Clean Power Plan Expert Forum

Alternative Compliance Payments under the Clean Power Plan

Nov 21, 2014 | Clayton Munnings

This is the ninth in a series of questions that highlights RFF’s Expert Forum on EPA’s Clean Power Plan.

RFF asks the experts: Could an alternative compliance payment help states comply with EPA’s Clean Power Plan and, if so, how might it be designed and implemented?

Under EPA’s Clean Power Plan, states will need to make long-term planning decisions even though significant uncertainties exist about the costs of complying with the rule. Could an alternative compliance payment (ACP), which might allow an electricity producer to pay an emissions charge in lieu of complying with a particular policy, aid in planning and allow states to better manage electricity prices and electricity system reliability? How might an ACP be designed and implemented so that its use ensures compliance with the Clean Power Plan?

 

dallas-burtrawkaren-palmer“Scholarly research suggests that an alternative payment mechanism linked to investment can be designed to meet and exceed environmental goals and produce more rapid investment in innovative technologies, and improve environmental outcomes at lower cost . . . the approach could yield similar investment outcomes in the context of the Clean Power Plan.” See full response.

—Dallas Burtraw, Darius Gaskins Senior Fellow, Resources for the Future

—Karen Palmer, Research Director and Senior Fellow, Resources for the Future

 

kathleen-barron“Yes! … EPA could facilitate this approach by including in the final rule a carbon price that, if imposed by a state on its generators during the compliance period, would satisfy EPA that the state would achieve sufficient reductions during that period.” See full response.

—Kathleen Barrón, Senior Vice President of Federal Regulatory Affairs and Wholesale Market Policy, Exelon Corporation

   

robert-a-wyman-jr“EPA should confirm the availability of the ACP option. Consistent with previous ACP applications, EPA also should confirm that the near-term price for a building block 1 ACP should reflect the upper bound of EPA’s anticipated building block 1 cost (e.g., $6 to $12 per ton of greenhouse gas emissions reduction) because the ACP would serve as an alternative to building block 1–related reductions.” See full response.

—Robert A. Wyman, Jr., Partner, Latham & Watkins LLP


Dallas Burtraw, Darius Gaskins Senior Fellow, Resources for the Future
Karen Palmer, Research Director and Senior Fellow, Resources for the Future

EPA’s Clean Power Plan offers substantial flexibility to states and energy providers to achieve environmental goals; however, this flexibility may not be adequate to address the special situations and concerns of every entity. EPA should therefore consider defining an alternative process involving a compliance payment with revenues targeted to specific uses.

Special circumstances may severely raise costs or even pose obstacles to compliance. For example, some states face a front-loaded compliance obligation that implies exceptional rates of emissions reductions by the year 2020. As another example, some plants have recently constructed post-combustion pollution controls that have remaining un-depreciated accounting and economic lives of a decade or more; rapid reduction in the utilization of these plants could impose arguably unfair economic costs. A third example is that many small systems lack a diversity of fuels and technologies, making compliance difficult.

The proposed Clean Power Plan would address these challenges by enabling flexible compliance through emissions rate averaging or emissions trading over multiple units and potentially across states, which can reduce overall costs. However, compliance could involve the purchase of credits from parties outside one’s system or state, effectively stripping the state of financial capital that could be used instead to achieve a long-run system transformation. Some entities or states may welcome alternative ways to comply.

EPA should consider broadening the policy goal to more explicitly allow for a fee-based approach. There are multiple ways that revenue might be used, and the level of the fee might be adjusted accordingly. Revenues returned to ratepayers as part of the electricity tariff would lower electricity prices. If the fee took the form of a tax with revenues directed to the state government, electricity prices would rise, yielding a reduction in electricity consumption, and perhaps enabling a lower fee. If the revenues were used for immediate investment in energy efficiency or other technology, or held in an escrow account to accumulate capital for a future investment, then ratepayers would see electricity prices rise and in addition they would begin paying immediately for the investments that would ultimately occur. Consequently, the payment might be lowest in this last case. In each case, however, compliance with the goals of the Clean Power Plan should be built into the plan for using an alternative compliance payment.

