Aging facilities along with new and proposed Environmental Protection Agency (EPA) regulations are driving the retirement of a significant amount of coal-fired power generation across the United States. The total unit retirements between 2012 and 2021 could exceed 30,000 megawatts (MW).² This trend will have a significant impact on midwestern and southern states, which have the second highest projected amount of coal-fired retirements. MISO has projected that recent proposals from the EPA could result in 3,000 to 12,600 MW of retirements within its footprint, resulting in insufficient reserve margins as early as 2016. ³ While the Energy Information Administration projects that energy consumption will experience a smaller demand growth than in the previous 20 years, it still expects US energy demands to increase over current levels.

Even though 3,00MW is a small percentage of the installed generation capacity in the MISO system, new generation in key locations is needed to satisfy demand and maintain a safe reserve.⁴ Given the current market, the most likely replacement will be new natural gas-fired units.

Predicting the likelihood of new generation investment in the MISO footprint requires evaluating the incentives or impediments to construction. Such generation investment is driven primarily by three factors: (1) the price for the capacity, which determines the return on invested capital, (2) the ability to demonstrate a need for the investment, and (3) the feasibility of developing potential sites. Under its structure, MISO conducts transmission expansion planning—including transmission upgrades and expansion needed for new generation—but does not conduct generation expansion planning. MISO’s structure and the regulatory structure of the states in its footprint are important considerations. They influence price, need, and feasibility of new generation construction.

MISO’s current voluntary resource adequacy construct provides limited price signals for generation investment. Generation investors typically negotiate directly with load serving entities (LSE) to provide capacity, rendering it difficult to determine if the value of capacity will support generation investment. MISO is changing this model, but it is unclear whether the changes will be sufficient to drive generation investment. By June 2013, MISO will implement an annual capacity auction to provide LSEs the ability to purchase capacity requirements. This auction will fix a value for capacity so generator investors can evaluate if the price supports their future investment. The new one-year construct, however, still may not provide sufficient price stability to support generation investment. Many believe that a longer, three- to five-year capacity requirement is needed before prices truly reflect the value of capacity and incent construction. PJM, for example, has adopted a three-year market commitment. Recently, two MISO members left to join the PJM markets due, in part, to PJM’s higher capacity price.

The MISO footprint also contends with a regulatory structure in several MISO-covered states that, to some degree, severs generation investment from a purely market-driven approach. Most of the utilities operating in MISO are vertically integrated and produce, transmit, and deliver electricity to retail customers under state oversight.⁵ Vertically integrated utilities have obligations imposed by state statutes to serve and supply power to retail customers. In return, utilities are provided compensation opportunities through retail rates.⁶ Vertically integrated utilities’ decisions about generation investment are not necessarily made on the basis of whether capacity payments will compensate them for their investment. Instead, vertically integrated utilities’ expansion plans typically are driven by integrated resource plans (IRP) that are generally reviewed by a state regulatory body. The incentive to build is based on projected needs, statutory obligation to meet these requirements, and an ability to earn a return on investment through retail rates—not the level of capacity payments. These incentives operate to encourage construction by vertically integrated utilities rather than third parties. This structure may also push down capacity prices in MISO because the auction depends on scarcity of generation to signal the need for investment (through higher prices) but a well-functioning state IRP process should result in generation being planned before prices rise too high.

Generation will be constructed in MISO either because market prices for capacity make generation investment attractive or because an IRP process projects the need for capacity. Load expectations determine the need for new generation. A significant obstacle to either factor driving investment derives from uncertainty over the need. MISO’s own analysis concludes there will be a sufficient reserve margin if the proposed EPA regulations and uncertainty around carbon control are resolved in a fashion that allows continued reliance on coal-fired generation.⁷ Generating the magnitude of investment required for a coal-fired or natural gas-fired generator is difficult, especially when there is significant uncertainty about when the capacity need will arise. The uncertainty acts to discourage generation investment by both vertically-integrated utilities and independent investors. Both must show a need for the generation, and uncertainty over the impact of regulations could operate to make it difficult to persuade investors and state regulators a project should be built.

Demand-side management (DSM) also affects the need for new generation. Investment in DSM could change the point in the planning process when the utility sees that it needs new generation to meet its projected demand. However, projections about savings generated by DSM programs sometimes overstate energy saved. Some studies even suggest that end-users may consume more energy as a result of more efficient products. Some states in the MISO footprint are requiring significant investments in DSM and may conclude that DSM should address all or part of projected capacity needs. There is a risk that DSM penetration that turns out to be less than projected will put more pressure on the need for capacity in a shorter time period. This could also limit or restrict the type of capacity that could be built in the time period to satisfy reserve requirements.

Capacity portability between MISO and PJM could help address the need for new generation. When implementing the RTO systems, FERC had an option to institute a standard market design for resource adequacy, including development of a capacity market. FERC chose instead to allow individual RTOs to develop individual standards. MISO’s resource adequacy planning has been sufficient given the significantly different state regulatory approach in many MISO states. However, differences between PJM’s and MISO’s approaches to resource adequacy render it difficult for one facility to have value in both markets. If generators have the option of selling capacity in either MISO or PJM, the electricity could be sold into the RTO with the greatest need. Expanding the available market provides greater assurance that generator investors will be able to earn a return on their investment. Currently, however, differences in the PJM and MISO market rules make this difficult. For example, the MISO capacity auction will require capacity availability for a one-year period, while PJM’s capacity auction mandates a three-year commitment. The problem is compounded because PJM and MISO look at transmission availability differently. MISO’s FERC comments express concern that current rules act as barriers to efficient capacity transfers between MISO and PJM.

Generator interconnection procedures in MISO generally support the feasibility of generation investment. While the feasibility of generation investment involves myriad factors, two primary factors are required—regulatory approvals and resource availability. MISO has made great strides in processing generator interconnection requests. Following a backlog of transmission requests, MISO implemented new policies to shorten application processing time. Vertically integrated utilities generally must establish a need before a state regulatory authority for new generation. New generation also needs infrastructure, water, and electric transmission. MISO generally is well positioned to provide these components.

MISO’s footprint is well positioned for the construction of new generation from a feasibility standpoint. However, consideration of price and need render it less certain that generation can be built. MISO’s adoption of a capacity market will provide a mechanism that could begin to signal a need for investment, but the IRP process may cap prices below a level necessary to signal investment. Uncertainty, both on the impact of EPA regulations and DSM initiatives, may also operate to inhibit investment in generation.

Endnotes

1. 2011 Long Term Resource Assessment, MISO, p. 8, available at http://tinyurl.com/99sxyzo (last visited Aug. 22, 2012).

2. Jesse Gilbert & Michael Niven, Upcoming, recent coal-fired power unit retirements, SNL Data Dispatch (Aug. 15, 2012, 9:40 AM ET), http://tinyurl.com/8rpjgz8.

3. 2011 Long Term Resource Assessment, supra, note 1.

4. BBL Summary, Electricity Sector Liberalization in the U.S. and MISO’s Effort, John Bear, presenter, Research Institute of Economy, Trade & Industry IAA. June 27, 2012, http://tinyurl.com/8tl29pr (last visited Aug. 20, 2012).

5. Id.

6. The Regulatory Assistance Project, Electricity Regulation in the United States: A Guide, 10 (March 2011).

7. 2011 Long Term Resource Assessment, supra note 1, at 7.