And what’s the goal: a share of load or a cut in carbon?
Michael R. Strong (firstname.lastname@example.org) is the chief legal counsel at the Illinois Power Agency. The views expressed in this article are his own. They don’t represent the views of the agency, nor do they indicate future agency actions.
After more a decade of state-based, targeted incentives for renewable electricity resources, evidence is accumulating that current production-based incentives should give way to results-based incentives if our goal is to trod the most economical path for getting to green.
Almost 10 years ago, I wrote an article for these pages entitled “What Do You Mean by Green?” It described the challenges of obtaining meaningful results from a renewable portfolio standard (RPS) using an Illinois proposal as an example.1 Although the specific example in that article didn’t become law, 10 years later Illinois and virtually every other state has some sort of renewable energy mandate or incentive. On top of that, the federal production tax credit is still in force. Having had years of experience under all of these programs, it’s possible to create and implement a framework for evaluating whether the goals of the RPS and federal incentives are being met.
The 2003 article posited that RPS programs contain two sometimes-conflicting goals: a) clean and b) renewable. For the purposes of this analysis, “clean” means a generating source that releases fewer U.S. EPA-regulated emissions per kilowatt-hour of output.2 Also echoing the 2003 article, “renewable” means generation that uses a fuel that doesn’t involve extracting matter from underground.3
State-level RPS regimes face enough of a challenge balancing (or choosing between) green and renewable, which don’t always overlap. The 2003 article, reflecting mainstream dialogue at the time, treated the goal of building more generation that’s clean or renewable (or both) as a desirable end result in itself. However, increased production from cleaner and more renewable resources serves only as a rough proxy for the real value of green energy – that being a marginal decrease in the use of non-clean and non-renewable generation. Green generation’s success depends on other generators curtailing either their emissions or their use of extracted fuels.
RPS in Illinois
State RPSs face two challenges to actually curtail emissions and fuel use from non-green generation. The first is an engineering issue: most preferred green resources, including virtually all new build, are non-dispatchable. We can’t cause the wind to blow, the sun to shine, landfill gas to percolate, or geothermal heat to rise on any sort of schedule.4 Many states – including Illinois – purchase either renewable energy credits (REC) or bundled RECs and energy on a yearly production basis (or similar length), rather than for scheduled deployment. This is a logical procurement strategy for non-dispatchable resources, but it also underscores the challenges of intermittency.
The second challenge of curtailment is the context of Illinois, which provides a unique framework for evaluating the success of the RPS. But first, a primer on the Illinois market.
Illinois allows electricity customers to choose an alternative retail energy supplier (known as “ARES”) other than the incumbent utility. For those that don’t choose, all but residential and the smallest non-residential customers default to a real-time (hourly) rate. Residential and small commercial customers may elect utility-provided real-time pricing, but the default rate for these customers is a fixed-price rate (known as the “bundled rate”) that passes through the actual costs of energy as procured by the Illinois Power Agency. The state’s two largest utilities, who account for more than 90 percent of all power delivery, don’t own or operate power plants.
Illinois has a system-wide RPS target that reaches 25-percent production from renewable energy resources by 2025.5 However, each of the three supply options – alternative supplier, default or utility real-time rate, and bundled rate – has a different RPS compliance structure.
• Bundled rate customers pay the actual costs of renewable energy procured by the Illinois Power Agency (IPA), subject to a hard per kilowatt-hour rate cap.6
• Alternative suppliers must make up at least 50 percent (and up to 100 percent) of their RPS compliance through a per-kWh payment (referred to as the alternative compliance payment, or “ACP”) at the same rate that bundled customers pay.7 Alternative suppliers may make up the difference with renewable energy credits, subject to certain fuel source targets.8
• Default and utility real-time rate customers are assessed a charge equal to the ACP rate.9
The Illinois RPS system has produced a significant increase in renewable energy capacity. In 2012, the American Wind Energy Association announced that Illinois ranked fifth in the nation in new-build renewable resources, with 823 MW of installed new capacity.10 Across all renewable resources, the IPA procured contracts from new build with expected annual production of over 1.86 million MWh.11 In September 2013, the fund holding ACP money is expected to swell to over $50 million for the IPA to purchase RECs. The enabling statute for investing these funds expresses preferences for purchases from distributed generation, solar- and wind-fueled resources, and long-term contracts.12
Given the state’s blend of competitive and regulated procurement, Illinois provides an opportunity to study whether the RPS initiative leads to more production from clean or renewable sources, and whether that production leads to curtailment of non-green sources.