Because other comments have addressed a role for an emissions fee with revenues going to customers (see Kathleen Barrón’s response to this question) and government, we will elaborate on the alternative with revenues directed to investment.

Revenues dedicated to energy efficiency can be spent promptly and would be expected to yield near-term results, but investments in a technological transformation to low- and non-emitting sources might require years to accumulate sufficient capital and complete projects. States offering a capital investment plan might be given additional intertemporal flexibility, with an accompanying obligation to achieve equal or greater cumulative emissions reductions. In sum, the investment approach does the following:

  • Avoids having to meet standards precisely in the near term;
  • Introduces a payment set by EPA for excess emissions (or emissions rates) above the standard;
  • May direct revenue from the payments to accumulate in an escrow fund;
  • Provides an incentive for compliance entities to expedite investments to reduce emissions, avoid the payment, and lower ratepayer costs; and
  • Can be designed to accelerate investment in innovative technologies, improve environmental outcomes, and lower costs to producers and consumers.

In effect, the payment is an environmental bond. It would be denominated in dollars per unit of emissions for emissions in excess of a state’s target, and it seems important that EPA would identify the payment amount. The amount could be based on system modeling and investment planning to identify the fee that would yield the requisite long-run environmental outcome. As an alternative to a planning process, EPA might allow states to impose a fee calibrated to the estimated social cost of carbon dioxide emissions as identified by the Interagency Working Group. Alternatively, EPA may allow states to impose a fee equal to the marginal cost of compliance expected to emerge in regional trading or averaging programs that others are joining for compliance. The distinction is the revenues collected would remain within the state.

Scholarly research suggests that an alternative payment mechanism linked to investment can be designed to meet and exceed environmental goals and produce more rapid investment in innovative technologies, and improve environmental outcomes at a lower cost than would an inflexible technology mandate (See Patino Echeverri et al. 2012, also published in the Journal of Regulatory Economics). And reasoning suggests the approach could yield similar investment outcomes in the context of the Clean Power Plan. The basic approach of an alternative payment mechanism is simple. The transparency of this approach may be an appealing attribute to some parties who otherwise view the challenges of the Clean Power Plan as complicated and confusing. The state’s obligation in developing its plan would be to describe how the revenues would be used. Such an alternative payment mechanism would provide assurance to ratepayers that their resources remain available within their own system or state.

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Kathleen Barrón
Senior Vice President of Federal Regulatory Affairs and Wholesale Market Policy, Exelon Corporation

Yes! One version of the alternative compliance payment concept would be to use existing centralized dispatch programs—such as those in use by regional transmission organizations (RTOs) —to co-optimize reliability and greenhouse gas reductions by requiring fossil generators to include a cost per ton of carbon in their electricity bids. EPA could facilitate this approach by including in the final rule a carbon price that, if imposed by a state on its generators during the compliance period, would satisfy EPA that the state would achieve sufficient reductions during that period. In return, the state would receive a “safe harbor” from compliance with its emissions rate or emissions cap for the period during which the carbon price was imposed on the state’s generators. Any state that opted into the safe harbor RTO dispatch approach would be both allowed and required to focus on crafting a long-term glide path to achieve EPA’s final emissions goals by 2030.

The Mechanics

In states with organized markets that opt in, the RTOs would dispatch the system as depicted in the figure below.

Figure 1

The independent system operation (ISO) would return the greenhouse gas fees collected to load-serving entities in the corresponding state, according to the number of megawatt-hours served. The state would direct its load-serving entities how to use the greenhouse gas fees, whether for mitigating customer bill impacts or for other state policy objectives, such as funding energy efficiency or demand response programs.

The same principles behind the RTO dispatch concept could be applied outside organized markets. Vertically integrated utilities similarly determine least-cost dispatch among the owned or purchased generation sources available to serve that utility’s native load, and customers pay rates based on the average fuel cost of the units dispatched plus fixed costs/return. To qualify for this safe harbor, a single utility dispatching multiple generation sources could agree to reflect a CO2 adder in the dispatch cost of its fossil generation, much like the RTO would. The utility would then determine least-cost dispatch, including the CO2 adder and customers would pay rates based on the increased average fuel cost associated with the units dispatched, again along with fixed costs/return.

