in excess of the system average return, yet Staffs proposal results in a 14.9% rate increase for Potlatch. Stated another way, depending on the cost of service methodology chosen, Potlatch is generating a rate of return that is approximately 3 to 5 til11es that of the residential class , but the Staff proposes only a 3.9% difference in the percentage rate increase assigned to the two classes. I respectfully subn1it this result is neither just nor reasonable. HOW DOES STAFF'S RECOMMENDATION IN THIS CASE SQUARE WITH ITS RECOMMENDATIONS IN THE PAST? As I understand it, in the previous A vista general rate increase Staff proposed three cost of service options-to move rates one-third, one-half, or entirely to respective costs of service. The Commission instead selected 20% as the overall cap on the movement to cost of service. DID THAT INITIATIVE IN FACT RESULT IN A PARTIAL CORRECTION OF RELATIVE RATE OF RETURN DISPARITY? REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 9 of Case Nos. A VU-04-t and A VU-04- 960 Unfortunately, no. In fact the inter-class subsidy of the residential class has increased rather than decreased, since the last A vista rate case. Under these circumstances, the rate shock argument is wearing very thin. There has been no progress toward the elimination of this subsidy for roughly five years, and I suspect Staff's proposal , if adopted, will be revealed to produce little or no progress when the next Avista rate case rolls around. fully realize this is a tough issue for the Commission, but the indefinite continuation of a subsidy of this magnitude is simply intolerable. It is bad econOl11ics and bad policy and at best, it only postpones the day of reckoning when the residential class will ultimately have to pay its full cost of service, or something very close to it. At that point, the rate shock will be far worse than it would be in this case. ARE THERE CIRCUMSTANCES IN THE PRESENT CASE THAT WOULD SOFTEN THE RATE IMP ACT OF MOVING MORE BOLDLY TOWARD COST OF SERVICE? Yes, the proposed PCA reduction provides an offset to any rate increase the Commission ultil11atelyapproves. For example, if the Commission adopts the Staff's proposed 15.80/0 general rate increase, the net increase for the Idaho jurisdiction after the PCA adjustment is only 2.40/0. Under Staff's 20% proposal , the net increase in residential rates would be only 5.% in this scenario. There is clearly room to make a more meaningful move than this to equal class rates of return without causing rate shock. WHAT DO YOU RECOMMEND THAT THE COMMISSION ADOPT IN TERMS OF MOVEMENT TOWARD COST OF SERVICE? I recommend that the Commission do two things. First, it should order that customer class rates move 50% toward cost of service in this case. Second, the Commission REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 10 of16 Case Nos. A VU-04-1 and A VU-O4- 961 should express the intent that in subsequent cases, or within 2 years if no general rate case is filed, rates will be moved an additional 50% toward cost of service. Coeur Silver Valley s Direct Assignment of Primary Distribution Costs I NOTICE YOU DID NOT DISCUSS SCHEDULE 25, THE OTHER CUSTOMER CLASS THAT APPEARS TO BE HEA VIL Y SUBSIDIZED, IN THE PRECEEDING SECTION OF YOUR TESTIMONY. WHY IS THAT? After reading Mr. Anthony Yankel's direct testimony on behalf ofCoeur Silver Valley, I am convinced that all of the cost of service studies in this case, including my own significantly overstate Schedule 25' s cost of service. Mr. Yankel points out that it is possible and practical to directly identify all those A vista primary facilities necessary to serve all Schedule 25 custon1ers from the Company s accounting records. Since this is possible, Mr. Yankel argues that it is always more accurate to directly assign those facilities ' costs to Schedule 25 customers , rather than average these customer-specific costs into all other residential and smaller general service customers and then allocate them on a less accurate basis. WHAT IS YOUR POSITION WITH RESPECT TO THIS ISSUE? While I have not fully reviewed Mr. Yankel's analysis, I can state that his position that directly assigned costs are more accurate than those derived by a computed allocation is correct. The reason that directly assigned costs better reflect cost of service is rather straightforward. If I can directly identify those investments made specifically to serve a customer, I can clearly trace both the cause and the costs of those investments to that customer. Mr. Yankel has identified the direct costs of primary distribution facilities REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 11 of16 Case Nos. A VU-O4-I and A VU-04- 962 used to serve Schedule 25 customers and, as I understand it, proposes to directly assign these identifiable costs to the Schedule 25 class. I certainly agree in principle that this direct assignment is preferable to an indirect cost allocation. According to Mr. Yankel's calculations, this direct assignment of primary distribution facilities significantly reduces the purported subsidy of Schedule 25 customers. I have not attempted to verify his calculations. But as I have just noted, Mr. Y ankel' adjustment is correct in principle, and unless sonleone can demonstrate that it has been improperly implemented or calculated, his ultimate conclusion-that Schedule 25' s cost of service is overstated-is correct as well. Staff's Proposal to Change Basis for Computing PCA Rates DOES STAFF PROPOSE TO CHANGE THE BASIS UPON WHICH PCA RATES ARE COMPUTED? Yes, on pages 22-24 of his testimony, Mr. Hessing proposes that the Commission change from the current method of spreading PCA account balances to custolner class rates on an equal percentage" basis to a method of spreading balances on an equal cents per kwh basis. WHAT IS YOUR POSITION ON THIS ISSUE? I oppose the proposal on both theoretical and practical grounds. First, I have always argued that power supply costs are not 100% energy or kwh-based and should not therefore, be spread on an energy-only basis. There is both a fixed or capacity component and a seasonally-differentiated cost component to power supply costs that makes spreading balances on a flat, equal kwh basis inaccurate. Recovering power REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 12 of 16 Case Nos. A VU-04-1 and A VU-04- 963 supply adjustments on a per kwh basis is inconsistent with the way we establish base rates , and should be rejected as a matter of principle. WHAT IS YOUR PRACTICAL OBJECTION TO THE PROPOSAL? In theory, whether PCA changes are recovered through percentage changes or energy rate adjust1nents should be a matter of indifference to ratepayers. If base rates are properly set, a customer who pays more under an energy only recovery of a surcharge will also receive a proportionately larger benefit from any PCA "rebate." Over the long haul, each customer s total PCA exposure should be the same under either recovery n1ethod. But as a practical matter, high load factor customers such as Potlatch who compete in national or global markets are not really indifferent. Switching to a per kwh recovery method will make these customers' rates much more volatile , because the surcharges and rebates will both be greater than under the current system. In ShOli, their high rates will be higher and their low rates lower under Mr. Hessing s proposal. This is a concern for Potlatch and other industrial customers because it makes business planning and management more difficult. FulihelIDore, rate increases can cause disruptions and losses that cannot be recovered by corresponding decreases in subsequent years. To cite but one example, a PCA rate increase can potentially shut an industrial customer off from some markets or, in an extreme case, render production uneconolnic in all markets. Losses like these are not likely to be adequately compensated by benefits from PCA rebates in good years. ARE THERE ANY OTHER PRACTICAL PROBLEMS WITH STAFF'S PROPOSAL? Yes. On page 23, line7 to page 24, line 2 , Mr. Hessing carefully explains that, due to the fact that there are currently positive balances in the PCA accounts, and these accounts REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 13 of Case Nos. A VU-O4-1 and A VU-O4- 964 were collected on the present equal percentage basis, it would be very unfair to high load factor customers to now change and attempt to recover these balances on a new, energy only basis. He proposes that any change approved in the PCA methodology not be implemented until the present deferral balances are cleared. I simply want to underscore that this mixing of methods to accumulate and then to recover such balances is potentially highly prejudicial to high load factor customers unless it is implemented when balances are essentially zero. DO YOU HAVE A SECOND RECOMMENDATION REGARDING THIS ISSUE? Yes. If the Commission decides to make the change Mr. Hessing recolnlnends in the name of consistency, it should take the proposal to its logical conclusion. If the Commission really believes that power supply adjustments are incurred on a "per kwh" basis, the "cents per kwh" recovery should be "seasonalized" on a monthly or quarterly basis in a manner similar to avoided cost rates. Doing so would allow PCA rates, like other cost components, to track the actual changes in power costs as they vary over the year. It is an easy matter to calculate the actual monthly kwh rate that cause the PCA deferral balances to change, and from this information detennine the basis for adjusting the PCA rate seasonally. All the benefits of cost-causation and price signal considerations that apply to base customer rates would then apply to PCA rates. DOES THIS CONCLUDE YOUR TESTIMONY? Yes. REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 14 of 16 Case Nos. A VU-O4-1 and A VU-04- 965 (The following proceedings were had in open hearing. (Potlatch. Exhibit Nos. 202 through 213, having been premarked for identification, were admitted into evidence. MR . WARD:And wi th that, Dr. Peseau is available for cross-examination. COMMISSIONER KJELLANDER:Thank you.Let's move now to Avista and Mr. Meyer. MR . MEYER:Thank you, and good mornlng.Gi ven our rebuttal testimony and the testimony that you received yesterday from wi tnesses Lafferty and Dr. Avera for the Company, we do not have cross of this wi tness. COMMISSIONER KJELLANDER:Thank you. Then , Mr. Woodbury. MR. WOODBURY:Thank you, Mr. Cha i rman . CROS S - EXAMINA T I ON BY MR. WOODBURY: Mr. Peseau, just a couple of questions for clarification. In your direct test imony, pages 29 through 33, you address test year mismatch and state that adjustment needed to correct mismatched revenues and expenses.In reading 966 HEDRI CK COURT REPORTING O. BOX 578, BOISE , ID 83701 PESEAU (X)Potlatch through that testimony, it appears that it's mostly focused at electric.Should your testimony be viewed as applying to both gas and electric, or is the Company's focus primarily electric - - Potlatch's focus? Potlatch is not a retail gas customer of Avista so the comments here, therefore, are - - do pertain to the electric mismatch.But, I mean , I've testified in this jurisdiction and others before that - - in general - - so I wouldn't exclude the gas.I think it's always a good idea to - - for both the shareholders and for customers to provide a match between expenses and revenue, so -- But you didn't work through the gas case in preparing your testimony, did you? Tha t 's correct. On page 15 of your direct testimony, you arrl at a number that you quote from Avista' s rebuttal testimony in the surrogate avoided resource case before the Commission , and that is $604 per kilowatt as a capital cost? Yes.That appears on line 6 of page 15. Yes.And then you've - - and you follow up in the middle of the page and say:Using that figure produces a fair market value for CS2 of $84 560 for Avista' s share of CS2. And that was simply $604 times 140 megawatts? Yes. And do you know whether the $604 figure was 967 HEDRI CK COURT REPORTING O. BOX 578, BOISE , ID 83701 PESEAU (X) Potlatch adopted by the Commission in the SAR case? No, the $604 was testified by Avista witnesses as their avoided capi tal cost.The Commission adopted a generic number based on several different numbers in the record. The Commission's number they adopted was a Northwest Power Planning Council Generating Resource Advisory Committee number.Is that correct? That was correct. And that was a 2000 chose $679 per kilowatt whi ch was $624 plus $55 adder for number , which I think they AFUDC , and that was in Order No.2 9124 . If you were to recognize that the - - that number was a year 2000 number and escalate it forward two years using the tilting rate or the capital escalation rate adopted by the Commission , would you accept that the number that falls out is $99,094 , OOO? What cost per kW? Taking 679 , which was ln the Commission's Order uslng a 2.10 percent escalation of two years forward.Do you have a calculator? No, I don'I was just trying to get the per-uni t cost.I accept, subj ect to check , the $ 9 9 mi 11 ion figure. All right.Thank you. MR . WOODBURY:Mr. Chairman , Staff has no further 968 HEDRI CK COURT REPORTINGP. O. BOX 578, BOISE, ID 83701 PESEAU (X)Potlatch questions. COMMISSIONER KJELLANDER:Thank you, MR . PURDY:I have none, thank you. HEDRICK COURT REPORTING P. O. BOX 578 , BOISE , ID 83701 Mr. Woodbury. Mr. Cox. MR . COX:I have none as well.Thank you. Are there questions COMMISSIONER SMITH:I don't think so. No questions, so we' Thank you. Thank you , Dr. Peseau. (The wi tness left the stand. Mr. Ward , if you'd like MR . WARD:Call John Thornton to the stand. produced as a witness at the instance of Potlatch, being first duly sworn , was examined and testified as follows: Mr. Purdy. COMMISSIONER KJELLANDER: COMMISSIONER KJELLANDER: from members of the Commission? COMMISSIONER KJELLANDER: ready for any redirect. MR. WARD:No redirect. COMMISSIONER KJELLANDER: COMMI S S IONER KJELLANDER: to call your next wi tness? JOHN S. THORNTON, 969 THORNTON (Di)Potlatch DIRECT EXAMINATION BY MR. WARD: Mr. Thornton, would you please state your name and address for the record? Yes.My name is John Stewart Thornton, Jr. business address is 7929 East Joshua Tree Lane, Scottsdale, Arizona, 85250-7967. For whom are you appearlng today? I m appearing today on behalf of the Potlatch Corporation. In preparation for this proceeding, did you prepare prefiled direct testimony? Yes, I did. And do you have any correct ions or addi t ions to that testimony? , I do not. Did you also, in preparation for today' s proceedings, prepare Exhibi t No.2 0 1 ? Yes , I did. And is that exhibit true and correct , to the best of your knowledge? Yes , it is. Now , returning to your direct testimony, if I ask you the questions contained therein today, would your answers 970 HEDRICK COURT REPORTING P. O. BOX 578 , BOISE , ID 83701 THORNTON (Di)Potlatch be as given? Yes, they would. Thank you. MR . WARD:With that , Mr. Chairman , I ask for the Exhibit No. 201 be identified , and for Mr. Thornton's direct testimony to be spread on the record as if read. COMMISSIONER KJELLANDER:Thank you, Mr. Ward. Without objection , we'll spread the testimony across the record as if read , and admit Exhibit 201. (The following prefiled direct testimony of Mr. Thornton is spread upon the record. 971 HEDRICK COURT REPORTINGP. O. BOX 578, BOISE, ID 83701 THORNTON (Di)Potlatch ... Witness Identification PLEASE STATE YOUR NAl\'IE AND BUSINESS ADDRESS. My name is John S. Thornton, Jr. and my business address is 7929 East Joshua Tree Lane, Scottsdale AZ 85250. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? I am an independent consultant in utility finance. I appear as a witness on behalf of Potlatch Corporation. PLEASE DESCRmE YOUR EDUCATIONAL BACKGROUND AND EXPERIEN CE. I hold a Master of Science degree from the University of London, having completed the Master s program (economics with specialty in corporate finance) at The London School of Economics and Political Science (The LSE). I also hold a Graduate Diploma from The LSE. I have participated as a cost of capital expert in numerous electric utility, local gas distribution, and telephone cases in the states of Oregon, Washington, California, Nevada, and Arizona, and I participated in gas pipeline cases before the Federal Energy Regulatory Commission. I was a Senior Economist for the Public Utility Commission of Oregon and its chief rate- of-return witness. I recently left my position as the Chief of the Financial and Regulatory Analysis Section of the Arizona Corporation Commission s Utility Division to consult independently. My background is described further in my Witness Qualifications Statement found on pages 48-50 of Exhibit JST- Scope of Testimony WHAT WAS YOUR ASSIGNMENT IN THIS CASE? DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4- 972 .., My assignment was to estimate a fair return on equity (ROE) and rate of return (ROR) for Avista Corporation s electric and gas utility operations in this proceeding. I also reviewed A vista Corporation s testimony on the rate of return prepared by Malyn Malquist and cost of equity testimony prepared by Dr. William Avera. Summary Recommendation PLEASE SUMMARIZE YOUR FINDINGS ON AVISTA CORP.S COST OF EQUITY AND RATE OF RETURN. I estimate Avista Corp.s cost of equity to be 8.5 percent. I recommend an 8. percent rate ofretum, calculated on page 1 of Exhibit JST-l. I also offer ROR calculations incorporating the high and low end of my cost of equity estilnates. WHAT DID YOU FIND IN YOUR REVIEW OF THE COMPANY'S COST OF EQUITY ANALYSES? I found that Mr. Malquist recommends an 11.5 percent return on equity. provides no cost of equity analysis or reasoning behind his recommendation other than a belief that "the 11.5% provides a reasonable balance of the competing objectives of regaining financial health within a reasonable period of time, and the impacts that increased rates have on our customers.(See Direct Testimony of Malyn Malquist, page 22 at 3 to 6.) He also believes that a return on equity greater than 11.5 percent is supported and warranted. SHOULD THE COMl\flSSION ADOPT AN 11.5 PERCENT ROE BASED ON MR. MALQUIST'S BELIEFS? DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-O4- 973 .... 1 .A , the CoIn111ission should not adopt an 11.5 percent ROE based on Mr. Malquist's beliefs, which are absent of any financial or econolnic analysis on his part. Mr. Malquist's testimony is also inconsistent with A vista s actions. A vista recently increased its dividend, thereby draining cash from the utility, and Avista fully intends to increase its dividend further. I would recommend that Avista retain that cash, build its equity position or payoff debt and thereby improve its financial health. In Avista s May 25 2004, Webcast conference, I understood Mr. Malquist to say that A vista would have been increasing dividends even further if it were not for a restrictive bond covenant that limited dividend increases. In other words, A vista is not sufficiently col1unitted to building its OvVl1 financial house internally. A vista prefers to improve its financial health through higher rates at the expense of ratepayers. WHAT IS THE PURPOSE OF DR. AVERA'S TESTIMONY? 