29102.doc

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER COMPANY'S INTERIM AND PROSPECTIVE HEDGING, RESOURCE PLANNING, TRANSACTION PRICING, AND IDACORP ENERGY SOLUTIONS (IES) AGREEMENT. )
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CASE NO. IPC-E-01-16
(PHASE II)

ORDER NO. 29102
In August 2001, the Commission directed the parties to make a good faith effort to settle this case. In particular, the parties were to address the following issues: the adequacy of Idaho Power’s hedging and risk management strategies; additional compensation to Idaho Power for transmission system and other system resource usage by IDACORP Energy, LP (“IE”); and whether the transfer prices for both day-ahead and real-time transactions between Idaho Power and IE approved in Commission Order No. 28852 should be modified on a prospective basis. Order No. 28831.
The parties have reached an agreement regarding the Company’s risk management and hedging practices. The parties’ Stipulation does not address the issues relating to the pricing of transactions between Idaho Power and IE or additional compensation for use of the Idaho Power transmission system by IE. The parties represent that this settlement is just, fair and reasonable, in the public interest, and in accordance with the law and regulatory policy. The parties request that the Commission review the Stipulation and adopt it by Order.
After reviewing the extensive record and the provisions of the Stipulation, the Commission accepts the Stipulation as a fair, just and reasonable resolution to the risk management and hedging issues presented in this case. In regard to the other issues remaining in Case No. IPC-E-01-16, we direct the parties to present either the resolution or a status report on the additional compensation for IE’s use of the system and any remaining transfer pricing issues to the Commission no later than December 20, 2002.
BACKGROUND
Idaho Power is an electric utility engaged in the generation, transmission, distribution and sale of electric energy and provides retail electric service to approximately 360,000 customers in southern Idaho and eastern Oregon. In February and March 2001, Idaho Power filed applications for authority to increase its rates under its Power Cost Adjustment (PCA) rate schedule. These applications were separately docketed as Case No. IPC-E-01-7 (“the -7 case”) and Case No. IPC-E-01-11 (“the -11 case”), but were processed as a joint case. In Order No. 28722 issued in the -7 and -11 cases, the Commission allowed Idaho Power to immediately recover $168.3 million dollars through the PCA mechanism. The Commission deferred recovery of approximately $59 million pending further investigation. As a part of that investigation, the Commission held an evidentiary hearing examining Idaho Power’s “. . . trading practices (to include hedging, transmission and wheeling charges, Mid-C pricing, and the use of weighted-average pricing), the November trading event and the Company’s resource planning.” Order No. 28722 at 17.
In Order No. 28731 the Commission separated a number of the issues identified for investigation in the -7 and -11 cases into a third case which was docketed as IPC-E-01-16 (“the -16 case”). In Order No. 28731 the Commission described the issues to be addressed in the -16 case as “. . . interim and prospective issues regarding Idaho Power’s trading practices (to include hedging, transmission and wheeling charges, Mid-C or Palo Verde pricing indexes, and use of weighted-average pricing for real-time purchases); the pricing, hedging and transmission terms of the IES Agreement and Order No. 28596; and the flexibility of the Company’s short-term planning. . . .” Order No. 28731 at 5.
In response to a joint motion by the parties in the -16 case, the Commission issued Order No. 28831 on August 24, 2001 which further bifurcated the issues in the -16 case into Phase I and Phase II. Testimony and exhibits relating to the Company’s trading practices (hedging, transmission and wheeling charges, Mid-C pricing and weighted-average pricing) on a prospective basis from March 1, 2001, were presented in hearings held on August 28-30, 2001 in Phase 1. All of the other issues identified for review in the -16 case, i.e., Idaho Power’s approach to hedging and risk management strategies, additional compensation to Idaho Power for transmission system and other system resource usage by IE, and a question of whether the transfer prices for both day-ahead and real-time transactions between Idaho Power and IE approved in Commission Order No. 28852 should be modified on a prospective basis, were assigned to Phase II. The parties were encouraged to make a good faith effort to settle the case.
Workshops to discuss settlement were held on September 20, October 12, December 18, 2001, February 28, 2002, March 14, 2002 and April 23, 2002. Representatives from Idaho Power Company, the Commission Staff and various customer groups attended the workshops. The customer groups in attendance included the AARP, the Industrial Customers of Idaho Power, Micron Technology, Idaho Irrigation Pumpers Association, the J.R. Simplot Company and the Idaho Retailers Association. In this agreement, these customers are collectively referred to as the Customer Advisory Group (“CAG”). All CAG members support adoption of the Stipulation.
In early April 2002, Idaho Power advised the parties that because of problems with the transfer pricing methodology in use for real-time transactions under the Supply and Management Agreement, Idaho Power was requesting that the settlement discussions be restructured to separate the risk management and hedging policy issues from the issues relating to the transactions between Idaho Power and IE. This would allow the parties to complete the risk management and hedging portions of the settlement and take up the balance of the –16 case issues at a later date. Idaho Power filed a status report with the Commission to address the current status of the parties’ efforts to resolve the issues relating to the transactions between Idaho Power and IE.
STIPULATED SETTLEMENT OF
RISK MANAGEMENT AND HEDGING ISSUES

