# Presentation: 438710

## Northwest Regional Proposal for an Independent Transmission Organization

- Kurt J. Conger
- EXS, Inc.

- Energy Expert Services, Inc.
- Woodinville, WA

## Overview

- RTO West Chronology
- Regional scope
- Problems and Opportunities
- Regional Proposal
- Impact Analysis
- Risks, Opportunities, Uncertainties

## RTO West’s History (1)

- 1999 (Dec)
- FERC concludes market power not full addressed by Order No. 888 tariffs
- FERC issues Order No. 2000 requiring jurisdictional utilities to file by October 2000 a proposal to form a regional transmission organization (RTO) or a statement describing why such an organization cannot be formed.
- 2000
- RTO West organized in Northwest to respond to FERC Order 2000
- October – Stage 1 Filing, describing governance and approach to further development.
- 2001
- April – FERC issues order with preliminary approval and guidance
- September – RTO West abandons “flowgate” model for congestion management and moves to injection-withdrawal model using locational pricing.

## RTO West’s History (2)

- 2002
- March – Stage 2 Filing which included adjustments to governance and proposals for pricing, congestion management, ancillary services, etc.
- July – FERC initiates rulemaking on Standard Market Design (SMD)
- September – FERC issues order accepting in part and asking for clarification on market design.
- October to December – Public process to respond to FERC order on market design, etc.
- 2003
- Disagreement among filers on key issues
- Regional resistance to the Stage 2 Proposal
- Congressional opposition to SMD in energy bill debate
- Regional Representative Group reinitiated:
**June** – Began reexamination of regional transmission problems and opportunities
**September** – Began consideration of alternatives for addressing problems
**December**** **– Regional Proposal accepted as basis for further work

## Regional Scope

*Includes most transmission in  of the Northwest Power Pool*
*Under consideration by:*
- Avista (Spokane),
- Bonneville Power
- BC Transmission Corporation (BCTC)
- Idaho Power
- Northwestern (Montana)
- PacifiCorp
- Portland General Electric
- Puget Sound Energy
- Sierra Resources and Nevada Power

## So why change?

## Regional Problems and Opportunities

- Difficult to make region-wide  transactions.
- Rate Pancaking (volumetric recovery of fixed costs) imposes barriers to efficient resource integration and dispatch.
- Separate reservations required for each system.
- Long queues for interconnection requests—may be on separate utilities without coordinated analysis.
- Lack of organized markets that produce prices which induce efficient use of system.
- TOs manage congestion internally by scheduling limits and curtailments without transparent redispatch pricing or settlement procedures.
- Complaints to FERC for post-mortem remedies are ineffective.
- Access to ancillary services are limited with technical barriers.
- Lagging infrastructure investment.

## Regional Problems and Opportunities

- Inefficient use of transmission
- Real-time congestion is managed by unfair curtailments. Prone to significant errors by transmission owner/operators.
- The lack of a system wide view of reliability implications of combined schedules requires greater capacity margins.
- Actual loss effects and the recovery of losses don’t match, resulting in under-recovery during peak load periods.
- Limited operational data available to reliability coordinator/authorities
- Parties unwilling to share commercially sensitive data with competitors.
- Existing data stream is incomplete
- No capability to perform reliability analyses of next-day and current-day operating conditions (NERC Policy 9 requirement).
- A single system viewpoint needed w/o commercial bias.

## Regional Proposal

- Basics:
- Create a new independent entity with provisions for regional accountability and governance.
- Use a staged implementation, phasing in features over time:
- Beginning State – Initial features to meet immediate needs.
- Interim State – Features added as ready for implementation.
- Advance Target State – Fully operational RTO.
- Voluntary control area consolidation
- operated by independent entity on behalf of consolidating parties.
- Transition Principles:
- Each step change must be a clear improvement over current approaches to managing and using the regional transmission system,
- Each stage of evolution is fully workable as it stands, and
- The proposed transition does not foreclose the ability to evolve to the target state (adapted as needed to changing circumstances).

## Beginning State

- Functional Roles for Independent Entity
- Transmission Services:
- Transmission system capability and new service evaluated on region-wide basis.
- Transmission rights reconfiguration auctions to improve access to capacity.
- Centralized scheduling process and OASIS.
- Planning & Expansion:  Annual plan from regional viewpoint.
- Control Area Operations:  May provide services under contract to those who choose to consolidate control areas.
- Energy Markets:
- Day-ahead re-dispatch for region.
- Balancing market within consolidated control area.
- Ancillary Services: Market within consolidated control area.
- Administrative Features
- Data repository and market monitoring.
- Cost recovery and dispute resolution.
- Governance
- Checks and balances for regional accountability.
- Key to acceptability to regional stakeholders.

## Advanced Target State

- Functional Roles for Independent Entity
- Transmission Services:
- Capability and new service evaluated on region-wide basis.
- Reconfiguration auctions to improve access to capacity.
- Centralized scheduling process and OASIS.
**Conversion to financial transmission rights.**
- Planning & Expansion:  Annual plan from regional viewpoint
- Control Area Operations:  **Consolidation of all control areas.**
- Energy Markets:
- Day-ahead re-dispatch for region.
**Region-wide real-time balancing market.**
- Ancillary Services: **Region-wide capacity and energy markets.**
- Administrative Features
- Data repository and market monitoring.
- Cost recovery and dispute resolution.
- Governance
- Checks and balances for regional accountability.
- Key to acceptability to regional stakeholders.

## Advantages of theStaged Approach

- Limited, Early Implementation
- Existing contract rights of parties preserved.
- Functions added to address specific, existing problems and opportunities.
- Feasibility of implementation must be evaluated.
- Markets initiated on a voluntary basis.
- Users gain experience with market operations.
- Shift to “financial rights” delayed until a price history exists to judge impacts.

