The odds that the Texas electricity market will undergo change this year are high. Despite the promise of low costs in an energy-only market, that market alone is providing insufficient incentives for the reserve capacity needed by the state’s growing population and economy.
On Feb. 2, 2011, a winter storm gripped the Lone Star State, bringing freezing temperatures and heavy ice loads onto the state’s electric infrastructure. Texas experienced a series of unexpected rolling blackouts. That circumstance changed the dynamics of energy policy in the state, along with the shape of energy politics. The outages raised the issue of whether Texas should implement a capacity market along with its long-functioning energy market, to ensure adequate electricity to consumers.
In the 2011 outage, more than a million Texas customers lost service, some for extended periods. More than 200 power plants shut down under ice loads and complications of cold temperatures, including frozen coal piles at generating stations. The Electric Reliability Council of Texas (ERCOT), the state’s wholesale electric market, scrambled to find adequate supplies of electricity (Texas has sparse interconnections to the rest of the U.S. grid), and short-term electricity prices soared.
As the crisis passed, Texan electricity boffins scratched their heads (after removing their Stetsons, of course) and began thinking about an aspect of the state’s wholesale market that is different from several of the other large electricity markets that have come to dominate over half of the U.S., including PJM Interconnection (PJM) in the Middle Atlantic states, the Independent System Operator-New England (ISO-NE), and the New York Independent System Operator (NYISO). What those big markets have implemented, and what Texas so far lacks, is a market for electric capacity, or potential electricity supply, to exist alongside the conventional market for energy supplied each and every day (see sidebar “Capacity and Energy in Electricity Markets”).
|Capacity and Energy in Electricity Markets
What’s the difference between “capacity” and “energy” when it comes to electricity markets, and does it make a difference? That question is a key to understanding the debate about how to structure the organized wholesale competitive markets that now provide electricity to more than half of U.S. customers.
Capacity is the amount of electricity a plant can deliver when it is operating at full power. For example, a nuclear power plant typically has a capacity of 1,000 MW. A wind plant may have a capacity of something on the order of 100 MW. But those numbers can be misleading, as the nuclear plant’s capacity is available around the clock, while the wind plant’s capacity varies based on whether the wind is blowing and how fast.
The U.S. Energy Information Administration defines capacity as “the maximum electric output a generator can produce under specific conditions. Nameplate capacity is determined by the generator’s manufacturer and indicates the maximum output a generator can produce without exceeding design thermal limits.”
On the other hand, energy is the amount of electricity generators actually provide to the grid and is available to be used at any moment. Organized wholesale electricity markets buy and supply electricity instantaneously. That’s energy. They buy capacity as backup, or inventory, in case of shortages.
The PJM Interconnection, which has the most mature and robust energy and capacity markets for electricity, dating back some 75 years, offers this definition of capacity versus energy markets: “Energy markets are used to coordinate the continuous buying, selling, and delivery of electricity. Capacity markets provide incentives that are designed to stimulate investment both in maintaining existing generation and in encouraging the development of new sources of capacity.”
Restructured Markets and the Disappearing Reserve
A little explanation is in order for those not deep into the weeds of electricity market economics. For those who already get it, please bear with us.
In traditional regulated monopoly markets, which dominated the U.S. until around the turn of the 21st century and which still prevail in much of the Southeast and West, state regulators require utilities to carry a reserve margin—generation in excess of what’s needed to meet day-to-day needs. This means backup electric generating plants, paid for by customers, which are ready to kick in when it looks like the utility is going to be stressed by weather or other events to meet its customers’ needs for electricity. This amounts to generating inventory.
Inventory is expensive. That’s a fact for most businesses (and one of the motivators of online commerce). But too little inventory is also expensive, in terms of lost sales and lost customers. In electricity markets, blackouts are devastating in terms of economic costs and political impacts. Though most electricity customers pay no notice when the lights go on as expected, they often raise a ruckus when the lights go off unexpectedly. No utility distribution company wants to go before its regulators to try to justify hundreds of thousands of customers sitting in the dark for hours, days, or weeks. And those customers have no choice about seeking other suppliers. It’s often a toxic political environment for the suppliers.
In the pre-restructured world of electricity, the cost of inventory—excess generating capacity—was simply folded into overall rates; customers never really saw those expenses of backup power. Supporters of competitive markets assert that the result of the old system was too much excess capacity, or power inventory, also known as “gold plating.” The utilities were able to reap a return on the investments in inventory, which encouraged them to stockpile generation. The more they spent, the more they earned.