1"\..Dr. Avera s purpose is to present his evaluation of Avista s current cost of equity for Avista s jurisdictional electric operations. (See Direct Testimony of Dr. William Avera, page 3 at 7 to 9.) He concludes that Avista s cost of equity significantly exceeds 11.5 percent. WHAT DID YOU FIND IN YOUR REVIEW OF DR. AVERA' ANALYSIS? I found that his results are upwardly biased and should not be used to set the ROE in this case. DIRECT TESTIMONY OF JOHN S. THORNTON - 3 IPUC Cas~ Nos. AVU-04-1 and AVU-G-O4- 974 Capital Structure WHAT IS AVISTA CORPORATION'S RECOMMENDED CAPITAL STRUCTURE ? Avista Corporation s recommended capital structure is found in the Prefiled Direct Testimony ofMalyn K. Malquist. He recommends the following September 30 2004, pro fonna capital structure: Avista Corporation Filed Capital Structure Debt 48.19% Trust Preferred Securities 79% Preferred Equity 72% Common Equity 44.30% DO YOU RECOMMEND ANY CHANGES TO MR. MAL YN'S PRO FORMA CAPITAL STRUCTURE? No. Fair and Reasonable Return on Equity HOW DO YOU DEFINE THE TERM "COST OF EQUITY?" A firm s cost of equity is that rate ofretum on equity that investors expect to earn on their equity investment given the risk of the firm. Investors' expected return is equally derIDed as the return on equity that they expect on other investments of similar risk. 1 My testimony on A vista Corporation s cost of equity starts with a More precisely, the marginal investor determines the firm's cost of capital. The marginal investor will bid theprice of t.1,.e securi~j up to a point that the investor expects to eaJ.ll the cost of capital and no less. Then, the securityis in equilibrium. The definition of expected return based on returns on investments of similar risk (the comparable earnings" standard) also assumes that the alternate security is in equilibrium and the investor does not expect to earn excess profits on that alternate security. For example, assume securities A and B are of similar riskand have a 10 percent cost of equity. Now assume that security B developed an invention such that it will realize a DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-O4-1 975 historical perspective on interest rates and stock returns and then it focuses on the cost of equity to the electric utility industry. A Historical Perspective on Interest Rates FIRST, PLEASE PUT CAPITAL COSTS IN PERSPECTIVE. WHAT HAS BEEN THE TREND OF INTEREST RATES OVER THE PAST TEN YEARS OR SO? Interest rates have declined significantly over the past ten years and breached the record lows seen in 1993. The chart below gTaphs intermediate-tenn2 U. US Treasury Rates (%) , 7- and 10-Year Constant Maturity Rates, April 1994 through April 2004 Source: Board of Governors of the Federal Reserve System Apr-Apr-Apr-Apr-Apr-Apr-Apr-Apr-Apr-Apr-Apr- 20 percent return to current investors forever. However, 20 percent is not security B's cost of equity; nor is itsecurity A's. The marginal investor will bid up the price of security Bls stock (the price will double) until themarginal investor only expects to earn the 10 percent cost of equity in equilibrium on security B. The 10 percentequilibrium rate of return is security Bl , and security A', required rate of return. S. Treasury constant-maturity five-, seven-, and ten-year rates published by the Board of Governors of the Federal Reserve System. DIRECT TESTIMONY OF JOHN S. THORNTON - 5 IPUC Case Nos. A VU-O4-1 and A VU-G-O4- 976 Treasury rates froln April 1994 through April 2004: WHERE ARE INTEREST RATES NOW WITH RESPECT TO mSTORICAL RATES? Interest rates are currently low compared to historical rates. The graph below shows ten-year U.S. Treasury constant maturity security yields from April 1953 (the beginning of the data series) through April 2004. You can visually see in the graph that interest rates are near lows over that span of history. 10-Year us Treasury Constant Maturity Rates (%) April 1953 to April 2004 Source: Board of Governors of the Federal Reserve System 16. 14. 12. 10. .2.~ ~ ~ m ~ ~ ~ ~ m ~ M ~ ~ m ~ M ~ ~ m ~ M ~ ~ m ~ M~ ~ ~ ~ m m ~ m m ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ m m m m ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ About seventy percent often-year-maturity U.S. Treasury constant-maturity rates throughout this historical time period exceed the current 4.73 percent ten-year rate. DIRECT TESTIMONY OF JOHN S. THORNTON - 6 IPUC Case Nos. A VU-04-1 and A VU-G-O4- 977 .., ::J The Federal Reserve reported that on May 4 2004, the Federal Open Market Committee voted to keep its target federal funds rate at 1 percent, a 46-year low. (See h!1p://www.stlouisfed.org/) Interest rates and capital costs are low by historical standards. A Historical Perspective on Stock Returns WHAT HAVE BEEN mSTORICAL NOMINAL RETURNS FOR AVERAGE-RISK SECURITIES? The following table reproduces average (arithmetic and geometric) nominal returns for a range of domestic and international stock price indicator series (1972 to 1995): Annual Percentage Rates of Return for Stock Price Indicator Series: 1972-1995 Stock Index Series Arithmetic Average Geometric Average Dow Jones Industrial Average 91%58% S&P 500 07%79% Al\AEX Value Index 12.81% NASDAQ Composite 12.79%10.67% Wilshire 5000 58%16% Toronto SE 300 Composite 11.97%10.680/0 Financial Times All-Share 14.24%94% FAZ 61%02%' Nikkei 11.54%76% Tokyo SE Index 11. 78%78% Morgan Stanley WorId 61%8.28% Average 10.94%77% Source: Frank 1. Reilly, Investment Analysis and Portfolio Management, fifth edition, p. 172. One should keep in mind that these series measure actual returns, not expected returns. However, any request for an allowed ROE above 11.0 percent DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-04-1 and AVU-G-O4-1 978 ""I ::J .L ""t exceeds the geometric mean return for all of these indices of average-risk securities ' returns. The average electric utility in my sample is significantly less risky than the average security, as I will later discuss in my capital asset pricing Inodel analysis. PLEASE EXPLAIN THE D IFFEREN CE BE TWEEN AN ARITHME TIC AND A GEOMETRIC AVERAGE RATE OF RETURN. Let me answer you through an example. Let us say that you invested $100 in a stock. The fIrst year you made 100 percent return on your money (your stock' value has risen to $200), but the second year you lost 50 percent of your money (alas, your stock's value has fallen back to $100). arithmetic average is the simple average of 100 percent and -50 percent, or 25 percent ((100% + -50%)/2). The geometric average is a bit more complicated. In this example, you add the number one to each of the annual returns to form two "value relatives " multiply the value relatives together, take the square root, and th~n subtract the number one: Geometric average (l + 100%)(1 + (-50%))- =0% Notice in this case the arithmetic average rate of return is spurious. If you invested $100, made 100 percent the next year but then lost 50 percent in the following year, then you would end up with $100, exactly where you started. The geometric average correctly indicates that your average rate of return over two years is zero percent. The arithmetic average rate of return would have you believe that, on average, you made 25 percent return per year. The geometric average rate of return is used to express average rates of return over time. DIRECT TESTIMONY OF JOHN S. THORNTON - 8 IPUC Case Nos. AVU-E-O4-1 and AVU-G-04-1 979 1 '"t WHAT HAS BEEN THE LONG-TERM AVERAGE NOMINAL RETURN TO THE AVERAGE-RISK STOCK SINCE 1926? The geometric average return for stocks from 1926 through 2003 was about 0. percent per Inonth, or about 10 percent cOlnpounded per year. WHAT HAVE mSTORICAL REAL RETURNS BEEN FOR A VERAGE- RISK SECURITIES? Wharton School finance professor Jeremy 1. Siegel, author of the book Stocks For The Long Run found that the average real return on U.S. equities has been 6. percent using 200 years of data from 1802 through 2001.3 I include pages 11 to 24 of his book on pages 2-12 of Exhibit JST-l because they discuss a number of issues pertinent to this case, including U.S. stock return history, international equity returns, and the equity premium. The 6.9 percent real return on stocks has been remarkably stable over time. Dr. Siegel writes on pages 12 and 13 of his 1___UUUK. The real return on equities has averaged 6.9 percent per year over the past 200 years. . . . Note the extraordinary stability of the real return on stocks over all major subperiods: 7.0 percent per year from 1802-1870 6 percent from 1871 through 1925, and 6.9 percent per year since 1926. Even since World War II, during which all the inflation that the United States has experienced over the past 200 years occurred, the average real rate ofretum on stocks has been 7.1 percent per year. This is virtually identical to the preceding 125 years, which saw no overall inflation. This remarkable stability of long-term real returns is a characteristic of mean reversion a property of a variable to offset its short-term fluctuations so as to produce far Inore stable long-term returns. " Jeremy 1. Siegel Stocksfor the Long Run third edition, McGraw-Hill, 2002, p. 13. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-O4- 980 The current expected rate of inflation over the next ten years is approximately 2.7 percent based on U.S. Treasury yield data leading one to ...,.:) conclude that the average-risk security is expected to yield a nominal 9.6 percent rate of return. HAVE OTHER MAJOR INTERNATIONAL MARKETS HAD REAL RETURNS GREATER THAN THE HISTORICAL RETURNS IN THE U. EQUITIES MARKETS INDICATING A IDGHER MARKET RETURN IF ONE WERE TO INCLUDE INTERNATIONAL EQUlTJES? , in fact just the opposite seems to be the case. Dr. Siegel calculated the following compound annual real equity returns for Ge allY, the Upited Kingdom, and Japan: Compound Annual Real Equity Returns (1926-2001) Germany Japan 000/0 6.44%01 %93~1o Therefore, these international equities' real returns did not exceed the 7. percent real return on U.S. equities over the 1926-2001 period and including them would not result in a higher assessment of equities' real expected returns. Similar conclusions to Dr. Siegel's were reached by Elroy Dimson , Paul Marsh and Mike Staunton in their book Triumph of the Optimists, 101 Years of Global Investment Returns. They found that for the 10 I-year period 1900 to 2000 4 Estimated as the link relative difference between la-year U.S. Treasury yield (4.73%) and a ten-year inflation-indexed Treasury security (2.0%) quoted in the May 26, 2004, of The Wall Street Journal.s Jeremy J. Siegel Stocks for the Long Run third edition, McGraw-Hill, 2002, p. 19. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-04- 981 S. equities returned 10.percent per annum in nominal tenns and 6.7 percent in real tenns. Electric Utility Risk and Its Relationship to an Average-Risk Security ARE ELECTRIC UTILITY COMPANIES MORE RISKY OR LESS RISKY THAN THE AVERAGE-RISK SECURITY? Electric utility companies are significantly less risky than the average-risk security. I provide quantitative evidence to support my assertion in the capital asset pricing model section of my testimony: the average risk security has a capital asset pricing model beta of 1., while the average electric utility from my sample has a Value Line beta of ., which is 28 percent less risky than the average-risk security. WHAT DOES THE EVIDENCE THAT AN ELECTRIC UTILITY IS SIGNIFICA-NTL Y LESS RISKY THAN THE AVERAGE-RISK SECURITY IMPLY ABOUT EXPECTED RETURNS ON ELECTRIC UTILITY EQUITY INVESTMENTS? The fact that an electric utility is less risky than the average-risk security implies that an electric utility's cost of equity and returns are expected to be significantly lower than the average-risk security. 6 Elroy Dimson, Paul Marsh and Mike Staunton, Triumph afthe Optimists. 101 Years a/Global Investment Returns Princeton University Press (2002) pages46 and 47. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-04- 982 p.~. Cost of Equity to the Electric Utility Industry WHAT METHODS DID YOU USE TO ESTIMATE THE COST OF EQUITY CAPITAL TO AN AVERAGE ELECTRIC UTILITY AND VISTA CORPORATION? I used the discounted cash flow (DCF) model and the capital asset pricing Inodel (CAPM). These two models are widely used for estimating the required return on equity. I applied my DCF and CAPM analyses to a sample of electric utility companies. I used a sample in order to limit estilnation error that might be involved with applying the models to Avista exclusively. Sample Selection WHAT SA:MPLE OF COMPANIES DID YOU USE AND HOW DID YOU SELECT THEM? I selected thirty-two electric utilities amongst all the electric utilities covered by The Value Line Investment Survey (Value Line). I eliminated colnpanies for whom Value Line did not report comparable data through at least 1998 or had skipped a dividend or had negative earnings since 1998, companies for whom Value Line did not forecast dividends, and companies that did not appear to be primarily domestic integrated electric utility companies. DCF Model Analysis PLEASE DESCRIBE THE DISCOUNTED CASH FLOW MODEL. DIRECT TESTIMONY OF JOHN S. THORNTON - 12IPUC Case Nos. AVU-O4-1 and AVU-G-04-1 983 '"I ... The DCF model7 is based upon the premise that a company s stock price is equal to the present value of all future dividends expected to be received by a share of stock. The expected dividends are discounted by the company s cost of common equity. Mathematically, the DCF model for the cost of equity is represented by the following equation: (1)Dl D2 D3 (1 + k) + (1 + k) 2 + (1 + k) 3 +... (1 + k) n Equation (1) is quite simple and says that the current price of a stock (Po) is equal to the sum of expected future dividends (D1 through sc.ounted into present value terms at the company s cost of equity (k). Dl is the dividend expected one year hence, D2 is the dividend expected two years hence, etc. Dividends can be related to each other by growth rates. For example, D2 is equal to Dl times a growth factor is equai to 2 times a growth factor, D4 is equal to D3 times a growth factor, etc. In this way, each dividend can be related to the dividend before it through a growth factor. If we already know a stock's price and can estimate forecasted dividends (or dividend growth rates) then we can use equation (1) to give us the cost of equity, k, through a calculation called an "internal rate of 7 A full derivation is included in the appendix to this testimony. The DCF model was first fonnalized in John Burr Williams book The Theory of Investment Value (Cambridge: Harvard University Press, 1938). The concept of discounting dividends to value a stock dates back to at least 1930 and Robert F. Wieses article "Investment for True Values.Barrons September 8, 1930 p. 5. The DCF model was resurrected by Myron Gordon and E. Shapiro who used it to solve for the cost of equity in their article , " Capital Equipment Analysis: Required Rate of Profit Management Science 1 02 (October 1956). Myron Gordon expanded the DCF model in the early 1960', employing the model mainly as a method for estimating the cost of capital. He later published his work in The Cost of Capital to a Public Utility (Michigan: MSU Public Utilities Studies, 1974). Myron Gordon is considered the father of modem DCF analysis. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-O4- 984 1 ;I.Lo return" calculation. That calculation essentially finds the cost of equity that equates the present value of dividends to the current stock price. HOW DID YOU APPLY THE DCF MODEL? I applied the DCF model using the lTIulti-stage growth model. The multi-stage growth model is generally superior to the constant-growth DCF model because it allows for flexibility in dividend growth rates. This flexibility is impossible in the constant-growth model. The extra computing cost associated with implementing the multi-stage model is minimal compared to the lTIodel' s benefits. The multi- stage model cannot be inferior to the constant-growth DCF model; therefore one should use the multi-stage model if possible. I applied the model to each of the thirty-two companies in the sample and I averaged the costs of equity derived from each of the companies. My lTIulti-stage growth model included Value Line dividends expected over the next twelve months (the rust stage), Value Line dividend forecasts and their implied dividend growth rates for 2004 to 2007-2009 (the near-term stage) and a series of forecasted dividends growing at a long-term growth rate (the long-term stage). The first input, however, is the current stock pnce. WHAT DID YOU USE FOR THE CURRENT STOCK PRICE, Po I used closing stock prices for the current stock price, Po, from the May 26, 2004 issue of The Wall Street Journal for May 25 2004, prices. The most current spot prices are the correct prices to use for Po because current spot prices include all current and past information. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-04- 985 The First Stage WHAT DID YOU USE FOR THE FORECAST DIVIDEND, Dh FOR THE FIRST STAGE? I obtained forecasts ofDl (the expected dividend per share over the next twelve months) directly from the May 21 2004 , " Summary and Index" to Value Line (Est'd Div d next 12 mos). This gave me a direct forecast ofDI, or dividends expected over the twelve months. My sample s average dividend yield is 4. percent, shown on page 13 of Exhibit JST- The Second Stage WHAT DID YOU USE FOR THE FORECAST DIVIDENDS FOR THE SECOND OR NEAR-TERM STAGE? I grew the expected dividend per share over the next twelve months (Dl) by Value Line implied dividend gTowth rates for the period 2004 to 2007-2009 for three years. The multi-stage model allows one to use Value Line (interpolated) dividend forecasts for each company to be included in the DCF and it is a superior method to using a constant growth rate across all colnpanies because one is using data more efficiently. The Third Stage WHAT DID YOU USE FOR THE FORECAST DIVIDENDS FOR THE THIRD OR FINAL STAGE OF GROWTH? I took the last dividend for each sample company in my near-term stage and gTew that dividend at a long-term rate. My estimate of dividend growth in the long- term stage is 3 percent to 5 percent. I estiInated the long-term dividend growth DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4-1 986 1'+ component after reviewing a large amount of historical and forecast electric utility industry and macroeconomic data that can be helpful in estimating long-term dividend growth, and based on my previous experience in estiInating dividend growth for electric utilities. My sample s average dividend actually declined between 1998 and 2003. Earnings and book value have both grown, on average 1.9 and 3.6 percent, respectively. Value Line estimated "'00-02/'01-03 to '07- 09" annual rate of dividend growth for my sample of companies averages 1. percent. The same estimates for earnings and book value growth are 3.3 and 4. percent, respectively. Sample br, or intrinsic growth, has averaged 3.4 percent for the period 1998 through 2003. WHAT BROAD MACROECONOMIC DATA MIGHT YOU USE TO GAUGE INVESTORS' EXPECTATIONS OF DIVIDEND GROWTH? One might use economic growth and share growth. Dividends per share is a ratio of total dividend payments divided by total shares outstanding. Therefore dividend per share growth might be modeled by estimating the expected growth in total dividends (in the nwnerator) minus the expected growth in shares outstanding (in the denominator). To model total dividend payment growth, one might use national econolnic growth because electric utility dividends cannot exceed electric industry earnings over the long term and electric utility earnings cannot exceed national domestic economic growth in the long tenn. Real U. gross domestic product (GDP) growth has been 3.26 percent per year from January 1953 through January 20048 and current inflation is expected to be 2. percent based on IllY earlier calculation, resulting in nominal growth of 6. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4- 987 percent (3.26% + 2.7%). My sample s outstanding shares grew 2.8 percent between 1998 and 2003 and are expected to grow .92 percent from 2003 through 2007-2009. Therefore, subtracting per share growth frOlTI nominal GDP growth results in a "dividend"per-share growth rate range of3.2 percent (6.0% - 2.8%) to 5.1 percent (6.0% - .92%). WHAT BROAD l\tIACROECONOMIC DATA SPECIFIC TO DIVIDENDS MIGHT YOU USE TO GAUGE INVESTORS' EXPECTATIONS OF DIVIDEND GROWTH? Jeremy Siegel, in his book Stocks For The Long Run (third edition, page 94) reports that real annual per share dividend grovvth has been 1.09 percent for the period 1871 through 2001 in the following table: Period Real GDP Real Per-Share Real Per-Share Growth Earnin2s Growth Dividend Growth 1871-2001 91%25%09% 1871-1945 51%66%74% 1946-2001 11%05%56% Adding an expected inflation rate of2.7 percent to a real 1.09 percent real dividend growth rate results in about 3.8 percent expected dividend growth (1.09% + 2.7%). Relying on the post-war 1.56 percent real per share dividend growth rate results in about 4.3 percent annual growth (1.56% + 2.70/0). These data suggest about a 4 percent dividend per share growth rate. WHAT IS THE MARKET-TO-BOOK RATIO FOR YOUR SAMPLE OF COMPANIES AND WHAT DOES IT IMPLY? 8 Source: U.S. Department of Commerce: Bureau of Economic Analysis. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-04-1 and AVU-G-04- 988 1'+ The market-to-book ratio for my sample of colnpanies is 1.62. Amarket-to-book ratio greater than 1.0 indicates that my salnple of utilities is expected to earn accounting ROEs significantly greater than the utilities' costs of equity. I prove this relationship in the appendix. Over earnings can result trom many factors including commissions authorizing ROEs in excess of the costs of equity. The observation that the electric utilities are expected to over earn casts doubt on using expected earnings or earnings growth to estimate long-term dividend per share growth. Therefore, earnings forecasts should not be used as a proxy for the cost of equity because they over estimate the cost of equity. The market-to-book ratio for A vista is 1., indicating that is expected to earn accounting returns close to its cost of equity. Value Line forecasts Avista accounting return on equity to be 8 percent in the 2007-2009 time fraIne. WHAT ARE YOUR AVERAGE COST OF EQmTY ESTIMATES FOR Ou'R SAIvll'ANIES USING THE MULTI-STAGE DCF MODEL AND YOUR RANGE OF LONG- TERM DIVIDEND GROWTH RATES? My estimates are sU111illarized in the table below: Multi-Stage DCF Estimates 3% long-term stage growth rate 7.5% 4% long-term stage growth rate 8.4% 5% long-term stage growth Average:8.4% I include the summary tables supporting my multi-stage DCF estimates on pages 14-16 of Exhibit JST- DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-04- 989 1 f\ Capital i\sset Pricing Model Analysis PLEASE DESCRIBE THE CAPITAL ASSET PRICING MODEL (CAPM). The CAPM is the result of the work of Nobel Prize winning financial economists Harry Markowitz and WillialTI Sharpe. The CAPM assmnes that investors like investment returns but dislike the risk or volatility associated with those returns. The result is that investors require a greater return for beari ng greater risk. The CAPM is based upon modem portfolio theory; the theory that assumes investors purchase assets in portfolios, and in doing so reduce the total variation of their returns. The total variation of a portfolio is less than the smn of its parts because in a diversified portfolio of dsk-y assets some returns are high while others are low, offsetting each other. For example, stock A (a suntan lotion company) and stock B (an umbrella company) are both expected to earn 10 percent and have equivalent risk. However, it seems that returns on the two stocks move in exactly opposite directions. When it is sunny, stock A makes 15 percent but stock B makes 5 percent. When it is rainy, stock B makes 15 percent but stock A makes 5 percent. Combining the two ~tocks in a portfolio allows all risk to be diversified away, even though each of the colnpanies' returns is still quite uniquely risky independently.lO The unique risk that can be diversified away becomes iITelevant and investors do not require a return on this diversifiable risk. Diversification 9 A more complete list of assumptions would include the following: (1) single holding period; (2) no restrictions on short selling or borrowing; (3) perfect and competitive securities market with no transactions costs; (4) the existence of a risk-free rate fixed over the holding period; (5) homogeneous expectations; (6) investors evaluate securities in terms of expectation and variance of future wealth; and, (7) investors are risk averse. Some assumptions can be relaxed and the basic result of the CAPM still holds. For example, the existence of significant transaction costs leads to parallel secu..rit'j market lines to the theoretical securit-j market line, but beta still remainsthe index of risk. DIRECT TESTIMONY OF JOHN S. THORNTON - 19 IPUC Case Nos. A VU-04-1 and A VU-G-O4-1 990 ..,""- allows investors to reduce their level of risk exposure for any given level of expected return. The risk that is left is called systematic risk. Systematic risk measures the extent to which a security's returns are correlated with returns in the general market of risky assets. In other words, the insight of the CAPM is that a firm s risk is not simply measured by the variability (standard deviation) of its own returns, but the extent to which its returns are related to market portfolio returns. The CAPM 11 is summarized in the following fonnula (2)t (E R f, WH ;\THESE V j\~1U;\....BLES PJ:PP~SENT? Et-l(Ri t) is the investors' expected return on security i over the investment horizon t and it is conceptually equivalent to the k term in the DCF model. 12 This tenD represents the cost of equity to A vista Corporation that we are attempting to estimate. Rt:t is the return on the risk-free asset during time period t. A default-free U. S. Treasury security is generally used as the proxy for the risk-free asset. J3i t is an index of security its systematic risk, called beta, expected over the investment horizon t. Et-l(RM,d - Rft is the expected market risk premium. The market risk premium entices investors to invest in the market portfolio of risky securities 10 More precisely, assuming that the variance of returns of companies A and B are the same, the portfolio of them together has the variance: cr (A) + cr (B) + 2p(A B)cr(A)cr(B). If p(A B) = -1 (the securities' returns are perfectly negatively correlated), and cr(A) = cr(B),then the portfolio variance equals O.11 Tne CAPMs derivation can be found in many finance textbooks, including Ross and Westerfiled's book Corporate Finance (St. Louis: Time Mirror/NIosby College Publishing, 1988). DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-O4-1 and AVU-G-04- 991 instead of the lower-yielding risk-free asset. The premium for investing in the market portfolio of risky assets is called the Inarket risk premium. WHAT DOES THE CAPM FORMULA SAY? The CAPM fonnula, equation (2), is intuitive and simple. The fonnula says that investors expect a yield on a company s risky security to equal the risk-free rate plus a risk premium. That colnpany-specific premium is determined by multiplying beta, the measure of risk, by the overall market risk premium. WHAT DOES BETA MEASURE? Beta measures the systelnatic risk of a company and it can be thought of as an index of relative ris ness. Syste atic risk is the ovly form of risk that is relevant to estimating a company s cost of equity because all other risk can be eliminated through diversification (that is, buying a stock along with a portfolio of other stocks) as I discussed earlier. Systematic risk can be thought of more concretely as an index reporting the extent to which a securityis returns are correlated with overall market returns (and the general economy). The average-risk security has a beta of 1.0 by definition and its returns are perfectly correlated with the market' returns. A Inore risky security has a beta greater than 1., and a less risky security has a beta less than 1.0. Public utilities generally have betas below 1.0 and are considered much less risky than the average finn. WHAT INFORMATION IS NEEDED TO APPLY THE CAPM? We need estimates of the following over an assumed investment horizon of " years: 12 The two methods can produce different results, in principle, as articulated by M.l Gordon and L.I. Gould in their article "Comparison of the DCF and HPR Measures of the Yield on Common Shares Financial Management (Winter 1984). DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-O4- 992 1 ().L V The risk-free rate (Rr); Beta (J3D; and The market risk premium (E(RmJ - Rr). HOW DID YOU APPLY THE CAPM FORMULA? I applied the CAPM formula by first assuming that investors have an intermediate-term investment horizon, which I defined as between five and ten years long. An investment horizon is a period over which investors expect to hold securities when they first purchase those securities. The investment horizon is more formally called a holding period in financial economics. 1"\WHY DO YOU NEED TO MAYJ: M.r EXPLICIT ASSU:MPTIOl"~ ABOUT INVESTORS' HOLDING PERIODS WHEN APPLYING THE CAPM? The CAPM is known as a holding period model. One makes estimates of the risk-free rate, beta, and the market risk premium over some particular holding period to estimate the cost of equity during that period. The holding period length corresponds to the subscript "t" in equation (2). WHY DID YOU CHOOSE AN INTERMEDIATE-TERM HOLDING PERIOD? I chose an intermediate-term holding period in conjunction with using intermediate-term U.S. Treasury securities (Treasuries) and based on my assumption that investors' expected investment horizons are intermediate in length. Intermediate-term Treasury yields are the most appropriate yields to use for rate making because short-term Treasuries (T -bills) can be too volatile for the rate-making process, though academic CAPM studies use short-term Treasuries. Long-tenn Treasuries (T -bonds) contain a "price risk" prelnium that should be DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-04-1 and AVU-G-O4- 993 estimated and extracted before use in the CAPM.13 I have never seen long-term Treasuries used in any academic study of the CAPM. Thirty-year Treasuries werent even sold until fifteen years or so after the CAPM's publication and the S. Treasury has suspended its sales of the thirty-year bond. The U.S. Treasury no longer publishes a rate for maturities over 20 years. The intermediate term also corresponds most closely to the typical period during which utility rates are in effect and the period during which shareholders would require compensation. Authorized rates of return are not set as frequently as monthly, or as infrequently as every thirty years, but somewhere in between the two extremes. After establishing my holding period, I estilnated the risk=free rate. Risk-Free Rate WHAT IS YOUR ESTIMATE OF THE RISK-FREE RATE AND HOW DID YOU ESTIMATE IT? I estimated the risk-free rate to be 4.3 percent. My estimate is based upon an average of intermediate-term U. S. Treasury securities' spot rates published in The Wall Street Journal. Published rates as detennined by the capital markets are objective, verifiable, and readily available, as opposed to rates published by a forecasting service which are not necessarily objective, and are certainly not verifiable or readily available. I averaged the yields-to-maturity of three intermediate-term (five-, seven- and ten-year) U.S. Treasury securities quoted in the May 26, 2004, edition of The Wall Street Journal. 14 The page on which I Ibbotson Associates SBB!2004 Yearbook page 175, estimates this long-term bond premium at 1.6 percent. The rates were: 3.88%4.40%, and 4.73%. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-04- 994 relied is included as page 17 of Exhibit JST-1. Page 18 of Exhibit JST-l also shows a variety of interest rates. Notice that the Discount Rate, a key rate on the economy, is quoted at 2.00 percent and the Prime Rate is 4.00 percent. Interest rates and capital costs are low and investors can reasonably expect low authorized ROEs based on these low interest rates. Beta WHAT IS YOUR ESTIMATE OF BETA? I provide three beta estimates (. , . , and .72) for the Commission consideration. They are derived from Value Line. My better beta estimates, as I discuss below, are the average Value Line betas for my sample of companies after correcting for a Value Line procedure that tends to bias utility betas upwards. ARE VALUE LINE BETAS THE BEST BETAS ON ",mCR TO RELY FOR ESTIMATING THE COST OF EQillTY FOR UTnITJES? No. Statistical evidence I reviewed indicates that other types of betas better represent actual market returns than Value Line-type betas which are ordinary least squares betas. These other betas include Fisher-Kalnin betas and Wells (autoregressive conditional heteroskedasticity-corrected) betas. However, these other betas are not currently available to me and so I relied on the best information I had available. I made improvements to the reported Value Line betas by "de-adjusting" them somewhat. Value Line betas are adjusted toward 1.0 (actually toward 1.06 implicitly) under the presumption that betas naturally move toward 1.0 over time. The problem for estimating electric utility betas is that electric utility betas are less than 1.0 and they haven t historically shown a DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4-1 995 systematic tendency over time to move toward 1.0. Therefore Value Line procedure upwardly biases beta estimates for electric utilities. WHAT IS VALUE LINE'ADJUSTMENT PROCEDURE AND HOW DID YOU IMPROVE VALUE LINE'REPORTED BETAS BY DE- ADJUSTING THEM? Value Line adjustment fonnula is Adjusted V-L beta: =.35 + .67*(unadjusted beta) The average beta for my sample of electric utilities is .72. Reversing the formula to de-adjust a .72 beta results in a .55 unadjusted (or raw) average beta. ~(lin~tp 'l_pt~. "'.-;: = (,,') - '2"'\t::.'7_4__J_""""'" .L..J ........... . ,J"" \. ,~ . .J.J). I also provide a beta re-adjusted to 1., but only by 10 percent: Re-adjusted beta: .59 = 10%x(1.0) + 90%x(55) I report CAPM results based on these three betas: . , . , and .72. My sample companies; 2003 capital structures Value Line betas, and my adjustments to them are shown on page 19 of Exhibit JST- HAVE ELECTRIC UTJLITY BETAS SYSTEMATICALLY RISEN TOWARD 100 OVER TIME? , they have not systelnatically risen toward 1.0, at least not since 1967. ON WHAT DO YOU BASE YOUR CONCLUSION? I performed a study examining the monthly sample average beta15 of74 electric utilities from 1967 to 1997. The results of my study are graphed below. CAPM beta risk has clearly fallen since the mid 1960s and 1970s. The chart below depicts the history of the average electric utility beta over time: DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4- 996 Electric Utility OLS Betas Over Time Decem ber 1967 through December 1997" a . , ., . ~ ~ ~ 0 - ~ ~ . ~ ~ ~ ~ ~ 0 - ~ ~ . ~ ~ ~ ~ ~ 0 - ~ ~ . ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ u u u u u u u u u u u u u u u u u u u u u u u UC C C C C C C C C C C C C C Q C C Q C C C C C C Q Q C C ~ C C The graph would have looked like a ramp heading upward to 1.0 if electric utility betas had been systematically rising toward 1.0. The last beta on the graph is . which is only 0.9 less than the current .55 raw Value Line beta that I discussed above. Therefore, both the chart and recent evidence indicate that electric utility betas have not tended to systematically rise toward 1. WHY DO YOU CALCULATE A VALUE LINE BETA ADJUSTED TOWARD 1.0 BY 10 PERCENT? I report a "re-adjusted" Value Line beta adjusted to 1.0 by 10 percent based on statistical studies of ordinary least squares betas and their forecast ability. The studies found that if an ordinary least squares beta is to be used and if it must be adjusted toward 1.0 then the best adjustment is 10 percent, on average. 15 60-month ordinary least squares. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-04-1 and AVU-G-O4- 997 1(\.LV Market Risk Premiuln WHAT IS YOUR RANGE OF MARKET RISK PREMIUM ESTIMATES? My range of estimates is 6.1 percent to 7.8 percent. HOW DID YOU CALCULATE YOUR MARKET RISK PREMIUM RANGE? My market risk premium range is my best estimate of the historical market risk premium (6.1 percent) and my current market risk premium (7.8 percent). If one consistently uses the long-run average market risk premium to estimate the expected Inarket risk premium, one should, on average, be correct. Dr. Siegel cited above, found that U.S. equities' reai returns were quite stable over long periods and averaged 6.9 percent historically. At anyone time the current market risk premium might be greater or less than the historical average. Estimating the current market risk premium presents more difficulty but it is useful information if it can be estimated with some confidence. PLEASE DESCRIBE WHAT AN INTERMED IA TE- TERM MARKET RISK PREMIUM IS AND HOW YOU ESTIMATED IT. The expected market risk premium for an investor with an intennediate-tenn holding period is the difference between expected colnpounded returns on the market portfolio and the compounded returns on the risk-free asset over an intermediate period. For example, the historicallnarket risk premium is the difference in returns between an investor s two accounts: one invested in the stock market and the other invested in U.S. Treasury securities, both over an intermediate period. The difference is then annualized. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-04- 998 I estimated the historical market risk premium by the following steps: 1. I used the Center for Research in Securities Prices ' 1926-1999 NYSE/ AIvIEX/NASDAQ returns as a proxy for the theoretical market portfolio returns. I updated market returns through 2003 using Ibbotson Associates Stocks, Bonds, Bills, and Inflation 2004 Yearbook (largecompany stock total return index (S&P 500)). 2. I used 1926-2003 data on intermediate-tenn U.S. Treasury securities rates from Ibbotson Associates Stocks, Bonds, Bills, and Inflation 2004 Yearbook to estimate risk-free rates over that period. I used two different series from the Yearbook: yields (ex ante rates) and total returns (ex post rates). I performed separate analyses using each of the senes. 