Benefits of This Approach

  • Provides states and customers with a viable voluntary approach to compliance
  • Resolves, in part, the compliance questions surrounding the reasonableness and viability of EPA’s building blocks by providing another pathway to compliance during the safe harbor period
  • Ensures effective deployment of capital in coal units by allowing existing units with limited remaining operational lives to be fully utilized without additional costly retrofits
  • Provides appropriate price signals to maintain and expand clean energy and natural gas utilization
  • Guarantees electric reliability at both the state and regional level by linking greenhouse gas abatement to reliability dispatch
  • Achieves significant greenhouse gas reductions at lowest cost
  • Collected fees can be utilized to significantly offset customer costs or to achieve other public policy objectives at the states’ discretion
  • Allows states to achieve the benefits of coordinated regional action without negotiating comprehensive interstate compliance agreements—a complex process that might take years to complete
  • Provides states and industry with longer compliance runway, allowing for improved planning and regulatory certainty

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Robert A. Wyman, Jr.
Partner, Latham & Watkins LLP

Both states and sources will need compliance flexibility to minimize costs, assure reliability and avoid stranding assets. The National Climate Coalition (NCC) originally proposed two types of compliance options for electric generating units (EGUs), expecting EPA’s proposal to be source- based consistent with prior section 111 rulemakings. The first recommended option would be traditional emissions trading of “emission reduction credits” from EGU over-performance, similar to lead credit trading under EPA’s lead phasedown program, and of “system offsets” from surplus energy sector reductions achieved outside the EGU fence line. This degree of flexibility is needed because many EGUs will not be able to make even the required heat rate improvements, while the other building blocks are by definition beyond the control of individual EGUs.

The second recommended EGU compliance option is the alternative compliance payment (ACP). A source would use an ACP as a compliance alternative when on-site limitations or regulatory risks (e.g., the risks of triggering New Source Review) prevent on-site modifications and the costs of the credits and system offsets are higher than anticipated. The state would collect ACP payments and apply the funds toward any other building block (i.e., building blocks 2, 3, or 4) or other qualified energy sector opportunity. This would provide states with valuable energy sector financing, while providing sources compliance assurance at reasonable cost.

There is Clean Air Act precedent for such a cost mitigation instrument. The ceiling-price ACP concept was first conceived during the 1990 Amendments stakeholder discussions and formally articulated in President Clinton’s July 1997 memorandum to EPA (62 Fed. Reg. 38421, 38429, July 18, 1997) when EPA revised the National Ambient Air Quality Standards (NAAQS) for ozone and particulate matter. Recognizing that the revised standards could impose an unanticipated level of cost on regulated sources, the memorandum recommended an ACP option for sources facing control costs at or above a cost-effectiveness threshold to fund reductions from other sources and to stimulate new technologies. EPA has approved ACP programs under Clean Air Act Section 110 (see, e.g., SCAQMD Rule 1121, “Control of Nitrogen Oxides from Residential Type, Natural Gas-Fired Water Heaters”).

As part of its final Clean Power Plan rulemaking, EPA should confirm the availability of the ACP option. Consistent with previous ACP applications, EPA also should confirm that the near-term price for a building block 1 ACP should reflect the upper bound of EPA’s anticipated building block 1 cost (e.g., $6 to $12 per ton of greenhouse gas emissions reduction) because the ACP would serve as an alternative to building block 1–related reductions. As the building block 1 obligations are expected to occur in the early years of the program, the ACP price for that component of the program should not be expected to interfere with the potentially more costly measures contained in some of the other building blocks, the implementation of which is likely to occur over a longer period of time.

Given the stringency of building blocks 2 through 4 and EPA’s interim and final goals, these ACP concepts should be expanded to cover the entire compliance burden facing EGUs. In addition to confirming state primacy in glide-path planning and timing, EPA should outline the conditions under which a state may use both banking and borrowing of reductions, as well as other mechanisms, such as market- and integrated resource planning–based development of clean replacement power, interstate trading, and multi-state energy planning. These tools will protect against the reliability, price, and market distortions that are likely to result from excessive compliance costs, while also enabling states to optimize energy planning and ensure that near-term commitments don’t compete with longer-term, lower-carbon strategies through the unintended lock-in of more carbon intensive investments.

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