The Northeast energy markets are working hard to establish new levels of regional coordination and cooperation. The region’s concerted effort is essential to resolving some of the industry’s toughest issues since the individual markets evolved. These issues include the elimination, reduction, or bridging of seams issues that prevent the economic transfer of capacity and energy between neighboring wholesale electricity markets, or control areas, as a result of incompatible market rules or designs.
Seams issues remain one of the greatest barriers to energy trading, market liquidity, resource optimization, inter-regional planning, and overall cost reduction. The Northeast is leading the charge to marginalize intra- and inter-regional seams issues. The Northeast is laying the groundwork for a future where regional goals—such as greenhouse-gas reduction, the economic transfer of capacity and energy, and the benefits of renewable energy—take precedence over individual market designs.
The Northeast region includes the New York ISO, ISO New England, Ontario, Québec, and the Canadian Maritime provinces, which together constitute all of the Northeast Power Coordinating Council (NPCC), as well as the “classic” portion of PJM, which is contained in the Reliability First Corp. (RFC) coordinating council.1,2
As Table 1 shows, this region overall has adequate generating capacity. However, what the table does not show is that the majority of the least-cost capacity is located in the north, west, and south of this region; while the eastern-central portion, with its heavily populated metropolitan centers, increasingly needs to access this power. And therein lay the keys to the region’s future—improved transmission access, reduction or elimination of seams issues, better utilization of existing resources, and price or regulatory signals that stimulate infrastructure investment where it is needed most.
In the Northeast markets, the generation-resource mix varies significantly by region. In the PJM part of the RFC region, coal, oil, natural gas, and nuclear make up 95 percent of total capacity, while hydro makes up only 4 percent. In contrast, the NPCC region is more heavily weighted with hydro assets. In NPCC, the mix is 37 percent hydro, 25 percent nuclear, 18 percent natural gas, and 13 percent coal. Most of the NPCC hydro assets are located in Canada, while most of the NPCC natural-gas assets are in the United States. One of the major trends of the last decade was the significant increase in the percentage of natural-gas-fired generation in both NPCC and RFC.
Figure 2 provides a more detailed view of the Northeast resource mix and provides some insight into the region’s market dynamics. In RFC, purchased-power transactions generally flow from west to east and south to north. This is because the majority of the less expensive coal generation is located in the west and south (see PJM-West, APS, and VP), while the more expensive natural gas-fired generation is located in the east and north (see PJM-East). Additionally, the generation owners in western and southern areas of PJM also have greater reserve margins (e.g., power to spare) than the generation owners in the east and north.
In NPCC, purchased-power transactions generally flow from west to east and from north to south. This is because the majority of the less expensive hydro, nuclear, and coal generation is located in the west and north, while the more expensive natural gas, oil, and dual fuel generation is located in the east and south.
The higher-demand metropolitan areas of the Northeast region (e.g., PJM-East, southeastern NY, Boston, and southwest Connecticut,) have the more expensive gas- and oil-fired generation, and lower reserve margins. PJM West, western New York, and the Canadian provinces have the less expensive hydro, coal, and nuclear generation, and greater reserve margins. This situation drives the major purchased-power transactions, and also creates the transmission congestion.
The Northeast region has experienced a significant increase in merchant power generation, perhaps more than any other region. Global Energy’s spring 2007 forecast includes over 6,000 MW of defined capacity additions coming on line between 2007 and 2011 in the Northeast region.
In determining a likely amount of initial entry, we reviewed a variety of publicly available sources describing projects currently being developed in the Northeast. As shown in Table 2, Global Energy found a total of about 35,000 MW of new capacity completed since the beginning of 2000. In addition, Figure 3 shows a breakdown of plant developments in the 2000-2007 period, including about 29,000 MW of new capacity that has been cancelled.
To determine total amounts of generation coming on line, Global Energy generally assumed that projects currently under construction would be completed regardless of early-year economics. While some regions clearly are overbuilt, most developers and investment bankers are willing to finish near-completed projects. A project that is finished, even though it may be deemed financially uneconomic given current market pricing, has more value than an unfinished, sometimes heavily indebted, project.
Facilities in earlier stages of development, such as announced or permitted (but not under construction) are assumed to be completed in response to future supply and demand conditions. Based on these assumptions, Global Energy included almost 6,400 MW of new capacity for the 2007-2011 period, with over 44,000 MW in the pre-construction phase. Many of the current projects being planned, permitted, and announced will be built after 2010 when capacity markets in New England and New York have matured.
In Ontario, significant capacity additions will be made during the next decade. In 2004, the Ontario government created the Ontario Power Authority (OPA), which is developing Ontario’s first Integrated Power System Plan (IPSP) since the late 1980s. This plan is expected to be completed by mid-2007. On June 13, 2006, the Ontario Minister of Energy gave the OPA its goals for the IPSP: Close all coal facilities by the earliest practical date; maintain the current level of nuclear generation; double the current level of gas, cogeneration, and renewables; increase conservation measures by a factor of 10; and strengthen the transmission system to achieve this desired supply mix. In an unprecedented open and public process, the OPA has addressed each aspect of the future market through various discussion papers posted on its Web site and has integrated the various market elements into a draft document which will eventually become the IPSP.
