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Clean Air Act: EPA’s Proposal for Reducing CO2 Emissions From Electric Power Sector Would Present the States With a Complex Task

July 8, 2014

The Obama Administration has released its much-anticipated proposal for limiting nationwide carbon dioxide (CO2) emissions from the electric power sector, calling for an overall 30 percent reduction by 2030, compared to a 2005 baseline (about a 17 percent reduction from current emissions). The proposal calls for increasing the efficiency of coal-fired power plants and for reducing the amount of power generated by coal- and oil-fired plants in favor of natural gas-fired combined cycle turbines, low- and zero-carbon power generation (renewables and nuclear) and improved demand-side energy efficiency. The proposal will likely receive a boost from the Supreme Court’s recent decision upholding the core of EPA’s existing permitting requirements for greenhouse gas emissions.[1]

There will be a major focus in coming months on whether EPA has legal authority to adopt this rule, since it rests on a little-used provision of the Clean Air Act. But equal attention should be given to the work it would impose on the states. While sweeping, EPA’s proposed rule only provides a broad outline and sets ultimate objectives: state-specific CO2 emission reduction goals. The task of fleshing out the details and implementing the reductions would fall to the states, which will have one to three years to submit plans for reducing emissions from their electric power sector. In many states, that will include making changes to or expanding programs administered by agencies that in the past have had no direct responsibility for air quality programs. The resulting decisions – made in the next two to four years – could substantially reshape the electric power sector in many parts of the country over the next two decades. EPA will be accepting comment on the proposal for 120 days and has said that it hopes to finalize the rule in June 2015. If it succeeds in doing so, states will be required to complete their plans between June 2016 and 2018.

Background

Context: The President’s Climate Action Plan

Noting that power plants account for “roughly one-third of all domestic greenhouse gas emissions,” President Obama’s Climate Action Plan, released in June 2013, committed to cutting such emissions from both new and existing power plants. Concurrent with issuance of the Climate Action Plan, a Presidential Memorandum directed EPA to propose two sets of Clean Air Act regulations.

First, EPA was directed to follow up its April 12, 2012 Notice of Proposed Rulemaking on greenhouse gas emissions from new power plants[2] by issuing a new proposed rule no later than September 20, 2013. EPA timely issued the revised proposed rule. See R. Allan, EPA Issues Revised Proposed Regulations for Carbon Dioxide Emissions from Power Plants, Marten Law Environmental News (Nov. 18, 2013). The revised proposed rule wasn’t published in the Federal Register, however, until January 8, 2014, with a 60-day public comment period.[3] That comment period subsequently was extended by 60 days to May 9, 2014.[4] The Presidential Memorandum instructs EPA to “issue a final rule in a timely fashion after considering all public comments as appropriate.”

Second, the President directed EPA to “issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed, and existing power plants by no later than June 1, 2014,” to issue a final rule no later than June 1, 2015, and to require that states submit their implementation plans under section 111(d) of the Clean Air Act “by no later than June 30, 2016.” The proposed rule released on June 2 responds to this second imperative of the Presidential Memorandum.

Statutory Basis for the Proposed Rule

The Clean Air Act includes both health-based and technology-based requirements to control air pollution. The health-based requirements are linked to ambient air quality standards – the amount of a particular air pollutant found in the ambient air that is deemed safe for public health and welfare. EPA’s existing greenhouse gas permitting rules were developed under the Act’s permitting programs aimed at achieving and maintaining ambient air quality standards. Under those rules, a permit is required before constructing a new major source of air pollutants that is subject to an ambient standard or any major modification to a major existing source of those air pollutants.[5] Permits for these sources must require them to implement the “best available control technology” (BACT) for each pollutant “subject to regulation” under the Act.[6] The U.S. Supreme Court recently upheld EPA’s determination that greenhouse gases have become “subject to regulation” and so must be included in the BACT determination made for sources that become subject to permitting because of their emissions of other air pollutants.[7] However, the Court struck down EPA rules requiring sources to obtain permits based solely on their greenhouse gas emissions (a ruling that reportedly affects only about 3 percent of U.S. greenhouse gas emissions).[8] .