Even so, Illinois doesn’t operate in a vacuum. Incentives outside the state can distort local effects. The most significant of these outside effects is the federal production tax credit. The PTC provides a very large incentive to wind and landfill gas – two of the three most important Illinois renewable resources, along with solar – of $22/MWh.13 Given that the published average imputed REC price for IPA procurements (both wind and solar) from new-build long-term renewable resources contracts that started delivery in 2012 was $12.56/MWh and $17.15/MWh for the two utilities (ComEd and Ameren, respectively),14 the federal production tax credit radically changes REC pricing for wind in particular.
Although the PTC makes wind more desirable from the perspective of an entity procuring renewable resources based on price, the PTC doesn’t maximize non-green energy curtailment. At first blush, the PTC should lead to reductions to non-green energy – on the theory that increased production from wind will displace non-green generation. However, as described above, wind (like most other preferred renewable resources) isn’t dispatchable. There’s evidence that wind (at least in the RTOs in which Illinois participates) tends to generate when non-curtailable resources (especially nuclear) are on the margin (i.e., during off-peak hours), rather than when curtailable and environmentally non-preferable sources, such as coal or oil, are dispatched.15
The key barrier to achieving the real value of green energy is aligning incentives with desired results. Both the Illinois RPS and the federal production tax credit are based on production, without regard to the benefits of displacing other generation. If incentives reflected the value of emissions not released and extractive fuel not used – results-based incentives – then green programs are more likely to achieve those goals.
The data needed to price a results-based incentive should be easy to collect in Illinois, because both PJM and MISO have well-developed markets, with information about the emissions profile of the plants on the margin at any given moment in the market. Until there’s a tax or market price on greenhouse gas emissions (similar to other emissions, such as SOx and NOx), the price may be artificially set in part to reflect state or federal preferences against fossil fuels and greenhouse gases.
To illustrate, consider the following two megawatt-hours generated by two comparable fictional facilities:
• MWh A was generated at night during a zero or negative pricing hour, when nuclear and wind are “on the margin” (in quotes because neither will curtail). Because there’s no anticipated environmental benefit, the results-based incentive would be $0 and the REC price would be the difference between the energy price and the facility’s costs – providing no competitive advantage against other RECs.
• MWh B was generated toward the end of peak, when several inefficient and polluting plants are on the margin, leading to emissions and fossil fuel curtailment. The value of the environmental benefit would reduce the necessary REC price, providing a competitive advantage against other RECs.
Over time, with results-based incentives like those in the hypothetical, renewable energy developers will tend to pursue resources that produce more output that looks like MWh B than MWh A. In turn, generators designed to capture the results-based incentives will be able to bid lower prices in REC procurements processes, whether conducted by cost-conscious utilities or by state agencies.16
Ideally, a results-based incentive would replace the PTC on the federal level as a subsidy for environmental results. With the PTC set to expire at the end of 2013, the federal government faces a perfect opportunity to set a results-based incentive structure for renewable development. For advocates of regulation of carbon, it will allow for a first attempt at creating a price for carbon based on incentives in advance of any future market-based pricing scheme. Through a results-based incentive, generators that displace emissions and fossil fuel use will be provided with a competitive advantage. In turn, the market should gain more generation options that produce environmentally preferable results. Also, because results-based incentives will likely value on-peak generation over off-peak generation, energy storage or other improvements in renewable dispatchabily would have a new potential revenue stream when used in conjunction with primarily off-peak generation.17 Those results have the potential to help Illinois and the rest of the country get to green.
1. “What Do You Mean by Green?” by Michael Strong, Public Utilities Fortnightly, October 1, 2003, pp.39-41.
10. See “Wind energy top source for new generation in 2012; American wind power installed new record of 13,124 MW,” American Wind Energy Association Press Release, Jan. 30, 2013.
11. “Illinois Approves Results of Renewable Energy RFP,” Illinois Commerce Commission Press Release, Dec. 15, 2010.
13. See energy.gov/savings/renewable-electricity-production-tax-credit-ptc. Note that the Illinois RPS wasn’t in effect in 2005 when solar was incentivized by the production tax credit.
14. Illinois Power Agency, Annual Report The Costs and Benefits of Renewable Resource Procurement in Illinois Under the Illinois Power Agency and Illinois Public Utilities Acts (April 2013) at 9-10 (available at http://www2.illinois.gov/ipa/Documents/201304-IPA-Renewables-Report.pdf).
15. See, e.g., Negative Electricity Prices and the Production Tax Credit, Northbridge Group, Sept. 14, 2012.
16. Regardless of whether results-based incentives come at the federal, RTO, or state level, it’s unlikely that (absent a breakthrough storage technology) any results-based incentive would allow green generation to compete across the board with non-green generation. As imagined in the example above, there will still be place for the REC system to pay the premium above market for renewable generation.