The PJM Interconnection has evolved significantly over the past few years. PJM expanded its footprint enormously between 2002 and 2005. It now traverses 13 Mid-Atlantic and Midwestern states. The PJM regional transmission organization (RTO) now represents the world’s largest centrally dispatched electric grid, with installed capacity approaching 167,000 MW by the summer of 2007.
While maintaining its stance as the most sophisticated competitive electricity market in the country, PJM still faces several challenges, all of which are augmented by its expanded footprint. Most prominent is the RTO’s plan to implement a new capacity market construct, referred to as the reliability pricing model (RPM), as early as this summer. Further, parts of PJM are ailing from transmission congestion issues that limit access to abundant, cheap power sources in the region.
During the summer of 2006, PJM broke its peak-load record three times. PJM has registered a peak-load growth of 8.3 percent since 2005. At the same time, transmission congestion is causing localized supply shortages in PJM despite the overall overabundance of generating capacity in the region. The RTO is devising a new resource-adequacy construct aimed at providing sufficient price signals for where and when to invest in transmission and generation-capacity additions.
During the past three decades, PJM has gone through several capacity market designs. Starting in 1974, PJM imposed a two-year, forward-looking annual installed capacity (ICAP) obligation. This obligation was spread across the load-serving entities (LSEs), which were charged a capacity deficiency rate based on the cost of new capacity when failing to show adequate reserves for the next two years.
In 1999, PJM replaced the installed capacity obligation construct with the current capacity credit market design, which covers up to 12 months of capacity through daily and monthly capacity obligations and auctions to ensure sufficient reserves at all times. While this market has evolved substantially over time to include a wider regional cooperation and adjustment of obligations for outages, the concept still is based on a regional (PJM-wide) capacity requirement and a vertical ICAP demand curve.
PJM and many of its market participants have been concerned about two problems with the current capacity credit market. First, the regional clearing of the capacity credit market does not provide sufficient locational price signals of where new capacity is most needed and valuable. Second, the vertical demand curve combined with the relatively short planning horizon of one year does not furnish sufficient economic incentives for developers of generating and transmission capacity to construct the new capacity needed to ensure longer-term reliability in the PJM region. These issues are escalated by the rapid expansion of PJM’s footprint, which has more than doubled in the past few years.
On Aug. 31, 2005, PJM filed with the Federal Energy Regulatory Commission (FERC) its reliability pricing model (RPM) capacity market paradigm proposal. This new capacity market design had been under discussion among PJM stakeholders for a long time, but reaching consensus has proven to be very hard due to the number of interests involved.
Hundreds of follow-up filings have been made with FERC, and many utility commissions, ratepayer associations, and major utilities have expressed concerns regarding the proposed RPM design. PJM originally had requested FERC’s approval of its RPM proposal by Jan. 31, 2006, and scheduled implementation on June 1, 2006. Yet, the lack of agreement regarding some of the major design issues of RPM has prevented FERC from making any decision on the RPM according to this tight schedule. Protests have raised a wide variety of concerns ranging from disputing the need for a locational market and whether the current ICAP paradigm is really defunct, to the cost of new entry and the methodology for defining the demand curves. Proponents continued to stress the need for RPM to stimulate new power-plant construction, while opponents argued among other things that RPM would result in extremely higher rates and do little to cause new construction.
FERC responded on April 20, 2006, with a paper hearing on PJM’s RPM filing indicating its overall agreement about the need to revise the current capacity market rules. On the other hand, FERC specified some areas that required further clarifications or modifications. After four months of discussions and negotiations among stakeholders, PJM filed a settlement agreement with FERC on Sept. 29, 2006. The major changes included in the settlement filing were a lower value for capacity in the RPM demand curve and a three-year forward auction schedule for acquiring ICAP requirements, rather than the originally proposed four-year horizon. Further, the settlement agreement removes the seasonal aspect of the RPM, proposed a year earlier, and proposes annual clearing of capacity prices.1
The September settlement filing—conditionally approved by FERC on Dec. 22, 2006—has not marked the end of controversy over the RPM as anticipated by PJM and the appointed administrative judge. In January 2007, several industrial consumers announced their withdrawal from the settlement agreement prompted by FERC’s decision to impose additional conditions that they argued would add more risk to consumers without any benefits. Some of the conditions imposed by FERC include:
• Modifying the provisions that discriminate between signatories and non-signatories;
• Expediting cost recovery for more resources incurred for compliance with state-mandated requirements; and
• Limiting the amount of discretion granted to the RTO market monitor.
The additional conditions are seen by industrial customer groups largely as benefiting generation owners rather than reducing costs to customers or improving reliability for the region. Also of concern is that the conditions will relax market monitoring and market-power mitigation when evidence of market manipulation has been confirmed in the past.
On Jan. 22, 2007, PJM filed changes to its tariff and reliability assurance agreement in compliance with FERC’s December order. These changes will become effective along with the rest of the RPM on June 1, 2007. The first auction is expected in April 2007 for the 2007-2008 delivery year.