The Agency’s newly-proposed greenhouse gas standards for existing power plants derive from another of the Clean Air Act’s technology-based requirements, contained in section 111 of the Act.[9] This section requires EPA to designate categories of stationary sources and to develop standards for performance of new sources within each category that reflect the “best system of emission reduction” (BSER) that “has been adequately demonstrated,” taking into account costs, non-air quality environmental impacts, and energy requirements.[10] The resulting rules are referred to as New Source Performance Standards (NSPS). As with other provisions of the Clean Air Act, “new” sources for purpose of NSPS include both newly constructed sources and sources that have been modified in a manner that increases emissions.[11] EPA has used its authority under section 111 to develop NSPS for source categories ranging from refineries, pulp mills and cement plants to dry cleaners, grain elevators and landfills.[12]

A less frequently-used provision of this section, section 111(d), also authorizes technology-based performance standards for existing sources, subject to three limitations:[13] (1) EPA must already have adopted a performance standard for new sources in the same source category; (2) no existing source performance standards are allowed for any air pollutant for which EPA already has established a health-based ambient air quality standard; and (3), standards also are barred for emissions (or possibly source categories) regulated under section 112 of the Act, which applies to hazardous air pollutants (HAPS).[14] (The 1990 Clean Air Act Amendments included two versions of this final constraint, creating some ambiguity as to whether the prohibition only applies to hazardous air pollutants regulated under section 112, or to any source category as a whole that has been listed under section 112.[15] This ambiguity may be the subject of future legal challenges to the proposed greenhouse gas rule.)

Section 111(d) actually looks to the states to develop the particulars of the performance standards for existing sources, in response to guidance from EPA. EPA is directed to adopt regulations that “establish a procedure similar to” the process used to develop State Implementation Plans (SIPs) under section 110 of the Act,[16] which are plans proposed by states, subject to EPA approval, for achieving the ambient air quality standards set by EPA.[17] EPA adopted regulations in 1975 that set EPA’s review process and approval criteria for state plans.[18]

EPA triggers the states’ planning process under section 111(d) by issuing guidelines that identify the “systems of emission reduction” that the agency believes have been adequately demonstrated for the relevant existing sources. The states must then submit a plan to EPA establishing performance standards for those existing sources for the designated air pollutant.[19] In formulating their plans, states are allowed to take into consideration, “among other factors,” the remaining useful life of any particular source to which the standard would apply.[20] As with SIPs, if a state fails to submit a plan or EPA determines a state plan is not satisfactory, then EPA may proscribe a plan for a state.[21]

EPA’s Proposed Rule

EPA’s 39-page proposed rule is embedded in a 645-page document that will be the preamble for the proposal when it is published in the Federal Register. The agency also has released several other documents in support of the proposed rule, including a 105-page “legal memorandum” defending EPA’s proposal as consistent with the agency’s interpretation of section 111(d) and seven “technical support documents” totaling another 490 pages. While a significant portion of this material is designed to bolster the future legal defense of EPA’s proposal, much of it is intended to provide direction to the states as they seek to implement this rule.

EPA’s preamble and supporting documents describe the components of a “system of emission reductions” for reducing CO2 emissions from the electric power sector, consisting of increasing the efficiency of power generation and replacing power generated by higher emitting plants. The states would not be required to implement the systems as described by EPA, but would need to develop a set of performance standards that will achieve emission reductions equal to the state-specific CO2 emission goals that EPA developed using the components it has described. The states would have to submit their plans for implementing CO2 reductions to EPA between 2016 and 2018, and would have to achieve state-specific emission goals by 2030 (with interim goals that would be phased in from 2020 to 2029).

EPA’s Guidance on Standards of Performance

The preamble to EPA’s proposal describes four “building blocks” that it says meet the criteria for a “standard of performance” under section 111(d):[22]

  1. Improving the heat rate (i.e., efficiency) of individual generating units, thereby reducing the amount of CO2 produced per unit of electricity generated;
  2. Reducing emissions of the most carbon-intensive generating units by substituting generation by more efficient fossil fuel-burning units;
  3. Reducing emissions of the most carbon-intensive generating units by substituting low- or zero-carbon generation (i.e., renewables or nuclear); and
  4. Improving demand-side energy efficiency to reduce the amount of electricity generation required.

Only the first of these “building blocks” involves reducing the rate at which a fossil fuel-fired power plant emits CO2 while it is generating electricity. The other three involve simply reducing the use of fossil-fueled plants with higher CO2 emission rates, either by reducing the demand for power or by substituting power from lower-generating sources. The fact that EPA is looking to reduce emissions by limiting the use of certain power plants is likely to be one of the central points of contention regarding EPA’s proposal.