Based on the discussions at the workshops and subsequent discussions with the CAG and the Commission Staff and in furtherance of a settlement of this case, Idaho Power has agreed to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales. The risk management program will be characterized by the following features:
■ Idaho Power staff will conduct an annual collaborative review and additional workshops as needed with Commission Staff and customer representatives to enhance the understanding of the risk profile faced by Idaho Power’s customers.

■ Idaho Power will seek input from Commission Staff with respect to desired risk tolerances and solicit upfront support for proposed implementation procedures.

■ Idaho Power will provide Commission Staff with regular updates on the status of the Idaho Power risk position and its impact on the Power Cost Adjustment balance.

Those changes are more particularly described in the following:
Risk Management. Idaho Power has developed an extensive set of policies and guidelines to more clearly define when and how Idaho Power will initiate short-term resource acquisitions and sales and carry out hedging transaction strategies to balance loads and resources. The following is a summation of the current Risk Guidelines as discussed in the workshops and in additional discussions with Commission Staff and the CAG.
The Company’s primary risk management objective is to manage “worst-case” price risk within a tolerable level. This tolerable level shall be described in the Risk Guidelines as the System Risk Limit or Tier One. Worst case is defined as a 95% confidence interval price move and incorporates low water conditions based on current snow pack and 50% of normal precipitation through the remainder of the runoff season. For the 2002-2003 PCA year, the System Risk Limit was initially set at $100 million based upon market price information that existed at the end of September 2001. Hedges will initially be put on at a minimum of 25 MW and unwound in 50 MW increments whenever the PCA calculation under the low water/high price scenario exceeds the System Risk Limit. Hedges will be established first in near months and will be only extended into more distant months if required.
The PCA balance to be protected is tied to the forecast revenue/cost for system purchases and sales based on the expected water/expected price scenario developed in October prior to the commencement of the PCA year. If the System Risk Limit is set at $100 million, this implies that the Company, its customers and the Commission do not want to experience an increase in the system PCA balance greater than $100 million (before jurisdictional allocations and sharing). Despite the establishment of a System Risk Limit, stakeholders must understand that uncontrollable violations of the risk limit can occur. Accordingly, Idaho Power will expeditiously advise the Commission, Commission Staff and CAG of any Tier One risk limit violations and describe the actions the Company has taken to address such violations.
When “worst-case” risk lies within the Tier One System Risk Limit, the Company after consultation with the RMC will undertake transactions to mitigate normal-course market risk. For descriptive purposes, this secondary risk management objective will be labeled Volumetric Limit or Tier Two risk management. Tier Two transactions in the form of short or long hedges will protect customers from exposure to price deterioration for forecast surplus months, and a price rise in forecast deficit months. For the 2002-2003 PCA year the Company will maintain no more than a 100 MW open position, computed for both heavy load (HL) and light load (LL) hours for any month. Deficiencies will be managed to the expected water case and surpluses will be managed to the low water case. Hedges will be put on at a minimum of 25 MW and unwound at 50 MW increments. Hedges will not be initiated that serve to increase worst-case risk scenario above the pre-determined System Risk Limit.
The foundation for the Company’s tertiary risk management objective is the recognition that even if the Company’s worst-case risk exposure lies within the System Risk Limit, there is a price point at which customers would be satisfied to lock in a purchase price on forecast deficit positions. Referred to as Floor Limit or Tier Three risk management, this type of hedge assumes that customers are willing to forego the benefit of a further price fall in return for price stability and mitigated exposure to severe price increases. For the 2002-2003 PCA year the Company will seek to cover expected deficiencies whenever prices fall below $30/MW HL and $15/MW LL. Additionally, the Company will seek to cover low water deficiencies whenever prices fall below $20/MW HL and $10/MW LL. Floor Limit positions will be put on in 25 MW minimum increments and unwound if there are changes to the position greater than 50 MW.
