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HomeMy WebLinkAboutholm.pdf 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 1 Q. Please state your name and business address for the record. A. My name is Alden Holm. My business address is 472 West Washington Street, Boise, Idaho. Q. By whom are you employed and in what capacity? A. I am employed by the Idaho Public Utilities Commission (Commission) as a senior auditor in the accounting section. Q. What is your educational and professional background? A. I graduated from Boise State University in 1994 with a B.B.A. degree in Accounting. In 1998, I completed a Masters Degree in Public Administration from Boise State University. I have attended the annual regulatory studies program sponsored by the National Association of Regulatory Utilities Commissioners (NARUC) at Michigan State University. Prior to joining the Commission Staff in 2000, I worked for two years as an accountant at the Boise Metro Chamber of Commerce and two years as an accountant at Rocky Mountain Audio Visual, Inc. Q. What is the purpose of your testimony in this proceeding? A. The purpose of my testimony is to describe purchased power costs, surplus sales and new accounts in the Power Cost Adjustment (PCA) mechanism. I will give IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 2 my analysis of the Company’s securitization proposal and describe my recommended changes to the PCA carrying costs proposed by Idaho Power Company (Idaho Power; Company). Q. Please provide a summary of your recommendations in this case. A. I recommend that Idaho Power be allowed to recover the majority of the costs included in its IPC-E-02-3 Application. I have made four adjustments to the amount Idaho Power requested. The first adjustment is to remove the reduced revenues associated with the Irrigation Load Reduction Program. Second, I removed part of the expenses associated with the mobile diesel generators. Third, I removed a portion of the Gas Fuel Expenses for unused transportation expense. Finally, I removed a capital expense from the Gas Fuel Expense account. I recommend that the Company not be allowed to securitize the requested $172 million. I believe the risks and expenses incurred by customers by securitizing outweigh the benefits to the Company. I also recommend that the Company not be allowed to change the interest calculation for the normal PCA period. Instead, I recommend that the Company be allowed to recover reasonable interest costs on amounts that are deferred for more than one year. IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 3 Purchased Power and Surplus Sales Q. Did you audit the Company’s PCA filing? A. Yes. I performed an extensive review of purchased power expenses, surplus sales, and other actual expenses and credits in addition to a review of all the new accounts in the PCA this year. Q. What did you find in regards to the purchased power expenses and surplus sales? A. With the exception of the real-time transactions, I found that the sales and purchases had been properly recorded according to Commission-authorized methods. Q. How were the power transactions priced? A. There are typically three kinds of power products that the Company bought or sold. They are term, day ahead, and real-time. Each of these is priced in a different manner. Q. Please describe the manner that the term purchases are priced and provide the audit results of the term transactions. A. The term transactions are transactions that involve purchases or sales of more than one month’s worth of power. Idaho Power sells surplus power when available or purchases needed power from various parties as determined by the Risk Management Committee. The IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 4 transactions are priced at the actual purchase or sale price, and are not bought or sold to or through IDACORP Energy. During the PCA year, the Company entered into several long-term transactions. Most of the transactions were purchases. All the long-term purchases or sales were authorized by the Risk Management Committee and carried out in a timely manner. The Company did enter into a few sell transactions longer than one month but not longer than three months. One transaction of note took place last year. During November 2001, the Company took action to replace some transactions that were in place with Enron when it became apparent that Enron was no longer an appropriate trading partner. The Risk Management Committee authorized the replacement transactions, and they were accomplished with little expense. These replacement transactions removed the potential risk to Idaho Power inherent in the Enron transactions. Q. Please describe the day ahead transactions, the manner that they are priced and the results of your audit of those transactions. A. The day ahead transactions are purchases and sales that are for the next day’s use. They are purchased entirely from the Company’s affiliate, IDACORP IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 5 Energy. The purchases and sales are priced at the Mid-C index price for the day the energy is delivered with additions or subtractions for the price of transmission. The Commission previously approved and now requires this pricing mechanism, and the Company carried it out appropriately. In reviewing the day ahead purchases and