Transmission constraints are indeed a problem in the Northeast region, particularly in eastern RFC and southern NPCC. This situation exists for several reasons:
1. The transmission systems in this region generally have not kept pace with the tremendous growth in demand.
2. The systems were not designed to handle the significant power flows that have resulted from wholesale competition.
3. Siting for new and upgraded transmission facilities within these highly congested areas is a difficult and long process.
4. Until very recently, investors have not had adequate incentive to invest in transmission development.3 It is not surprising, therefore, that the Department of Energy recently has identified this area as a potential candidate for designation as a national transmission corridor.
The Energy Policy Act of 2005 authorized the Department of Energy (DOE) to designate “national interest electric transmission corridors” where there is major transmission congestion. On Aug. 8, 2006, the DOE released its first National Electric Transmission Congestion Study. This study identified two critical congestion areas that the DOE believes may be appropriate for designation as national corridors. One of these areas was the Atlantic coastal area from New York south through Northern Virginia; the other area was Southern California.4 The DOE currently is assessing commentary from stakeholders in these areas to determine how best to alleviate the congestion problems and whether or not it is in the public interest to designate these areas as national corridors.5
Applicants who want to build transmission within these corridors now may seek construction permits directly from the Federal Energy Regulatory Commission (FERC), assuming the relevant state regulators are unable, or unwilling, to grant such permits. For generators in transmission-constrained areas, FERC’s new supplemental siting authority could, in time, ease the “path to market” and increase both profitability and overall value of select generation assets.
Transmission constraints are the reason behind the use of locational marginal pricing (LMP), which is used in the RFC and the U.S. portion of the NPCC. LMP is discussed below. Transmission constraints can be ameliorated by adding or upgrading generation or transmission. We assume that the above actions will be undertaken on an economic basis over the forecast period; however, in our price forecasts we rely almost solely on generation additions that are located to serve load inside any congested market zone. We also consider and apply the relevant transmission rates and line losses for through-and-out reservation service on interconnecting lines. However, if the reader intends to perform short-term or location-specific analysis, we recommend that transmission constraints be considered in more detail because they can affect short-run plant profitability.
FERC has proposed a gradual migration to locational marginal pricing (LMP). LMP markets already are in place in New York, PJM, New England, and most recently in the Midwest ISO (April 1, 2005) and are under development in California, Electric Reliability Council of Texas, and elsewhere.
The need for location-specific price information is driven by regional transmission organizations that have adopted standard market design-compliant market structures, as well as for market participants in regions that have yet to adopt nodal pricing but need to assess locational impacts consistent with FERC’s SMD initiative. Moreover, the use of LMPs as part of a congestion management system is viewed favorably by FERC for its ability to convey appropriate price signals to market participants. It creates the need for market participants to forecast nodal prices to assess generation or transmission system improvements, and to assess the value of congestion revenue rights in mitigating congestion exposure.
LMPs capture the cost of supplying the next megawatts of load at a specific location. LMPs are calculated using a security-constrained unit commitment dispatch model. A security-constrained model goes beyond security constraints typically included in zonal models—such as operating reserves, unplanned outages at generating facilities, and transportation-like representation of key regional transmission paths—to introduce additional constraints tied to a detailed description of the transmission network. These include transmission links and interface limits, and complex operating schedules tied to multiple interfaces.
The hourly dispatch and commitment data, along with bid curves of the units, are passed to the optimal power flow (OPF) model and an accompanying detailed transmission network model. The OPF simulation utilizes the initial EnerPrise Market Analytics Module zonal solution and cost-and-performance characteristics of generators, combined with a detailed electrical model of the entire transmission network—including important constraints associated with the electrical network—to minimize power costs subject to generator bids or costs.
Figure 5 is a visual illustration of a nodal analysis. Blue signifies an area where nodal prices are $30/MWh or less, green signifies approximately $35/ MWh nodal prices, and red signifies prices $40/MWh or more. The nodal price snapshots assist in visualizing hourly nodal prices. This type of price visualization technique assists in identifying load (red zones) or generation pockets (blue zones), as well as the congestion expected to occur within the region (spanning the red and blue zones).
Solving this range of seams issues that prevent the Northeast energy markets from operating efficiently is a key challenge for all market participants. Federal and state regulators should continue to encourage solutions and force the framing of issues in an effort to reach settlement of the differences.
1. NPCC and RFC are two of the eight the North American Electric Reliability Council (NERC) regional reliability councils in the Lower 48 U.S. states and Canadian provinces.
2. Price and resource data also is provided for the neighboring market zones denoted APS and VP.
3. “Promoting Transmission Investment Through Pricing Reform,” FERC Order 679, issued July 20, 2006. This rule is applied on a case-by-case basis and the applicant must justify his use of the specific incentives FERC has identified as allowable.
4. National Electric Transmission Congestion Study, U.S. DOE, August 2006.
5. DOE comment period ended Oct. 10, 2006.