In an effort to provide a more effective consumer price signal and allow timely recovery of extraordinary power supply costs, Idaho Power agrees to confidentially advise the Commission and Staff when it enters into a forward monthly term purchase where the price exceeds the Market Review Trigger (“MRT”). The MRT will be initially set at $60 per MWh and will be reviewed annually by the CAG and RMC. Should Idaho Power fail to provide the MRT notification for a purchase, the Commission may find full recovery of expenditures for that purchase to be unreasonable. After considering the then-current circumstances (e.g., market prices, water conditions, time left in the PCA year, etc.) on a case-by-case basis, the Commission may wish to implement a temporary emergency surcharge or other mechanism that allows power supply costs exceeding the MRT level to be recovered in a time frame more consistent with when the costs are incurred.
The Commission previously indicated that it was “appropriate for the parties to discuss a greater sharing of the PCA purchased power cost components or other incentive mechanisms” in this case. Order No. 28852 at 7. This finding stemmed from concern that the 90/10 Idaho Power procurement cost sharing may not be proper incentive for the Company to seek lower market prices. Id. Although it does not address the Company’s motivation to seek lower prices in a stable market, the parties believe the MRT notification and the three-tiered risk management structure under the Risk Guidelines provide a disciplined approach to purchasing power and eliminate some opportunities to engage in manipulation or rote behavior. Consequently, the parties agree that the 90/10 sharing mechanism should not be modified within the context of this case at this time.
The parties to this Stipulation have reviewed the Risk Guidelines and agree that it would be desirable for Idaho Power to utilize the Risk Guidelines to formalize its decision-making process for short-term resource acquisition and sales, and hedging decision-making. Once the Manual and initial Risk Guidelines receive final approval by the Idaho Power Board of Directors, the parties will review them and submit a follow-up stipulation or comments to the Commission for review and approval.
2. Separate Risk Management Committees. In his testimony in the 16 case, Staff witness Lord was critical of the fact that IDACORP and Idaho Power operated under a single risk management committee. In response to that criticism, Idaho Power has formed a risk management committee that is separate and distinct from any risk management committee operated by IDACORP. John Prescott, Idaho Power’s Vice President - Power Supply, is the Chairman of the Idaho Power RMC and is also the Oversight Manager described in the Supply and Management Agreement. The Idaho Power RMC will maintain separate records documenting the decisions of the Idaho Power RMC for resource planning, acquisition, sales and hedging transactions. These records will be subject to audit by the Commission Staff consistent with Staff’s regulatory audit authority and the audit agreement contained in the settlement stipulation entered into in Case No. IPC-E-00-13.
3. Long-Term Resource Planning. In its testimony in the -16 case, the Commission Staff addressed a number of resource planning issues that came to the forefront as a result of the Company’s need to make significant purchases of energy on the wholesale market during calendar years 2000 and 2001. Idaho Power has agreed to address all of the concerns raised by Commission Staff in its 2002 Integrated Resource Plan (IRP) that is currently in the development process. With the exception of incorporating IRP review in the annual collaborative review of the Risk Guidelines prior to October 1, the parties to this Stipulation agree that it is preferable for these resource planning issues to continue to be addressed in the context of the 2002 IRP. The parties also agree that the relationship between the RMC and the integrated resource planning process will be explained at the time of the initial review of the Risk Guidelines and updated as necessary thereafter during the annual review of the Risk Guidelines.
4. Term Agreements. Idaho Power agrees that term market purchase or sale transactions will be undertaken by Idaho Power, not IE.
