On March 31, 2009, House Energy and Commerce Chairman Henry Waxman of California and Rep. Ed Markey of Massachusetts, issued a draft proposal for combined energy and climate change legislation. The proposal combines a national Renewable Energy Standard (RES) with a carbon cap-and-trade program. Here, the McGuireWoods Energy and Climate Change Team provides an analysis of the RES proposal in the context of a carbon cap-and-trade program.
The RES requires power companies to source a defined, and increasing, percentage of their power from renewable resources such as wind, solar, biomass and incremental hydro. In the proposal, the term also includes energy produced from fuel cells as a renewable resource, and provides bonus credits for renewable non-combustion distributed generation.
The RES is accompanied by few “carrots,” but many “sticks,” which may combine to promote construction of renewable facilities across the country, without any focus on specific geographic areas where renewables may be more cost-effective (typically, wind generation in the Upper Midwest and the Great Plains). In that regard, the RES is likely to provide a bonanza to the renewables industry, but will also likely impose relatively higher costs of compliance on power companies, and their ratepayers, that are not located in resource rich renewables areas.
The RES applies to most retail electric utilities that supply power to end use electric consumers. Beginning in 2012, such utilities are required to surrender annually sufficient Federal renewable electricity credits (RECs) to cover the annual RES mandates. RECs are issued to generators of renewable electricity by DOE, with one REC equal to one megawatt hour of generated renewable electricity. RECs are freely tradable, and may be “banked” and used for later compliance for up to three years. Since some states with their own RES requirements implement the programs through support payments from power companies, the legislation provides these power companies with federal RECs equal to the amount of renewable power generated as a result of the support payments. The legislation also directs that complying retail electric suppliers shall not be denied the opportunity to fully recover in retail rates the prudent costs of compliance with the RES (although, as discussed below, whether REC payments will be considered prudent may become a complicated question).
The RES mandate begins at a hefty 6% (as a percentage in megawatt hours of annual power generation for end use consumption by a retail electric utility, excluding existing hydropower), and escalates between 2.5% to 3.5% roughly every other year until it reaches 25% by 2025. Thus, the RES increases to 8.5% in 2015, then to 11% by 2016, and so on. States are provided with a partial opt-out provision, whereby the Governor can elect, on an annual basis, to reduce the RES requirement by up to 20% per year, provided all electric and natural gas retail companies in the state are in compliance with the legislation’s proposed Federal Energy Efficiency Resource Standard (that proposed efficiency standard generally requires retail electricity and gas companies to reduce electric or gas consumption by a defined percentage over a baseline, starting at 1%, through adoption of energy efficiency measures). The energy efficiency opt out provision essentially pushes the fight over the size of the RES down to the state level so that renewable resource poor states have an option to reduce their RES obligation. If a state fully elects the energy efficiency opt out, the RES mandates would start at 4.8% in 2012, rise to 6.8% in 2014, 8.8% in 2016, and end at 20% in 2025.
The size of the proposed RES is quite substantial, ending at 25% in 2025. As a consequence, renewable power will become an important, and perhaps predominate, power company compliance option for the legislation’s associated carbon cap. Under an RES, the generation of renewable power generally produces a carbon reduction, because the renewable power, wherever it is consumed, displaces fossil fuel power, and its associated carbon content. This carbon reduction also “counts” as a reduction under a carbon cap. The amount of carbon reductions associated with renewable energy generation largely depends on the carbon content of the fossil fuel that is displaced. In general, a MWh of carbon free renewable energy might displace about one third to one ton of carbon (based on e.g., the relative carbon content of a MWh of inefficient gas up to a MWh of inefficient coal). Hence, under the RES requirement of 17.5% in 2020, one might expect an associated carbon reduction of 6-12% from the power sector. Under the proposed legislation, the carbon cap requires a 20% reduction from 2005 levels by 2020, so one might expect to see one third to one half of the power sector’s carbon reductions to meet the cap come from renewables.
The implications of this correlation between the RES and the cap appear to be unexplored. Two issues arise. First, the RES effectively undermines the market-based mechanisms (and benefits) of the carbon cap for the amount of reductions the power sector achieves as a result of compliance with the RES. Under a pure market-based carbon cap-and–trade program, to assess renewables as a carbon compliance option, a power company would compare the costs of purchasing carbon reductions from renewable generation with the auction price of a carbon allowance, and chose the lower cost option. However, under an RES, a power company is required to choose the renewables option, up to the amount of the RES, regardless of cost or the availability of lower cost carbon reduction options. If some (or much) of renewable power is not a cost-effective compliance option for carbon reductions, then compliance with the carbon cap will cost more than it should, and would not be the least cost solution intended by the cap structure.
