CPP Roadmap

One of the most significant decisions confronting the state is how to assign the allowance value created by the limitation of carbon emissions under the CPP. The options are many, but generally include producers, consumers, clean energy programs and other state programs including tax reductions. States can decide on some combination of the following options and thus distribute value across a variety of entities or objectives:

1) Allocate allowances to producers

• Allocating allowances to producers involves granting the economic value of emissions allowances to EGUs. Inherent in the rate based approach, it is one mass based option.
• This approach reduces utility costs but forgoes the opportunity for sharing the value of emissions allowances more broadly.
• It can be used to protect trade-exposed industries and prevent economic activity leakage.
• Grandfathering or Updating Output Based Allocation?
• For restructured states, such as Pennsylvania, there is a key decision about how to allocate value by grandfathering or updating output based allocation (OBA). In regulated cost of service states – such as Michigan, Missouri and Utah – there are much smaller implications from this decision since all costs are passed on to ratepayers.
• Grandfathering sets the allocation at the time of the policy design, typically based on the EGU’s share of production in recent years, and does not change over time. Because the allocation is fixed, producers do not have an incentive to alter production to earn free allowances. Generators that participate in competitive electricity markets will bid to supply power at a price that reflects the opportunity cost of using allowances—the fact that once they have been used to cover emissions from electricity generation, they are not available to sell at their market price—even though they are received for free. This prohibits new cleaner sources of generation from receiving production incentives since they were not historically producing. It is more economically efficient since it does not have a production subsidy yet it is more costly to ratepayers than an updating OBA.
• Updating Output Based Allocation grants EGUs allowances for each MWh of generation based on the ratio of EGU generation to state emissions budget set for producers. As such, it changes over time based on actual production and creates an incentive to produce. This enables cleaner sources of generation to also be eligible for production incentives based on their level of output.

2) Allocate allowances to consumers via LDCs

Consumers (ratepayers) receiver the emissions allowance value by granting emissions allowances to LDCs who then sell them to EGUs. Through legislative or PUC requirements, the value must be passed on to consumers.

Consumers may receive the value of the emissions allowances through electricity bill refunds via an annual lump-sum, semi-annual, or monthly deduction. One caution is that bill reductions may reduce consumer incentives to invest in efficiency if they offset emissions rate increases or are large enough to reduce bills below business as usual.

States may choose to help low-income consumers who will be disproportionally impacted by any increase in electricity prices.

3) Auction and distribute revenue to state programs or tax reductions

Allowances can be auctioned and use the resulting revenue to fund programs within or outside of the energy sector (e.g., transportation, education, health care) or some combination thereof. The RGGI program auctions 94 percent of its allowances and focuses its revenue on supporting EE and RE; the CA trading includes a range of state programs.

The revenue also can be used to offset taxes or reduce state debt.

If auctioning allowances, the state needs to determine how often an auction is needed to address market volatility (e.g., annually or quarterly) and decide various design features, for instance if it wants to set a price floor (e.g. California has a price floor of $10 per ton, increasing annually at the rate of inflation plus five percent) or have a reserve to give EGUs and investors more price projection stability. In addition, the state can put in place rules around third party auction participants, hording, etc.

4) Set-aside (grant) allowances to particular complementary policies, energy technologies or industries

• Complementary policies to reduce overall emissions can be funded through set-asides, which designate the revenue of a certain number of allowances to particular efforts.
• Can be used for a variety of zero-emissions technologies – such as nuclear, wind, solar, hydro, or EE – or other emerging technologies. Allowance allocation in RGGI states to energy efficiency programs led those states to economically benefit from RGGI by reducing consumers’ utility bills.
• Allowances can be designated to energy-intensive industries that might face economic hardships.
• Set asides of allowances for clean energy can be very similar to out-based allocation and can be designed to either be technology-specific or technology-neutral.
• Can be directed to specific sectors for EE -- residential, commercial, and/or industrial.

5) Designate some allowances for early action credit

• Does the state want to allocate allowances for early action measures in RE and low-income EE that would qualify for free doubling of credit from EPA? How much does the state want to allocate to this program?

DONE!

Decision #9: Complementary Policies (CPs)

If a state chooses to pursue CPs, the following two questions arise:

1) Does the state want to support CPs through allocating allowance value?

To help support CPs, states can choose to auction emissions allowances (under a mass based approach) and dedicate some portion of the revenue to the CPs. For example, states in the RGGI dedicated around 2/3 of their emissions allowance auction revenue to energy efficiency programs. Documentation of that approach indicates that it reduced the cost of compliance for ratepayers and increased local clean energy jobs.