EPA justifies this approach by asserting that a “standard of performance” need not be based on the performance of individual regulated sources, and instead can be applied across a collection of sources, possibly including sources that are not subject to regulation under section 111(d). Section 111(a) provides that a “standard of performance” must reflect “the best system of emission reduction which … the Administrator determines has been adequately demonstrated.” EPA maintains that the statute imposes no constraint on the type of “system” that may serve as the basis for an emissions standard. The only requirement, according to EPA, is that the “system” reduces the emissions of the affected sources.[23] Thus, the “system” may include “anything that reduces emissions, ranging from add-on controls applied to the affected sources’ smokestacks to control emissions, to measures that replace production or generation at the affected sources and thereby reduce emissions from those sources.”[24] EPA therefore reads the phrase “standard of performance for any existing source” to include the possibility of reducing or eliminating the use of that source and replacing it with a source of a different type.

While discussed at length in the proposed rule’s preamble and technical support documents, EPA’s “building blocks” are not spelled out in the proposed regulation. Instead, EPA opens the door to their use by the states through a proposed definition of “emission standard” that tracks its broad reading of what may constitute a “system of emission reduction.” EPA’s proposes that, for purposes of this rule, an “emission standard” would include any requirement that applies to entities other than fossil fuel-fired generating units “that has the effect of reducing utilization of one or more affected sources, thereby avoiding emissions from such sources, including, for example, renewable energy and demand-side energy efficiency measures requirements.”[25] However, the proposed rule would require that the resulting emission reductions are “quantifiable, non-duplicative, permanent, verifiable, and enforceable.”[26]

State-Specific Goals

EPA’s proposed state-specific goals are expressed as an emission rate – a specific number of pounds of CO2 emitted for each megawatt-hour (MWh) of electricity generated by “affected electric generating units” (EGUs) – steam generating units, integrated gasification combined cycle (IGCC) facilities, and stationary combustion turbines.[27] The combined result of every state achieving these goals would be about a 30 percent reduction in CO2 emissions nationwide, compared to 2005. But while the state goals are aimed at achieving a relatively uniform result, the proposed emission rates vary substantially state to state. The lowest proposed is for the State of Washington, at 215 pounds of CO2 per MWh. The highest is for North Dakota, at 1783 pounds of CO2 per MWh.

The proposed rule would give states the option of converting the state-specific emissions rate performance goal into a mass-based performance goal, i.e., the total tons of CO2 emitted.[28] For states that use the rate-based performance goal, EPA would allow an adjustment to recognize that increases in electric generation from low- and zero-carbon sources, as well as use of demand-side energy efficiency measures, would reduce overall CO2 emissions without decreasing the emissions rate from affected EGUs.[29] No such adjustment would be necessary for states that convert the rate-based performance goal to a mass-based goal: shifting to low- or zero-carbon generating units and reducing electric demand through energy efficiency measures would directly contribute toward achieving a mass-based standard.

The wide variation in EPA’s proposed goals reflects the differences in the electric power sector across the states. There are about 1000 fossil fuel-fired power plants, housing about 3000 units (boilers and combustion turbines), in the United States. CO2 emissions from these plants make up roughly one-third of greenhouse gas emissions nationwide. But in some regions, zero-emitting hydroelectric and nuclear power have long been a significant source of electricity. The last decade also has seen significant growth in renewable energy installations (particularly wind and solar) in many states. Thus, in formulating its proposal, EPA had to take into account the differences among the states in their reliance on fossil fuel-powered electricity generation.

EPA’s proposal of state-specific goals expressed as an emission rate also reflects its view that a “system of emission reduction” can be applied collectively, at a state-wide level, and need not be achievable by individual regulated sources. EPA explained that it took a two-step approach. First it determined what would constitute the “best system of emission reduction” – the four building blocks discussed above – and then it applied that “system” to each state’s power sector, on a state-wide basis.[30] EPA’s preamble explains that the state-specific goals reflect assumptions that the agency made as to how much each of the four “building blocks” could contribute to emission reductions:[31]

