On June 2, 2014, the U.S. Environmental Protection Agency (“EPA”) announced proposed regulations (the “Clean Power Plan” Notice of Proposed Rulemaking (“NOPR”)) to limit greenhouse gas (“GHG”) emissions from existing fossil-fuel-fired electric generating units (“EGUs”).1 These proposed regulations would establish rate-based (pounds of C02 per MWH), state-specific goals for carbon dioxide emissions to achieve an overall 30 percent reduction of GHG emissions by the electricity sector from 2005 levels by 2030.
I. Comment Deadline When the NOPR was published in the Federal Register June 18, 2014, EPA established a 92 day deadline, until October 16, 2014, for comments. EPA also scheduled a series of all-day (9 a.m. – 8 p.m.) public hearings on the NOPR on both July 29 and 30 in the following cities:
Atlanta (Sam Nunn Atlanta Federal Center)
Denver (EPA Region 8 Building)
Washington, D.C. (William Jefferson Clinton East Building)
Pittsburgh (William S. Moorhead Federal Building)
II. Overview of the Clean Power Plan Under the CPP, EPA has set individual goals for each state. To achieve their individual goals, EPA expects the state implementation plans (“SIPs”) to include a portfolio of one or more of four “building blocks” to create a Best System of Emission Reduction (“BSER”).2 The building blocks consist of:
Building Block 1: Heat rate improvements at fossil fuel plants (e.g., increasing heat rates at coal plants by 6 percent)
Building Block 2: Displacing coal-fired steam and oil/gas-fired steam generation by increasing generation from existing natural gas combined cycle (“NGCC”) plants to raise NGCC plant capacity factors to as much as 70 percent) (the “Re-Dispatch Option”)
Building Block 3: Substitution of renewable resources and new nuclear facilities, and extension of life of existing nuclear plants that may be shuttered
Building Block 4: Demand reduction aimed at 1.5 percent annual electricity sales from 2020-2029
Of these four, EPA anticipates that the largest percent reduction of CO2 could come from Building Block 2, dispatching NGCC plants instead of coal-fired generation, i.e., the Re-dispatch Option, and Building Block 3, substituting renewable and nuclear generation for coal-fired generation. It should be noted that Building Blocks 2-4 are system-wide approaches that a state may use to achieve EGU emission reductions indirectly. They are also “outside the fence” reductions because their implementation depends on system-wide measures, not direct control of a particular EGU.3
This alert focuses on Building Block 2, the Re-dispatch Option, and how it might work.
III. EPA’s Assumptions for Building Block 2 Building Block 2 relies on reductions from emissions of CO2 from EGUs through “re-dispatch,” substituting electricity generation output from the most carbon-intensive EGUs, such as coal-fired and oil/gas-fired steam units, with generation output from less carbon-intensive EGUs, such as NGCC plants, which generally have lower heat rates and lower CO2 emissions.
In creating Building Block 2, EPA made at least two basic assumptions. First, it estimated that the average availability (capacity factor) of NGCC plants exceeds 85 percent, and that a substantial number of NGCC plants have operated above 70 percent for extended periods of time. BSER, therefore, assumes that all NGCC plants operate up to a 70 percent capacity factor and displace higher emitting generation (coal and gas steam units). It should be noted that, while EPA concluded that a 70 percent utilization rate for a state’s NGCC plants is feasible, it solicited comments on whether the target should be 65 percent or 75 percent. EPA noted that in 2012, the average utilization rate of U.S. NGCC capacity was 46 percent, and only approximately 10 percent of NGCC plants operated at annual utilization rates of 70 percent or higher.4
In setting this goal, EPA stated that it took into account three constraints on the ability to increase NGCC utilization: (1) limits on the ability of the natural gas industry to deliver the necessary increased quantities of natural gas, (2) the ability of steam EGUs to reduce generation while remaining able to supply electricity during peak hours, and (3) the ability of the electric grid to accommodate changed geographic patterns of generation.
IV. Electricity Regulation in the United States In order to understand how Building Block 2 might be implemented, it is important to understand how electricity is regulated in the United States.