Then competitive electricity markets came along, beginning with Federal Energy Regulatory Commission (FERC) Order 888. One of the questions arising from the competitive world of electricity procurement was how to handle reserves. When restructuring and competitive markets kicked in, driven by FERC policies, the new markets had to decide how to deal with the issue of backup power, or capacity. One choice, which Texas took, was to rely on daily energy markets to supply the needed power. Markets would determine how much inventory to carry. Texas had always enjoyed an excess of electric supply, and there was no obvious reason in 1995 to expect that would change. Its restructured market, among the most aggressive in the country, elected to face shortages rather than paying for excess generation.
In the East, where a massive blackout in 2003 hit some 50 million electric customers from Canada to New Jersey, the new regional transmission organizations (often created out of long-standing existing power pool sharing agreements such as PJM) decided to structure competitive markets for both energy and capacity (see sidebar “PJM’s Capacity Market”). PJM, ISO-NE, and NYISO now conduct auctions for generators to bid to supply backup power supplies to the energy market. The basic concept is that market prices from capacity auctions will be high enough to encourage investment in new electric generating plants and to encourage large consumers of electricity—or companies that can aggregate small users into large consumers—to reduce their use. This latter concept is “demand response” in electricity industry argot. In the capacity markets, large consumers and aggregators of load can bid demand response into the markets on the same basis as generation. FERC blessed this concept in its Order 745 in 2011.
|PJM’s Capacity Market
The PJM Interconnection, which covers a wide swath of the U.S. from New Jersey to Ohio, has the most robust and developed capacity market among the organized wholesale electricity markets. Known internally as the “reliability pricing model,” the PJM capacity market rests on an auction each year to reserve capacity three years ahead. As PJM describes it, “PJM’s capacity market provides forward pricing signals to encourage retention of existing resources and development of new resources in the PJM region. Adequate capacity resources are required to support the reliability and stability of the electric grid for consumers’ demand.”
The most recent PJM capacity auction last May produced good results for the wholesale market, drawing a record amount of new generation at lower prices than previous sales. “The results of this year’s capacity auction reaffirm that well-designed, mature markets are a powerful tool for procuring new resources at competitive prices,” said PJM CEO Terry Boston. “Again this year, we see record amounts of new conventional generation and strong showings from renewables and energy efficiency.”
Texas decided to keep the prices that consumers must pay for electricity lower by avoiding capacity costs. The choice between an energy-only market and a capacity market is clearly a matter of money.
A FERC technical conference last fall explored the cost implications—expressed as the “missing money”—of introducing capacity costs into the wholesale cost of energy. The “missing money”—as economist David Patton, market monitor for both ISO-NE and NYISO, explained—is the difference between the levels of excess capacity that an energy-only market would provide (probably in the range of 7% to 10%) and the higher planning levels that most electric system operators want to see (in the range of 17%).
The substantial costs of buying capacity in advance, as opposed to buying energy today, have proven controversial. In the PJM region, both Maryland and New Jersey state regulators and their governors objected to the higher costs of PJM’s inventorying capacity at market rates. The public service commissions in both states hatched schemes to use taxpayer funds to subsidize new gas-fired generating plants that would bid into the PJM capacity market. The states perceived that the prices awarded in the market’s auction were too high and the state-subsidized plants would win in the auction and lower costs of future generation. But PJM and FERC objected, arguing that the state subsidies would drive down bids in the capacity market auctions because the subsidized plants would drive out nonsubsidized competitors.
Federal courts in both states last year nixed the Maryland and New Jersey plans, saying that the federal government was in control of these interstate markets and FERC had blessed the capacity purchases. The legal presumption that federal agencies have rights that trump state regulatory commissions blocked both Maryland and New Jersey. As is often the case when it comes to the operation of sophisticated wholesale competitive markets where state-regulated monopolies once prevailed, considerable contention remains about the need for capacity markets. In overturning the New Jersey and Maryland attacks on FERC, the courts didn’t address the economics in play in the debate over capacity markets.
Because buying reserve energy (inventory) is expensive, consumer interests often oppose the idea. That’s what motivated the state governments in New Jersey (with a supportive Republican governor) and Maryland (with a supportive Democratic governor) to offer their now-illegal options. A paper for the libertarian Cato Institute concludes, “The theoretical case for capacity markets is weak at best. Many of its arguments depend on oversimplified assumptions that are at variance with reality, particularly those that are necessary to produce the missing money phenomenon.” But the capacity markets in play in the Northeast and Middle Atlantic states are working, a powerful argument for their wider use.
Texas Bucks Capacity Markets
The issue of capacity markets has now landed squarely in Texas, where the three-member Public Utility Commission of Texas (PUCT) is pondering scrapping its energy-only approach in order to include a mandatory reliability margin and an auction mechanism to achieve that margin.