2) Which types of Complementary Policies does the state want to pursue?

There are many options for CPs that reduce carbon emissions. Some are easier quantify, making them easier to conduct cost assessments, and some are easier to implement. Detailed information on these policies can be found in NAACA’s report “Menu of Options” , as well as the State and Local Energy Efficiency Action Network (SEE Action). The following list of CPs are categorized based on NGA Center staff assessment; states should undertake more detailed analysis based on their specific context.

• Easier to quantify and implement: EERS, RPS, CHP in electric sector; CHP in other sectors; reduce losses in T&D; building codes; behavioral EE, appliance efficiency standards; lead by example procurement; change the dispatch order of power plants; improve utility resource planning practices; improve demand response policies; tax carbon emissions;
• Harder to quantify and implement: Optimize grid operations, foster new markets for EE, incentives for clean energy; revise capacity market practices; improve integration of RE into the grid; carbon capture;

Decision #9: Complementary Policies (CPs)

CPs are state policies, incentives, and programs that require or support additional sources of emissions reductions that may not be a part of an EGU emissions standard approach. Examples include Energy Efficiency Resource Standards (EERS) and clean energy incentives.

1) No Complementary Policies Included in Compliance Plan

• This is simpler for the state to manage since it does not require additional state effort to analyze and adopt additional measures.
• Assuming a robust trading market where EGUs can buy ERC credits or allowances from other states to comply, if a state does not adopt complementary policies that require in-state investments in clean energy, the state may lose investment opportunities and jobs in the clean energy sectors. A trade-off to consider is if in-state clean energy development is more expensive than importing ERCs, then compliance costs may not meet “least cost” criteria.
• May raise the cost of compliance by missing low-cost opportunities that a pure emissions standard approach may not capture (e.g., building codes or third party energy efficiency). Energy efficiency policies have been pursued by most states because the market has not led to capturing all cost-effective efficiency. Academics debate the reasons and best ways to address this issue, but they largely agree that this ‘energy efficiency gap’ in the market exists. Under the CPP, a carbon cost will create a new value for EE and address part of the market failure of externalized costs of energy. However, many argue that several other market barriers will remain such as: split incentive between landlords and renters, additional externalities, and information gaps.

2) Add or Expand Complementary Policies

• Under any type of state plan, there is potential to reduce total compliance cost for residents from augmenting state EGU emissions standard plans with CPs that are lower-cost than the utility compliance costs. When those CPs are more expensive than utility compliance cost, the state may decide to not pursue, or may want to pursue for other co-benefits such as jobs, local air quality, etc.
• Increases in-state investments and job creation for clean energy services, by targeting state policies and programs at in-state efforts.
• While CPs are not needed for CPP compliance, it may be difficult to gain political attention and staff time for their consideration if not included in the state compliance planning process. This is a consideration especially where programs are set to expire under the compliance period or face extensions.

Decision #8: ERC and EMV Protocol Development

Under the intra-state and multi-state plans, states can either:

1) Follow the EPA federal plan protocol for ERC definition and EMV protocols.

• Significantly less administrative burden for the state.
• Lose ability to define what qualifies as an ERC

2) Propose alternative formulas for: gas-shift ERCs, ERC value for fossil generation, ERC formulas for CHP, waste to energy, solar PV, biomass, and other sources not prequalified by EPA. The state can also change their REC protocols to allow for ERC credit creation.

• Gain ability to earn credit for additional resources.

3) Determine if and how to create the early action credit use for ERCs between 2020-2022.

Decision #7: Trading Options Under Rate

1) Trade-Ready for Sub-Cat Rates

*ONLY AN OPTION FOR SUB-CAT

• If selecting two sub-category rates for coal and gas, then the EGUs can trade ERCs between states only within their respective sub-categories.
• Must use federal EMV standards for ERCs and use federal registry
• Does not require inter-state coordination since market players all following federal guidelines.
• States do not need to revise plans if other states “drop out”
• State is less dependent on the actions of other states
• Likely to be most transparent cost expectations within the rate options for investors, utilities and regulators due to larger market size. Larger markets will have market analysts that track and analyze prices while the smaller markets are harder to analyze and offer less financial incentive for consulting firms to track.

