They say “the neon lights are bright on Broadway,” and keeping them all lit is a monumental task 1 New York City, America’s most populous city, is like many other urban areas in that it depends on high-voltage transmission to import much of its power from generation located in the surrounding countryside.
Faced with state-wide electric utility restructuring and power-market deregulation, the state of New York constantly has been adjusting the state’s power markets to meet the potentially contradictory goals of low cost, yet reliable power. In New York this has taken many forms, including monitoring of energy prices, caps on capacity prices and forced divestment of assets to reduce potential market abuses. While much progress has been made, the New York City Market, labeled Zone J by the New York Independent System Operator (NY-ISO) still is evolving, and asset-investment decision-makers need to recognize the risks associated with potential changes.
The NY-ISO manages the state’s power system and administers all power-related markets—energy, ancillary services and capacity. Energy is priced using locational-based marginal-pricing to value congestion on a near real-time basis, similar to the system already in use in New England, PJM, MISO and SPP.
Capacity market prices are managed in a series of three auctions. The first auction is conducted to set monthly prices for the upcoming six-month winter or summer capacity obligation period (the “strip auction”). The second auction is conducted monthly for the prompt month and the balance of the current strip. In the third and last auction, commonly called the spot auction, the prices are set to accommodate any prompt-month demand not fulfilled in the first two auctions.
In the first two auctions there is no direct regulation of prices. In the third auction, all uncommitted capacity is offered, and the price is determined by a pre-defined downward-sloping demand curve.2 While much attention is focused on the demand curve associated with the spot-market auction, in recent history capacity has been actively traded in all three auctions. Most of the capacity in Zone J initially was offered into the six-month strip auctions (see Figure 2). For the summer 2003 capability period starting in May of that year, the NY-ISO implemented its current downward-sloping demand-curve process for the spot-market price determination, replacing a methodology that implicitly relied on vertical demand curves. The impact on relative participation in the markets was immediate and dramatic, with much of the capacity moving to the monthly and spot markets. Post-2003, asset owners continually have “searched” for a proper balance in the three markets to maximize their own revenues. However, the conventional wisdom that all of the capacity has been transacting in the spot market is not accurate.
The May 2003 implementation of the downward-sloping demand curve for the spot auctions provided some level of discipline in the first two auctions, as market participants now know that deviating too far from the anticipated spot-market outcome is not rewarded. For example, prices across the three markets dramatically converged in 2003 and stayed that way through last winter’s auctions (see Figure 3). So, even though capacity is offered in all three auctions, the existence of a known range of prices in the spot auction so far has provided price stability in all three auctions. It is notable that this price discipline is most evident in New York City—there still is more price disparity among the three auction results for both Long Island (NY Zone K) and the balance of the state.3
The price discipline has come in part from many of the assets in New York City having been divested from Consolidated Edison’s ownership. So now these assets are subject to FERC market-mitigation measures, including capacity market price caps. These so-called “divested generation owners” or DGOs, have tended to offer their capacity near their FERC-approved price caps, providing much of the apparent price stability. A recent FERC ruling now allows DGOs to enter into bilateral contracts (previously they were limited to selling capacity only in the auctions), but they still are required to offer all unsold capacity into the capacity auctions. Price caps (technically offer caps) still exist for all assets that could be used to wield potential market power, but now are structured around both a ceiling offer as well as an individual generator’s “going forward costs.” The net impacts of this latest ruling are yet to be seen, but early indications are they will be significant.
The results of the summer 2008 strip auction were posted on the NYISO’s website on April 2. The summer 2008 strip auction for Zone J resulted in a price of $6.50/kW-month, nearly half that of summer 2007, and the volume was about 495 MW, 74 percent less than in summer 2007. The results of the first monthly auction were posted on April 15, and the May monthly price is $6.52/kW-month while the volume is only 903 MW. Clearly, most of the capacity is either tied up in bilateral contracts or is moving to the spot market. The spot- market results were not known when this article was submitted, but will be available near the publication date.
A capacity market construct that involves periodic administrative tinkering leaves one major question—how to induce new resources to serve growing demand? The New York State Reliability Council annually reviews supply adequacy requirements for the state and for N.Y. Zone J. For the 2008 capability year it has recommended setting the local resource requirement at 79 percent, down from last year’s 80 percent value.4 This means that 79 percent of the resources needed to meet peak hourly demand must be electrically located in NY Zone J so they are geographically located within Zone J or physically connected to Zone J via dedicated transmission lines. This capacity is a mixture of over 130 mostly older thermal units, fueled by natural gas, fuel oil, or kerosene. Many are very small, with nearly 100 units rated less than 40 MW.