sales, I discovered no irregularities that required Commission action. Q. Please describe the real-time purchases and sales, the manner that the real-time transactions are priced and the results of your audit. A. The real-time transactions are purchases or sales carried out the day and hour the energy is needed or becomes surplus. All real-time energy is purchased from or sold to the Company’s affiliate, IDACORP Energy. During the PCA year, the Company changed the way the transactions were priced. From March 2001 through June 2001, the real-time transactions were priced at the weighted average price of all real-time transactions on the Idaho Power system. This method was approved by the Commission, but currently is being reviewed by the Federal Energy Regulatory Commission (FERC). In July 2001, the FERC contacted the Company and required a change in the way these transactions were priced. The FERC proposed that real-time sales to Idaho IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 6 Power be priced at IDACORP Energy’s highest purchase price in each hour and that the real-time purchases be priced at the lowest sales price in each hour. At a first glance, this pricing mechanism seems to provide a reasonable method to price the energy. However, as outlined in the Company’s testimony, it has proved to be inappropriate. As required by the FERC, the Company changed the way the transactions were priced. However, Idaho Power is working with the FERC to establish a more appropriate pricing mechanism. Q. Do you agree that the adjustment made by the Company for real-time transactions is appropriate? A. The adjustment for real-time transactions provides customers the benefit of pricing based on regional markets, which Idaho Power believes to be a more appropriate pricing methodology than that required by the FERC. I have reviewed the adjustment and agree it is needed to reflect a more equitable transfer pricing methodology for both the Company and its customers. The adjustment results in $4,306,635.82 being credited to the customers after jurisdictional sharing and interest. Q. Do you have a recommendation for real-time pricing? A. I believe that real-time pricing should be IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 7 based on regional markets that reflect the cost of power bought and sold in this area. The Company should continue to work with the FERC to develop a more reasonable transfer pricing methodology. In addition to the method proposed by the Company, Staff would support the FERC method if it included only transactions in the Northwest and used the Mid-C Index when there are no other relevant transactions in a particular hour. Once a method is established with the FERC, it should be filed with the Commission and evaluated by Staff. Q. Did the Company follow the operational reports and recommendations of the Risk Management Committee? A. I reviewed the Risk Management Committee meeting minutes to make sure the Company was operating in the best interest of the ratepayers. During the PCA year, the Company instituted a Risk Management Committee for Idaho Power that was separate from the committee for IDACORP. At each regularly scheduled meeting, an operational plan was presented to the committee. This plan was prepared by Company personnel to show price forecasts, energy deficiencies and surpluses, and other factors that affect the Company’s ability to operate. I reviewed these operating plans and found that they were reasonably based on the best information available at the IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 8 time. The Risk Management Committee used the information to take appropriate action. I found that the meetings and actions were well documented and that the Company followed up appropriately. New Accounts in the PCA this Year Q. What new accounts were included in the PCA this year? A. There were several new accounts in the PCA this year. They included expenses relating to the Irrigation Load Reduction Program and associated Reduced Revenues, the Astaris Load Reduction Program, Mobile Generation Costs, Gas Fuel Expenses relating to the Danskin facility in Mountain Home, Mobile Home Metering shortfalls, Intervenor funding from a variety of cases and a credit associated with the IDACORP Energy contract. Q. Would you describe each new account and make a recommendation regarding the reasonableness of the expenses? A. Certainly. I will describe each account, give the Commission order number that addressed the issue, and make recommendations for recovery of the proposed expenses and credits. Irrigation Load Reduction Program - These expenses relate to the Commission-approved program to pay irrigators to reduce their consumption of energy. In IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 9 Order No. 28992, the Commission authorized the Company to recover direct costs associated with the program. The Company has identified, and I have verified $73,941,839.42 of direct program costs. These costs consist entirely of payments to irrigators in exchange for reductions in irrigation loads. I found this amount to be included in the PCA account appropriately. Reduced Revenues – These revenues were calculated by the Company to provide it with revenue it claimed was lost when irrigators participated in the Irrigation Load Reduction Program. As per the