All Commentary
Friday, June 1, 2001

Did Deregulation Kill California?

Any State Could Have Experienced a Crisis Like California's

Jerry Taylor is director of natural resource studies at the Cato Institute.

Skyrocketing wholesale power prices in California and the daily threat of brownouts and blackouts have cast a pall over deregulation. “Liberals,” led by California Governor Gray Davis, blame a restructuring law passed in 1996 for the crisis, arguing that it left the state vulnerable to market manipulation by greedy power producers. Conservatives for the most part agree that the 1996 reforms are the culprit. They charge, however, that the ham-handed regulations attached to those “reforms”—primarily the prohibition of long-term contracts between utilities and power generators and the mandatory imposition of a centralized daily spot market—are largely responsible for the price spike. The right also argues that California’s regulations, crafted by environmental activists and antigrowth consumer groups, have long discouraged investment in new generating capacity and that the blackouts represent a long overdue flock of chickens coming home to roost.

While both sides are busily settling political scores, the real story of what happened in California is largely being missed. Accordingly, the important lessons that this crisis teaches about regulation and electricity are largely being overlooked: retail price controls are a recipe for disaster; and state regulators have little idea how best to efficiently organize important industries and certainly shouldn’t attempt to do so under the mantle of “deregulation.”

The Architecture of California’s “Deregulation”

Unlike the deregulation of the airline and trucking industries—which largely curtailed regulatory oversight of those industries and freed markets to go in whatever directions that market agents thought best—the “deregulation” of the electricity industry in California was heavily proscriptive and not, on balance, a loosening of regulatory controls at all. California simply replaced the old set of regulations with a new set of regulations, some of which were less interventionist than the old, some of which more.

The central thrust of the restructuring was to create a competitive wholesale market for electricity. Any investor who wished to get into the power business could henceforth do so. But politicians feared that the utilities would use their control of the electricity grid to “rig” this new marketplace so as to disadvantage competitors. Reformers thus adopted a whole new set of regulations and government interventions to ensure that a competitive market would arise:

Mandatory Open Access. Utility companies were forced to allow any generator who desired access to the grid to gain such access at terms, conditions, and prices established by the state.

Vertical Disintegration. Incumbent utilities could no longer sell the power they generated directly to consumers. Instead, utility generators could only sell power to the centralized state-managed power exchange in a day-before spot market.

Centralized Power Exchange. Any power the utilities needed for its customers had to be purchased from the state-managed power exchange through the year 2003. Other parties could buy through the exchange on a voluntary basis. The exchange was charged with procuring power in a voluntary day-before spot market made up of bids from non-utility power generators.

Utility Retail Price Caps. Regardless of the power source, utility rates were frozen in place until the source recouped its share of “stranded costs,” which were levied by a tax on all ratepayers.

Independent System Operator (ISO). The day-to-day operation of the grid (that is, the management of electricity traffic along the wires) would be directed, not by the utilities that actually owned the grid, but by a state official answerable to a 26-member advisory board made up of representatives of grid users. The ISO was further empowered to procure electricity on an emergency basis if on any given day the amount of power procured in the centralized power exchange was insufficient to meet demand.

Industry consultant Charles Cicchetti, former chairman of the Wisconsin Public Service Commission, echoed the thoughts of many when he wrote at the time, “Two things should be obvious. First, none of this should be called deregulation. Second, it is difficult to see how any of these myriad regulatory schemes, unless altered significantly but perhaps not fundamentally, will lower prices.”

California’s electricity market under the new regime, however, appeared to work reasonably well from 1997 through the spring of 2000. Even though the hoped-for retail competition for electricity ratepayers never fully materialized, wholesale electricity prices dropped to nearly $30 per megawatt hour (MWh), the equivalent of 3 cents per kilowatt hour (kWh), in May 2000. Those low prices allowed utilities to make a reasonable return on sales even with the rate cap.

Nor were any storm clouds apparent on the horizon before the crisis occurred. We have searched in vain for any industry report, analysis, or study that warned that a supply crunch was about to hit the state. On the contrary, the National Electricity Reliability Council (NERC) issued an advisory suggesting that California’s reserve capacity heading into the summer of 2000 stood at 15 percent, a reserve that was roughly the same as those held by other states.

