Historically, regulated investor-owned utilities had the exclusive authority to provide integrated power services within a state. Under the Public Utility Holding Company Act of 1935, retail electric power service was regulated and provided as a bundled product, including both electricity and transportation of electricity. This created barriers for anyone to own power assets and prevented the emergence of non utility power companies. Transportation included transmission over long distances and local distribution to individual customers. State and federal regulatory agencies had jurisdiction over the certification of transmission, distribution, and most power plants. They oversaw utility service territories and the pricing of bundled utility services to the local retail customers. Federal regulators monitored wholesale interstate activities, interstate transmission, and the licensing of hydro and nuclear facilities which was carried out by the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC), respectively.
The 1978 Federal Public Utility Regulatory Policy Act (PURPA) started changes in the electric power industry which are still evolving today. Adopted in large part to discourage our nation’s dependence on foreign oil, PURPA required utilities to purchase electricity from independent producers (also known as nonutilities), as long as the purchase price was no more than the utility’s “avoided cost” of production. Under PURPA, a power plant had to meet an efficiency standard by generating both electricity and useful process steam. Once these standards were met, the plant was considered a Qualified Facility (QF). Aided by strict state regulations that enforced PURPA, independent power plants grew rapidly through the 1980s and the first half of the 1990s.
The Energy Policy Act of 1992 was passed to set goals, create mandates, and amend utility laws to increase clean energy use and improve overall energy efficiency in the United States. It extended the exemption of power plants to those generating and selling electricity at wholesale rates. It also gave FERC the power to direct utilities to provide transmission service at cost. This lead to a slowdown in construction of independent generators, as utilities no longer were willing to provide power purchase agreements (“PPAs”) under PURPA. Depending on the region, some utilities decided to buyout the earlier PURPA-mandated PPAs and replace this generation with power purchases in the open market from merchant power plants. Starting in the late 1990s, PPAs were expiring after their typical 15 to 20 year contractual terms.
Without PPAs, these PURPA plants were either shut down or operated as merchant power plants at significantly reduced operating rates. By the end of the 1990s, an active market was emerging for buying and selling power plants. Without a PPA, these plants would be typically sold for a fraction of their construction cost.
FERC Orders 888 and 889, which went into effect in June 1996, helped promote additional competition in the electric power industry, with FERC 888 requiring utilities to unbundle their electricity services and FERC 889 requiring utilities to make information about their transmission systems available to other utilities. In addition, utilities were required to unbundle wholesale power from transmission operations.
As a result of FERC Order 2000, all public and nonpublic utilities put their transmission operations under the control of a Regional Transmission Organization (“RTO”). The goal was to eliminate price discrimination and to broaden the suppliers of electricity. Many states required utilities to divest generating assets, allowing for the growth of generating companies who bought these assets. Many new natural gas-fired power plants were built as the fuel was relatively inexpensive. These plants sold electricity in a spot market or under a PPA. The spot electricity price is based on supply and demand, and is determined through a bidding process where participants ask for a price that will compensate them for their operating costs (including fuel), and provide a profit.
The Great Recession brought on a staggering decline in electricity demand in the U.S., starting in late 2008. This lower electricity consumption continues although there are signs of strengthening demand as the nation’s economy continues to improve. Also causing a shift in the nation’s power industry is the federal government’s support for renewable power given its concern over global warming that may be caused by power plant carbon dioxide emissions. As a result of new regulations, many coal fired power plants are scheduled to close, especially in the eastern interconnect, with replacements coming from natural gas fired plants and alternative sources such as solar panels and wind turbines. Currently, there is significant uncertainty as to the number of coal fired power plants that will be shuttered over the next 5 years.
Regulating Agencies
The North American Electric Reliability Corporation (“NERC”) was formed in 1968 by the electric utility industry to ensure reliable power transmission in North America. NERC’s major responsibilities include working with all stakeholders to develop standards for power system operation, monitoring and enforcing compliance with those standards, assessing resource adequacy, and providing educational and training resources as part of an accreditation program to ensure power system operators remain qualified and proficient. NERC also investigates and analyzes the causes of significant power system disturbances in order to help prevent them from recurring. There are eight regional electric reliability councils that conform to industry standards set by NERC.