Commission’s Order No. 28992, in Case No. IPC-E-01-34, the recovery of reduced revenues was denied. Therefore, I have removed the $15,146,639.32 associated with the reduced revenues requested by the Company. See Staff witness Hessing’s Exhibit No. 104, line 14, for the monthly amounts. Astaris Load Reduction Program – The Astaris Load Reduction Program involved payments to Astaris for reductions in the firm energy used by that company. In Order No. 28992, the Commission authorized the inclusion of costs incurred by the program. I have reviewed the expenditures associated with the Astaris Load Reduction Program and found that the Company has correctly included expenses totaling $96,842,644.86 in the PCA account. IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 10 These amounts are subject to change pending an order resolving issues related to the Astaris Load Reduction Program rate reduction in Case No. IPC-E-01-43. Mobile Generation Expenses - These expenses are the result of the 25 diesel-powered generation units that were leased during the months of May through October 2001. In May 2001, the Company filed an Application in Case No. IPC-E-01-14 with the Commission seeking an accounting order to authorize the recovery of expenses associated with these generators. While the Commission allowed the Company to flow the expenses through the PCA accounts in Order No. 28837, it did not guarantee that any specific amount would be recovered by Idaho Power. During that case, the Commission Staff made a recommendation that a portion of those expenses should not be recovered. Staff’s position has not changed and I recommend that the associated power supply costs be reduced by $3,832,663. Staff’s comments in Case No. IPC-E-01-14 are attached as Exhibit No. 101 to provide a detailed analysis of the expenses and an explanation of the adjustment to the mobile generators expense proposed by Staff. The adjusted amounts are also shown in Staff witness Hessing’s Exhibit No. 104, line 17. Gas Fuel Expenses – These fuel expenses are the result of the Danskin single-cycle natural gas fired IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 11 plant in Mountain Home, Idaho. In Case No. IPC-E-01-12, the Company filed an Application requesting a Certificate of Public Convenience and Necessity to include the proposed plant in base rates. In addition, the Company requested that the Commission allow the Company to include the costs of the plant’s fuel, gas transportation and storage for recovery through the existing Purchase Cost Adjustment (PCA) mechanism. In Order No. 28773, the Commission allowed Idaho Power to account for and recover expenses associated with fuel and transportation in the PCA mechanism. I have reviewed the purchases of gas and transportation and found that the Company has an agreement with IGI Resources to supply it with fuel and transportation to run the plant. The fuel is currently purchased at a monthly index price and the Company is not required to pay for the fuel if it is not needed. On the other hand, the Company is required to pay for firm transportation for the fuel whether or not it is used. The agreement provides that IGI Resources will attempt to market the unused transportation, but so far the Company has received only two credits totaling $54,433.72. Staff will continue to work with Idaho Power and IGI Resources to insure that customers receive all potential benefits from the unused portion of the Company’s firm IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 12 transportation purchases. For the 2001-2002 PCA period, the Company included $3,337,553.12 in the PCA account for Danskin fuel expenses. I have made two adjustments to the amount requested by the Company. First, the Company contracted for firm transportation on April 11, 2001 with the intention of finishing the plant in July 2001. However, due to various delays, the plant did not operate until September 25, 2001. Customers never had the opportunity to benefit from the transportation expense incurred by the Company during the months of July, August and most of September. Because it was not used or useful during this time period, I removed the $682,272.40 from the Company’s PCA request. The second adjustment relates to $419,054 that the Company paid to Williams Gas Pipeline West (Williams). This amount was characterized as a “Facility Cost of Service Charge”. In essence, Williams built a 4,200 foot pipeline from its mainline to the Company’s facility, a meter station and control equipment that Idaho Power will use at it’s Danskin facility. The facility charge recorded by Idaho Power in the PCA account will pay for these items over the next 30 years. Since this is a capital cost and not an annual gas delivery cost, I believe that it should be considered in IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 13 a rate case and not be recovered in the PCA filing. Consequently, I removed the $419,054 from the Company’s request. Both adjustments are shown in Exhibit No. 104 on line 21. From September 25, 2001 through March 2002, the Danskin plant produced 27,789 MWHs of energy. The average variable fuel cost was $26.44 per MWH. Mobile Home Metering Shortfalls – These expenses result from modification of the three-tier rate as it applies to master-metered mobile home parks. After the last PCA rate change, the