Combined heat and power (CHP) is a technology that produces electricity and thermal energy using the same fuel. Replacing conventional boilers with CHP at industrial, commercial and institutional facilities improves the efficiency of energy use, and results in significant emissions reductions, both conventional air pollutants and greenhouse gas emissions. And because CHP displaces electricity generation from the power grid and reduces electric sector emissions, CHP presents an opportunity to support compliance with EPA’s forthcoming carbon dioxide standards for the electric power sector under Section 111(d) of the Clean Air Act. Under a system-based approach to 111(d) compliance, these emissions reductions can potentially be sold to covered sources and create a new incentive to invest in efficient CHP.
To better understand the opportunity for CHP to contribute to compliance, CCAP undertook a new study, Expanding the Solution Set: How Combined Heat and Power Can Support Compliance with 111(d) Standards for Existing Power Plants. We found that 111(d) regulations are most likely to drive new CHP in industrial and coal-heavy regions most in need of low cost solutions—in large areas of the Midwest and South.
States expected to see growth in CHP will benefit from lower cost compliance with the 111(d) standard. At the same time, as highlighted in an earlier CCAP paper, CHP investments help the industrial, commercial and institutional sectors lower their energy costs and improve economic competitiveness in the global marketplace. CHP also promotes electric grid stability and enhanced energy resilience.
To assess the role that CHP can play in supporting power sector 111(d) compliance, CCAP pioneered a new approach that involved iterating between ICF International’s Integrated Planning Model® (IPM) and their CHPower Model. IPM® is a power sector dispatch model that solves for the least cost way of meeting generation and capacity requirements subject to constraints. The CHPower Model forecasts the industrial, commercial and institutional facilities most likely to install or expand CHP systems over time.
For each model run, we starting by running IPM®, and entered the resulting electricity, natural gas and, where applicable, the carbon price outputs as inputs to the CHPower Model. The CHPower Model was then run to determine the degree to which the new prices would lead to new investment in CHP, based both on the economics of the investment as well as historical rates of acceptance of economical investment opportunities. The resulting new CHP capacity was input as new capacity within IPM®, and the model was rerun. Iterations continued until the electricity, natural gas (and carbon price) outputs were essentially unchanged from one IPM® run to the next. A detailed discussion of the IPM® and CHPower Model assumptions can be found in our full report. The proposed assumptions and scenarios were reviewed by a multi-stakeholder advisory group, including experts from business, the federal government, and the environmental community.
Our study looked at two scenarios: a CHP Base Case, and a CHP 111(d) Policy Case. Both scenarios made use of the iterative approach, described above. In running the CHP Base Case, we sought to understand how much CHP might become economic and be accepted under a business-as-usual scenario, without a carbon standard. The CHP 111(d) Policy Case included an assumed carbon standard to understand the potential impacts of a 111(d) scenario that includes combined heat and power as a generation option and as a means of compliance.
In terms of total new CHP capacity, the CHP Base Case and CHP 111(d) Policy Case together resulted in nearly 10 GW of new CHP capacity by 2030. To put this in context, 10 GW is roughly equivalent to 15 average sized coal-fired power plants. CHP’s impact was greater in later model run years as our assumptions acknowledged that CHP projects can take time to deploy even after a decision is made to implement a CHP project; as such, CHP played a smaller role in 2020 (roughly 5 GW in total).
Our study found important regional differences. Under the CHP Base Case – without 111(d) – the models project that much of the new CHP capacity would be deployed in regions with higher than average retail electric rates and that are already subject to state or regional carbon cap-and-trade programs – California and the Northeast. In contrast, under the CHP 111(d) Policy Case, most of the incremental capacity is located in states with higher CHP technical potential and jurisdictions that are expected to see higher-than-average 111(d) compliance costs – regions that tend to have more coal-fired power generation and may also have more limited compliance solutions. We find the greatest opportunity in the Midwest, western portions of the PJM transmission organization territory, and some northern portions of the Southeast Electric Reliability Council (SERC) territory. In these states and regions, CHP can meaningfully contribute to 111(d) compliance while bringing a range of secondary benefits, potentially including manufacturing competitiveness, job creation, resilience to electrical disruptions, and reduced electrical grid congestion.
We conclude that combined heat and power can offer a cost-effective solution towards achieving 111(d) compliance. At the same time, a system-based 111(d) policy design can put these efficiency investments ‘over the top,’ shortening payback periods to the point that companies will choose to undertake projects at a number of industrial, commercial and institutional facilities. Designing a compliance strategy that recognizes the electric sector emissions reductions from CHP will help lower the costs of 111(d) compliance while encouraging investments in more efficient industrial, commercial and institutional facilities. This presents a win-win solution that supports economic growth and creates new employment opportunities while still achieving significant emissions reductions.