The Roots of the Crisis

California’s happy state of regulatory affairs changed radically in 2000-2001 when two large supply shocks and a demand shock simultaneously struck. None of those shocks was triggered by state policy. All of them, however, had a serious impact on wholesale electricity prices.

Supply shock number one was a massive demand-driven run-up in regional wholesale natural gas prices, the fuel input for 49 percent of California’s electricity capacity and nearly all its peaking capacity. From 1998-99, the average price of natural gas delivered to utilities in California was $2.70 per million British thermal units (Btu). By December 2000, however, wholesale gas prices had risen to an average $25 per million Btu. Given that 90 percent or more of a generator’s cost of producing electricity stems from fuel costs, simple math demonstrates how those prices have driven electricity prices. Gas prices of $25 per million Btu, for instance, translates into a production cost of $400 per MWh for the most efficient gas-fired plants (or, alternatively, 40 cents per kWh) and $500 per MWh (50 cents per kWh) for the least efficient power plants.

While those prices are subject to daily fluctuations, the price of natural gas at the time of this writing still averaged around $15 per million Btu, a 455 percent increase over last year’s price. That translates into $240-$300 per MWh for gas-fired electricity.

Remember, the price of electricity in the state-managed California power exchange is set by the highest price paid to any generator, so this hike in natural gas costs for the least efficient power generators set the price for all the electricity sold throughout the exchange, even power produced from other fuels.

Supply shock number two was caused by a three-year dry spell that dropped western water tables and thus reduced regional hydroelectric generation by 20 percent since 1998. Things became even worse in 2001 with streamflows in January only about 60 percent of average. The practical effect of this falloff in hydroelectric generation was essentially to wipe out California’s reserve capacity, leaving the state with little generating capacity to fall back on during peak demand periods.

Making everything worse was the fact that electricity demand shot skyward first last summer with unseasonably warm temperatures (a 13 percent increase in cooling degree-days across the Pacific region from 1999 to 2000), and then last winter as a consequence of the coldest winter on record since temperatures were first systematically recorded in 1895. Demand for heat in December 2000 grew over the demand in December 1999 by an amount greater than the annual consumption of Finland, Norway, and Sweden combined.

Two important points thus emerge. First, each of those phenomena driving the price spike was an “act of God.” No state politician, regulator, or businessman could have headed it off. Second, no regulatory system—not the pre-1996 regulatory regime, not the post-1996 regulatory regime, not a completely laissez-faire regime, and certainly not any of the various regulatory regimes in other states—could have prevented wholesale electricity prices from climbing to record levels under these circumstances.

The NOx Hammer

While environmental regulations in general affect both generating costs and the ability to site new capacity, California’s requirement that generators have sufficient nitrogen oxide (NOx) emissions credits before going on-line has had a particularly important role in the price spiral.

In the winter of 1999, NOx credits were selling for about $2 per pound. By the summer of 2000, those same credits were selling for $30-40 per pound, where they have stayed ever since. Since an efficient gas-fired plant emits about a pound of NOx per MWh and an inefficient plant emits about two, that translates into an additional cost of $40-80 per MWh. California regulators moved last January to waive NOx permit requirements for power generators for the next three years, but the damage was done.

While it’s true that the NOx program affects only those generators in the L.A. Basin—the source of only a fraction of the state’s power—observers forget that the highest cost source of electricity sets the price for all electricity sold through the state power exchange. Aaron Thomas, a manager at AES Pacific, points out that generators in the L.A. Basin “are setting the clearing price for everybody in California. And to the extent that that market is influencing markets in the West, all of a sudden you’re getting these basin units driving costs for 50 million people in the West.”

The Damage from Price Controls

In September 2000 the state of California imposed a $250 per MWh price cap on electricity sold to the state power exchange. Since wholesale prices ranged between $150-$1,000 per MWh depending on the time of day, generators responded by dramatically curtailing their sales to the California exchange.

Moreover, since retail electricity prices were for the most part capped at between 6 and 7 cents per kWh ($60-$70 per MWh), generators that stayed in the market had no incentive not to hold up the power exchange for the best price available when the ISO came calling for emergency power to avert blackouts. After all, the wholesale price demanded by the generator would not have any effect on demand whatsoever . . . a sort of dream scenario.

