Electricity pricing reflects its real-time cost

Severin Borenstein

Long before US electricity restructuring began in the 1990s there was a recognition that the marginal cost of producing electricity could change significantly hour to hour. Combined with the high cost of storing electricity, this meant that the true opportunity cost of consuming electricity also would vary constantly. For many decades economists have argued that retail electricity prices should fluctuate accordingly - this is known as real-time pricing (RTP) - but the technology to meter hourly consumption and to communicate fluctuating prices was quite costly.

Business hours

In the last half of the twentieth century, the industry created a system meant to approximate RTP with standard technology: ‘time-of-use’ priced that varied systematically by time of day and day of the week, usually with a higher price Monday through Friday during business hours and a lower price at all other times. The two prices (or sometimes three, with an added ‘shoulder’ pricing period) were set months in advance, however, and did not change to reflect system demand/supply balance on a daily basis. Because of the cost of even this simple pricing and metering scheme, it was used only for large commercial and industrial customers.

In a regulatory environment, two additional factors worked against adoption of RTP. Under regulation, the utility nearly always charges prices that are based on some notion of average cost, including the accounting amortization of long-term capital expenditures. Such an approach is targeted at cost recovery, not efficient pricing. Also, regulated utilities may be less likely to appreciate one of the main attractions of RTP, the effect it has in shaving demand peaks and reducing the need for capital investment. If regulators allow utilities to earn generous returns on investment, or if the utility management simply wants to grow the company, a pricing strategy that constrains new capital investment is unlikely to be popular with managers.

It is not that utilities did not understand or calculate their marginal cost. In fact, engineers tasked with minimising production costs were constantly calculating ‘system lambda’, the value of the production constraint, which corresponds directly to economic marginal cost. They needed this information in order to choose among different production resources. The information was just not used on the consumption side.

RTP program

As metering technology improved, a few utilities began to experiment with RTP. The pioneer and still a leader in this regard is Georgia Power, a company that was, and remains, a traditional regulated utility. GP introduced its first RTP program in 1991 for large industrial customers. By 2000, nearly one-third of its entire electricity demand was on RTP.

Wholesale electricity markets were deregulated in many parts of the United States in the late 1990s. The idea was that electricity generation could be a competitive industry with many generators vying to sell their output into a common power market.

Infra-marginal units

The underlying economic model for this market, however, required that prices occasionally rise to well above the marginal cost of producing most units of output in order for firms to earn operating profits on infra-marginal units, operating profits that allowed the firm to cover its capital cost, at least in expectation. In some simple framework of a constant marginal cost of each generator up to its capacity, this meant that the market had to sometimes clear ‘on the demand side’.

That is, high prices would occur at times of high demand or reduced supply and those high prices would cause quantities demanded to decline until they were in line with system capacity.

Such price-responsive demand would constrain prices from jumping too high, whether the tight market was caused by a true supply shortage or an artificial shortage caused by some firms exercising market power. What went largely unnoticed at the time was that the technology and market organization to enable RTP was not in place in any of the markets headed towards deregulation. My own pre-deregulation work with Jim Bushnell, which forecast market power problems in deregulated electricity markets, just assumed that there would be some degree of real-time price response.

When deregulated markets launched in California, Pennyslvania - New Jersey - Maryland, and New England in the late 1990s, retail customers could choose among retail providers who were buying power out of the wholesale power market.

Since electricity is a homogeneous good delivered over a common-carrier infrastructure of transmission and distribution wires, there was no ability to differentiate the product sold. In nearly all cases, the final delivery and metering of usage was also left to the still-regulated utility that was providing transmission and distribution services. The centralization of the metering service meant that even if a retailer wanted to offer new time-varying retail pricing structures it was difficult to actually do so.

Still, because these markets were in a period of excess capacity, prices remained low and steady at first, with the primary complaint coming from producers who argued that prices were too low to justify new investment.

Courtesy: NBER Reporter