Included in this supply picture are remote resources that through dedicated transmission are treated as if in N.Y. Zone J. For example, the Linden Cogeneration plant in Linden, New Jersey is connected to Staten Island via underwater 345-kV transmission, which counts as if it were physically located within N.Y. Zone J. Several proposed projects with similar connections are under consideration. An example is the proposed 660-MW Hudson Transmission Project, which would connect a PJM substation in Bergen, New Jersey to ConEd’s 49th Street substation in Manhattan.
What types of resources make sense to power new generation in N.Y. Zone J? Historical zonal average energy prices in N.Y. Zone J have run almost $17/MWh above the NY-ISO Reference Bus, which is located upstate in Zone E. At first this may not seem like a large difference, as burner-tip natural gas prices tend to be higher inside Zone J than upstate. But even controlling for higher gas prices, the market heat rates faced by Zone J generation is significantly higher compared to the NY-ISO Reference Bus.
The effect of this difference in market heat rates is dramatic when illustrated in terms of the annual operating margins faced by gas-fired generation. A dispatch analysis of hypothetical combined-cycle, combustion-turbine and gas steam units5 yields a very different picture for assets exposed to these two markets.The annual operating margins6 for these assets at the NYISO Reference Bus in Zone E are relatively modest, nearly zero for the gas steam unit, and under $10/kW-year for the combustion turbine and about $30-70/kW-year for the combined-cycle unit.
Within Zone J, the annual operating margins are much higher, trending under $15/kW-year for the gas steam unit, about $20-60/kW-year for the combustion turbine and about $120-200/kW-year for the combined-cycle unit.
These operating margin differentials have enormous implications for the design of the NY-ISO capacity market in Zone J. Traditional thinking has led to the conclusion that combustion turbines, with their lower capital costs, should serve as the benchmark for determining market revenue shortfalls used in capacity market price setting. As a result, combustion turbine capital costs are used to set the Cost of New Entry (CONE) in formulating demand curves in New York and other jurisdictions. This CONE, reduced by a forecast of energy and ancillary services operating margins, yields a “Net CONE” that is used to anchor the capacity market demand curve.
However, in New York Zone J, combined-cycle assets have a much greater energy operating margin potential than do combustion turbines. Historically, this higher operating margin potential has been in the range of $100 - $140/kW-year (see Figure 4). This higher energy operating margin more than compensates the owners of the combined-cycle assets for their incremental investment costs. This observation, based on historical data, is substantiated by the development queue for New York Zone J—most proposed assets are combined-cycle units, not peakers.
The issue is that as the Zone J capacity market is administered today, capacity prices based solely on the cost of new combustion turbines may lead to significant over-compensation for combined-cycle asset owners. That is, in Zone J, the capacity revenue plus energy operating margin realized by a combined-cycle asset can exceed the cost of new construction. If this condition persists, equity issues will be raised by retail electric customers, meaning that the Zone J capacity market will be subject to more redesign efforts as the competing interests of generation owners and retail customers clash in Albany and Washington, D.C. Investors who assume that today’s capacity market design will persist in the future run the risk of over-estimating future revenues and potentially paying “too much” for assets located in Zone J.
1. Apologies to The Drifters, George Benson, and everyone else who has recorded “On Broadway.”
2. NY-ISO capacity markets are discussed in more detail in “Capacity Markets Demystified,” Public Utilities Fortnightly, March 2008
3. See “Report on Implementation of the Installed Capacity Demand Curves,” NY-ISO, Jan. 15, 2008.
4. “New York Control Area Installed Capacity Requirements for the Period May 2008 through April 2009, Technical Study Report,” New York State Reliability Council, LLC, Installed Capacity Subcommittee, Dec. 14, 2007.
5. The combined cycle unit is assumed to have a heat rate of 7,000 Btu/kWh and a VOM of 2.00/MWh. The respective values for the combustion turbine are 10,000 and 3.50, and for the gas steam unit 15,000 and 4.00.
6. These annual operating margins are based on a dispatch analysis of historical hourly LMPs and gas prices, with no allowance for fixed costs. Revenue is only from the energy market, not capacity or ancillary services. This assumes assets are responding to prices only, with no allowance for out-of-merit order dispatch due to local reliability requirements.