The RPM is a capacity market design through which LSEs would acquire their long-term unforced capacity (UCAP) obligations, with the objective of ensuring long-term system reliability and energy market equilibrium, and sending price signals based on the future locational capacity needs. Consequently, the RPM would generate incentives for investing in new generation and transmission, and for retiring uncompetitive older units. The PJM RPM differs from its New York counterpart in that it uses a three-year planning horizon and it is open to transmission and generators alike.2 Further, the RPM allows for not-yet-built capacity to bid into the market, aiming at providing revenue certainty to allow developers to finance and build new generation and transmission.
The RPM introduces a locational ICAP market in PJM similar to that of New York and the now shelved LICAP market proposal for New England. It introduces a sloping demand curve, called the variable resource requirement (VRR) curve, which was developed to provide adequate incentives for siting and building new generation and transmission—with more compensation available when reserves are below the target reserve margin levels and less when reserves are above target. This forms a demand curve, as illustrated in Figure 2. That figure also compares the originally proposed VRR curve to the revised curve proposed in the September 2006 settlement filing.
As shown, the settlement agreement preserves the structure of the VRR curve but establishes a lower value for capacity at all reserve margin levels—except for the 16 percent level. For example, the originally proposed VRR curve would allow capacity prices to rise to levels sufficient for a new gas turbine to recover 200 percent of its revenue shortfall when installed reserve margins were at 12 percent or lower. PJM’s recent settlement agreement caps the total recovery allowed at 150 percent. The revised VRR also yields a lower value for capacity than originally proposed at reserve margins higher than 16 percent (and lower than 20 percent).
The locational aspects of RPM are to be expanded in phases:
• For the delivery years 2007 through 2010, four local deliverability areas (LDAs) are used: SW MAAC, Eastern MAAC, MAAC region plus APS, and Rest of Market.3
• After 2010, the LDAs will be expanded to include potentially more than 23 reliability zones or areas with a meaningful separation of these reliability zones existing only if ICAP values turn out to be different among the zones.
PJM hopes this locational market will give market participants sufficient economic incentives to resolve the existing capacity bottlenecks in eastern PJM, such as Delmarva, Baltimore, and eastern New Jersey. Along with its forecast of electricity prices, Global Energy prepares a forecast of the ICAP market values for selected locations under the proposed RPM construct. Our forecast shows ICAP values for selected locations where our analysis shows locational markets are most likely to be critical for ensuring future market reliability.
PJM develops an annual Regional Transmission Expansion Plan (RTEP) to identify transmission system enhancement requirements. The RTEP process identifies two kinds of upgrades: reliability-based upgrades and economic-based upgrades. PJM recently decided to extend its transmission expansion planning horizon from 5 to 15 years to better address reliability and economic needs and major system changes.
The first 15-year RTEP was approved in June 2006. PJM expects its board-authorized $1.3 billion in transmission additions and upgrades by 2011 to result in annual congestion cost savings of $200 million to $300 million. PJM approved Allegheny and Dominion Energy’s proposed 240-mile, 500-kV transmission project between southwestern Pennsylvania and northern Virginia. This project is estimated to cost $800 million to $850 million, with commercial operation planned for 2011. Allegheny and Dominion plan to initiate construction in 2009.
In addition, the PJM RTEP has identified areas with major physical constraints that together with robust load growth, generation retirement, and slow generation development affect the system’s ability to handle customer demand reliably: Eastern PJM, Southwestern PJM, and the Delmarva Peninsula. The RTEP continues to draw attention to limited energy transfers into Southwestern PJM and Eastern PJM through the interstate transmission system from the west, augmenting reliability and congestion concerns. The RTEP identified six facilities as limiting west-to-east transfers:
• Bedington - Black Oak 500-kV line;
• Wylie Ridge 500/345-kV #5 and #7 transformer;
• Doubs - Mt. Storm 500-kV line;
• PJM Central Interface/Juniata 500 kV;
• Harrison - Kammer Tap 500-kV line; and
• Fort Margin - Pruntytown 500-kV line.
In May 2005, PJM introduced the “Project Mountaineer” concept to identify required transmission projects to improve the ability of the cheap coal-fired generation in the west to access eastern PJM. This initiative establishes cooperation among PJM, state regulators, the coal industry, and PJM utilities to advance the required upgrades and address siting, environmental, cost recovery, and ownership issues. Project Mountaineer uses the RTEP process to evaluate alternatives for improving fuel diversity and relieve west-to-east transmission congestion. It initially was estimated that between 550 and 900 miles of 500- or 765-kV lines, at a cost of $3.3 million to $3.9 million, would be needed to increase west-to-east flows by up to 5,000 MW.4 Last year, two major projects—detailed below—were proposed to achieve the benefits of Project Mountaineer.