3. I separated my 1926 to 2003 data into holding periods of five to ten years each such that all my data were used once, but only once (this method is technically called the simple unbiased estimator). I then calculated the average rate-or-return difference betv/een holding fL~e market portfolio and holding the risk-free rate over the intennediate term and then I annualized the difference. My estimates are shown below: Historical Market Risk Premium Estimates Ex Ante Risk Free Rates - - 72-month holding period 10% 78-month holding period 70% 104-month holding period 6.30% Average:40% Ex Post Risk-Free Rates 72-month holding period 700/0 78-1nonth holding period 6.30% 104-month holding period 50% Average:80% Average of two midpoints:10% Estimates rounded to three decimal places The average of my midpoint estimates is 6.1 percent. My method is substantially the same as published by Russell J. Fuller and Kent A. Hiclcrnan in their article , " Note on Estimating the Historical Risk Premium Financial Practice and Education (FalllWinter 1991) pp. 45-48. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4- 999 HOW DID YOU ESTIMATE THE CURRENT MARKET RISK PREMIUM? I estimated the current market risk premium by essentially the same method that I used to calculate the historical market risk premium but I applied the method to forecasted data. For the forecast return on the market, I used Value Line forecasted dividend yield and capital appreciation for alII 700 stocks it covers three to five years hence, or four years on average. Value Line forecasts 1. percent dividend yield over the next twelve months and 50 percent price appreciation three to five years hence. This gave Ine a total return forecast of about 11.9 oercent er year for this broad basket of Value Line stocks over the ... next four years. The rate on a four-year U.S. Treasury note is currently 3. percent. 17 The implied annual expected Inarket risk premium from these figures is 7.8 percent18 (rounded to three decimal places). This calculation assumes a 1 A1 "t four-year holding period which is i~ss than my five- to ten-year holding period assumption and it would lead to a biased-upward market risk premium estimate (shorter holding period assumptions tend to result in higher market risk premium estimates). However, I do not expect the bias to be significant enough to outweigh the benefit of the calculation. WHAT ARE YOUR CAPM COST OF EQUITY ESTIMATES? My CAPM estimates, based on my three beta estimates and my historical and current market risk premium estimates, follow: 17 May 26 2004, edition of The Wall Street Journal.18 The calculation is not the simple difference of the annualized market return and the annual risk-tree rate.The nominal annual rate is calculated trom the ratio of the two value relatives, one for the market basket andthe other for the investment in the risk-free rate, and then annualized (annualized nominal montWy). DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-04- 1000 f'\ '::I CAPM Estimates E(Ri)Risk-Free Beta MRPRate 70%30%Historical Iv1RP 90%4.30%6.1% 70%4.30% 60%4.30%Current 90%30%0.59MRP 90%4.30% Average 60% Cost of equity estimates rounded to three decimal places. Cost of Equity Estimates to The Electric Utility Industry PLEASE SUM:MARIZE YOUR COST OF EQillTY RANGE AND POINT ESTIMATES FOR THE ELECTRIC UTILITY INDUSTRY AND EXPLAIN HOW YOUR RANGE WAS CHOSEN. I estimate that the cost of equity to the electric utility industry is within a range of 5 percent to 9.9 percent, based on IllY estimates shown in t e table below: Summary of Cost of Equity Estimates To The Electric Utility Industry DCF low 50% DCF midpoint 40% DCF high 20% CAPM low 70% CAPM midpoint 60% CAPM high 90% Electric industry cost of equity:50% My point estiInate is 8.5 percent, the average of Iny DCF and CAPM . 1 mlapolnts. DIRECT TESTIMONY OF JOHN S. THORNTON - 30 IPUC Case Nos. AVU-O4-1 and AVU-G-04- 1001 .., 1 ()l.V Cost of Equity Estimates and ROE Recommendation For Avista Corp. SHOULD YOU ADJUST YOUR COST OF EQUITY FROM THE ELECTRIC UTllJTY SAMPLE FOR DIFFERENCES IN CAPITAL STRUCTURES BE TWEEN THE SAMPLE AND A VISTA CORP? Yes. One should consider differences in capital structures between a sample and the company to which the estimate is applied (a higher percentage of debt in a capital structure implies a higher cost of equity because of increased financial risk). This adjustment is intended to be consistent with the CAPM. However, the percentage of common equity in A vista s filed capital structure (44.3 percent) is not significantly different from my sample s average ievei of common equity (45 percent). Therefore, I did not make any adjustment and I used my sample average cost of equity as my estimate of Avista s cost of equity. My estimate of Avista cost of equity is 8.5 percent. Recommended Rate of Return WHAT RATE OF RETURN (ROR) DO YOU RECOlVlMEND? I recommend an 8.49 percent ROR. I also present two other ROR calculations based on my high and low cost of equity estimates. The three ROR calculations are shown on page 1 of Exhibit JST- IS YOUR ROR EXPECTED TO MAINTAIN THE COMPANY' FINANCIAL INTEGRITY? Yes. The interest coverage ratio implied by my recommended 8.49 percent ROR is 2., vvhich can be expected to maintain or enhance the Cofnpany s financial integrity. Standard and Poor Corporate Ratings Criteria (page 50) reports that DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-04-1 and AVU-G-O4- 1002 the median interest coverage ratio for utilities rated BBB was 2. 1 in the 2000- 2002 period. Avista Corporation s current rating for senior secured debt is BBB- Neither of my other options results in a coverage ratio less than 2.1. Standard and Poor Corporate Ratings Criteria reports that the median ROE for BBB-rated utilities was 7.4 percent (my recommendation is higher, which is better for the Company) and total debt to total capital was 62.6 percent (Avista s filed capital structure has 55.7 percent debt and preferred stock, which is lower and better for the Company). Therefore, the end result of my recommendation should allow Avista to maintain its financial integrity, earn returns colnparable to returns of pallies of similar risk, and attract capital. Examination of Mr. Malquist's 11.5010 Return on Equity Recommendation ON WHAT DOES MR. MALQUIST BASE HIS 11.5 PERCENT RETURN ON EQUITY RECOMMENDATION? Mr. Malquist bases his recommendation on his own personal belief that "the 11.5% provides a reasonable balance of the competing objectives of regaining financial health within a reasonable period of tilne, and the impacts that increased rates have on our customers.(See Direct Testimony of Malyn Malquist, page 22 at 3 to 6.He also believes that a return on equity greater than 11.5% is supported and warranted. He provides no financial analysis or cost of equity calculations to support his recommendation. SHOULD THE COMMISSION ADOPT AN 11.5 PERCENT ROE BASED ON MR. MALOmST'S PERSONA-L BELIEF? .... DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-O4- 1003 No. The Commission should not adopt an 11.5 percent ROE based on Mr. Malquist's personal beliefs and assertions. Examination of Dr. Avera s Cost of Equity Analysis PLEASE SUMMARIZE DR. AVERA'S COST OF EQUITY ANALYSIS. Dr. Avera performed a constant-growth DCF on a sample of eight "western electric utilities, an allowed ROE premium analysis on an undefined number of companies, a realized risk premium on an undefined number of companies, and a CAPM on his electric utility sample. His range of estimates from these methods is 10.2 percent to 11.7 percent. He adds 0.2 percentage points to his cost of equity estimates to account for flotation costs. I address his cost of equity analyses in turn, and then I address the inappropriateness of his increasing a cost of equity for flotation costs and for a unique risk adder based on bond yields. DR. AVERA SEEMS TO PORTRAY A RATHER GLOOMY OUTLOOK FOR THE ELECTRIC UTILITY INDUSTRY. DO YOU SHARE IDS PESSIMISM? I do not share his pessimism. On page 15 beginning at line 3 of his direct testimony he states Combined with a stagnant economy and global uncertainties, the dramatic upward shift in investors' risk perceptions and the weakened financial picture of most industry participants, have combined to produce a severe liquidity crunch in the electric power industry. " His view seems to be supported by reports from 2002 and early 2003. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-O4-1 1004 However, a more recent report by Fitch Ratings, titled Fitch 2004 Outlook. u.s. Utilities and Merchant Energy Companies Both Stabilize dated December , 2003, says Although the Outlook for the regulated and unregulated sectors is stable in both cases, this masks the divergent paths both segments have taken. While the investor-owned utilities (IOU s) either maintained creditworthiness or are well on their way to recovery, the merchant or competitive energy sector will need much more time (and consistent favorable developments) to recover. I include Fitch's synopsis of its report as pages 20-21 of Exhibit JST-l. I do not share Dr. Avera s pessimism but look for financial improvements to IOUs in 2004 and beyond. IS illS SAMPLE OF EIGHT WESTERN ELECTRIC UTILITIES APPROPRIATE? I find that his sample is overly restrictive and that useful information on the risk of owning shares in an electric utility can be gained from col11panies in addition to those defined by Value Line as operating in the West (his sample universe). small sample results in less efficient estimates and in which one should have less confidence. For example, in calculating the dividend yield in the DCF model, a larger sample allows for random daily fluctuations in spot stock prices to even themselves out, resulting in a more efficient estitnator. An eight-company sample is less reliable than a thirty two-company sample, all else being equal. I am also concerned that Dr. Avera s sample includes Sempra Energy that has divested its generation, according to Value Line and Xcel Energy, Inc. that operates primarily in l11id-westem states and is emerging from its discontinued non-regulated NRG operations resulting in accelerated dividend growth. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-04- 1005 .., Dr. Avera s Constant-Growth DCF Analysis HOW DID DR. A VERA APPLY THE DCF? Dr. Avera used the constant-growth DCF model. He calculated a forward-looking 2 percent dividend yield from Value Line data, to which he added a 5 to 7 percent growth rate range. DO YOU AGREE WITH DR. AVERA'S DIVIDEND YIELD CALCULATION? I take issue with his calculation of the dividend yield, though his 4.2 percent dividend yield is within my range of estimates that averaged 4.55 percent. The problem "vith his calculation is that he takes the dividend forecasts and stock prices from the same Value Line Summary Index publication. His procedure inappropriate because if the particular edition of Value Line from which he took dividend forecasts had any new information then that information would not be reflected in the (old) stock price that appears in the saine edition. One should take stock price data after dissemination of the Value Line dividend forecast information in case the forecast contains any news. I point this out in order --- - ~ ~ 1 ~ - -- - - - - - - - !TIake tl!~ !~~Qgi ~9mQl~Je ill this _~se ,- -- ~ - -- - - -- - -- -- - -- - - -- - -- - - - - - - - - - - - - - - -- --- - - DO YOU AGREE WITH DR. AVERA'S 5 TO 7 PERCENT DIVIDEND GROWTH FORECAST ASSUMPTION? No. I do not agree that investors could reasonably expect dividends for Dr. Avera s sample of companies to grow at 5 to 7 percent per year forever. His own data do not support a 5 to 7 percent dividend growth forecast. Dr. Avera relies on earnings growth forecast data shown on page 42 of his direct testimony. Those data show earnings growth forecasts between 2.4 percent and 5.4 percent. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-O4- 1006 Ilf ,., 0 Furthennore, those earnings growth forecasts are near term (not indefmite) in length and earnings growth forecasts are widely known to be overly optimistic. The average dividend growth rate for his sample companies for the ten years 1994 through 2003 is close to zero (0.219 percent). (See page 22 of Exhibit JST-1 for this calculation.) Dr. Avera s assumption that his companies will suddenly and forever increase their dividends by 6 percent per year forever after 2004 seems to be tremendously optimistic to the point of incredible. A six percent annual growth rate would exceed the historical dividend per share growth rate of the whole economy, according to evidence I presented earlier. WHAT AR-E v.AT.ljR LlVE'DIVIDEND GRO\VTH PROJECTIONS FOR DR. AVERA'S SAMPLE COMPANIES? Value Line publishes dividend forecasts for 2004 2005, and the 2007-2009 period. The implied dividend growth rate for his sample is 3.35 percent for 2004 to 2007-2009 and 3.35 pergent for the 2005 to 2007-2009 period. (See page 23 of Exhibit JST -1 for these calculations.) Therefore, one cannot conclude that investors reasonably expect an average annual 6 percent dividend growth in the near future (through 2009) much less into infinity. IF DR. AVERA'S DATA SUPPORTED A 3.0 PERCENT TO 5.0 PERCENT RANGE WHAT WOULD BE IDS DCF ESTIMATES? Dr. Avera s cost of equity estimates would be 7.2 percent (4.2% + 3.0%) to 9. percent (4.2% + 5.0%) using a 3 to 5 percent growth rate range. In other words, a more reasonable interpretation of his data would lead to results near my range of estimates. DIRECT TESTIMONY OF JOHN S. THORNTON - 36 IPUC Case Nos. AVU-E-O4-1 and AVU-G-04- 1007 Dr. Avera s Allowed ROE Premium Analysis WHAT IS DR. AVERA'S ALLOWED ROE APPROACH AND IS IT AN ACCEPTABLE APPROACH TO USE IN TIDS PROCEEDING? Dr. Avera s allowed ROE approach compares annual average authorized ROEs for the years 1974 through 2002 with the yield on Moody s annual average public utility bond yield. This approach is frought with problems, from theoretical to statistica1.19 The fatal flaw of the approach is that the Idaho Public Utilities Commission is in no way able to determine what these allowed ROEs actually represent, what companies are used in the analysis, what data underlie the ROEs to what capital structures they were applied, what risks the electric utility industry was facing at the time of the decisions, or what methods were used to arrive at them. For example, how many of the allowed ROEs in Dr. Avera s sample already include a flotation cost adjustment to which Dr. Avera would add a second adjustment in this proceeding? Other adjustments might also infect the allowed ROE such as the market pressure adjustment that utilities have sought, or an upward bias from applying the quarterly DCF model, which utilities have sought, or use of the "comparable earnings method " an inferior approach to estimate a cost of equity. Moreover, since market-to-book ratios have been above 0 for most of the years I have been performing electric utility cost of equity analysis, I conclude that allowed ROEs have, on average, been too high according 19 Dr. Avera s regression includes the average public utility bond yield on both sides of his equation. Therefore, his "independent" variable is not truly independent. Even if there were no relationship betweenallowed ROEs and the average public utility bond yield, a regression of the premium of allowed ROEs abovethe average public utility bond yield and the average public utility bond yield would appear to show a relationship. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4- 1008 to the DCF model. Dr. Avera s approach sitnply reinforces past errors into A vista Corporation s future rates, and therefore his approach is circular in its logic. This Commission has no way of evaluating these other authorized ROEs from other jurisdictions. Authorized ROEs from other jurisdictions and under other capital market circumstances do not determine the current cost of equity for A vista Corporation. One would hope that commissions' cost-of-equity methods would improve over time. Dr. Avera s allowed ROE method locks in the lower common denominator of analyses performed years ago into future rates. Dr. Avera s study in no 'way corrects for changing industry risk. Above, I presented evidence that electric industry risk has declined since the 1974-1979 period. Dr. Avera s study locks in dated and higher industry risk to the extent that it appropriately estimates the cost of equity at all (which I do not believe r. Avera s analysis does not account for the increasing risk of bonds since about 1970 (bonds can have betas too). I discuss this problem more fully below but the net result is that his method unambiguously overestimates the cost of equity. Finally, Dr. Avera s study errs in that even if using other authorized ROEs were valid, he has not determined on what risk-free rates these other allowed ROEs were actually based. Commission orders can appear many months after any risk-free rate data on which they were based and taking yearly averages as Dr. Avera does only obscures any relationship. Interest rates declined for Inuch of his period of study. Dr. Avera s method is out of step by mismatching authorized ROEs with declining interest rates. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-04-1 and A VU-G-O4- 1009 In short, I recommend that the Comlnission give Dr. Avera s allowed ROE approach no weight. The reasoning is circular and it is not based on any substantial capital market theory. Dr. Avera s Realized Rate of Return Analysis PLEASE EXPLAIN DR. AVERA'S REALIZED RATE OF RETURN APPROACH. Dr. Avera calculates the average premium of realized electric utility stock returns above A-rated public utility bonds for the period 1946 through 2002. His calculated premium is 4.01 percent. He then adds this 4.01 percent premium to a (November 2003) 6.61 percent BBB-rated public utility bond rate. IS IDS APPROACH APPROPRIATE? No. His approach is not appropriate for several reasons. First, realized returns on electric utility stocks include both systematic risk (that is rewarded in the CAP~v1) and unsystetnatic risk. This limited portfolio is exposed to unsystematic risk because it is not fully diversified into other industries such as banking, retail, etc. The problem is that unsystematic risk does not require a return and it is not priced in the market precisely because it can be diversified away. Dr. Avera s method effectively includes this unsystematic risk into his cost of equity estimate. The volatility of his sample s returns from 1994 through 2002 (25 percent) is greater than the volatility of the S&P 500 for the same period (22 percent), a clear indication of the unsystematic risk he is pricing into his analysis. His method asks ratepayer to recompense stockholders for risks that stock..holders have diversified away. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-O4-1 and AVU-G-O4- 1010 Second, his analysis makes no allowance for changes in electric utility industry risk over the years. In fact, it incorporates varying risk levels over the entire 1946-2002 period, an approach that is certainly inconsistent with his CAPM approach which uses a current beta. This approach is really nothing more than the old "comparable earnings method" in stock return clothes. Third, Dr. Avera s method does not take into account any increase in single- A rated public utility bonds' risk over the period. Below, I discuss Dr. Laurence Booth's finding that long-tenD bonds' betas have increased and how realized excess return premium methods will result in an upwardly biased estimate of the cost of eQuitY to utilities. .. Fourth, actual returns in the market likely exceeded expected returns for much of the time period on which Dr. Avera relied. As Fama and French indicate in their article "Equity Premium The Journal of Finance volume L VII, number 2 1 A1. "'t I" A. . , """""" V\.pnl LUUL), Our evidence suggests that the high average return for 1951 to2000 is due to a decline in discount rates that produces a large unexpected capital gain. Our main conclusion is that the average stock return of the last half-century is a lot higher than expected. Dr. Avera chose almost the same period and his analysis is affected by the SaIne problem: realized returns exceeded expected returns. Fifth, and most obviously, Dr. Avera inappropriately added his premium based on A-rated bonds to a BBB-rated bond yield. His mismatch results in a high premium added to a high bond yield resulting in a biased-upward cost of equity estimate. The bias is inherent because A-rated bonds have lower yields than BBB-rated bonds. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-04- 1011 HAVE ANY PUBLISHED STUDIES INVESTIGATED THE PROBLEM WITH THE RISK PREMIUM METHOD? "'I Yes. Laurence Booth's article "Estimating the Equity Risk Premiulll and Equity Costs: New Ways of Looking at Old Data,,20 investigated the increase in the risk of long-term bonds and found that their betas have been increasing since about 1970. Four of his main conclusions follow: ( 1) Examination of bond market performance and market interest rates experienced since 1925 make it abundantly clear that the term premium bias is significant. As a result, the long-run realized excess return over long-term bonds cannot be used. as a riskpremium to add to current long-term bond yields. (2) Total bo d Inarket risk (as measured by standard deviation of returns) has significantly increased over the last 20 years, and attime has been almost equal to that of the equity market. This indicates that the equity risk prelnium over long-term bonds isunlikely to have been constant. (3) Bond market betas, whether measured based on ten-year annualreturns or five-year monthly returns, have increased from the negligible level prior to the 1970s to the 0.40-80 range by 1990s.As a result, conventional risk premiums over long-tenn bondyields that may have been valid in earlier periods are excessive in the CUITent interest rate environment. (4) With bond market betas of 0.40-80, risk premiums forlower risk equity securities, such as utilities, should be close to zero. " (emphasis added) Dr. Avera s realized return approach suffers from upward bias because it did not take into account either the decreasing electric utility betas on one hand or increasing bond betas on the other. These two effects have worked since the 20 Laurence Booth , " Estimating the Equity Risk Premium and Equity Costs: New Ways of Looking at OldDataJournal of Applied Corporate Finance Vol. 12, No.1 (Spring 1999) pp. 100-112. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-04- 1012 1970s to squeeze the equity risk premium for utilities close to zero, according to Dr. Booth. Dr. Avera s CAPM Analysis HOW DOES DR. AVERA IMPLEMENT THE CAPM? Dr. Avera implements the CAPM on his sample of electric companies by estimating a risk-free rate, market risk premium, and an electric-utility industry beta. Risk-Free Rate WfJAT IS DR..A VEP~S RISK=FP~E RATE AND BOY; DID HE ESTIMATE IT? Dr. Avera s risk-free rate is 5.2.percent. The rate represents the "average of the daily yields on long-term government bonds for December 2003 reported by the S. Department of the Treasury at www.treas.gov" according to his exhibit (see WEA-6). The Federal Reserve website before June 1 2004, indicated that the data were "Based on the unweighted average of the bid yields for all Treasury fixed-coupon securities with remaining terms to Inaturity of 25 years and over. Averages of business days." That data series was terminated. DOES THE U.S. TREASURY CONTINUE TO CALCULATE AND PUBLISH THE DATA SERIES THAT DR. AVERA CHOSE? No. On June 1 2004, the U.S. Treasury discontinued the "LT:;::.25" average due a dearth of eligible bonds. First, the fact that few bond were available to begin with should make one question whether these long-term U. S. bonds could have actually been used as a risk-free asset by investors. Second, the fact that they are DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-04- 1013 .., now unavailable to the point of being a "dearth" as the U.S. Treasury describes it should eliminate any need to consider them because they don t exist. Nevertheless, I will describe below the problems with using a long-term U. Treasury security for the risk-free asset in a CAPM. IS DR. AVERA'S CHOICE OF A LONG- TERM U.S. TREASURY YIELD FOR THE RISK-FREE RATE APPROPRIATE? No. Dr. Avera s choice of a long-term U.S. Treasury security yield as the proxy for the risk-free rate is not appropriate for a number of reasons. (1) The CAPM is a holding period model, as I explained earlier. One makes estimates of the risk-free rate, beta, and the market risk premiu over the investors' expected holding period. The use ofa long-term U.S. Treasury bond for the risk-free asset implies a long-term holding period. I do not find his implied assumption reasonable. Studies I have seen in other cases indicate that investors' hoiding periods are nearer to two years in iength, if not intermediate in term, and I have never seen a study indicating that the average investor has a holding period of greater than twenty-five years, which is the implied holding period in using the risk-free rate Dr. Avera chose. (2) I do not see value in using the U.S. Treasury s calculated average rate for December 2003 as a source when Dr. Avera could have looked up an actual market-based Treasury yield in The Wall Street Journal or other such source to make estimates that were consistent in time with his DCF estimates (December , 2003). (3) I have never seen an academic study of the CAPM use long-term U. Treasury bonds for the risk-free asset. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4- 1014 (4) Long-tenn U.S. Treasury yields contain a "liquidity risk premium." One could subtract the liquidity risk premium from the long-tenn rate before using the rate in a CAPM, as described in Brealey and Myers' book Principles of Corporate Finance The risk-free rate could be defined as a long-tenn Treasury bondyield. If you do this, however, you should subtract the risk premium of Treasury bonds over bills... This figure could be in turn be used as an expected average future rf in the capital asset pricing model. " Dr. Avera did not estimate or subtract the liquidity risk premium from his long- term risk-free rate estimate before using it in his capital asset pricing model. Ibbotson Associates SRRl 2004 Yearbook estimates the liquidity risk premium at 1.6 percent (page 175). (5) Use of a long-tenn U.S. Treasury bond rate creates implementation issues such as the inability to correctly estimate a historical market risk premium and the increased difficulty of estimating beta. For example, a twenty-five-year assumed holding period requires twenty-five years of both stock market data and long-term U.S. Treasury rate data before an analyst can calculate a single sample historical market risk premium over a twenty-five-year period. The data frequency used in the beta estimate should correspond as well as possible to the assumed holding period. The same implementation probleln exists for estilnating a market risk prelnium. Richard A. Brealey and Stewart C. Myers: Principles of Corporate Finance rd ed., McGraw-Hill Book Co.New York (1988): pp. 184. DIRECT TESTIMONY OF JOHN S. THORNTON - JPUC Case Nos. A VU-04-1 and A VU-G-04- 1015 (6) Finally, Dr. Avera has a holding-period consistency problem throughout his CAPM analysis that biases his estimates upward. I summarize his inconsistencies below in a table. Beta WHAT BETA ESTIMATE DOES DR. AVERA RELY ON AND HOW DID HE DERIVE IT? Dr. Avera s beta estimate is ., the average Value Line beta for his sample. DO YOU AGREE WITH IDS BETA ESTIMATE? No. I do not entirely agree with his beta. Value Line adjustment procedure (electric utility betas are adjusted upward toward about 1.0) is not optimal for estimating electric utility betas, as I discussed earlier. This upward bias should be at least considered and offered for correction before deriving a cost of equity to the electric utility industry. Market Risk Premium WHAT MARKET RISK PREMIUM DOES DR. AVERA RELY ON? Dr. Avera s market risk premium estimate is 8.5 percent, a DCF-derived market risk premium. HOW DID DR. A VERA ESTIMATE THE MARKET RISK PREMIUM? Dr. Avera performed a DCF model estimate of the cost of equity to the Standard & Poor s 500 (13.7 percent) and subtracted the same 5.2 percent average December 2003 long-term Treasury bond yield he used for the risk-free rate to arrive at an 8.5 percent market risk premium. DO YOU AGREE WITH IDS METHOD AND CALCULATIONS? DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-O4-1 and A VU-G-04- 1016 His method might have merit but he has assumed that dividends on the Standard and Poor s 500 composite companies will grow at 12.1 percent per year forever. I ,., find this assumption unreasonable given historical per share dividend growth in the U.S. stock market (1.09 percent real growth) and historical growth of the U. economy as a whole (3.26 percent real growth) minus share growth that I discussed earlier. Those data suggested a 3 to 5 percent nominal growth rate range. A leap to 12.1 percent annual per share dividend growth into infinity could not be reasonably expected by investors. PLEASE SUMMARIZE ANY CONSISTENCY ISSUES IN DR. AVERA' CAPM ANAl,YSIS H Ii~IR HI t\SES. The table below summarizes my findings: Summary of Dr. Avera s CAPM Application Consistency Issues Variable Implicit Holding Bias/reasonPeriod Risk-free rate Greater than 25 Upward bias--doesn t extract liquidity risk years premium; data discontinued Upward bias---calculation assumes shorter Beta Weeldy than a reasonable holding period assumption and inappropriately adjusted upward to 1. without consideration of an unadjusted beta Upward bias--unrealistic forecast of indefinite Market risk Greater than 25 12.% dividend growth in the S&P DCF leads to an unrealistically high market risk premium;premIum I years no consideration of historical premium Dr. Avera s Flotation Cost Adjustment IS DR. AVERA'S 0.20 PERCENTAGE POINT FLOTATION COST ADJUSTMENT APPROPRIATE? .L1..I do not recommend adjusting the cost of equity upward for notation costs or market pressure." This topic is controversial and complex. Dr. Avera has not DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-O4-1 and AVU-G-04- 101 7 shown that A vista Corporation, specifically, will incur any such costs and in what amounts. I recommend that the Commission avoid increasing A vista Corp. ' ROE for flotation costs. Furthermore, he applies his flotation cost adder to all equity, both contributed capital and retained earnings that never incurred such costs. PLEASE COMMENT ON DR. AVERA'S FLOTATION COST ADJUSTMENT. I have two general points to make about Dr. Avera s flotation cost adjustment: 1. Dr. Avera s flotation cost adjustment compensates Avista for costs that aren t specifically inclLrred by l\vista Corporation. The flotation costs appear to be from some undefined study(ies) of costs in other jurisdictions and summarized by Roger Morin in his book. 2. The proposed adjustment lacks support. Dr. Avera relies on a conclusion whose study and details are left unexamined by Dr. Avera and lacking working papers. He presents neither the theory behind his adjustment nor the method of the adjustment nor the details behind the adjustment's calculation. Such an adjustlnent deserves full presentation if it is to be seriously proposed in this case. DID DR. AVERA ACCOUNT FOR ALL STOCK EXPENSES IN IDS ADJUSTMENT, SUCH AS FEES THAT WOULD REDUCE IDS ESTIMATE? No. His flotation cost adjustlnent appears to fail to account for stock purchase fees, otherwise known as brokers' fees, as opposed to the stock issuance fees he did consider. These fees result in an investor paying more than the price quoted on the stock exchange, and would reduce the required dividend yield in the DCF DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-04-1 and AVU-G-04- 1018 offsetting the issuance cost adjustment. The effect of brokers' fees is analyzed in David Habr s article , " Commission Staff Report: A Note on Transaction Costs and the Cost of Common Equity for a Public Utility,NRRl Quarterly Bulletin 9: 1. Brokers' fees of 5 percent would completely offset a 5 percent flotation cost adjustment. SHOULD A UTILITY RECOVER ITS FLOTATION COSTS IN RATES? Yes. Flotation costs are a necessary cost of business. However, I recommend that expected normalized issuance expenses be recovered as an expense item, not through a ROE increase. Finally, as I mentioned above, 'Nhen the market~to~book ratio is greater than , under the DCF model, a firm is expected to earn more than its cost of capital. The market to book ratio for Iny sainple is 1.62, implying that my sample companies are already expected to earn more than their costs of equity. Boosting the authorized ROE above the cost of equity through a flotation cost adjustment would provide a one-time gain to shareholders at the expense of ratepayers. DO YOU RECOMMEND THE IDAHO PUC FORMALLY REJECT THE FLOTATION COST ADJUSTMENT TO A VISTA'S ROE IN FAVOR OF THE ACCOUNTING TREA T:MENT YOU'VE DISCUSSED? Yes, I recommend the order in this proceeding find that the flotation cost adjustment to ROE is inappropriate, and should be rejected in favor of an accounting treatment for valid common stock issuance expenses. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-O4- 1019 Dr. Avera s Assessment of Avista s Unique Risk PLEASE EXPLAIN HOW DR. AVERA JUSTIFIES MOVING TO THE IDGH END OF IDS COST OF EQUITY ESTIMATES TO ACCOUNT FOR VISTA CORPORATION'S UNIQUE RISK? Dr. Avera s discussion, beginning on page 60 of his testitnony and titled Relative Risks " concludes that" . . . the capital markets would require approximately 3.0 to 5.8 percent in additional return in order to compensate for the greater risks associated with speculative grade debt instruments. . . Investors would undoubtedly require a significantly greater premium for bearing the higher risk associated vvith the Inore junior cormnon stock of a utility with A vista) s below investment grade rating.(See Direct Testimony of Dr. Avera, page 62 at 11-15.) His analysis leads him to conclude that the uppennost end of his 10.4 to 11.9 percent range is justified. IS DR. AVERA'S RISK ADJUSTMENT APPROPRIATE? , Dr. Avera s increase to his cost of equity estimates to account for Avista Corporation s BB bond rating is not appropriate for several reasons. (1) Increasing a return on equity to account for the unique risks of a company s debt is inconsistent with modem corporate finance theory, notably the capital asset pricing model for which the Nobel Prize in Economics was awarded. Specifically, as I discussed earlier, the CAPM and modem portfolio theory have shown us that investors can avoid risk by diversifying. Since investors can hold diversified portfolios, the only equity risk that relnains and is priced in the market is systematic risk. In my example above I discussed a suntan lotion company and an ulnbrella company. Through diversification, the unique risk of each of the DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-E-04-1 and AVU-G-04- 1020 investments is diversified away and an investor cannot expect, in a competitive market, to be systematically rewarded for taking on risk that is diversified away. (2) Adding a bond rating premium to a cost of equity analysis is not consistent with either the CAPM or the DCF. Adding a bond premium to an equity cost is arbitrary and unwarranted. (3) Adding a unique risk adder to A vista Corporation because of its poor financial situation would inappropriately compensate investors for the Company past imprudence to the extent that past imprudence, or utility diversification contributed to its current financial situation and below-investment-grade ratings. HAS THIS ISSUE OF INCLUDING UNIQlW. llTSK Il'T A COST OF EQillTY ANALYSIS BEEN ADDRESSED IN A RECENT PUBLICATION? Yes. The issue has been addressed in award-winning article titled "How Improper Risk Asse~slnent Leads to Overstatelnent of Required Returns for Utility Stocks" published in the National Regulatory Research Institute Journal of Applied Regulation Vol. 1 , June 2003. That article concludes Risk and return are important issues in regulatory proceedings. Understanding how risks affect stock prices leads to better estimates of the market's required return on utility stocks. Risks that are specific to the utility affect expectations about future utility cash flows, but they have little bearing on the investors' required return. Regulators should therefore ignore testimony suggesting that finn-specific risks influence the required return. Once the inappropriate firm-specific risk adjustments are eliminated regulators will likely find that required returns on most utility stocks today are below 10%. I include that article as pages 24-47 of Exhibit JS T -1. The proper approach to estimating the cost of equity to A vista Corporation is by using market-based DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-04- 1021 models of the cost of equity to firms of comparable risk rather than by arbitrarily adding risk adjustments to account for finn-specific unique risks. DO BOND HOLDERS AND COMMON EQUITY OWNERS HAVE THE SAME INTERESTS AND CAN BOND YIELDS BE DIRECTLY COMPARED TO REQUIRED RETURNS ON EQUITY? Bond holders and stockholders frequently have divergent interests. Bond holders might very well focus on firm-specific risk because they are concerned about the probability of default, a probability that is affected by firm-specific issues and measured by bond ratings. The reason for this focus of concern is that, unlike a stock, bond holders ' expected returns are capped at the coupon rate of debt. That is to say, even.ifthe firm has excess returns it will still, at best, only payout to bond holders the coupon rate of the outstanding debt. For example, say a utility issues 8 percent coupon debt. The most it will ever pay bondholders is 8 percent but the company might pay less than 8 percent if the bonds have any risk at aU. An investor s expected return on the bond is, therefore, less than 8 percent and might be 7 percent for example. The possibility of default means that the bond holders ' expected returns are actually lower than the coupon rate of debt. Therefore, bond holders focus on the probability of default. Adding a bond holder s default premium for A vista Corporation s BB-rated bonds to a cost of equity is, therefore, inappropriate because the two are not comparable. Dr. Avera s Cost of Equity Conclusion WHAT IS DR. AVERA'S COST OF EQUITY CONCLUSION? DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. AVU-E-O4-1 and AVU-G-O4- 1022 Dr. Avera concludes that Avista Corporation s required return on equity falls in the upper end of his 10.4 to 11.9 percent cost of equity range and that the 11. percent ROE that A vista requested is conservative. His cost of equity estimates go as high as 17.7 percent (11.7 percent from the electric industry CAPM plus the 20 percent flotation cost adjustment plus the 5.8 percent unique risk adder). Conclusion WHAT DO YOU CONCLUDE GIVEN THE EVIDENCE YOU REVIEWED? I conclude that the Commission should authorize an 8.5 percent ROE and an 8.49 percent ROR, but I offer two other alternatives based on my high and low cost of equity estimates. The Commission should reject Mr. Malquist's 11.5 percent recommendation because it is not based on a cost of equity analysis or any other evidence other than his personal belief. Dr. Avera significantly overestimated Avista Corporation s cost of equity, particularly in a period when interest rates are not far frOlTI historical post-war lows. His adder for the unique risk of A vista Corporation is also inappropriate. His analyses are upwardly biased and inconsistent with current capital markets and capital market theory. DOES TIDS COMPLETE YOUR PREFaED DIRECT TESTIMONY? Yes, it does. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-E-O4-1 and A VU-G-O4- 1023 Appendix Derivation of the Constant-Growth DCF Model Cost ofEqJilly Stock I's price today (Po) is equal to its value, which in turn is worth the present discounted value of its expected dividends (D L. ), discounted by the stock's cost of equity (ki): (1)Po + ... + ( 1 + ( 1 + ki ki ki )n ..----.-.--.-_uo...-..- .-...-..-. -- Now assume that dividends 2 through are related to dividend 1 by a constant growth rate gi, such that: (2) 2 = D 1 X ( 1 + g (3) 3 = D 1 X ( 1 + g (4) = Dl X )n- Expressing equation (4) in terms of Dj: (5)Po Dl x DI x gi Di x ( 1 + gi )n- ( 1 + ki ki ( 1 + ki ( 1 + ki )n Now, multiply each side by 1 + ki: DI X (1 + g.) DI (1 + g DI x (1 + g i )n (6) o x (1 + ki) = DI + (1 + ki) (1 + ki) ... (1 + ki)n- The right hand side of the equation can be expressed using summation notation: (7) - 1 (1 + o x = L Dl ( 1 + k i )t Now, we assume that dividends are paid infinitely (n ~C()). The right hand side of equation (7) becomes the sum of a geometric series. We can simplify equation (7) by assuming that )- gi (for convergence): DIRECT TESTIMONY OF JOHN S. THORNTON - JPUC Case Nos. A VU-04-1 and A VU-G-O4- 1024 (8)Po x ( 1 + ki ) = 1 - ( 1 + gi Simplifying: (9)Po x ( 1 + ki ) = 1 + ki - 1 - ( 1 + ki Canceling terms and simplifying further: (10) Po ki Manipulating equation (10) to solve for the cost of equity: (11)ki + g. Po This is the constant-growth DCF formula for the cost of equity and is often referred to as the Gordon model. " Note that this proof does not require any assumption of the relationship between and Demonstration that Expected Market ROE is Greater than Expected Book ROE when M/B Ratio is Greater than 1. Start by assuming that the expected market return in dollars (expected market ROE times the market value of equity) is equal to the expected book return in dollars (expected book ROE times the book value of equity), ki X M r Book X DIRECT TESTIMONY OF JOHN S. THORNTON - 54IPUC Case Nos. AVU-O4-1 and AVU-G-04- 1025 Move the expected rates ofretum to the right hand side and the equity values to the left hand side lvf r Book Now make the observation that if M/B equals 1.0 then rBook must equal ki because the ratio rBooJ!ki is also equal to one. However, if M/B is greater than 1.0, then the ratio rBoo,/ki greater than 1., and therefore, the expected book ROE must be greater than the expected market ROE. DIRECT TESTIMONY OF JOHN S. THORNTON - IPUC Case Nos. A VU-O4-1 and A VU-G-O4- 1026 (The following proceedings were had in open hearing. (Potlatch Exhibit No. 201 , having been premarked for identification , was admitted into evidence. MR . WARD:Mr. Thornton is available for cross -examination. COMMISSIONER KJELLANDER:Thank you.Let's move first to Mr. Meyer with Avista. MR . MEYER:Thank you. CROSS - EXAMINATION BY MR. MEYER: Good mornlng, Mr. Thornton. Good morning. In his rebuttal testimony, the Company witness Dr. Avera calculates the impact of your recommendation on pretax interest coverages , doesn't he? He calculates a pretax interest coverage for the recommended ROE.I do have a range , but, yes, I know what you're talking about. And in doing so , doesn't he arrive, again based on your recommendations, at a pretax interest coverage ratio 2 . 54? I believe he does. 1027 HEDRI CK COURT REPORTING P. O. BOX 578, BOISE , ID 83701 THORNTON (X)Potlatch Are you aware that S&P , or Standard and Poor' publishes guideline coverage ratios associated with a triple B bond rating? Yes, I am. And is it also the case that these ratios vary depending on the individual company's business profile ranking? Yes , they do.I think it might be called business risk profile, but Same thing? Same thing,yes. Do you know what guideline range for the pretax coverage ratio S&P has specified for a triple B utility with Avista's business profile ranking of six? While I don't have the S&P criteria in front of , I believe that the low end is 2. Would you accept that it is - - subj ect check -- that it's 2.6 to four times? That sounds about right, yes. Now, is it reasonable to suppose or believe that S&P will upgrade Avista I s bonds to investment grade Avista is unable to achieve coverage that even meets the very bottom of the range that S&P specifies for a triple B rating? Yes, I think it can be, because I think you need to understand how those ratios are used.A company can fall 1028 HEDRI CK COURT REPORTING O. BOX 578 , BOISE , ID 83701 THORNTON (X)Potlatch below those guidelines without actually incurring a ratings downgrade.So if Standard & Poor's believes that Avista Corporation is on the up swing and is doing the right things which in my opinion would be increasing the quantity of equity in its capital structure, decreasing the debt in the capital structure, which is going to be the biggest thing to work towards improving those coverage ratios - - as opposed to the Company doing those things that would harm itself financially, then I think Avista could continue on its uphill tick. But, the nub of this is that you don't disagree that the impact of your recommendation is to drive a pretax interest coverage ratio of 2.54, which is less than the bottom end of the S&P range.Correct? Well , I'd still have to do some investigation into his calculation.There's a bit of confusion I think if Dr. Avera is correct on that calculation.He might be, but the problem is that Mr. Malquist testifies that the trust-preferred securities are now counted as debt under the generally accepted accounting principles.So the quest ion remains why weren I they included as debt. ve seen trust-originated preferred securities handled in a couple ways, one of which is you don't see them a line item on the capital structure in the rate of return. They're simply included as part of the debt.So you, when you look at a debt schedule for a utility, the first thing that 1029 HEDRICK COURT REPORTING O. BOX 578, BOISE , ID 83701 THORNTON (X)Potlatch normally you would see is first mortgage bonds, medium-term notes, debentures , and perhaps trust -originated preferred securi ties.That way, the trust-originated preferred securities are included in the interest synchronization calculation done by the revenue requirement analyst. The other way I've seen it is wi trust-originated preferred securities as a line item in the rate of return , but at that point, the debt tax shield is taken out.So to give you an example , if combined State and Federal corporate income tax were, say, 35 percent and if your trust-originated preferred securities yield, which is a dividend yield, were ten percent, you'd see 6. 5 percent as the cost of the TOPRS.S is the acronym for that. So it doesn't matter much in this case , because there's not a lot of trust -preferred securi ties in the capi tal structure. Mr. Thornton , did you sponsor testimony regarding a fair rate of return on equity for Nevada Power Company before the Nevada Commission in January of 2004? Well , I did earlier this year.I forget if was January or February when we filed. Within that time? Do you have the case number offhand? I sure do.It's Docket No. 03-10001 and 03-10002. 1030 HEDRI CK COURT REPORTING O. BOX 578 , BOISE , ID 83701 THORNTON (X)Potlatch Yes, I did. All right.And what return on equity did you recommend in that case? I don't have that testimony in front of me. MR. MEYER:May I approach the wi tness? COMMISSIONER KJELLANDER:Yes. MR . MEYER:And I don't have the next exhibi number for purposes of identification.I would like to, though, have thi s marked as an exhibi t . Do we have that number?I m sorry. COMM IS S IONER KJELLANDER:We're get t ing somewhat close. MR . MEYER:I'd ask that a three-page document, the first page of which is a cover sheet from a Nevada Commission Order dated March 24 , 2004 , be marked for identification as Exhibit No. 31. COMMISSIONER KJELLANDER:Okay.So without objection , and without finding out later that we already have an Exhibi t 31 , we'll call this Exhibi t 31. MR . MEYER:Thanks. (Avista Exhibi t No. 31 was marked for identification. BY MR. MEYER:Mr. Thornton , would you agree that in that case , you recommended a return on equi ty of just over eight percent, or about 8. 1 percent? 1031 HEDRICK COURT REPORTING P. O. BOX 578, BOISE , ID 83701 THORNTON (X)Potlatch That sounds about right, yes. Now , what cost of long-term debt did you use in that case to develop the overall rate of return , if you recall? Well , that was a bit complicated.There were , as I recall , there were three costs of debt.The problem in that case, as I recall , is that the Company was asking for costs of short-term debt which were a large amount of fees - - it seems to me it was in the millions - - but they didn't have a line item for short-term debt in the capital structure which they normally do in Nevada.Just like we have long-term debt here, they have short-term.The problem is under that Company' financial statement , they weren't actually able to issue short-term debt. But is it -- I'm sorry. And there are other issues too in terms of the Company was asking for , it seems to me, millions in amortization of debt discount and expense on old debt that it had refinanced but wasn't able to show it was refinanced cost effectively.So the debt element of that case was a bit compl i ca ted Complications aside, was your recommended return on equity in that case lower than the long-term cost of debt that you used in that case? I'd have to check , but that sounds correct, basically. 1032 HEDRICK COURT REPORTING O. BOX 578 , BOISE , ID 83701 THORNTON (X)Potlatch Now , would you please turn to what has been marked for identification as Exhibit 31 , and this, in addition to the cover page with reference to that Nevada Commission case which is the cover page of the Order in that proceeding, I' provided some excerpts, and I'd like you to turn to the second page of thi s exhibi t , Paragraph No.2 06, pI ease? m there. Okay.m going to read this aloud: The traditional tools of analysis to determine the appropriate ROE with some modifications were utilized in this case.The resul t was a range of recommendations for the ROE from percent - - parens,Thornton end parens - - and a half percent - - parens,Morin end parens. Mr.Thornton bel ieves that return of percent which below the cost of debt, is justified.However , the Commission does not believe that a result showing the cost of equity capi tal below the cost of debt is a reasonable resul t . Mr. Fetter , a rating expert , points out, it would be very unusual to have such a situation.Dr. Avera points out that the resul ts must be examined to make sure they are reasonable. Accordingly, the Commission will give very little weight to this recommendation.As a consequence, the Commission will focus on the range of overall recommendations from 9. percent - - parens, Mr. Parcell's lower end - - to 12 and a half percent - - parens , Dr. Morin's upper end , end of parens. 1033 HEDRICK COURT REPORTING O. BOX 578, BOISE , ID 83701 THORNTON (X) Potlatch Have I read that accurately? Well, I wasn't following as you were reading. was listening to you. Would you accept, subj ect to check , that have? Yes. Now, in this case, let's fast forward.In this case , what are you recommending for Avista' s return equi ty? Well , as shown on Exhibit JST-, page 1 , I' recommending eight and a half percent for the return on equity. And what are you recommending in this case for Avista for the long-term cost of debt? ve got 8.70 percent , which is what I took from Mr. Malyn I s (sic) testimony. MR . MEYER:Thank you.That's all I have. COMMISSIONER KJELLANDER:Thank you. THE WITNESS:Could I make one comment about the section that you read though , and that is - - actually, that' my favorite part of that Order , because it really is not appropriate to compare a marginal forward-looking cost of equi ty wi th a historical cost of debt.That one paragraph basically eliminates any concern about the quality of that part of the Order.You simply can't compare an embedded cost of debt for a utility which could have first mortgage bonds that 1034 HEDRICK COURT REPORTING P. O. BOX 578 , BOISE , ID 83701 THORNTON (X)Potlatch are - - date 30 years ago, or let's say to 1981 , which was the peak of interest rates , wi th a forward-looking cost of equi ty, particularly in these times. If you look at page 6 of my testimony in which provide a chart of ten-year US constant maturity rates from developed by the US Treasury Department, you'll see that we currently at a very low trough of interest rates.So you can' compare a forward-looking cost of equity with a historical cost of debt. MR. MEYER:Mr. Chairman , wi th that , I move the admission of Exhibit 31. COMMISSIONER KJELLANDER:Thank you.Let's move now to Mr. Woodbury. MR. WOODBURY:Staff has no cross.Thank you. COMMISSIONER KJELLANDER:Mr. Purdy.Mr. Purdy. MR . PURDY:m sorry.No, no questions. COMMISSIONER KJELLANDER:Mr. Cox. MR . COX:No questions. COMM IS S IONER KJELLANDER:Are there questions from members of the Commission? Redirect, Mr. Ward? MR . WARD:Briefly. 1035 HEDRICK COURT REPORTING P. O. BOX 578, BOISE , ID 83701 THORNTON (X)Potlatch REDIRECT EXAMINATION BY MR. WARD: Obviously, from the excerpt that Mr. Meyer just read , Dr. Avera al so appeared in thi s Nevada Power proceeding, did he not? Yes, he did. Do you recall what his return on equity recommendation was? m sorry, I'm afraid I don't, offhand. Do you recall what the Commission actually adopted in this proceeding as the return on equi ty? Mr. Thornton , excuse me.Go ahead. Well , I believe it was 10.4 percent, but I' sorry, I don't know exactly. Okay. MR . WARD:Thank you.That's all I have. COMM IS S IONER KJELLANDER:Thank you , and thank you for your testimony. (The wi tness left the stand. MR . WARD:Mr. Chairman , may Dr. Peseau and Mr. Thornton be excused? COMMISSIONER KJELLANDER:Certainly, wi thout obj ect ion. Mr. Purdy, I believe we're ready for your 1036 HEDRI CK COURT REPORTING P. O. BOX 578, BOISE , ID 83701 THORNTON (Di)Potlatch wi tnesses Thank you, Mr. Cha i rman .Communi t YMR . PURDY: Action Partnership Association of Idaho calls Teri Ottens to the stand. Excuse me while I again move theMR . MEYER: admission of 31.I don't know that we had a ruling on that. The way that our RulesCOMMISSIONER KJELLANDER: work is that if I should forget to actually admit an exhibit that was introduced in the record, it's automatically admitted, and so we'll go ahead and admit it without objection. Okay.MR. MEYER: (Avista Exhibit No. 31 was admitted into evidence. TERI OTTENS, produced as a witness at the instance of Community Action Partnership Association of Idaho, being first duly sworn, was examined and testified as follows: DIRECT EXAMINATION BY MR. PURDY: Would you please state and spell your name? Teri Ottens, T-I, O- And by whom are you employed and in what 1037 HEDRICK COURT REPORTING P. O. BOX 578, BOISE, ID OTTENS (Di) CAPAI83701 capacity? m the executive director of the Community Action Partnership Association of Idaho, representing the low lncome people in Idaho. Thank you.And have you previously prefiled direct testimony in this case consisting of 12 pages? have. And you attached to that testimony and have relied upon Exhibits 401 through 406.that correct? Yes. And if I were to ask you the same questions today as contained in your direct testimony, would your answers be essentially the same? Yes, wi th one exception:On page 6, line 14, in estimating the number of households in the Avista service territory that were eligible for low income weatherization , I failed to take into account the co-op customers, which reduces that figure by about 30 percent.This oversight was brought to my attention last week by PUC Staff Anderson , and we had a discussion about it and I do agree that that was an oversight on my part. So you accept Mr. Anderson's adj ustment? Yes, I do. And how , if at all, does this affect the overall recommendations contained in your testimony and the substance 1038 HEDRI CK COURT REPORTING O. BOX 578, BOISE, ID OTTENS (D i ) CAPAI83701 of your testimony? I don t believe it affects it at all.What did was it reduced the number of years that we could catch up wi th the backlog of homes at the current rate from 70 years to 50 years, but I still feel that that is a significant number of years to wait to have all homes weatherized in North Idaho. And that backlog you referred to, the reduction from roughly 70 to roughly 50 years, is that a calculation that you re of the impression that Mr. Anderson prepared? Yeah.Yes. And you accept that as well? Yes. All right.Aside from these adjustments or corrections, does the rest of your testimony remain unchanged? That's correct. Mr. Chair , at this point, gl ven thatMR . PURDY: Community Action Agencies have reached a tentative agreement with Avista, if you would indulge me in a few additional direct questions to clarify that, I would appreciate it. COMMISSIONER KJELLANDER:That would be fine. Please continue. BY MR. PURDY:Ms. Ottens, since the filing your direct testimony, did , in fact, the Communi ty Action Agencies and Avista reach essentially what is a settlement 1039 HEDRI CK COURT REPORTING P. O. BOX 578, BOISE, ID OTTENS (Di) CAPAI83701 agreement with respect to the low lncome weatherization program? Yes, we did.We contacted Avista and they, as always, were very willing to work with us and talk to us about our position versus theirs.We did come to an agreement where the funding levels on an annual basis would be 350,000, and there are several program changes that we discussed that are in Mr. Stamper I s testimony. Program design changes? Yes, correct. So that $350,000 funding level , that's an increase from roughly what in terms of Avista-specific funds? Avista currently, if that's the question, Avista currently gives us about 110,000. Okay.Now in his direct testimony,Mr.Anderson set out number of $320,000,and he apparently obtained that figure by by looking at the Idaho Power lowcomparlng - - lncome weatherization Order and then making a per-customer calculation to try to determine what would be an equivalent award for Avista, and that, again , came to 320,000. Is there some justification that you could glve to the Commission for a slightly higher annual funding level for Avista? Our - - and it was one of the reasons thatYes. justifies our higher amount:The poverty rate in Idaho is much 1040 HEDRI CK COURT REPORTING P. O. BOX 578, BOISE, ID OTTENS (Di) CAPAI83701 higher than in the rest - - in North Idaho is much higher than the rest of the state.The rest of the State's average is a little under 12 percent -- it's about 11.8 -- whereas, the poverty rate in North Idaho is 14.29.So there is - - I think it justifies more need.There are more people unemployed up there.I think it justifies the fact that there are probably more homes that are now eligible. Okay.And are there any benefits to Avista' s ratepayers on the whole that you can identify resulting from an increase in funding to the low income weatherization program? Well, we think so.We think that weatherization is a DSM program, which means that you re going to see some energy savings which may delay the need to acquire maybe some higher-priced energy in the future. Also, we believe that if we can aid the low lncome in paying their utility bills and having reasonable utility bills, this helps the Company in uncollected debt, turnons, turnoffs, that type of thing, the costs that are associated with that. All right.Does - - on the whole then for the purposes of this proceeding, do you find the agreement that you reached with Avista to be acceptable to your organization? We do. Do you think that it fully meets all of the needs of Avista' s low income customers in Idaho? 