Except with respect to municipal utilities and most electric cooperatives (which are often unregulated), regulation of electricity in the United States is bifurcated between the states and the federal government – in reality, FERC. State utility commissions regulate retail rates charged by utilities providing traditional electricity service and electric serve providers, as well the distribution level delivery of electricity to end-users, and the siting of generation. FERC regulates electric transmission in interstate commerce (essentially everything but distribution) and wholesale sales of electricity, including both bilateral contracts and the electricity markets run by Regional Transmission Organizations (“RTOs”). FERC also regulates natural gas transportation on interstate pipelines.
In the United States, wholesale electricity is traded in two ways: through bilateral contracts and through organized markets. Bilateral contracts between an individual seller, such as an independent power producer, and a buyer, such as a traditional utility serving retail load, are subject to the exclusive jurisdiction of FERC. Such contracts generally have multi-year terms.
Electricity sales into an organized wholesale market operated by an RTO, such as PJM Interconnection, Inc. (“PJM”), are also subject to FERC jurisdiction, but focus on spot or short-term sales in the real-time or day-ahead markets.5 Typically, RTOs dispatch EGUs in order of least-cost, based on the EGU’s bids or estimated variable costs. These bids and short-run marginal costs can incorporate environmental compliance costs. A good example is the California Independent System Operator Inc.’s (“CAISO”) market rules, which allows EGUs interconnected with the CAISO grid to incorporate certain GHG allowance costs into their bids. In the Northeast, PJM, ISO-New England, Inc., and the New York Independent System Operator, Inc., also allow generators to incorporate the cost of GHG allowances incurred by fossil fuel-fired EGUs subject to the Regional Greenhouse Gas Initiative.
V. Using Building Block 2 If a state wants to incorporate Building Block 2 into its SIP, it should have a couple of methods by which it could do so. Each approach has its own set of advantages and disadvantages, but given the length of time states have to meet the final goal (2030), many of the disadvantages may be eliminated by time.
a. Air Permit Amendment (Cap but no trade)
An amendment to an EGU air permit could force its re-dispatch by limiting its operating hours of operation or “run-time.” The consequences of imposing a CO2 cap on the generation of electricity from a high-carbon EGU must be analyzed under the regulatory regime in which the EGU operates.
For units selling into RTO markets, the new air limitations could be “written” into the unit’s bids, which are based on marginal costs. However, this method would not necessarily prevent the energy product (energy, capacity or ancillary services) from being replaced by coal-fired generation from another source if the energy product were sold into an RTO market.
If bilateral contracts are involved, a different problem could emerge. Many such power sales contracts have force majeure provisions that allow the power seller to suspend in part its performance – because of, for example, new air permit limitations – but these agreements often also give the buyer the right to suspend its performance, i.e., payment, if the seller is not providing product. In these situations, the power seller could lose a revenue stream, which could be catastrophic for an independent power producer.
For retail service utilities owning an EGU, new air permit limitation costs are very likely to be borne by ratepayers, although there could be some mismatch between the period in which the costs were incurred and recovered.
b. Limiting GHG Emissions at the Company Level
Many state utility commissions require their regulated electric utilities to engage in “Integrated Resource Planning” (IRP) (approximately 34 have some form of IRP), which has been an accepted way by which utilities create long-term resource plans. EPA noted that a state’s IRP process could serve as a method to implement re-dispatch in combination with the long-term substitution of NGCC plants for coal-fired generation.7 EPA particularly noted Colorado’s regulatory program under the Colorado Clean Air, Clean Jobs Act, which requires each investor-owned utility with coal-fired EGUs to prepare a multi-pollutant plan for meeting current and foreseeable EPA standards for emissions of NOX, SO2, particulates, mercury and CO2. EPA did note, however, that the Colorado statute was generally focused more on affecting a utility’s long-term planning, and affecting short-term dispatch decisions.8
c. Mandating Purchases
An easy option for state implementation may be simply to require retail electric service providers to purchase increasing amounts of electricity from low GHG generation, similar to the renewable power standard programs in place in 29 states. A state public utility commission simply could enact regulations requiring electricity suppliers (whether traditional utilities or new market entrants in restructured state markets) to purchase specific amounts of electricity from NGCC plants, renewable resource or nuclear facilities.9
d. Multi-State or Regional Approaches