2) Intra-State Trading: EGUs Trade Only within State

*OPTION FOR ANY RATE PLAN

• Avoids cross-state legal and political challenges
• May be easier for PUC to anticipate and regulate costs since all within the state
• Restricts market size so can be much more expensive
• Limits incentive of to maximize reductions since limited in ability to sell ERCs

3) Multi-State Plan

*OPTION ONLY FOR BLENDED RATES

• States can partner to allow trade between their EGUs only if they agree to blend their rates and give the combined average rate to all affected EGUs.
• Allows for trading with partners that identify mutual benefit from trade.
• Enables better analysis of carbon price based on smaller pool and known state decisions.
• Political challenge for state with easier target to agree to more difficult target.

Decision #6: Rate Plan Design: Sub-Cat v. Single Average v. State-Defined v. Blended Rate

Potential Options:

1) Sub-Category Standards:

• Grants coal units lower generating costs, thereby increasing coal generation, thereby increasing demand for, and price of, ERCs. The net impact on coal is unclear. May assist cleaner coal units and hurt dirtier units since the coal sub-cat rate will be hard for dirtier plants to meet and will give production subsidy to cleaner coal plants. (RFF will report on their model results on this item at workshop)
• Can follow EPA’s Model Rule, thereby reducing: planning burden, administration, legal uncertainty of EPA approval, and need for joint-planning with trading partners.
• This is the only rate-based option that allows for trading-ready option; it also allows for trading with specified states.
• State takes on the ERC administrative burden: state needs to develop ERC EMV guidelines, monitoring, plan using state or EPA registry, operate ERC desk, oversee third-party ERC verifiers.
• Legal challenge risk for utilities if ERC discredited.

2) Single Average Standard:

• By using technology-neutral standard, states can achieve the most economically efficient outcome within the rate options, however, it cannot have cross-state trading unless it uses blend rates, so the lost trade opportunity may mean a net economic loss.
• Trading allowed only by blending rates, which is a politically challenging prospect for a state with an easier target.

3) State-Defined: (i.e. states can apply standards to individual EGUs, categories of EGUs that are equivalent to EPA standard)

• Can be designed to favor either coal or natural gas to meet state energy goals.
• Does not allow for trading with other states so lost trade opportunity may cause large economic loss. EGUs can trade within the state.

4) Multi-State Blended Rate:

• States can partner to allow trade between their EGUs only if they agree to blend their rates and give the combined average rate to all affected EGUs.
• Allows for trading with partners that identify mutual benefit from trade.
• Enables better analysis of carbon price based on smaller pool and known state decisions.
• Political challenge for state with easier target to agree to more difficult target.

CPP Roadmap

(draft as of 7/5/16)

Decision #5: Allowance Value Distribution Options

Decision #4: Trading Options Under Mass

The following options are available for all mass-based plans. State measures approaches are not necessarily trade-ready but can be made so.

1) Trade-Ready:

• Minimal state oversight once a state agrees to use federal tracking system

• Likely maximum market size so likely least cost option

• States do not need to revise plans if other states “drop out”

• State is less dependent on the actions of other states (compared to a joint state program)

• Likely to provide the most transparent cost expectations for investors, utilities and regulators due to national market size and market analysis.

2) State-Specified Multi-State Partners:

• May offer political buy-in to only trade with similar states.

• If EGUs in the state are sellers of allowances to EGUs in other specified trading states that have tougher targets, then it may increase revenue compared to participating in a larger national market.

• Can easily expand to national trade-ready at any point

3) Intra-State Trading: EGUs Trade Only within State:

• Avoids cross-state legal and political challenges

• May be easier for PUC to anticipate and regulate costs since all within the state

• Restricts market size so can be much more expensive

• Limits incentive of utilities to maximize reductions since limited in ability to sell allowances.

Decision #3: Mass Plan Design: How to Address Leakage to New Sources? Allocate, Justify, or New Source Cap

NGA Center for Best Practices

Potential Options:

1) Allocate emissions to existing NGCC sources

• The EPA proposed allowance allocation for handling leakage is to use updating output-based allocation averaging around 5% of allowances, and an allowance set-aside that targets incremental RE.

• States can propose alternative allowance allocation methods to address leakage and seek EPA approval.

2) Submit justification for why leakage to new sources is not a problem for your state

• Does the state want to demonstrate that leakage is unlikely to occur due to unique state characteristics or state plan design? What are key reasons this might be true?

3) Include new source complement

• New source caps are 1 to 10% above the existing source cap. Many observers believe this additional amount to be small.

• Does state have authority to regulate new sources? Can it be attained?