Commission became aware of an inequity created by applying the tiered rates to master-metered mobile home and RV parks. To address this inequity, Commission Order No. 28753 authorized a temporary subclass of Schedule 1 called “Schedule 3” so that master-metered customers could be billed at a flat rate. In addition to the new tariff, the Commission allowed Idaho Power to include and pass on to customers through the PCA account any revenue shortfall created by the new tariff. The Company has calculated the amount to be $106,528.87. I have reviewed the calculations and found that they appear to be reasonable. Intervenor Funding – In Case No. IPC-E-01-03, the Idaho Irrigation Pumpers Association (IIPA) filed for intervenor funding. The Commission granted $14,201.75 in IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 14 funding to the IIPA and required the Company to flow the amounts through the PCA account with recovery from the irrigation class. In Case No. IPC-E-01-06, the Idaho Irrigation Pumpers Association (IIPA) received $5,932.54 of intervenor funding per Order No. 28770. The Commission also allowed Idaho Power to recover that amount in the Company’s next PCA filing and required the Company to flow the amount through to the irrigation class. In the Case Nos. IPC-E-01-7 and IPC-E-01-11, the Land and Water Fund of the Rockies, Mary McGowen, Idaho Rivers United and Idaho Rural Council (Intervenors) petitioned the Commission for intervenor funding in the amount of $9,661.84. Idaho Power did not object to the intervenor funding, but it did seek authority to include the amounts of any award as an expense in the PCA mechanism. In Order No. 28756, the Commission granted the total amount requested and allowed the amount to be flowed through the PCA mechanism to all customer classes. I reviewed the amounts included in the PCA accounts and found that the $29,796.03 allowed above has been properly included. IDACORP Energy Credit – In Case No. IPC-E-00-13, Idaho Power filed an Application with the Commission requesting approval of an electricity supply IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 15 and management services agreement between Idaho Power and an affiliate, IDACORP Energy (IE). This agreement provided a mechanism to allow the Company to purchase wholesale energy at published index prices from IE. One benefit of the agreement was that a credit would flow back to Idaho Power customers for the difference between the contract charges and the amount reflected in the last rate case. That amount was rounded to $2,000,000 annually. The payments were to commence on the date that all commissions (Idaho, Oregon and the FERC) approved the contract between Idaho Power and IDACORP Energy. The Idaho Commission approved the stipulation on December 19, 2000 in Order No. 28596. By July 2001, all three commissions had approved the contract and Idaho Power began booking PCA entries for the required credits. For the PCA period of 2001-2002, Idaho Power booked $1,500,000 for July 2001 through March 2002. These credits were accounted for properly and should be included in the PCA accounts to benefit all Idaho customers. Securitization and Interest Costs Q. How does the Company’s securitization proposal differ from the traditional PCA cost recovery? A. First, the Company receives all of the $172 million of securitized power supply costs immediately. IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 16 Under the traditional PCA mechanism, Idaho Power must wait to recover the deferred amounts over twelve months. This shifts responsibility for carrying charges on the deferred amounts during recovery from the Company to customers. Rather than rates that reflect recovery of power supply costs as required under the existing PCA mechanism, the Company’s proposal results in rates that reflect both power supply cost recovery and carrying charges during the three-year recovery period. Idaho Power states that financial analysts on Wall Street would like the Company to have the amounts securitized to guarantee recovery and improve cash flow quickly. The Company believes that it could have a positive impact on its ability to borrow. I believe that the Commission can structure the recovery of deferred costs to provide the recovery assurances these analysts want by guaranteeing a fixed recovery period even if it is greater than one year. Q. Please describe the additional expenses to customers associated with the securitization of deferred costs. A. There are some significant expenses associated with the securitization of deferred power costs. Expenses are incurred before the bonds are ever issued. Idaho Power must pay to set up a Special Purpose Entity IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 17 (SPE) that will administer the bonds and proceeds. This requires legal fees, accounting fees, and capital funding. Then the Company must pay brokers, analysts and others to administer the bonds. Finally, there are interest amounts that are added to the outstanding financed amounts. The Company estimates that the initial fees to borrow $172 million dollars are up to $7 million dollars. The ongoing servicing fees and trustee expenses total approximately $1.5 million dollars and the interest expense will be about $12 million dollars over three years if the Company can finance the bonds at 4%. If