EPA was very supportive of multi-state or regional approaches, and noted several times in the NOPR that the RTOs already have mechanisms in place to incorporate the cost of CO2 reduction plans into their markets. To that end, EPA proposed that SIPs relying on multi-state approaches would not need to be submitted until June 30, 2018 (rather than June 30, 2014 for single-state SIP approaches), in order to give states participating or planning multi-state approaches additional time to establish such program.10
The Brattle Group (“Brattle”) projects that many states are likely to opt to develop or join an emission trading or renewable energy trading program as part of their SIPs. Brattle suggests that a carbon-price-based regional approach could help to equalize the marginal cost of compliance and provide a platform for states to collaborate. Such programs should produce the most efficient solutions achieving the lowest-cost combination of NGCC-generation, energy efficiency and fuel efficiency at high CO2 sources throughout the trading footprint. In general, states with high marginal abatement costs could pursue lower-cost abatement opportunities from states with lower cost opportunities.11
Brattle also suggests that a trading program could take one of three forms:12
CO2 emissions allowance programs most consistent with the mass-based programs as in RGGI and California, which would start with a specific number of allowances (distributed to individual entities by auction or allocation) with generators needing to surrender one allowance to emit one ton of CO2, imposing an incremental production cost based on a market price for carbon, and in turn causing an increase in energy prices that benefit all zero-carbon resource types
A CO2 abatement credits program, under which CO2 allowances would be created by zero-emitting resources and could be purchased by fossil generators to reduce the numerator in their rates, also increasing electric prices but creating greater financial benefits for qualified zero-carbon resource types than for non-qualified types
A zero-carbon MWh credit, similar to a renewable energy credit, that qualified zero-carbon resources could create and sell to fossil generators to increase the denominator of their rate (with similar potential disparities in financial impacts for qualified versus non-qualified zero carbon resource types)
VI. Conclusion States will need to address many issues in developing their dispatching as part of their implementation plan. Is a stand-alone, multi-state or regional approach the best for insuring that reduction goals are met? Can a price be set for carbon; is it politically possible? Do state laws need to be changed? What role will be played by state public utility commissions? To what extent and how will the cost to the electric consumer be considered? What are the implications of shifting from coal to natural gas?
Developing a SIP will be an enormous public policy challenge in each state, given the variety of options available, the many shareholders, and – in the case of re-dispatching – the technical complexities involved. Participating in the EPA comment process now may well shape how the states implement this program.
The NOPR was published in the Federal Register June 18, 2014, 79 Fed. Reg. 34830 (June 18, 2014).
These “building blocks” are contained in guidelines in the NOPR. EPA has stated that a state is not required to use the “building blocks,” but may devise other methods to meet its goals.
To the extent these “outside the fence” measures require control of the energy market, they may not be authorized by the Clean Air Act or state air pollution control laws. See Utility Air Regulatory Group v. Environmental Protection Agency, et al., No. 12-1146 (U.S. S.Ct., decided June 23, 2014 at pp. 25-27).
79 Fed. Reg. at 34857.
There can be some longer-term contracts with RTOs, such as must-run contracts, but such contracts are beyond the scope of this analysis.
Under the CAISO’s tariff, natural gas-fired EGUs subject to California’s GHG regulations use a GHG allowance cost adder that has three components: (1) the EGU’s heat rate or fuel requirement, (2) the applicable GHG allowance price established by the California Air Resources Board (“CARB”), and (3) the authorized GHG emissions rate. All other fossil fuel-fired units subject to the GHG regulations bidding into CAISO’s markets must provide CAISO with GHG compliance costs consistent with the information that they provide to the CARB.
79 Fed. Reg. at 34887. IRP processes generally involve forecasting future loads, identifying potential resource options to meet future loads and then associated costs, determining the optimal mix of resources, receiving and responding to public participation, and creating a resource. Once the plan is prepared, it is submitted to the state utility commission for review and approval.
79 Fed. Reg. at 34881.
Inclusion of such provisions in a state implementation plan may be problematical without enabling state legislation. If enforcement of mandated purchases and other rules regulating energy markets rest only with the public utility commissions, EPA may not accept these provisions as enforceable parts of a state’s implementation plan.
79 Fed. Reg. at 34838.
“EPA’s Proposed Clean Power Plan: Implications for States and the Electric Industry,” The Brattle Group (June 2014) at 13.
Id. at fn 15.1