On Jan. 31, 2006, AEP proposed through its new subsidiary, AEP Transmission Co. LLC, to develop a 765-kV transmission line and associated facilities originating at its Amos 765-kV station in West Virginia, extending through Allegheny Power’s Doubs Station in Maryland, and terminating at Public Service Electric and Gas’ Deans Station in New Jersey. The line would run about 550 miles and cost approximately $3 billion—if built above ground and excluding necessary related upgrades by utilities. AEP projects an in-service date of 2014 for this project, assuming three years to site and obtain certifications and five years to construct.
Referring to PJM’s high congestion costs, AEP stresses that its transmission development would bring about substantial congestion relief and reliability improvements increasing Midwest-to-East transfers by 5,000 MW and fulfilling the published goal of Project Mountaineer. In addition, AEP Interstate would reduce peak-hour loss by 280 MW, and provide opportunities for the development of interim transmission investment by incumbents that eventually would integrate into the 765-kV transmission line.5
AEP already has filed the proposal with the PJM Interconnection, FERC, and the DOE. PJM announced that it intended to analyze the project’s potential for reducing congestion as well as its impact on capacity pricing and other market elements. In July 2006, FERC approved the requested transmission incentives consistent with its recent transmission incentive ratemaking rule. The incentives approved for AEP include: (1) enhanced return on equity; (2) full recovery of construction work in progress (CWIP); and (3) pre-construction and pre-operation cost recovery.
AEP requested that the DOE designate the proposed route as a “national interest electric transmission corridor” (NIETC) under the Energy Policy Act of 2005. The new law allows transmission developers of projects in these corridors to seek the necessary permits from FERC to move forward if states fail to act on the projects within a year or lack authority to site the facilities. It also places conditions on their approvals.
Less than a month after AEP’s announcement, Allegheny Energy proposed building a 330-mile, 500-kV transmission line that would increase west-to-east power transfers through its territory by 3,800 MW. The company hopes to bring the first sections of the $1.4 billion project into service by 2013. Called the Trans-Allegheny Interstate Line, this project would originate from Allegheny’s Wylie Ridge substation in the panhandle of West Virginia, run through southwestern Pennsylvania, then through north-central West Virginia before entering western Maryland, and reaching its end point at a new substation near Kempton in central Maryland. It would remain in Allegheny’s territory throughout the route.
Allegheny emphasized that Trans-Allegheny was not meant to compete with AEP’s project, since the lines would proceed mostly on different paths and terminate in different states. Similar to AEP, Allegheny filed a request with FERC for incentive rate treatment and asked the DOE to designate its project as an NIETC. FERC granted the Trans-Allegheny project the same transmission pricing incentives as those approved for AEP Interstate in addition to recovery of all prudently incurred development and construction costs if the project was abandoned for reasons beyond Allegheny Energy’s control.
In addition to AEP and Allegheny Energy’s proposals, Pepco Holdings Inc. (PHI) recently proposed the construction of a 230-mile, 500-kV interstate transmission line—referred to as the PHI Mid-Atlantic Power Pathway. The line would originate in Northern Virginia and would travel through Maryland and the Delmarva Peninsula, ending in New Jersey. Filed for inclusion in PJM’s latest RTEP, this $1.2 billion project—to be completed by 2014/2015—represents the only south-to-north proposal. The Mid-Atlantic Power Pathway is expected to improve reliability significantly and to relieve congestion in eastern PJM, complementing AEP and APS west-to-east proposals.
PJM’s first 15-year RTEP recommended the evaluation of about 10 proposed transmission projects estimated to cost $10 billion, including the three transmission projects proposed by AEP, Allegheny, and PHI. Given sponsors’ filing of additional siting and environmental studies, PJM expects to make decisions on these projects in 2007.
In its recent report on national transmission congestion, the DOE has identified the area between New York City and Northern Virginia as a “critical congestion area.”6 Critical congestion areas represent candidates for designation as NIETCs, which would be eligible for federal backstop siting authority when states fail to act on transmission-expansion applications. AEP, Allegheny, and PHI view that NIETC designation as a probable requirement for their projects to be approved, given the top two obstacles to their transmission proposals—individual landowners and conflicts involving federal agencies. On Oct. 11, 2006, PJM told the DOE that it had asked FERC to designate three areas within PJM as NIETCs. These areas include the Allegheny Mountain, the Delaware River, and the Mid-Atlantic corridors.
1. Settlement Agreement and Explanatory Statement of the Settling Parties Resolving All Issues in PJM Interconnection LLC, Docket No’s ER05-1410-000 and -001, and EL05-148-000 and -001.
2. The August 2005 filing originally had proposed a four-year planning horizon, which later was amended in the September 2006 settlement agreement to a three-year planning period.
3. The delivery year begins on June 1 through May 31 of the following calendar year.
4. FERC Docket No. AD05-3-000.
5. Total congestion costs in PJM in 2005 reached $2.09 billion, representing a 179 percent increase from the 2004 costs of $750 million. This huge increase is partially driven by the expanded PJM footprint in 2005.
6. “National Electric Transmission Congestion Study,” August 2006, U.S. Department of Energy.