Second, while some level of cost-ineffective carbon reductions required by compliance with an RES may be acceptable as a policy matter, the size of the proposed RES will tend to make renewables an important compliance method under the cap for power companies because the RES appears to equate to 25-50% of the power sector’s carbon reduction requirements (in 2020). Under that scenario, there is potential for research, development and deployment of other cost-effective carbon reduction technologies for the power sector, e.g. geologic sequestration (a technology favored under the legislation), to be delayed or crowded out, because the amount of demand for non-renewable carbon reductions from this sector is more limited.
The legislation also provides an alternative compliance payment option so that power companies unable to obtain RECs may still comply. However, that alternative compliance payment provision is essentially punitive. Its sets the alternative payment option at double the prevailing REC price from last year (with a maximum of $50 per REC). In addition, monies spent on the alternative compliance option are refunded back to those power generators (and their ratepayers) which actually complied with the RES requirements by submitting RECs, in proportion to the amount of RECs submitted. Thus, power generators in resource rich states not only can comply more readily with the RES, but would also receive subsidies for that compliance from power generators in resource poor states, which might be expected to utilize the alternative compliance option payment. In the event of a REC shortage, the ultimate affect of the alternative compliance option would seem to be to encourage construction of above-market renewable facilities (as compared with the prevailing REC price) in order to avoid paying a double REC alternative compliance payment.
The proposed legislation also specifically fails to connect the RES requirement with the associated carbon benefit in ways that are likely to undermine the least cost objective of the REC program, and result in deployment of renewable resources in states where they are less cost effective. The purposes of the REC program are (1) to establish a market- based (least cost) trading scheme for renewable energy such that power generators located in states where renewable resources are less cost-effective can forgo constructing, or purchasing power from, local above-market renewable facilities, and instead purchase RECs from renewable facilities located in areas that offer more cost-effective renewable power generation opportunities; and (2) to ensure that the United States deploys its investments in renewable power in locations where renewables are most cost-effective. Because the legislation provides no connection between a REC and the associated carbon benefit, neither objective may be fully met.
In brief, a purchaser of a REC loses the associated carbon reduction benefit, which instead provides “free” fleet decarbonization benefits to the state where the renewable power is consumed. As a consequence, the real cost of a REC in the context of a carbon cap-and-trade program is the price of the REC plus the price of the lost carbon benefit. As a result, two possible outcomes arise: (1) the legislation will encourage some degree of construction of above-market renewables facilities in resource poor states because that is where the economics go; and (2) to the extent that power companies in resource poor states purchase RECs, rather than construct above-market renewables facilities, their REC purchase will also subsidize compliance with the carbon cap (through fleet decarbonization efforts) in those states where the renewable power is actually consumed.
The possibility that the legislation incents construction of above market renewable facilities in resource poor states arises because of the unaccounted for carbon benefit. When a power company decides whether it should prudently purchase a REC or invest in its own renewables portfolio, its price calculation is based not only on a comparison of the cost of a REC versus the cost of constructing a renewable power portfolio or purchasing local renewable power. In addition, the company must also include the cost benefit of the carbon reduction it would obtain if it constructed a renewable facility or purchased renewable power for on system usage to calculate the true costs of a REC purchase versus a renewable power purchase. The value of the additional carbon cost benefit from on-system renewable power consumption could be 15-20% of the cost of a REC, and therefore may make “prudent” the construction of an above-market renewables facility or the purchase of above-market renewable power in lieu of the purchase of RECs. In that circumstance, the result will be legislation that promotes the construction of uneconomic renewable facilities at the expense of more economic renewables facilities (i.e., those more cost-effective renewables facilities that would have been constructed in resource rich states had the power company chosen to purchase RECs rather than construct its own facility).
While the REC program is intended to make the national RES more cost-effective, by allowing access to the most cost effective renewable power by companies in any part of the country, many power companies in e.g., the Southeast, have complained that it will simply result in their ratepayers transferring money to wind-based renewable facilities located in the Upper Midwest and the Great Plains. However, that result may not obtain because it fails to account for the carbon penalty associated with a REC purchase. Instead, the real complaint for power companies in the Southeast may be that the proposed legislation largely compels them to construct above-market renewable power facilities in the Southeast because this is the least cost solution to the combined RES/carbon cap problem. To the extent the legislation encourages construction of above market renewable facilities, those higher costs will also raise the cost of compliance with the carbon cap since the RES effectively mandates that a large portion of power sector carbon cap compliance must come from renewables. Since the RES will represent compliance with a large share of the power sectors carbon cap requirements, the possibility may have relatively large overall cost impacts. Of course, if a power company opts to purchase a REC instead, the effect is to subsidize the fleet decarbonization efforts of the state where the renewable power is consumed, which raises additional equity issues.
In the end, it is difficult to layer performance standards such as an RES over a market-based carbon cap-and-trade program without upsetting the intended functioning of the carbon market. It is equally difficult to set up a market-based program such as the REC market, and expect it function optimally when a primary economic element of that program (the carbon benefit) is simply ignored. Under the proposed legislation, since the carbon benefit of renewables is unaccounted for, the efficient functioning of a least cost REC market as well as a least cost carbon cap market is compromised.