Control over the electric power industry is evolving. For example, two of the main governing bodies for Mississippi’s electric industry are the SERC and the Midcontinent Independent System Operator, Inc. (“MISO”). The SERC region includes the entire states of Missouri, Alabama, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, and parts of Iowa, Illinois, Kentucky, Virginia, Oklahoma, Arkansas, Louisiana, Texas, and Florida. In late 2013, MISO integrated the MISO South Region covering portions of Texas, Louisiana, Mississippi, and Arkansas. SERC is a non-profit entity whose mission is to promote and preserve the reliability of electricity service in the Southeast region.
MISO follows SERC rules for electricity transmission, ancillary services, energy, and power transactions on the SERC region power system. MISO, a non-profit organization, operates the electricity grid and administrates wholesale electricity production and the installed capacity market in its region. MISO is responsible for the reliable operation of more than $17 billion in transmission assets and provides comprehensive reliability planning for the region’s bulk electricity system. Under the MISO installed capacity market, power plants are paid for production capability even when not operating. However, this has historically been a relatively small payment.
Although MISO’s electric industry analysis in 2013 did not support private investment in new power plants, concerns are now rising as environmental regulations, increasing wind output, and low natural gas prices accelerate the retirements of many coal-fired resources over the next several years. This is especially true as MISO estimates a planning reserve margin of 30 percent for the South Region and 19.8 percent for the Midwest Region, well in excess of the earlier expected reserve requirement of 14.8 percent. Incorporating a realistic performance of the system and hotter than normal summer conditions reduces the actual margin in the Midwest Region to below 7 percent. Given that this margin must account for forced outages that can average 5 to 8 percent of the reserve margin, and MISO’s operating reserve requirements that are more than two percent of its peak load, MISO would need to rely on non-firm imports and emergency actions to satisfy its needs under these conditions.
While electricity supply is likely adequate for upcoming summers, more stringent environmental regulations and other factors (that is, sustained low natural gas prices and rising electric demand) will gradually decrease MISO’s reserve margins. MISO’s most recent surveys indicate expected coal retirements of 8 to 10 GW, which alone would cause MISO to be capacity-deficient.
Impact of Federal Environmental Regulations
Current federal environmental regulations in the electric power industry target sulfur dioxide (“SO2) and nitrogen oxide (“NOx“) emissions at power plants in the United States. Many small coal-fired generating stations do not have sufficient pollution controls to adhere to these emissions standards and cannot economically retrofit such controls. As many of these coal plants are expected to shut down, a significant amount of generating capacity is expected to be removed from the market. To compensate for this loss of coal-fired power plant capacity, increased demand for cleaner natural gas-fired power plants is anticipated. According to a report by the Institute of Energy Research, more than 72 gigawatts (GW) of coal generating capacity across the country is expected to retire due to more stringent environmental regulations. This capacity represents over 20 percent of the total U.S. coal energy capacity.
MISO continues to study and model the potential impacts of the Environmental Protection Agency’s (EPA) Cross-State Air Pollution Rule (CSAPR) and Mercury and Air Toxics Standards (MATS) on the MISO market. As noted, MISO’s most recent surveys suggest that 8 to 10 GW of capacity in MISO is at risk of retirement because of the compliance costs of these regulations. CSAPR was reinstated in April 2014, and MISO estimates an energy cost impact of $1 to $5 per MW hour (MWh), mostly in the form of higher variable operations and maintenance costs for control technologies. Additional coal-fired capacity could be at risk of retiring if low natural gas prices continue in the long term.
Electricity prices in the most coal dependent region of the U.S. are expected to increase to levels that ensure a positive spark spread for gas-fired power plants. Those gas plants which currently operate as seasonal mid-load facilities are likely to generate additional electricity or become baseload units.
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