1041 HEDRI CK COURT REPORTING O. BOX 578, BOISE , ID OTTENS (Di) CAPAI83701 There are - - there are many needs, andNo.No. weatherization is one of the ways that we can meet those needs. There are other ways, and, in fact, other states have implemented other ways, to meet the needs of the low income. And, in fact, we will be - - our organization will be introducing some legislation this year that we hope we'll be working with the utilities on some voluntary low income programs that might be allowed with some changes in the law. Okay.And, finally, I note that you urge the Commission to consider the limitations of low income customers in ruling on Avista' s proposed rate increase, but the scope of your involvement in this case has really been limited to the weatherization program.Is that to be construed as indifference on the part of your organization to these - - the general rate increase requests and the other issues that have been raised in these proceedings? Certainly not.We have - - our organization has limited resources and limited time, and there are many other lssues, including the impact that a rate increase has on low lncome, that we would have liked to have addressed but our resources at this time didn't allow us to do that as fully we would have I iked to. With that, Mr. Chairman, I would askMR . PURDY: that the direct testimony of Ms. Teri Ottens be spread upon the record as if read, and Exhibits 401 through 406 be marked as 1042 HEDRI CK COURT REPORTING O. BOX 578, BOISE, ID OTTENS (Di) CAPAI83701 identified. COMMISSIONER KJELLANDER:Thank you, Mr. Purdy. Without objection, we will spread the testimony as if read across the record, and admit Exhibits 401 through 406. (The following prefiled direct testimony of Ms. Ottens is spread upon the record. 1043 HEDRI CK COURT REPORTING O. BOX 578, BOISE, ID OTTENS (Di) CAPAI83701 I. INTRODUCTION Please state your name and business address. My name is Teri Ottens. I am the Executive Director of the Community Action Partnership Association of Idaho headquartered at 600 N. Curtis, Suite 175 , Boise, Idaho, 83706. On whose behalf are you testifying in this proceeding? The Community Action Partnership Association of Idaho ("CAP AI") Board of Directors asked me to present the views of an expert on, and advocate for, low income customers of VISTA on behalf of CAP AI. CAP AI's participation in this proceeding reflects our organization s view that low income people are an important part of A VISTA's customer base and that these customers may be uniquely impacted by the proposed rate increase. Specifically, CAP AI recommends that the Commission order an increased level of funding for A VISTA's low income weatherization program, as well as program design changes. CAP AI is an association of Idaho s six Community Action Partnerships, the Idaho Migrant Council and the Canyon County Organization on Aging, Weatherization and Human Services, all dedicated to promoting self-sufficiency through relnoving the causes and conditions of poverty in Idaho s communities. Community Action Partnerships ("CAPs ) are private, nonprofit organizations that fight poverty. Each CAP has a designated service area. Combining all CAPs, every county in Idaho is served. CAPs design their various programs to meet the unique needs of communities located within their respective service areas. Not every CAP provides all of the following services, but all work with people to promote and support increased self-sufficiency. Programs provided by CAPs include: elnploYlnent preparation and dispatch, education assistance child care, eillergency food, senior independence and support, clothing, home weatherization, energy assistance, affordable housing, health care access, and much more. Why is CAP AI intervening in this particular case? T'T"""""""'-".-r"' .-r"'~""""""T' ..", TT "T"' .-r"""""T"T ".-r"""""~' T'-'1044 CAP AI is of the belief that general rate cases are appropriate proceedings to address the vast majority of issues that affect rates, including funding of Demand Side Management programs. To encourage recognition of the value that low income assistance programs in particular play in helping our seniors, disabled and low incol11e fan1ilies to beCOl11e and to rel11ain self-sufficient and to seek funding and design of applicable programs that will accomplish these objectives. In the context of public utilities, these objectives can be furthered through low income weatherization and energy assistance programs. Without assistance from these programs, seniors and low income families can experience higher energy costs, pay a higher proportion of their income for energy and subsequently, fmd themselves in greater danger of being forced to be a further drain on the welfare assistance system or even into homelessness and cause A VISTA to incur debt collection costs and bad debt write-offs. According to discovery responses provided by A VISTA to CAP AI, the Company currently is carrying an "uncollectible" balance of roughly $2 million. VISTA mentions that write-offs have been higher than expected. In addition to the cost of uncollectible accounts, the Company incurs other costs when its customers cannot afford to pay their bills. These other costs are associated with arrearages, disconnection, reconnect ion, personnel and other administration. By providing a weatherization program to low income customers, the Company allows those customers to reduce their levels of consumption, and reduce the likelihood of non- payment of their bills. What is your relevant experience regarding matters before, or issues invo lving, this Commission? CAP AI has been involved in low income issues, including energy related issues, since the early 1980s. CAPs have been involved in the distribution of weatherization funding, implementation of weatherization programs, and Low Income Home Energy Assistance Program LIHEAP") payments for more than three decades. .........."'"'...................... ..............,..,............ ..".,. TTT "....... ...................... "......................,. T""1045 . 16 What other relevant involvement or activities have you or your organization been part of? As the Executive Director of CAP AI, I am the statewide administrator of the federal Community Service Block Grant, the Emergency Food Assistance Program, the Idaho Telecommunication Services Assistance Program, the statewide Weatherization program, and in working with the six Idaho CAPs and Canyon County Organization on Aging in the distribution of the Low Income Home Energy Assistance and the Weatherization funds. These, and other service programs administered and/or provided by CAP AI and our CAPs, all deal with the needs of the low income in Idaho. Previously, I worked as the Energy Director for the Association of Idaho Cities, working with 2002 cities and 44 counties to address energy and conservation issues within their respective jurisdictions. Prior to that, I worked with several local governmental entities in Idaho Wyolning and California dealing with both low incolne and energy related issues. Exhibit 401 to my testimony is my curriculum vitae. Have you previously testified before this Commission? Yes, CAPAI intervened in the recent Idaho Power Company general rate case (Case No. IPC-03-13) and I testified on behalf of CAP AI in that proceeding in the same capacity in which I offer this testimony. CAP AI intervened in this proceeding prior to issuance of the fmal order in the Idaho Power rate case. II. SUMMARY Please summarize your testimony? My testimony will establish the following: That A VISTA's proposed rate increase would have significant implications for the Company s low income customers; That these low income customers are at risk of paying a disproportionate percentage of their income for a basic need commodity essential to human ........ T"no """"-'rr"' rr""""""" rr"'T' .."....., TT "..... T"\ rr""""'"no T "..... rr"'rr""""" T"'" 1046 survival, exposing them to potential payment arrears, disconnection of electricity, and even homelessness; That there is a significant number of residential customers who are low income and are in need of assistance in lowering their energy bills through home weatherization, and other means, and; That A VISTA's low income weatherization program provides relief to the Company s impoverished customers as well as system-wide benefits to ratepayers and shareholders in the form of reduced debt collection costs, arrearages, and write-offs. ill. NEED FOR ASSISTANCE What defInitions are you using to describe a "low income household" and how many of these households are located within the service area of A VISTA? The state of Idaho uses an income defmition to defme eligibility for low income weatherization and energy assistance as 150% of the federal poverty guidelines as established by the Federal Office of Management and Budget. Exhibit 802 to my testimony provides a chart of incomes in relation to the poverty level. Would you please provide the Commission information regarding the state of poverty in Idaho and, more specifically, within A VISTA's service territory? Yes. According to the Idaho Department of Commerce, 12% of Idaho s population . 20 based on the 2002 Idaho Census, fall within federal poverty guidelines and 21 % fall within the state guidelines set at 150% of the federal poverty level. The Idaho Census is a state update of the Federal 2000 Census figures and is conducted by the Idaho Department of Commerce. "T' T"Mo"-""1'T' I'T"'-' r'OI'T'T'" .. "... T"" 7' "....., I'T"'-'"Mo T "I'T'I'T"'-"" Tr'O 1047 Specific to A VISTA, the poverty rate in the ten northern counties 1 is 14.29%, based on Idaho guidelines, thus, higher than the statewide average by approximately 17%. The 2000 Idaho Census reveals that those living in poverty are categorized as 8.30/0 elderly, 13.8% children, 8.30/0 all other families, 35.3% single mothers and 34% all others. Do you have relevant information based on numbers of low income households? Yes, according the A VISTA's response to CAPAI's discovery request there are 106 515 total electric customers in Idaho of which 91 076 are residential customers (i.e. households) served in 2002. Of the residential customers in the A VISTA service territory, based again on 2000 Census figures, it is estimated that almost 24 700 households, or 26% of customers in the AVISTA area, are at or below 150% of the federal poverty level (see Exhibit 403). According to 2002 LlHEAP statistics obtained from the U.S. Department of Energy, 923 households were eligible in Idaho for assistance and 29 867 households (74 693 people) statewide received LIHEAP assistance. In 2003 , 9 449 households applied for LIHEAP funding out of the estimated 24 700 eligible, representing only 38% of those eligible. Exhibit 404 contains figures confIrmed by the Idaho Department of Health and Welfare concerning the LIHEAP funds distributed in A VIST A territory in 2003. Please discuss the "ability" of low income customers to pay their monthly energy bills? According to the U.S. Department of Energy ("DOE"), the "affordability burden" for total home energy is set nationwide at 6% of gross household income and the burden for home heating is set at 2% of gross household income. According to the Idaho LIHEAP data provided by the Idaho Department of Health and Welfare ("IDHW"), 7.60/0 of all LIHEAP program participants fall into the "High" energy 1 Benewah, Bonner, Boundary, Clearwater, Idaho, Kootenai, Latah, Lewis, Nez Perce, and Shoshone. -r-.T..-.......,""'""", ,...,.,.....,ro,...,.,T, ..",. T" ",..., ,...,.,.....,..-..T ",...,."...,.,.....,... Tro r::.1048 burden category, paying 11 % or more of their annual income for utilities ("medium" burden is determined to be 5-10% of annual income and "low" is considered at less than 50/0. IDHW does not keep statistics for Inediu111 or low burdens. Exhibit 405 fron1 the Idaho Deparhnent of Health and Welfare shows these figures. IDHW's data also support a recent study conducted nationwide by Fisher, Sheehan & Colton, a public fmance and general economics consulting fIrm. That study is attached to this testimony as Exhibit 406. This study is an extremely well-known work rel!ed upon nationwide by a myriad of different organizations and governmental entities. I rely upon it frequently in conducting my business affairs. Based on the Fisher study, the following statistics apply to Idaho. % OF INCOME FEDERAL % OF INCOME PAID ON # OF HOUSEHOLDS POVERTY LEVELS 2002 HOME REA TING 50% of poverty level 45%000 50- 75% of poverty level 18%000 75-100% of poverty level 16%000 100-125% of poverty level 11%000 125 to 150% of poverty level 000 Will you please provide a context for foregoing figures? According to the Fisher, Sheehan & Colton study, these figures represent a gap of $96 000 000 between what Idahoans could afford to pay (based on federal standards) for energy in 2002 and what they actually did pay. This gap is expected to increase to $113 million in 2003 based on rising energy costs. Currently, the LlREAP program funds $10.5 million (for energy assistance, weatherization and administration) to the state of Idaho providing an average benefit of $202 per household to help close, but far from eliminate, this gap. What are some other relevant demographics of low income customers? TTOo ~'-"rT"' ~,.., rT"'T' ........., T"" ....... -y-, rT"'~ TOo ,.... rT"'rT"'T"" T,.., 1049 According to the 2000 Census, approximately 32 688 customers occupied units (representing 35.80/0 of the total residential customers in the A VISTA service area) heating primarily with electricity. Almost all households that are low income use electricity for lighting, refrigeration and small appliances. Idaho 2002 State Weatherization program data shows that 1487 homes were weatherized with D.E. funds in the amount of$I 997 798 at an average of 344 per home. An additional 995 were weatherized by LIHEAP funding and 132 by Bonneville Power Administration (for 2002-2003 only). To date, according to the CAP receiving A VISTA weatherization funds, approximately 1391 households in A VISTA's Idaho service area have had weatherization measures installed by Company programs since 2000. VISTA (including its predecessor Washington Water Power Company) has contributed weatherization program funds since 1980. Based on currently existing electrically heated homes weatherized with A VISTA funds (average of21 households per year) and other funding, we can assume that an average of300 households per year have been weatherized in the past ten years (one must understand, however, that even if households were weatherized in the past, they will require future weatherization measures). Based on 300 homes per year over the past ten years, approximately 3 000 homes out of 700 determined to be currently eligible have been weatherized. It is estimated, therefore, that over 21 000 households in A VISTA's Idaho service area are currently eligible and in need of funding. At a rate of300 households per year (based on and including past and future anticipated funding levels of A VISTA, D.E. and B.A. weatherization programs) it will take nearly 70 years to weatherize all households in A VISTA's Idaho service area that are eligible and in need of weatherization. As previously mentioned, the poverty rate in the A VISTA service area is considerably . 24 higher than the statewide average at 14.29% colnpared to 12% statewide. Furthennore, A VISTA ~y............,........... """""""""""""Y'" ..r-..... T...- r-..T"' """"""""'Y r-..,..."...,......... Trt 1050 has a higher percentage of total households eligible than Idaho Power at 26% compared to 18%. This is due to higher poverty and unemployment rates. Please discuss the level of energy costs in relation to the ability of low income customers to pay those costs? More than 11 358 of the households in the A VISTA Idaho service area have annual income of less than $9 000. The average yearly energy bill for low income customers is $1 607 with 30-35% of that amount spent on home heat alone. Though low income people are more easily described in statistical tenus, in reality they are our neighbors, friends and relatives. Whe considering the possibilities of accidents, ill health, loss of employment, etc., they potentially include each of us. What are the special circumstances that low income households face? These households pay the highest percentage of their income for energy costs compared to other income groups and are the most vulnerable and at risk to change in a competitive market. They live in society s worst case housing stock, are at risk to hypothermia and indoor air quality problems. Coupled with an array of other fmancial burdens (cost of child care, lack 0 affordable housing, lack of living wage jobs, cutbacks in federal assistance of most kinds, etc. they are increasingly moving closer to homelessness. Often, the affordability of a utility bill can mean the difference of eating, a medical prescription, having a roof over their heads rather than living in a car, or worse. When calculating the average take-home pay of a low income head of household, and deducting basic living expenses such as housing (often 70% of their income), childcare and food, they are in fmancial crisis before even looking at the cost of utilities, clothing, transportation, and other basic needs. . 24 What is the need for electrically heated weatherization and efficiency retrofits? T"'o.T~"""""""""'" """"""""..".......T, ",... T...