The Grid, Part III: The Dream of Deregulation

Welcome to Part III of our look at the electric power industry. See here for Part I and Part II (including bibliography)

For most of the industry’s history, electric power in the US had largely been provided by vertically integrated utility companies that handled every part of the electricity supply: generating it, transmitting it, distributing it to customers, and managing the overall system. Utilities were granted monopoly status in their area of operations, and in return had their rates regulated by state public utility commissions. Most utility companies were private enterprises known as investor-owned utilities (IOUs), though there were several other models, such as municipally-owned utilities, rural co-ops, or the federal Tennessee Valley Authority.

Via 1970 National Power Survey

This industry structure had developed because it was believed that the electricity industry was a “natural monopoly.” The large upfront investment required, the tendency towards declining costs as scale increased, and the impracticality and wastefulness of duplicating transmission and distribution infrastructure meant that the electricity supply would never be a competitive market, and would inevitably be dominated by a single large company with structurally lower costs. 

Until the 1960s, due to the steadily falling price of electricity, this industry status was mostly unquestioned. But as the industry struggled in the late 60s and early 70s, this consensus began to crack, and people began to question whether monopolies were the best vehicle with which to structure the electric power industry.

The first cracks - Otter Tail and PURPA

The first crack in the monopoly status of utilities came in 1966, when the Minnesota town of Elbow Lake voted to establish its own municipal utility company and stop relying on Otter Tail Power Company, a small utility company Instead of getting its power from Otter Tail, Elbow Lake would buy cheap power from nearby federal hydroelectric sites. But to get power from the federal dams, Elbow Lake needed to use Otter Tail’s transmission lines, and Otter Tail, worried about future loss of business, refused. Elbow Lake sued, and in 1973 the case reached the Supreme Court, which found that Otter Tail violated the Sherman Antitrust Act by refusing to provide transmission services. While its direct impact was relatively minor, the Otter Tail case was “the first major challenge to the electric utility’s vertical monopoly” (Lambert 2015) and established a basic principle necessary for a competitive electricity market: transmission services needed to be available to all.

The next major blow to monopoly utilities was a seemingly innocuous provision in the sprawling 1978 National Energy Act. In response to the 1973 energy crisis, the act was designed to “reduce dependence on foreign oil, encourage conservation, and develop sustainable sources of energy” (Lambert 2015). Amidst its many different pieces of legislation was one that focused on utility regulation, called the Public Utility Regulatory Policies Act (PURPA). Most of PURPA’s provisions concerned utility rate structures, but Section 210 addressed “nontraditional” energy technologies such as small dams, wind, and solar. In an effort to encourage development of new energy technologies, Section 210 created a new class of energy producer, the Qualifying Facility (QF). A QF could be either a small power production facility (less than 80 megawatts) which used biomass, waste, or renewable sources as fuel, or a cogeneration facility which produced both heat and electric power. QFs had several special privileges. Most importantly, utility companies were required to buy their power at the utility’s avoided cost (ie: how much they would save by not having to produce their own power or buy it from another utility). This meant that small, non-utility electricity producers had a guaranteed market for their power.

Section 210 received relatively little attention during the passage of the National Energy Act. It was added largely for the benefit of one constituent of a single senator¹. But it ultimately became the most significant part of the National Energy Act. PURPA spawned an entire industry of non-utility electricity producers, called independent power producers (IPPs). By the early 1990s, more than half of the electricity generation capacity being added each year was IPP-owned.

This explosion in independent power producers was in part due to the generous way that avoided costs were calculated, particularly in California. California created several standard contracts that QFs could adopt, and one of them, Interim Standard Offer #4, set the rate that utilities had to buy power based on the projected future costs of fuels such as oil or natural gas, which were expected to rise. When fuel costs instead fell in the mid-1980s, ISO #4 looked “like a real sweetheart deal” (Hirsh 1999), and a large number of independent producers signed up in the brief window that it was available. California’s PURPA rollout, combined with generous state and federal tax credits for renewable energy generation, was largely responsible for the explosion in wind power in California in the 1980s. By 1991, non-utility generators were providing a third of California’s electricity.

Independent power providers were also helped by the 1978 Powerplant and Industrial Fuel Use Act, which prevented utilities from constructing natural gas power plants (the act was repealed in 1987). Qualifying facility plants, however, could use natural gas, so long as it was used in a cogeneration facility that generated both heat and electric power. To meet this requirement, QFs used combined cycle gas turbines (CCGTs), which use the waste heat from a gas turbine to produce steam which drives a conventional steam turbine. By 1992, combined cycle gas plants made up 39% of non-utility power capacity in the US.

Electric power restructuring, aka “deregulation”

While non-utility power plants were being built under PURPA, other US industries that had long been monopolies or subject to government price controls were being restructured to introduce market-based competition. Industries such as airlines, telephone service, natural gas, trucking, and railroads were all deregulated to some extent in the late 70s and early 80s, resulting in lower prices and better service. The airline industry was successfully deregulated without compromising safety, and the deregulation of telephone service showed that competition could exist without wasteful duplication of infrastructure (in this case, the phone lines). With utility companies facing billions of dollars in cost overruns on nuclear plants, and PURPA showing that non-utility generators could provide electric power at reasonable costs, analysts and experts began to advocate for deregulation of the electricity industry. The Federal Energy Regulatory Commission (FERC) began to explore restructuring the industry to introduce competition in the mid-1980s, and it slowly became a reality in the 1990s and 2000s. Through a series of new laws (the Energy Policy Acts of 1992 and 2005) and FERC orders (Orders 888, 889, 1000, and 2000), the monopoly status of utility companies was slowly unwound, and the changes introduced by PURPA were expanded. In this new industry structure, while the distribution and transmission portions of electric service would remain regulated monopolies, electricity generation would become something resembling a competitive market.