  • Heat Rate Improvement – EPA assumed an average 6 percent increase in efficiency for coal-fired plants;
  • Increased use of existing natural gas-fired combined cycle (NGCC) plants – EPA assumed that the utilization of existing NGCC plants could be increased to an average of 70 percent of their capacity, displacing more CO2-intensive coal- and oil-fired steam generation;
  • Renewables and Nuclear – EPA assumed a nationwide average of 13 percent of power from low- and zero-emission sources by 2030, with state-specific targets based on current renewable generating capacity. EPA also assumed that nuclear plants at risk of closure - about six percent of nuclear power capacity – would not be retired and that construction would be completed on proposed, currently permitted nuclear plants;
  • End-Use Energy Efficiency – EPA assumed an average of 10.7 percent energy savings annually, starting in in 2030 and each year thereafter (rates for individual states based on 0.2% annual improvement over their current savings rate for existing energy efficiency programs).

In calculating potential renewable energy objectives, EPA divided the country into six regions and developed both an annual growth factor and a maximum renewable generation target for each region. The regional growth factors range from six percent in the West to 13 percent in the Northeast and 17 percent in the Eastern Central states.[32] EPA applied these growth factors to a state’s existing renewable capacity to determine state-specific renewable targets (as a percentage of each state’s total generation).[33] In a few states, EPA’s targets are lower than the state’s existing renewable capacity, but for most states EPA has assumed the need to steadily increase installed renewable generating capacity from 2017 through 2030.

State Plans

EPA’s proposed rule would require states to submit plans for achieving CO2 emission reductions equivalent to the state-specific goals to EPA by June 30, 2016.[34] States may obtain a one year extension if they make certain commitments before that deadline,[35] and may obtain a two year extension if they are participating in a multi-state plan.[36] Thus, if EPA is successful in completing the rule by June 2015, attention will immediately shift to the states, which will need to work quickly to put the specifics of emission reduction plans in place. Presumably some states or regions will begin working on plans before EPA’s rule is finalized. Others may be expected to oppose EPA’s rule, and will likely resist developing plans as long as possible, potentially forcing EPA to develop plans on their behalf. As authorized by the statute,[37] the proposed rule provides that EPA will develop a federal plan for any state that fails to submit an approval plan.[38] The rule also provides that any federal plan would be an interim action, automatically withdrawn when the applicable state plan is approved.[39]

State plans would need to:[40]

  • Identify the entities that will be subject to obligations under the plan (which can go beyond the regulated power plants);
  • Provide an inventory of CO2 emissions from the state’s fossil fuel-fired generating units during the most recent prior calendar year;
  • Describe the plan’s approach and geographic scope (including any other states participating in a multi-state plan);
  • Specify the average emission performance level expected from 2020 to 2029;
  • Specify the emission performance level expected in 2030;
  • Emission performance levels may be expressed as an emission rate (pounds of CO2 per MWh of net energy output from all affected entities) or as a mass-based limit (the total tons of CO2 emitted by all affected entities during the relevant period);
  • Identify the emission standards that will apply to each affected entity, and a demonstration that those standards, when taken together, will be sufficiently protective to meet the state’s emission performance level;
  • Demonstrate that each emissions standard is “quantifiable, non-duplicative, permanent, verifiable, and enforceable with respect to an affected entity.”;
  • If the plan relies on reductions that are not directly enforceable against fossil fuel-fired power plants, it must include milestones for events such as increasing renewable portfolio standards or starting end-use energy efficiency programs, as well as corrective measures that will be implemented if actual emissions are exceeding the plan’s projections;
  • Identify monitoring, recordkeeping and reporting requirements for each affected entity;
  • Provide for annual state reports to EPA about progress in implementing the state plan;
  • Provide supporting materials, such as a demonstration of the state’s legal authority to carry out each component of its plan, including emissions standards.

Implications

It is not difficult, broadly speaking, to identify potential winners and losers under EPA’s proposed rule: the proposed rule, its preamble, and the technical support documents are clear that virtually any source of power will be preferred to coal. The proposed rule promises – or threatens, depending on one’s viewpoint – to recruit a broad array of state and even local agencies into the effort to meet applicable state-specific CO2 performance standards. The proposed rule’s emphasis on quantification and verification of results, moreover, likely will trigger new attempts at multi-state pacts as well as a reassessment of existing programs to promote renewable energy and energy efficiency.