the interest rate is higher, the costs will be higher. Q. Is there another risk to customers of securitization? A. Yes. Another risk in addition to the expenses associated with securitization is that additional deferred expenses may have to be recovered in future cases. These costs may have to be recovered at the same time customers are paying off the power supply bond. This would add one cost recovery on top of another to create a pancaking effect. It is difficult to predict what the total rate may be. Q. Is there a fairness issue associated with securitization? A. Yes. The longer the power supply cost recovery IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 18 is delayed, the greater the risk that the customers who caused the deferred costs will avoid payment of an equitable share. Q. Did you review other securitization options besides the one proposed by the Company? A. Yes. I analyzed the costs of securitizing amounts smaller than the amount proposed by the Company. In the case of the lower amounts, it did not prove economical to securitize because the fixed costs that have to be spread over fewer dollars reduce the benefit that securitization may have provided. Q. Do you recommend securitization be accepted in this case? A. No. I do not support securitization in this case. I believe the costs and risks to customers for securitization outweigh the benefits to customers. However, if the Commission decides to allow Idaho Power to securitize a portion of the deferred expenses, it is important that Staff be allowed to review the true up of the recovery and expenses every year to verify that the customers are paying the bond charges appropriately and the Company is not overcollecting. Q. Does Staff have alternatives to propose regarding the recovery of PCA expenses? A. Yes. Mr. Hessing has proposed three IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 19 alternatives for recovery of the PCA expenses. His recommendation involves deferring a portion of the PCA expenses for one year to allow a decrease while avoiding some of the costs and risks associated with securitization. Those alternatives are described in the testimony of Staff witness Keith Hessing. Carrying Costs of the PCA Q. Do you accept the Company’s proposal to change the interest rate on deferred costs to the authorized rate of return on a going forward basis? A. No, I do not. I believe the Company and Commission have taken steps to reduce the amounts in the deferral account going forward. For example, in Case No. IPC-E-01-16, the Company and Staff are working with interested parties to develop risk management guidelines that should limit significant deferrals and market exposure. The parties have discussed permitting the Company to come to the Commission earlier in the PCA year to review significant high cost transactions. The Company is also considering changing its planning practices from median water to a 70% of critical water level. All of these steps should limit the size of deferrals going forward. Q. What interest rate do you recommend? A. I do not recommend that the structure of the IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 20 PCA mechanism be modified to allow interest accrual on amounts that are in rates. I recommend that the carrying charges continue to be based on the customer deposit rate that is set annually, currently at 4%. Q. Has the Commission allowed another company to change the interest rate on deferred amounts in recent years? A. No. In Case No. AVU-G-00-4, Avista applied to change the interest rate calculation on its deferred balances. The Commission did not change the rate and, in fact, reiterated that the customer deposit rate was to be used even though the deferrals were large and the customer deposit rate did not cover the costs of borrowing. In some years the allowed customer deposit rate may be higher than the short-term debt rate and the Company may recover more than its actual cost. When the Commission allows utilities to recover interest on deferrals, the customer deposit rate is the rate that is generally used to calculate that interest. Q. Should the Company be allowed to earn interest on an amount held in the deferred account for a time period longer than the traditional PCA recovery period? A. If the normal PCA procedure of passing through increases over a period of one year is not used, I agree that the Company should be allowed to set aside the IPC-E-02-3 STAFF 4/22/02 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CASE NOS. IPC-E-02-2 HOLM, A (Di) 21 IPC-E-02-3 STAFF 4/22/02 amount deferred in excess of one year and earn interest on that amount. The rate should be equal to the larger of its short-term debt rate or the customer deposit rate. This will allow the Company to recover its reasonable carrying costs during the additional deferral period. Once the deferred amounts are placed into rates, no additional carrying charges would accrue. Even using a hypothetical rate of 7%, Mr. Hessing’s analysis shows that Idaho Power customers will save $14.6 million over the Company’s securitization proposal by paying off the deferrals according to his recommended schedule. Currently, Idaho Power’s short-term debt rate is lower than the 4% customer deposit rate, but it varies monthly. Q. Does this conclude your direct testimony in this proceeding? A. Yes, it does.