Texas has what can best be described as an “aspirational” reserve margin. The PUCT has established what it wants as a goal for excess generation (somewhere around 14%), but there is no way to require any participants in the ERCOT market to meet that target.
The North American Electric Reliability Corp. (NERC), the national judge of whether the nation has enough electricity capacity to meet its customer demands, has long targeted Texas as a problem. In its December 2013 report, “Long-Term Reliability Challenges and Emerging Issues,” the Atlanta-based group said, “Since 2011, NERC has highlighted resource adequacy challenges in ERCOT.”
The February 2011 blackouts (which came on the heels of a 2006 summer set of politically fraught rolling blackouts), sparked Donna Nelson, PUCT chairman, to push for a Texas capacity market. Nelson, a lawyer, was Gov. Rick Perry’s advisor on energy and telecommunications issues when he named her to the powerful PUCT in 2008 and chairman in July 2011, after the February energy crisis. She quickly concluded that Texas should implement a capacity market to provide needed backup power to prevent future blackouts.
She also quickly ran into opposition from fellow PUCT Commissioner Kenneth Anderson, also a Perry appointee and a lawyer. He has argued forcefully against a capacity market for Texas. In testimony to a state Senate committee recently, Anderson said, “A mandatory capacity reserve margin will result in billions of unnecessary, unavoidable and largely un-hedgeable costs to customers, without guaranteeing rolling blackouts will not occur.”
He’s had support from Texas business interests and the Dallas Morning News. The newspaper has said that arguments by power generators that they need a market for their services are bogus. “That’s nonsense, and a scare tactic designed to get a payday from consumers,” said the editorial. “PUC Commissioner Ken Anderson recently suggested as much, challenging industry claims that Texas would lose $14 billion over the next decade and a half because of power outages.”
Nelson and Anderson butted heads for two years on the issue of a capacity market for Texas. A vacancy on the three-member PUCT prevented action. But last August, Perry filled the vacancy on the regulatory commission with Brandy Marty, who had been his chief of staff. She is also an attorney and was a budget and planning guru for the Perry administration before becoming his chief of staff. Although she has not made her views known on the capacity market, many analysts expect she will be the deciding vote to break the Nelson-Anderson deadlock in Nelson’s favor.
The policy debate in Texas is coming to a head in early 2014, after much political maneuvering at the end of last year, according to many observers.
Opponents of a capacity market have argued, as does PUCT Commissioner Anderson, that the costs of reserve capacity in a formal market are too high. That’s won support from the Texas Association of Manufacturers, which consists of large electricity users. Their chief, Tony Bennett, argued in the Dallas Morning News that “a capacity market assumes worst-case, hypothetical scenarios, and all existing power generators receive the same subsidy payment, regardless of whether their power is ever needed or used.” His group has proposed an alternative, which he calls a “Supplemental Reserve Service.” Under this plan, ERCOT “would determine the amount of additional power that needs to be purchased, say during the summer, and would provide payments only to those generators who provide the additional power.”
Bennett’s proposal, as outlined in the press, appears to duck the issue of how much ERCOT might pay for the reserve power and the terms and conditions under his alternative. As a practical matter, it appears Bennett’s plan could amount to a capacity market by another name.
Capacity Market or Bust?
Generators have promoted the idea of a classic capacity market, as implemented in PJM, NYISO, and ISO-NE. Exelon’s John Orr told the Dallas Business Journal, “I need to be sent a signal and have a reasonable expectation of what I’m going to get or I won’t drop a dollar here. You have to think what you’re competing against. It’s a world market for money and it’s certainly a national market for money. And every other place is willing to pay you, but not here. You’re gambling here if you’re an investor.”
Today, as the issue moves toward a resolution in Texas, the betting is that Nelson and Marty will approve some sort of plan for a Texas capacity market that resembles what exists in the Northeast. UBS utilities analyst Julien Dumoulin-Smith, one of the savviest savants of electricity markets, recently told his clients, in a private analysis obtained by POWER, “We see ERCOT as repositioning itself strategically to make any new capacity market palatable; while clearly on board with the idea in our view, the price ‘must be right.’”
A major indicator will be the release of a report by the consulting firm The Brattle Group, which is imminent as this article is being written. Dumoulin-Smith says the report’s recommendation of a reserve margin for ERCOT could be crucial for the debate on implementing a capacity market for the state; the recommended margin will determine the overall cost of a market. The lower the suggested margin, the less capacity ERCOT will have to buy and the less impact on overall consumer prices. In any case, he says, Texas is moving toward some form of a capacity market for ERCOT. ■
— Kennedy Maize is a POWER contributing editor.