## Regional ProposalEstimated Developmental Timeline

|  | 2004 |  |  |  | 2005 | 2006 |
| --- | --- | --- | --- | --- | --- | --- |
|  | Q1 | Q2 | Q3 | Q4 |   |   |
| Beg. State General/Technical Development |   |   |   |   |   |   |
| Early Board Creation |   |   |   |   |   |   |
| Develop Funding Plan |   |   |   |   |   |   |
| Regional Approvals |   |   |   |   |   |   |
| Detailed Development |   |   |   |   |   |   |
| FERC Approval |   |   |   |   |   |   |
| Commencement |   |   |   |   |   |   |
|   Execute TOAs |   |   |   |   |   |   |
|   Board Membership and Authority |   |   |   |   |   |   |
|   Build Organization |   |   |   |   |   |   |
|   Commence Staged Operations (Startup) |   |   |   |   |   |   |

**Notes:**
Kurt

## Cost Impacts

**Notes:**
Lon

## Cost of Basic Transmission Service

- Beginning State increase:
- Assume $25,000,000 per year for Grid West
- Result: approximately 1% increase in BPA transmission rates
- If transmission is 10% of retail revenue requirement, 0.1% retail rate increase
- Advanced State increase:
- Assume $180 to $360 million per year for Grid West (depends on tax liability assumption)
- Result: approximately 7 to 14% increase in BPA transmission rates
- If transmission is 10% of retail revenue requirement, 0.7 to 1.4 percent retail rate increase
- For BPA customers that resell PTP, balancing market displaces resale of transmission

**Notes:**
Lon

## Cost of EMS and Scheduling Software Changes

- Modifications/upgrades to EMS and Transaction Management Systems
- System integration
- Staff training
- Most EMS and TMS vendors have products designed to interface with RTOs

**Notes:**
Kurt

## Cost of New Transmission Capacity

- Transmission may be needed for:
- Chronic, Commercial Congestion and/or
- Transmission System Adequacy
- Congestion costs provide price signals for new capacity
- Is it less costly to redispatch rather than build new wires?
- Still not clear who pays congestion costs: transmission customer or transmission provider
- Not clear on cost of new construction: rolled-in or participant funding

**Notes:**
Kurt

## Revenue Effects

**Notes:**
Lon

## Sale of Surplus Energy

- Outcome depends on whether customer is in an energy surplus or deficit position
- Value of surplus energy depends on:
- Future spot market prices (including congestion cost differences)
- Critical, average or high water assumption
- Conversion of existing transmission rights
- Acquisition of new transmission rights
- Expect average spot market prices to be lower, but continued volatility

**Notes:**
Lon

## Sale of Ancillary Services

- Current market supports some limited operating reserve marketing
- Beginning State:
- A/S markets to be developed in consolidated control area
- Incremental addition of product markets.
- Long-term increase in market potential
- Market for shorter-term products envisioned (e.g. hourly, daily, weekly and monthly)
- New A/S product markets including regulation and load following have higher revenue potential
- RTO markets must develop substantially to create these product markets.

**Notes:**
Lon

## Risks, Opportunities and Uncertainties

- Staged Implementation
- Governance: Regional Oversight v. FERC
- Effect on FERC Jurisdiction
- Congestion Cost Risk and Settlement Opportunities
- Reliability
- Control Area Consolidation
- Conversion of Transmission Rights
- New Incentives, Market Power Risk, Market Monitoring and Price Caps
- Hedging

**Notes:**
Kurt – Bullets 1 thru 5 (Reliability)
Lon – Bullets 6 thru 9

## Slide 22

## Regional Proposal Staged Functions:Operations

- 1.1. Reliability Coordination: Enhanced PNSC  Integrated w/Operations
- 1.2. Physical Interconnection: RTO coordinates process  RTO process
- 1.3. Transmission Service Requests: TO process  Medium-term Rights Auction  RTO process
- 1.4. Tariff Administration: TO tariffs  Single RTO tariff
- 1.5. New Transmission and ATC: New Injection/Withdrawal Rights  Medium-term Rights Auction  Financial Rights
- 1.6. Day Ahead Scheduling, Congestion Management
-   Step 1: TO reviews, IE computes redispatch if needed
-   Step 2: IE does pre-schedule with TOs
-   Step 3: IE develops inventory of rights
-   Step 4: IE scheduling process (2 years after Op. Start)
-   ATS: Congestion Management using financial rights
- 3. Control Area Operations: Initial Control Area Consolidation  Additional CCA

## Regional Proposal Staged Functions:Planning, Expansion

- 2.1. Planning: annual open process
- 2.2. Expansion: I/W rights for New Construction  Backstop for Chronic Congestion

## 4. Energy Markets

- 4.1. Real-time Balancing Energy: Balancing in CCA  Integrated Capacity/Energy Markets
- 4.2. Hour-Ahead Energy : Bilateral  Voluntary RTO  Integrated RTO
- 4.3. Day-Ahead Energy: Bilateral with Inc/Dec postings  Scheduled Bilateral w/Integrated Capacity/Energy market
- 5.0. Ancillary Services: Voluntary A/S mkt in CCA  Integrated Capacity/Energy Market
- 6.0. Market Monitoring: Reporting and Examination  Expanded Authority

## 7. Cost Recovery

- 7.1. Fixed Cost Recovery: Company Rate  Company Rate unless modified
- 7.2. Losses: Existing contracts  Possible new methodology
- 8. Regional ADR included in IE's provisions
- 9. Data Repository: Planning, Operations, Inc/Decs  add market monitoring