5. Commission Review. The Company shall file with the Commission an analysis of its three-tiered risk management strategy detailing its effect on customers, the Company and IDACORP Energy once it has been in place for two years. The analysis will include a monthly comparison of loads, resources and RMC strategy, demonstrate that Idaho Power considered purchase alternatives consistent with its IRP, and show what hedge products it considered and used. The report shall also include any recommended changes or modifications that the Company may have to its three-tiered risk management program. Staff will review the Company’s analysis and make recommendations to the Commission to modify the three-tiered risk management strategy as necessary. In the context of the collaborative annual review of the Risk Guidelines that will take place prior to October 1, the CAG, other interested parties and Staff may recommend prospective changes to Idaho Power and the Commission. The parties recognize that the Idaho Public Utilities Commission maintains the right to review and modify the three-tiered risk management program as necessary after reviewing the analysis of the first two years or as circumstances dictate.
6. Case No. IPC-E-00-13. This Stipulation does not supersede the Stipulation entered into in settlement of Case No. IPC-E-00-13, which was filed with the Commission on November 17, 2000 and approved on December 19, 2000 in Order No. 28596.
7. Future Modification. The parties agree that this Stipulation is in the public interest with respect to the issues covered by it and that all of the terms of the Stipulation are fair, just and reasonable at the time this Stipulation was reached. However, all parties agree that the Stipulation may need to be modified in the future to account for unforeseen circumstances and ensure that the Risk Guidelines continue to function in the public interest.
PARTIES RECOMMENDATION
All parties to this case that participated in the settlement, as well as the additional interested parties that formed the Customer Advisory Group, have signed the Stipulation resolving the risk management and hedging issues. Thus, the matter is ripe for Commission review and determination of whether the stipulated settlement is just, fair and reasonable, in the public interest, or otherwise in accordance with law or regulatory policy.
The parties recommend that based upon the Stipulation, the Commission accept this settlement as presented without material change or condition. However, all parties agree that the Stipulation may need to be modified in the future to account for unforeseen circumstances and ensure that the Risk Guidelines continue to function in the public interest. The parties further recommend that once the Idaho Power Board approves the Manual and the initial Risk Guidelines are developed, the Commission accept this Stipulation and the record in Phase I of this case as a reasonable resolution of the risk management and hedging practices issues raised in the –16 case.
COMMISSION FINDINGS AND DISCUSSION
Pursuant to Commission Rule 274 we shall decide whether to accept the Stipulation and Settlement Agreement based on the record currently before us. IDAPA 31.01.01.274. The record is substantial and all parties that participated in the settlement negotiations in this case have signed this Agreement. Accordingly, we find further proceedings are not necessary for us to determine whether we should accept this Agreement.
When we granted the joint motion to bifurcate this case into two phases, we agreed with the parties that a collaborative process would more likely produce mutually acceptable results than the adversarial hearing process. Order No. 28831. Phase II of this proceeding was intended to address: Idaho Power’s approach to hedging and risk management strategies; additional compensation to Idaho Power for transmission system and other system resource usage by IE; and whether the transfer prices for both day-ahead and real-time transactions between Idaho Power and IE approved in Commission Order No. 28852 should be modified on a prospective basis.
After reviewing the Stipulation signed by the parties, the Commission finds that it accurately reflects those elements that constitute an appropriate resolution of the risk management and hedging issues presented in this case. First, the Stipulation provides a structure in which Idaho Power will manage its market and hedging risk. Under the Risk Guidelines set forth pursuant to the Stipulation, Idaho Power must operate within an overall monetary System Risk Limit, a Volumetric Risk Limit for hedging, and a price Floor Limit for power purchases. We find that these objectives will cap potential increases in the PCA balance at an agreed-upon level, reduce customer exposure to changes in wholesale market prices, and secure relatively inexpensive power at times when the system is at a deficit, respectively. Moreover, we believe this three-tiered risk management structure will allow the Commission, Staff and the public to better monitor and review the Company’s risk management and hedging decisions on a prospective basis.