-T ,........., """"""~T ,....,.......,..............,... T,..,1051 According to IDHW, there are approximately 21 000 households in A VISTA's service area that remain to be weatherized. According to CAP data, only 85 households have been weatherized since 2000 with A VIST A funds. These funds have been supplemented with federal weatherization funds bringing the total to approximately 300 households per year. At the current level, with all current funding sources it would still take almost 70 years to reach all eligible homes in the A VISTA Idaho service area. In responses to CAP AI's production requests, A VISTA stated that its Idaho gross operating revenue for 2002 was $229 561 337. The Comprehensive Review of the Northwest Energy System, sponsored by each of the Governors of the four Northwest states asked for each utility to spend 3$ of its gross operating revenues for public purpose energy programs. Of that , 14% was to be spent for low income weatherization. Fourteen percent of3% of their Idaho revenue for A VISTA then suggests a weatherization program level of$964 158 annually. As set forth in the testimony of Mr. Larry Stamper, A VISTA's current funding level is a slnall fraction of this alnount, allowing for the Weatherization of an average of 21 holnes a year. CAP AI requests that A VISTA's funding level be increased to the level identified in Mr. Stamper s testimony and that the program more closely match D.E. requirements so that funding can be utilized on all homes meeting the eligibility requirements. You previously testified that you participated in the recent Idaho Power general rate case. What was the nature of your request in that case? CAP AI took a position on several issues in that case, including matters of rate design, as well as an increase to funding levels of Idaho Power s low income weatherization program and program design changes. How did the Commission rule on the low income weatherization issues raised by CAP in Case No. IPC-03-13? ~T-r..~.......'T" 'T"~""'T"T' r"""T....r,......,..., 'T"~-r..T """T"'T"~'T""1 () 1052 The Commission granted the full amount of LIW A funding requested by CAP AI in the amount of $1.2 million per year for at least the next three years and suggested an increase in administrative project costs, among other things. CAP AI is immensely grateful to the Commission for recognizing both the plight of the impoverished, and the tangible benefits to ratepayers and shareholders provided by Idaho Power s LIW A program. Though there are some fundamental differences between A VISTA and Idaho Power and their respective custolners, CAP AI's objective with respect to weatherization funding in this case is to propose a funding level for A VISTA that is in relative parity to Idaho Power s funding level as recently ordered by this Commission. IV. CONCLUSION Could you summarize your recommendations to the Commission? Yes. They are listed below: Do not approve a general rate increase, and associated customer class revenue allocation, without taking into consideration the disproportionate impact that it will have on the ability of low income customers to pay; Increase electric low income weatherization and efficiency retrofits from its current level to $490 000 annually as proposed by CAP AI witness Larry Stamper; Allow for contract changes in the A VISTA low income weatherization program to include windows and doors as part of the S.I.R. of 1., baseload measures as proposed, eligibility requirements to met D.O. E. and explained in detail, by Mr. Stamper. Does that conclude your direct testimony? Yes it does. I thank the Commission for the opportunity to participate in this proceeding. T...-.. -r-.,-,rT' rT'-r-. r"'OrT'T' """ TT "T"' rT'-r-....-.. T "rT'rT'-r-.... Tr"'O 1 1 1053 (The following proceedings were had in open hearing. (CAPAI Exhibit Nos. 401 through 406, having been premarked for identification, were admitted into evidence. That's all I have.Thank you.MR . PURDY: COMMISSIONER KJELLANDER:Thank you. now for cross.Let's move to Mr. Woodbury. MR. WOODBURY:Thank you, Mr. Cha i rman . to Ms. Nordstrom. We're ready I defer MS. NORDSTROM:Staff has no questions, thank you. COMM IS S IONER KJELLANDER:Thank you. now to Mr.Meye r. MR.MEYER:And I have no quest ions. COMMISSIONER KJELLANDER:Thank you. Mr. Cox. MR . COX:I have no quest ions. COMMI S S IONER KJELLANDER:Mr. Ward. No questions.Thank you.MR . WARD: Let's move Thank you. COMMI S S IONER KJELLANDER:Are there questions from members of the Commission? I f not, then we thank you very much for your testimony, and thanks for your presence today. (The wi tness left the stand. 1054 HEDRICK COURT REPORTINGP. O. BOX 578, BOISE, ID 83701 OTTENS (D i ) CAPAI Mr. Purdy, if you wouldCOMMISSIONER KJELLANDER: like to call your next witness? Yes, sir.Community Action callsMR . PURDY: Larry Stamper. LARRY STAMPER produced as a witness at the instance of Community Action Partnership Association of Idaho, being first duly sworn, was examined and testified as follows: DIRECT EXAMINATION BY MR. PURDY: Would you please state and spell your name? My name is Larry Stamper , L-R- Y And by whom are you employed and in what capacity? I am employed by Communi ty Act ion Partnership as the weatherization director. And where do you reside, Mr. Stamper? We're located at 124 New Sixth Street in Lewiston. That's your business address? Yes. 1055 HEDRI CK COURT REPORTING O. BOX 578, BOISE , ID STAMPER (Di) CAPAI83701 So you provide low income weatherization serVlces for the - - for North Idaho.Correct? Yes.We provide weatherization serVlces to the low income families in Region One and Two, which encompasses the ten counties of Northern Idaho. Commission? Okay.Have you previously testified before this No, I have not. All right.And did you, in this case, previously prefile direct testimony consisting of seven pages? that correct? today in your the same? Yes, I have. And there are no exhibits to your testimony. No.Tha t 's correct. If I were to ask you the same questions contained prefiled direct testimony, would your answers be Yes, they would. All right. MR . PURDY:And, again, Mr. Chairman , at this point, if I could just ask a couple additional questions? COMMISSIONER KJELLANDER:Yes, Mr. Purdy. MR . PURDY:Okay.Thank you. BY MR. PURDY:You just heard Ms. Ottens testify about the agreement that Community Action reached with Avista. 1056 HEDRI CK COURT REPORTING P. O. BOX 578, BOISE , ID 83701 STAMPER (Di) CAPAI Were you part of the settlement discussions that led to that agreement? Yes, I was. Do you think that Ms. Ottens has accurately characterized that agreement? Yes, I do. All right.And is it fair to say that all of the - - all of the program design changes that you proposed in your direct testimony were agreed to by Avista? Yes, they were. The only issue that was adjusted somewhat pertains to the level of funding.Is that right? Yes, that's right. Okay.And could you just briefly explain why these program design changes are important to you, as the low income weatherization manager for North Idaho? The reason the program changes are important to the program is the fact that as the weatherization program for Avista stands now , it's not a standalone program.And what I mean by that is that it requires other funding, such as DOE, to supplement part of that.Avista did not pay for all measures, and al so, there was an R requirement.So it pulls an extra strain on those funds available for the other low income families. For those of us not in the trade and that don' 1057 HEDRICK COURT REPORTINGP. O. BOX 578, BOISE , ID STAMPER (Di) CAPAI83701 know what an "R requirement" is, for example, is it fair to just generally say that these program design changes provide you with greater flexibility Yes. - - ln weatherizing low income homes? Yes, it does. All right.And, finally, is there any doubt at all in your mind, Mr. Stamper, that you'll be perfectly able to utilize the entire $350,000 -- Not all. - - funding annually? expend our funds annually that we have available to us, and we could expend additional dollars if they were available with these program changes. Also, we would like to thank Avista for their coopera t ion wi th the program in making these program changes available to make it more easily-administered and program-friendly for the low income families of our service area. All right.Thank you. Thank you. Wi th that, Mr. Chair, I would askMR . PURDY: that the direct testimony of Larry Stamper be spread upon the record as if read. Thank you, Mr. Purdy.COMMISSIONER KJELLANDER: 1058 HEDRI CK COURT REPORTING P. O. BOX 578, BOISE , ID STAMPER (Di) CAPAI83701 And without objection, we would spread the direct testimony of Mr. Stamper across the record as if read. (The following prefiled direct testimony of Mr. Stamper is spread upon the record. 1059 HEDRICK COURT REPORTING O. BOX 578, BOISE , ID STAMPER (Di) CAPAI83701 I. INTRODUCTION Please state your name and business address. My name is Larry Stamper and I am the Weatherization Program Director for Community Action Partnership (CAP) located at 124 New 6th St., Lewiston, ID. 83501. Please provide a brief description of your organization? CAP is one of six CAPs statewide. We are a non profit organization that provides services to low income citizens in Region 1 and 2 of North Idaho. Region 1 includes the counties ofBenewah, Bonner, Boundary, Kootenai, and Shoshone. Region 2 includes the counties of Clearwater, Idaho, Latah, Lewis and Nez Perce. Our service area starts just north New Meadows and runs approximately 350 miles north to the Canadian border, encompassing the entire North Idaho Panhandle. CAP? Please describe the scope of your relevant work experience and responsibilities with As Weatherization Progran1 Director, I an1 responsible for providing energy conservation measures to low income househo Ids within our two-region service area, with priority given to elderly, disabled and households with "high" energy burdens, as determined by the Idaho Department of Health and Welfare. I have worked for CAP for more than twenty years, seventeen as the Weatherization Program Director. Although I am responsible for a large service area, I am a hands-on Director who is frequently in the field performing energy audits on income eligible homes. As such, I personally observe the daily struggles that low income families must endure. This might appear as small children wrapped in coats to stay warm in a poorly heated, drafty home. It might be entire families living in only one room of the home because they cannot afford to heat the entire structure. I am often contacted by the elderly who tell me they cannot afford to purchase their medication because they do not have any money left after paying for shelter, utilities and food. ~T""""...."...ry-, """""",...,ry-,T'" ..,..."... TTr ,...",....,.... . """,""",Tr ,...,ry-,.... .""....,"""' 1060 Often, I observe individuals who have installed alternative forms of heat into their homes that constitutes a serious safety and health risk, for example, un-vented oil, kerosene and propane heaters, improperly installed wood stoves, etc. These desperately fashioned heating devices are particularly harmful to the elderly, infITm and to children, but the choice of those using them is to either accept the risk of exposure to toxins and rITe, or to freezing. II. VISTA WEATHERIZATION PROGRAM Please describe the programs funded by A VIST A? CAP receives funding from A VISTA to provide energy conservation measures to electrically heated homes of low income customers located within AVISTA's Idaho service area. Pursuant to its contract with A VIST A, CAP is allowed up to 150/0 of the subtotal for health and safety measures and 15% for Administrative costs. There are two specific programs that A VISTA funds. The fITst is the regular weatherization program. With this program, CAP is reimbursed for major weatherization measures such as attic, wall, and floor insulation, duct and pipe wrap, as well as infiltration (i. air leakage). In order for a home to qualify for funding under this program, it must have an " number, which is the total kilowatt usage per year, of at least 4000, and at least one major measure addressed (e., attic insulation). As discussed later, I propose that this R number requirement be removed from the contract with A VISTA. The reason I make this recommendation is that many customers who are in need of weatherization and qualify as low income, are relatively low electricity users. Seniors, in particular, are quite frugal in their consumption of electricity. The R number is provided by A VISTA and is the reason why many homes with alternative heat sources do not qualify for this program. The second A VISTA program is the "Energy Exchange Program." This program pays for the change-out of electric space heat and water heat to natural gas. Under this program, CAP is reimbursed 00% of actual costs, but also requires an "R number" of at least 4000. This """'T~"-"""""" """"-',...,.....,T... r"... TTT "..-. T ~~TT ,...,....., . ... r~..-.~ 1061 means that to qualify for weatherization, the household must consume more than 4000 kilowatt 2. hours per month. ill. Please describe the typical housing structure that low income A VISTA customers reside Approximately 55% of the housing stock are mobile homes. These homes are generally in fair condition, but because of the nature of their construction, they are highly energy inefficient. As mentioned, they often have had added to them a secondary, unsafe, heat source. Because of problems associated with the use of aluminum wiring, the inability to install wall insulation, and A VISTA's R nulnber criterion, these hon1es usually do not qualify for A VISTA' regular weatherization program and receive no funding ftom the Company. This places additional burden on D.E. resources which have already been drastically reduced based on the 2000 Census. In 2003, CAP was granted federal funding of 128 homes in the Region 2 area and 185 homes in Region 1. For 2004, CAP's funding will allow weatherization of only 93 homes in Region 2 and 187 in Region 1. This does not include any A VIST A funding. Is there a backlog of households eligible for weatherization funding under the A VISTA weatherization program? Yes. CAP is unable to advertise the weatherization program because it has already exhausted its allocated monies. To advertise would only provide false hope to those in need. Because of the small number of households in some counties, CAP has a very large waiting list. For example, in Lewis County, CAP has more than 60 households on its waiting list and is projecting only 5 households weatherized per year in that county. In Idaho County, there are approximately 100 households on the waiting list and we are projecting weatherizing only 20 per year in that county. Clearwater County is our largest county with approximately 145 households waiting weatherization. We project being able to "",T"""'~""""'" ~roo"""T" "~"'T""'" ~....., T . ...................,. roo.....,... ~T""1""'"1062 weatherize only 10 units per year in that county. Clearwater County was hit hard, economically, over the last few years when the Potlatch plywood mill was shut down. We have more people on our priority list than we have available federal funds for these three counties alone. Occasionally, CAP attempts to update its waiting lists and remove those whose income eligibility has lapsed. Some of those customers have given up seeking weatherization due to their perception that it will never occur and the inconvenience of being required to re-verify their eligibility every year. Are there any program changes that you recommend? Yes. I propose changing the current contract between A VIST A and CAP to add windows and doors as allowable weatherization measures funded by A VIST A toward meeting the S.I.R. ("savings to investment ration ) of 1.0 and to allow for base load measures to be included. Base load measures include non-heating or cooling measures such as energy efficient appliances. In 2004 alone, 9449 households qualified for LlHEAP making them also eligible for A VISTA's weatherization program. There are approximately 21 000 households currently eligible for A VIST A weatherization. At current funding levels and program design, it would take nearly 70 years to meet all the needs in North Idaho. In light of this, do you recommend increasing A VISTA's low income weatherization level of funding? Yes. I propose increasing A VISTA'S funding to the weatherization program from the current 2004 level of$108 208 (Idaho only) to $490 000. What is the basis for this recommendation? Assuming the incorporation of my proposed program design changes (to include base load measures as allowable costs, eliminate the R number requirement, etc.), CAP would be able -r-..T~T"'.rtrT"' rT"'T"'rorT"'T'" r", TTr "T"' T . ~~Tr rorT"' . ... """'T"'~r::,1063 to weatherize 123 A VISTA units in North Idaho. This constitutes an average of 10 per month at an average cost of $4 000 per unit and a total budget of $490 000 annually. How does this recommended funding level compare to the Idaho Power low income funding level recently approved by the Commission? Idaho Power has 61 000 customers below 150% of the federal poverty guidelines in its Idaho service area. VISTA has 25 000- such customers. Thus, the $490 000 budget for VISTA would be proportionate to the $1.2 million Idaho Power budget. III. CONCLUSION Would you please summarize your recommendations to the Commission? Yes. I recommend the following: Make necessary changes to the A VIST A weatherization program so that it correlates to D.E. regulations and includes addressing all measures which show an S.I.R. of 1.0 or better. This includes weatherization of doors and windows and base load measures. Increase A VISTA's low incomer weatherization funding level to $490.000; Amend the weatherization program to qualify all A VISTA households using electricity as the primary heat source for weatherization, no matter what secondary fuel source is being used. People with all electric heat typically install secondary heat sources because of the relatively high cost of electricity as a heating source. Amend the weatherization program to eliminate the R number requirement. Again, all households with electricity as the primary heat source should automatically qualify for weatherization. Does this conclude your testimony? Yes it does. ......................."..."..., ,...,......"...,...,...... '-"""" T....r"...,."-"" . ................r,...,..,...,.... .".......,..,. c::. 06L~ (The following proceedings were had in open hearing. And we're ready now forCOMMI S S IONER KJELLANDER: cross, and I believe we are ready for -- oh, let's shake it up a little bit -- Mr. Ward. No questions, thank you.MR . WARD: Mr. Cox.COMMI S S IONER KJELLANDER: No question.Thank you.MR . COX: COMMI S S IONER KJELLANDER:Mr. Meyer. MR. MEYER:Bet ter wake up.Sorry. quest ions.Sorry. COMMI S S IONER KJELLANDER:Let's look for the Counsel representing PUC Staff. Thank you.MS. NORDSTROM: CROS S - EXAMINA T I ON BY MS. NORDSTROM: Good morning, Mr. Stamper. Good morning. I just had one question to clarify your testimony.In your description of the regular weatherization program on page 3, line 16, you include the qualifying condition of a household using at least 4 000 kilowatt hours per year, but at the end of your description of the energy 1065 HEDRI CK COURT REPORTING O. BOX 578, BOISE , ID STAMPER (X) CAPAI83701 exchange program at the top of page 4 , you mention the qualifying condition of 4 000 kilowatt hours per month. Is the per-month reference an error? Yes, that is an error.I apologize for that. So it should be It should be yearly. Okay.Thank you. MS. NORDSTROM:That's all I have. COMM IS S IONER KJELLANDER:Are there any questions from members of the Commission? And an opportunity for redirect, even though it' very slim? MR . PURDY:I have none, thank you. COMMISSIONER KJELLANDER:Thank you. We thank you for your testimony and your presence here today. THE WITNESS:Thank you very much. (The wi tness left the stand. COMMI S S IONER KJELLANDER:And as we move forward, I believe we're ready now for Staff and its remaining wi tnesses. MS. NORDSTROM:Thank you.As its third witness Staff will call Patricia Harms. 1066 HEDRICK COURT REPORTING O. BOX 578 , BOISE, ID 83701 STAMPER (X) CAPAI