To accomplish this, the transmission and distribution portions of electric service had to be unbundled from generation. Via the 1992 Energy Policy Act and FERC Orders 888 and 889, utility companies were forced to open up their transmission lines and provide transmission services to anyone who wanted to use them at “just and reasonable rates” (Lambert 2015). If a power producer in, say, Virginia, wanted to sell power to a utility in South Carolina, but needed to use the transmission lines of a utility in North Carolina, the utility would have to offer those services (called "wheeling power").

Moreover, no preferential treatment could be given when offering services. A utility company couldn't prioritize the transmission of its own power over that of another utility. Transmission services had to be posted publicly for everyone to see, on a system called “OASIS.” To ensure there was no preferential treatment when offering transmission services, utility companies had to separate their transmission and generation businesses. In some states, this meant utilities had to sell off their power plants and become “pipes and wires” companies, while in other cases generation was simply moved to a different subsidiary in the same company.

To encourage competition in electricity generation, the 1992 Energy Policy Act created yet another new class of power supplier, the exempt wholesale generator (EWG). Similar to the Qualifying Facilities of PURPA, EWGs were allowed to sell wholesale power without being regulated as utilities. Unlike Qualifying Facilities, however, EWGs had no restrictions on the size or type of power plant they could build, and there was no mandated requirement that utilities buy their power as there was with Qualifying Facilities.

Beyond unbundling generation and transmission services, FERC pushed utilities to go even further, and hand control of their transmission lines over to a new type of organization called an Independent System Operator (ISO), non-profit corporations that owned no generation assets and would manage the transmission lines of many different utilities. While utilities would retain ownership of the transmission lines, the actual operation of them (such as determining who uses them when) would be handled by the ISO. The hope was that the larger scale of ISO operations would both reduce operating costs via economies of scale and reduce prices by creating larger wholesale electricity markets.

In addition to managing transmission lines, ISOs would create and operate wholesale power markets, which would use market mechanisms to determine which power plants were used. In ISO areas, power providers (both utility and non-utility) bid for the right to provide electricity in competitive auctions. The lowest priced bidders that meet overall power requirements (and other requirements such as reliability) are the winners of the auction. The price of electricity in an ISO area thus fluctuates hour by hour depending on what generators are bidding to provide wholesale power.

FERC later created another type of organization, the Regional Transmission Organization, or RTO, in what seems like an effort to make things more confusing. RTOs are similar to ISOs, but have somewhat more responsibility for system reliability, and were intended to operate over a wider geographic area. All US ISOs became RTOs, but many of them still have “ISO” in their name, and the terms are used somewhat interchangeably, though it's still possible to be an ISO and not an RTO.

ISO/RTOs in the US and Canada

FERC’s original intent was for ISO/RTO managed transmission lines and wholesale power markets to be used over the entire US, but this effort was derailed, in part due to its catastrophic implementation in California. California restructured its power industry early and opened its wholesale electricity market in 1998. But its market design and overall implementation had critical flaws. As part of deregulation, California utility companies were forced to sell off their generation assets and were not allowed to enter into long-term purchase contracts for power. All electricity purchases had to be done through the wholesale market. However, the rates at which utilities could charge customers for electricity was capped.

For the first two years, California’s market seemed to perform well, but in May of 2000 wholesale electricity prices began to skyrocket. Independent power providers and electricity trading companies like Enron found that design flaws in the market made it possible to withhold generation and drive up the price, which the utility companies would be forced to pay. But because of electricity rate caps, those prices couldn’t be passed on to customers. As a result, utility companies were forced to buy wholesale power for more than they could sell it for, and lost billions of dollars. Many of them defaulted on their payment obligations, and California’s largest utility (PG&E) declared bankruptcy. Due to its poorly designed market, California’s electricity costs nearly quadrupled between 1999 and 2000, and were projected to more than double again in 2001. From December 2000 until June 2001, California suffered 38 rolling blackouts.

California eventually recovered, and its electric service continues to be managed by an ISO/RTO (CAISO), but the debacle dulled the momentum for electric power deregulation. While many utilities joined ISOs, FERC never specifically required it, and most southeast and northwest states opted not to, instead staying with their traditional, vertically integrated utility companies. Today, about two-thirds of the country's electricity is supplied by ISOs/RTOs, with the other third supplied by traditional vertically integrated utilities, though as we’ve noted they must still offer their transmission services publicly, and they often buy power from non-utility "merchant" generators. About 40% of the US’s power is provided by IPPs.

1. Briefly, Wheelabrator-Frye corporation had built a waste to energy plant near Boston, which burned garbage and sold the heat to General Electric. The plant hoped to turn the heat into electricity, and wanted legislation that would require utilities to buy the power. They were able to get the support of Senator John Durkin of New Hampshire, and got their requested changes included in the bill