• How does the state’s projections of new emissions from electricity load growth compare to the assigned new source cap?

• Consider that electricity demand growth has been increasing at a slower rate than economic growth. Will this trend continue in the state?

• Are complementary policies able to help the state achieve cap with new sources?

• Does the state want to propose an alternative projection for new source complement to EPA? If so, on what grounds?

Decision #2: Mass-EGU-only v. Rate v. Mass-State Measures

1) Mass - EGU-Only:

• About 10% easier target for most states based on EPA figures;

• Lower cost from national total; but state and regional differences may vary so states would want to confirm this, perhaps using detailed modeling.

• Captures the emission reduction benefits of fossil plant retirements more readily than rate plans. Retirements under rate plans offer less compliance value and will depend on the change in fuel mix.

• Less state administrative time since the state does not need to create federally approved EMV protocols nor oversee ERC trading and third-party verifiers;

• In order to facilitate a market for EE, and to compensate utilities for their investments in EE, states will need to use existing EMV protocols or develop new ones, but they do not need to be submitted to EPA for approval.

• Less legal liability for state and utility to use allowances that are ‘created’ by state at the beginning of the compliance period compared to the uncertainty of whether sufficient legitimate ERCs will be produced in time for compliance deadlines;

• Some observers have asserted that the availability of mass allowances is more certain compared to the rate-based ERCs that have to be generated.

• Would be favorable for protecting existing nuclear.

• Creates the opportunity for a state to assign the value of emissions allowances outside of EGUs (e.g., via an auction of some or all of the emissions allowances).

2) Rate:

• Both rate and mass plans can accommodate electricity demand growth through increased renewable energy. However, in a rate plan, coal and gas generation can increase if there is a corresponding increase in non-emitting sources. (Meanwhile, in a mass plan, growth of fossil production can only increase if there is a shift out of coal into gas.)

• Could be competitive advantage for in-state EGUs if the neighboring states adopt a mass approach, especially if neighboring states are deregulated.

• Allows for clearer materialization of EE and RE credits in ERCs for third-party providers when using the Trade-Ready ERC plan;

• May pose a legal liability for utilities if an ERC does not materialize as contracted or is found to be invalid (the risk of this needs to be further defined).

• States will need to develop ERC and EMV protocols, oversight and tracking (although EPA may provide some assistance). This will require a greater state administrative burden than under a mass plan.

• Some observers have raised concern about the potential for only a limited number of rate-based trading partners (since rate based states an only trade with other rate based states) and the creation of so-called “ERC Islands”.

3) Mass - State Measures:

• If the state is already implementing a state cap and trade plan that includes features not allowed under a simple mass cap, such as offsets, then a state measures plan allows for the existing policy to stand alone without implementing a new policy.

• States that do not want to impose a cap and trade program or rate-based targets may implement a portfolio approach that will achieve the mass goals under a state measures plan.

• A benefit of the state measures plan is that it can catalyze the political will to analyze and pursue complementary policies that operate outside the market-oriented rate and mass EGU plans. Complementary policies, such as an energy efficiency resource standards, can reduce the compliance cost to the state. The economic benefits of complementary policies are no different weather they are pursued as part of the state measures plan or if are pursued to complement mass or rate EGU plans and are not submitted to the EPA as part of the official compliance plan. However, it may be easier to attain the political will and staff time needed to evaluate these options if you are including them in your federal plan, which has a clear deadline.

Decision #1: State Plan v. Federal Plan

1) State Plan:

• More decision making authority at state level; Increased ability to coordinate and manage political and economic decisions between Governor, DEP, PUC, utilities and stakeholders

• Allows EE for in-state cost reductions directly -- through use of ERCs in rate plans or allowance set-asides in mass plans – which is not directly allowed in the proposed federal plan. However, since federal-plan states can trade credits, it is unclear that this advantage holds.

2) Federal Plan:

• Shifts political and administrative burden to the federal level; allows state to indicate its disapproval of the rule and have more limited involvement in compliance.

• Its shape is not certain: do not know the overall design of the federal plan until it is finalized (expected this summer) and additional specifics will be set according to each state. For instance, final version of the federal plan may use a rate based approach, a mass based approach or allow for either; that can significantly impact utility company economics based on neighboring state decisions around rate and mass approaches that EPA may not take into consideration.

• Can specify how to allocate allowances (as an alternative to the federal plan default), but likely will have more limited options for allocation decisions than under a state plan.

• Can maintain ability to trade credits nationally and shift to a state plan at any time.