Policy Issues in the Treatment of CO2 Emissions—Oregon+ Hal T. Nelson, Ph.D. Visiting Professor Technical Advisor to the Carbon Allocation Task Force ( ) Agenda Why: The Oregon Electricity Supply Industry How: The proposed Oregon Carbon Allocation Standard CO2 accounting methodologies Market based instruments Trading with other systems? Treatment of rational behavior: contract shuffling A couple of possible approaches

The Oregon Electricity Supply Industry Two IOUs account for nearly 70% of statewide sales: PGE~40% Pacificorp~30% Consumer Owned Utilities account for balance of 30% Munis 11% Co-ops 10% PUDs 9%

Some Customer Choice Allowed Restructuring law SB 1149 (2001) Retail customers could choose cost of service or portfolio options Allowed commercial and industrial customers direct access or market based rates: Uptake low: <10% PGE, <1% Pacificorp Electricity Service Supplier (ESS) sales ~3% in 2005

Heterogeneity in Regulated Actors

Oregon Carbon Allocation Standard (to be submitted to the legislature within the month) Load-based cap applies to all owned and unit contingent resources, as well as market purchases Captures emissions associated with T&D, on-site usage Covers assets in Oregon, Arizona, Wyoming, Utah and Montana Design intended to prevent “leakage” Contract shuffling still an issue Covers thermal installations > 15,000 tonnes / yr CO2 Alternative Compliance Payment—safety valve at $40

Oregon Emissions Growth and Mitigation by Program 1.7% gross load growth Doubling charge for efficiency 15% (of load) RPS by 2020 CO2 to 10% below 1990 by 2020 Clean Energy Planning Model © medium case run EE RPS Cap (& Offsets)

Trading Into but not Out of Oregon?? Biannual auction open only to Oregon Providers 5% initial auction, 95% grandfathered Proceeds go to EE, generation efficiency, renewables, offsets Allowances tradable only between Oregon Providers Subject to rulemaking request from Governor to link with other states’ CO2 caps Oregon retail providers could buy and sell other states’ allowances if “consistent and comparable” Providers can retire allowances for customers

Market Based Instruments Offsets allowed into the system at 25% of required reduction for investor owned utilities and declines over time 100% for consumer owned utilities Unbundled Renewable Energy Credits allowed up to 10% of required reduction, declining over time Accounted for at LSE average mix

CO 2 Accounting Methodologies Providers’ average emissions rate for crediting unbundled RECs OPUC CO2 methodology Boiler level emissions tracking for thermal units  Owned, unit contingent  Share of Oregon IOU ownership of asset’s total annual emissions Washington State methodology for BPA load for COUs Northwest Power Pool net system mix for market purchases ~.5 tonnes/MWh for 2005

What do with “Lost” Resources Over the Program’s Life ? A more likely case for contract shuffling Unit contingent contract expires and new contract becomes a system purchase Potentially from the same unit to same buyer A less likely case If a provider sells a plant or multi-state PUC process reallocates high CO2 intensity assets to states without CO2 cap Placeholder language in legislative bill to account for consequences (CO2 allowance allocation decrement) This could work if most allowances are grandfathered No really easy answers for contract expiration issue without more detailed generation attribute system

OK, Semi-Easy Approach #1 1.Reduce incentives for contract shuffling Net NW Power Pool net CO2 mix is being adjusted upward from 900 to 1,160 lbs/MWh BPA, CA, other hydro sales coming out of NW mix Take rate base and unit contracts out A higher avoided CO2 figures increases bottom up incentives for product differentiation

Approach #2 2.A “ risk adjustment ” to account for asymmetries in market purchase motivation of unspecified imports Significant financial incentives exist for “dumping” high carbon intensity resources into the system mix Difference between an older one ton/MWh coal plant vs net system mix Plant level Incentive up to.5 tons/MWh $40/ton CO2 = $20 MWh incentive for a one ton/MWh coal resource to be accounted for as net system mix  This could be almost double the marginal cost of production

Risk-Based CO2 Adjustment to Unspecified Import Baseline Applied only to imports exceeding 2009 level Aka “new” or increases in imports from beginning of CO2 cap period Related to CO2 auction prices from previous year Assume baseline of 1,100 lbs (.5 tons) per MWh for unspecified imports from NW Power Pool: $0-$10 ton/CO2 = 0 tons/MWh risk adjustment on imports $10-$20 ton/CO2 =.10 tons/MWh risk adjustment $20-$30 ton/CO2 =.20 tons/MWh risk adjustment $30-$40 ton/CO2 =.30 tons/MWh risk adjustment At $30 ton “new” CO2 imports would be credited at.70 tons Simulation modeling could inform risk adjustment levels?

An Example Provider with 50% coal, 50% market purchases Average CO2 intensity ~.75 tons/MWh In 2017 auction price is $25/ton CO2 Policy Scenario: All coal contracts expire and provider buys unit power from 3 rd party— market purchases increase to 100%. The incremental 50% is credited at.70 tons/MWh Average provider intensity =.60 tons/MWh No Policy Scenario: All load served at.50 tons/MWh

The Logic of Adjusting Imports for Risk Recognizes the benefits of market efficiencies from trading liquidity: moving low efficiency resources out of pool If there are a lot of dirty resources hiding in the pool this penalizes efficient units No incentive for redispatch Risk adjustment value is known year ahead for planning purposes Explicitly recognizes the risks to the program from contract shuffling Adds to reasons not to shuffle: spark spread, wheeling charges, price volatility, etc Increase the incentives for acquisition of low carbon resources Increase the transparency and accountability of the program

The Effects of a CO2 Cap on RPS in the UK CO2 cap can make RPS redundant Depends on policy and market conditions

Implications for Compliance Reporting Double regulation considerations Harmonize reporting systems between renewables program and CO2 cap Bundled & unbundled RECs, allowances, offsets, other caps’ allowances Pooling for small providers More information is on the Oregon proposal and modeling is available at:

Cost Variability of Load Serving Entities Possible Rate Impacts of RPS and CO2 Cap by Utility—Medium Load Growth Case

Allowance Price Risks

Efficiency Improvement Possible Coal plant heat rates serving Oregon Weighted average = 11,100 BTU/kWh Range = 9,600 to 12, best performing coal fired fleets Average heat rate = 9,854 Range = 9,382 to 10,146 Efficiency gains expected to be capped at 3-5% due to boiler design limitations under BAU Fuel treatment technologies might further improve heat rates