Regardless of how much market manipulation might have been going on, simple math demonstrates that most of the price spike was real, reflecting higher input costs. Yet the price cap encouraged ratepayers to consume more electricity than was available. Blackouts were the inevitable result of attempts to regulate and legislate basic economic laws out of existence.

Unexpected shortfalls in transmission capacity, incidentally, also contributed to the blackouts. The main transmission line between northern and southern California (Path 15) has at times been limited to half its normal capacity, significantly complicating northern California’s power supply. It’s no coincidence that most of the blackouts have been concentrated in that region.

The Blame Game

While all informed parties largely agree with this story, some remain unconvinced that it fully explains the high prices and the lack of power. A thorough review of cost data by analyst Edward Krapels, an executive with ESAI Power and Gas Services, demonstrates in a recent issue of Public Utilities Fortnightly that, while the December price of wholesale power can be completely explained by the set of supply and demand shocks discussed above, an average of $50 per MWh between April and November of 2000 cannot be readily explained by increases in the cost of production.

Although one answer is that “strategic behavior” on the part of generators might explain that gap, another is that the shortage last summer caused numerous power plants to run flat out for months, postponing needed maintenance and repairs that came due this winter. Approximately 40 percent of the state’s generating capacity, after all, comes from plants 30 years or more old. Power plants have accordingly been out of service at various times this winter in unprecedented numbers. During the first blackout on January 17, for instance, fully 11,000 megawatts of in-state power was off-line due to repair and maintenance work, about a third of the power typically required during peak winter time periods. During times of shortage, of course, prices will rise to whatever the market will bear.

Many have argued that California is short on electricity because environmentalists and consumer activists have blocked new capacity, slowly starving the state of needed power. Yet only once in the past ten years has neighborhood opposition blocked a power plant in California. Moreover, since Governor Davis was elected in 1998, California has approved the construction of nine power plants, with another 22,600 MW of generating capacity somewhere along the licensing process. A new study by Resource Data International concludes that “Even in the West, where shortages and unprecedented high prices have been the rule in 2000, more than enough new capacity is under development to bring power markets into balance and perhaps provide a mild over-correction within the next couple of years.”

A better explanation for why more capacity wasn’t built in California during the 1990s is simple economics. Wholesale electricity, after all, was “dirt cheap” there throughout the decade. Profit opportunities were minimal. The supply shock was completely unforeseen. Moreover, since investors couldn’t be sure how regulatory changes would affect their businesses, it’s natural that investment was curtailed during the legislative and regulatory struggle of the mid-to-late 1990s.

Exclusive concern over California’s generating capacity, however, ignores the fact that the power market in the west is one, large interconnected system. There is no reason in principle to demand that California internally generate all its power; we would not, after all, demand that Rhode Island produce all the food it consumes. Importing power across state lines is no more economically risky than importing power across county lines. So whatever obstacles that might have prevented new facilities in California should not have affected overall power availability.

Self-Inflicted Regulatory Wounds?

A frequent argument forwarded is that, since other states are doing fine, there’s something about California’s “deregulation” plan that has caused the crisis beyond environmentalist meddling. After all, the average price for wholesale power in California was $313 per MWh in the middle of January 2001 compared to $74 per MWh in New England, $63 per MWh in New York, and $39 per MWh in Pennsylvania, New Jersey, and Maryland.

While it’s true that some of the states that have restructured their electricity regulations have perhaps done a better job of it than California (Pennsylvania, for instance, did not force their utilities to sell off nearly as many generating assets as California, allowed long-term contracting for power, and established a more robust retail and wholesale market of competing suppliers), it’s not true that the price differentials between power in California and the power in those states have anything to do with the “better” regulatory climate. It has to do with fuel composition.

Remember, the main drivers of the spike in California are the increased costs of natural gas and the decline in water tables that has crippled hydroelectric generation. States east of the Rocky Mountains, however, rely almost completely on nuclear and coal-fired power for their electricity during the winter (and only a few rely heavily on natural gas during peak demand periods in the summer). That alone explains why the electricity crisis has been confined thus far almost exclusively to California and its neighboring states.