EPA’s proposed regulation provides a framework for reducing CO2 emissions from the electric power sector, but looks to the individual states to fill in the details. This will be a major undertaking for many states. Some states are likely to start work before EPA finalizes its regulation; others will resist until the final court challenge to EPA’s rule is decided. The proposed rule invites states to join together in multi-state plans,[41] which could revive regional cap-and-trade efforts like the Western Climate Initiative. Whether states act independently or collectively, some aspects of the proposal will require states to develop new regulatory regimes, and some states may need to enact new state laws before they can implement elements of their CO2 reduction plans.

But the most difficult choices will face states served by utilities dependent on coal- and oil-fired power plants. EPA’s proposed rule effectively requires some of the power plants in those states to be shut down, but leaves it to the states to decide how those plants will be selected and how the electricity they generate will be replaced.

The Expansion of Clean Air Act Responsibilities: State Agencies and “Affected Entities”

For many states, the state plan required under the proposed rule could involve programs administered not only by traditional environmental regulators, but also programs under the jurisdiction of other agencies that, up until now at least, have not been directly responsible for implementing the Clean Air Act. For example, most states with renewable portfolio standards place the implementation of that program under the jurisdiction of a public utility commission, public service commission, or similar entity charged with regulating utility service. Some energy efficiency programs – particularly those financed with ratepayer dollars – are also under the oversight of utility regulators. On the other hand, if a state includes energy efficiency for new residential and commercial construction as part of its Section 111(d) plan, it effectively will be recruiting state building code officials and municipal building departments into the growing cadre of Clean Air Act implementers.

Some states undoubtedly are better prepared than others for these jurisdictional challenges. In Connecticut, for example, air quality regulation, utility regulation, renewable portfolio standards, energy efficiency requirements and demand management programs are aggregated under one agency, the Department of Energy & Environmental Protection. That model, however, is the exception rather than the rule. Where responsibilities for the four “building blocks” of EPA’s proposed rule are spread among disparate state agencies, legislative direction likely will be necessary to establish how those building blocks will be assembled into a coherent state plan. In those states, it likely will be difficult to complete action and have a state program in place within the one to three year timeline proposed in EPA’s rule.

The reach of the proposed rule extends well beyond state agencies. For example, utilities or state governments may already have programs in place to invest in improved end-user energy efficiency (EPA’s fourth building block), and a state may wish to rely upon or expand that effort as part of its plan to reduce CO2 emissions. But if a state plan relies on reduced power demand as a means of reducing CO2 emissions, EPA’s proposed rule would require that those reductions be “quantifiable, non-duplicative, permanent, verifiable, and enforceable with respect to an affected entity.”[42] The state would have to decide who will be the “affected entity” – i.e., who will be held accountable for the success of an end-user program in actually reducing the demand for electricity. The same will be true for any other measure a state adopts in order to comply with the state-specific performance goal.

All of the state emissions standards – all of the “building blocks” included in the state’s section 111(d) plan -- will be federally enforceable, including by citizen suit. Thus, if a state plan relies upon an existing or enhanced renewable portfolio standard (requiring utilities to obtain a percentage of their power from renewable sources), utility compliance with that standard could be enforced by EPA, or by an environmental group through a citizen suit.

Quantification: Linking Renewable Energy and Energy Efficiency to CO2 Emissions

The need to make renewable energy and demand-side energy efficiency programs “quantifiable, non-duplicative, permanent, verifiable, and enforceable” may lead to a reexamination of a range of such programs. For example, 43 states have adopted “net metering” policies.[43] Unlike large renewable energy generating facilities, for which energy production generally is directly measured as it enters the grid, meters for smaller generating projects (such as residential rooftop solar PV installations) may measure only the customer’s net load: the amount of energy purchased from the grid, net of the amount of customer-generated energy delivered to the grid. The meters therefore typically understate the total amount of energy generated by the renewable energy source. EPA has noted that net metering programs “may … require supplemental reporting in order to track total generation that avoids CO2 emissions.”[44]

In determining compliance with their renewable portfolio standards, some states grant “bonus credit” to certain types of renewable generation, effectively multiplying the MWh or renewable energy credits (RECs) associated with a type of generation the state wishes to encourage. For example, several states grant bonus credit for solar PV installations; Delaware grants triple credit for PV.[45] Noting that “these credit multipliers and bonuses are not an accurate representation of the amount of renewable energy generation that is attributable to a RPS,” EPA has signaled that when “quantifying the amount of renewable energy produced as a result of a RPS included as a measure in a state plan, only the actual renewable energy generation used to comply with an RPS is relevant.”[46]

In other words, states have adopted policies that may, for purposes of convenience or to encourage certain technologies, either overstate or understate the amount of energy generated or, in the case of energy efficiency, the amount of generation avoided. Although states are free to adopt such policies for purposes of compliance with state law, greater rigor will be required for purposes of state plans under section 111(d).