The Commission also finds this Stipulation should be approved because it establishes an annual review with customer groups and Staff to evaluate the Company’s risk profile and customer risk tolerances. This collaborative review will also set the prices at which Idaho Power must take action or notify others of the Company’s position relative to the wholesale market. We believe that allowing the Consumer Advisory Group to participate in annual risk analysis will benefit Idaho Power and its ratepayers with additional perspectives and expertise on these issues.
We also find that this Stipulation will increase the flow of critical information between Idaho Power, the Commission and the Commission Staff. Idaho Power agrees to provide regular updates on the Company’s risk position and how it impacts the Power Cost Adjustment balance. The Company also promises to advise the Commission, Commission Staff and the Customer Advisory Group of any System Risk Limit (Tier One) violations so that steps can be taken to reduce the system’s overall monetary market exposure to less than the level agreed upon during the annual collaborative review. The Commission also finds value in Idaho Power’s agreement to confidentially advise us when it enters into forward term purchases where the price exceeds a set level. With this information, the Commission could send consumers more timely price signals by taking action to recover the extraordinary power costs rather than waiting until a hefty PCA application is filed in the spring.
Based on our review of the Stipulation and the above justifications, we find that this Stipulation is just, fair and reasonable, and in the best interest of the public based on the information known at this time. Likewise, the Stipulation is in accordance with state law and regulatory policy. Thus, the Commission accepts the Stipulation without modification.
In regard to the other issues remaining in Case No. IPC-E-01-16, we direct the parties to identify and attempt to resolve what additional compensation is owed Idaho Power’s ratepayers for IE’s use of the transmission system and other capital assets. The Commission is aware that IDACORP recently announced it was winding down the speculative electricity trading activities of IE and instead focusing on processing and transporting natural gas to wholesale natural gas customers. We direct the parties to identify and attempt to resolve any remaining transfer pricing issues that are not rendered moot by these changed circumstances. Finally, we direct the parties to present either the resolution or a status report on these issues to the Commission no later than Friday, December 20, 2002.
CONCLUSION
After reviewing the Stipulation, the Commission adopts and approves it as presented. We find that this Stipulation finally resolves the risk management and hedging issues among the parties. We further find that this Agreement has been made to compromise contested claims and is entered largely for the purpose of avoiding expense, inconvenience, and uncertainty of further litigation. Finally, pursuant to Commission Rule 275 we find that the parties have carried their burden of showing that the Agreement is just, fair and reasonable, in the public interest, and in accordance with the law and regulatory policy of this State. IDAPA 31.01.01.275. Accordingly, we accept the Stipulation as proposed by the parties in this case.
O R D E R
IT IS HEREBY ORDERED that the proposed Stipulation is just, fair and reasonable, in the public interest, and in accordance with the law and regulatory policy of this State. Accordingly, we accept the Stipulation as proposed by the parties in this case.
IT IS FURTHER ORDERED that the parties shall comply with all terms contained in the Stipulation.
IT IS FURTHER ORDERED that the parties submit the Idaho Power Board-approved Manual and the 2003-2004 Risk Guidelines for final review and approval by the Commission no later than October 1, 2002.
IT IS FURTHER ORDERED that the parties file a resolution or a status report on the transmission compensation and affiliate transfer pricing issues with the Commission no later than Friday, December 20, 2002.
THIS IS A FINAL ORDER as to the risk management and hedging issues presented in this case. Any person interested in this Order (or in issues finally decided by this Order) or in interlocutory Orders previously issued in this Case No. IPC-E-01-16 may petition for reconsideration within twenty-one (21) days of the service date of this order with regard to any matter decided in this Order or in interlocutory Orders previously issued in this Case No. IPC-E-01-16. Within seven (7) days after any person has petitioned for reconsideration, any other person may cross-petition for reconsideration. See Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this
day of August 2002.

PAUL KJELLANDER, PRESIDENT

MARSHA H. SMITH, COMMISSIONER

DENNIS S. HANSEN, COMMISSIONER

ATTEST:

Jean D. Jewell
Commission Secretary

O:IPCE0116_ln
ORDER NO. 29102 1

Office of the Secretary
Service Date
August 28, 2002