If major exogenous supply and demand shocks were to hit those states touted as deregulatory “successes,” they would find themselves experiencing the same meltdown going on in California. Bruce Radford, editor-in-chief of Public Utility Fortnightly, explains:

As I see it, the Texas law (Senate Bill 7, the Texas Electric Choice Act, signed in 1999 by then-Governor George W. Bush) contains the same basic failing as did Assembly Bill 1890, the California law—it creates a tariff structure for Texas that will surely run aground if electricity prices don’t behave as expected. Just like California, the Texas law creates a rate freeze keyed to revenue levels set under the old regulated regime, and then mandates a guaranteed rate cut on top of that for residential and small commercial customers (6 percent in Texas, instead of 10 percent, as in California), good until Jan. 1, 2007 (both with adjustments allowed for fuel cost increases).

So if power prices in Texas should spike out of control between now and 2007, more than warranted by fuel costs, you could have the same mess as in California—utilities buying high and selling low.

The same critique applies to Pennsylvania, Michigan, Maryland, and all the other states occasionally trotted out as examples of deregulation “done right.”

Some might be tempted to argue that California “went wrong” then by eschewing coal and nuclear generation, but that’s questionable. Natural gas-fired generation made perfect sense in the 1990s; it was cheaper and easier to build than coal and nuclear plants. Nor was California alone in relying on natural gas for new capacity. Virtually all new power plants built throughout the nation in the 1990s were gas-fired. Remember also that decisions about new capacity are made not by state politicians or regulators but by private investors. While state authorities do have the final say over whether a plant does or does not get a license to go on-line, they do not dictate to investors what kind of plant to site.

Long-Term Contracting: The Way Out?

Many on both the left and right believe that the prohibition against long-term contracting for power is at the root of the crisis. The idea that long-term contracts can reduce electricity costs in the long run, however, is extremely dubious. First, below-market prices in the short term can only come at the expense of above-market prices for years to come, and locking in long-term prices at the summit of a price spike is hardly the best way to minimize cost in the long run. Second, long-term contracts do not offer a “better deal” than spot market purchases. They simply reallocate the risk of price volatility from the consumer to the producer. But producers require a premium to accept this reallocation of risk. Generators are not about to offer prices that will, over the long term, return them fewer profits than sales on the spot market. In fact, spot-market prices for electric and gas utilities have historically been more favorable to consumers than contract prices.

What if California’s utilities had signed long-term contracts before the wholesale electricity price spike hit? Wholesale prices would still be sky-high. Independent power producers would be obligated to sell power at, say, 6 cents per kWh despite the fact that it cost them 15-100 cents per kWh to make that power. It wouldn’t be long before the independent power plants started to declare bankruptcy and tear up the contracts, which is what happened during the mid-1980s in the natural gas industry. It’s already happening to the few generators (including the natural gas giant Enron) that signed long-term contracts in California.

Nor would long-term contracting have stopped the blackouts. No matter how the contracts were written, it would not have changed the fact that exogenous supply and demand shocks have curtailed the supply (and, accordingly, increased the price) of electricity. As long as the state prevents retail prices from reflecting that scarcity, demand will outstrip supply and shortages will occur.

An axiom of economics states that the most expensive source of supply at the margin must set prices for all sources of supply. If it didn’t, shortages would occur. So if 95 percent of all the utilities’ power were supplied by long-term contracts (as the Governor hopes) at 6 cents per kilowatt hour, as long as 5 percent of that power were coming from the spot market, the price they’d charge to keep the lights on would reflect the spot—not the contract—price.

H.L. Mencken once said that “Democracy is the theory that the common people know what they want and deserve to get it good and hard.” That appears to be the case in California today. A recent poll asked Californians whether they would prefer a regime that capped the retail prices of electricity but produced the occasional blackout or a regime that decontrolled retail prices but eliminated the blackouts. Two-thirds favored the former. In essence, Californians demonstrate the fact that there’s a little bit of East Germany in all of us.

The simple fact is that high prices for power must be paid. Since it’s politically difficult to have ratepayers pick up the tab on their monthly bill, California’s politicians have decided to have taxpayers pick up the tab out of the state budget surplus. So Californians will not escape high prices. The problem with paying bills that way, however, is that the high prices will not affect electricity demand and thus will not play their intended role in allocating scarce goods as they would if they were simply passed on through the market.

The California electricity crisis is not really a story about environmentalists gone bad, deregulatory details left unattended to, or unrestrained capitalists running amok. It’s basically a story about what happens when price controls are imposed on scarce goods.