A more difficult problem raised by EPA’s proposed rule involves how to account for interstate emission effects. As EPA recognizes, “electricity flows across state lines”:

Reducing electricity load through improved end-use energy efficiency (e.g., through state energy efficiency programs) or deploying new renewable energy electric generating capacity (e.g., through a state RPS) therefore can result in CO2 emissions effects that are realized outside the state that implements the regulation or program that produces the effects.[47]

States may pursue a variety of approaches to account for interstate emission effects. The proposed rule would allow states to propose multi-state, regional plans to comply with EPA’s emission performance goals. States also can develop tradable regional credit markets. At a somewhat simpler level, states could develop mutual agreements regarding how they will allocate avoided CO2 emissions. EPA notes that while this approach “avoids the potential for double counting of interstate emission effects among states,” it depends “on regional collaboration among all states in a grid region.”[48] Simply put, without cooperation among states, the requirement for emission standards to be both “quantifiable” and “non-duplicative” may mean that a state will not be able to claim all emission benefits associated with the renewable energy and demand-side energy efficiency elements of the state plan.

For more information on EPA's regulations for existing power plants or on renewable project development, please contact Richard Allan or any other member of Marten Law’s Energy or Air Quality practice groups.

[1] United Air Regulatory Group v. Environmental Protection Agency, 573 U.S. ___ (2014).

[2] 77 Fed. Reg. 22392.

[3] 79 Fed. Reg. 1352.

[4] 79 Fed. Reg. 12681 (March 6, 2014).

[5] 40 CFR §51.166(a)(7); 40 CFR §52.21(a)(2).

[6] 42 U.S.C. §7475(a)(4).

[7] United Air Regulatory Group, 573 U.S. ____.

[8] Id.

[9] 42 U.S.C. §7411.

[10] Id. at §§7411(a)(1) & (b)(1)

[11] Id. at §§7411(a)(2) & (a)(4) (definitions of “new source” and “modification”).

[12] See 40 C.F.R. Part 60.

[13] 42 U.S.C. §7411(d)(1)(A).

[14] See id. at §7412.

[15] See 70 Fed. Reg. 15994, 16030-32 (March 29, 2005).

[16] Id. at §7411(d)(1).

[17] See id. at §7410.

[18] 40 C.F.R. Part 60, Subpart B.

[19] Id. at §7411(d)(1); 40 C.F.R. § 60.22.

[20] Id.

[21] Id. at §7411(d)(2).

[22] See Preamble at 33-34 and Section VI.

[23] Legal Memorandum at 53.

[24] Legal Memorandum at 52.

[25] Proposed 40 C.F.R. §60.5820.

[26] Proposed 40 C.F.R. §60.5740(a)(6).

[27] See Table 1 to Proposed 40 C.F.R. 60 Subpart UUUU.

[28] Proposed 40 C.F.R. §60.5740(a)(3)(ii).

[29] See Preamble at 342-43; TSD for Goal Computation at 15-18.

[30] See Legal Memorandum at 35.

[31] See Preamble at 139-237.

[32] See TSD for GHG Abatement Measures at 4-18.

[33] See Preamble at 202-205.

[34] Proposed 40 C.F.R. §60.5755(a).

[35] Proposed §60.5755(b).

[36] Proposed §60.5755(c).

[37] 42 U.S.C. §7411(d)(2)(A).

[38] Proposed §60.5720.

[39] Id.

[40] Proposed §60.5740(a).

[41] See proposed §60.5745.

[42] See proposed §§60.5740(a)(5) & (6).

[43] See Database of State Incentives for Renewables & Efficiency (DSIRE).

[44] See TSD for State Plan Considerations at 82-83.

[45] See DSIRE.

[46] See TSD for State Plan Considerations at 63-64.

[47] Id. at 85.

[48] Id. at 93-94.

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