Hope Robertson, Cambridge Energy Research Associates
Two-and-a-half years have elapsed since the Federal Energy Regulatory Commission (FERC) requested transmission owners to band together and create regional transmission organizations (RTOs) throughout the country. The boundaries of the RTOs have been in a constant state of flux since 2001. Although the scope of many RTOs is beginning to solidify, several still remain in question for a variety of reasons, including state government concerns or questions about the participation of public and cooperative utilities. On balance, significant strides have been made in the development of RTOs.
The status and key issues facing each of the RTOs are summarized below.
Efforts to merge the ISO-New England (ISO-NE) and New York ISO (NY-ISO) fell apart last fall owing to opposition from state governments and many transmission owners. Despite the failed effort, both independent system operators feel great improvements were made in the cooperation between these two markets. Since neither NY-ISO nor ISO-NE gained approval for their original RTO filings, both will need to refile to gain approval as an RTO.
ISO-NE announced its intent to refile as an RTO and currently plans to file by June 30 with FERC. In addition to reworking its RTO filing, ISO-NE is focusing on implementing its real-time market system, launched on March 1, 2003. At the eleventh hour, opposition by the attorneys general of both Connecticut and Massachusetts surfaced over the possible cost impacts of the new market design. Although both FERC and the U.S. Court of Appeals denied the Connecticut attorney general’s request to place a stay on the market implementation, it is expected the attorney general will file another appeal. Whether Connecticut will be successful in stopping implementation of the standard market design (SMD) is unknown. ISO-NE’s SMD puts it on a parallel path with both NY-ISO and PJM Interconnection (PJM) in terms of utilizing locational marginal pricing (LMP) and having a day-ahead and real-time market. Their market design tracks many of the policies in FERC’s SMD proposal.
NY-ISO has not announced any plan to refile to become an RTO, but in light of some of the financial incentives recently proposed by FERC for participants in RTOs, it is likely NY-ISO will refile.
PJM has a number of outstanding issues that merit close attention by anyone interested in the transmission business. PJM was given full RTO status by FERC in December 2002. However, as part of that decision FERC also asked PJM to comply with some additional requirements. One of the important requirements was for PJM to file by March 20 the details of how its planning process will incorporate competitive enhancement projects. This will be the first effort by any RTO to detail how it will handle competitive enhancement projects (also referred to as economic projects) in its expansion planning efforts. Since this planning detail has important ramifications for merchant transmission companies as well as all utilities, it will be key to track.
PJM has also made two other important filings to FERC. One is PJM’s proposed interconnection policy for merchant transmission projects. This filing has already stirred up significant controversy by other stakeholders. Again it is one of the first efforts to standardize how merchant transmission projects should be handled in terms of interconnection. The second filing covers proposed changes to PJM’s financial transmission right (FTR) system to make the process more flexible and to offer more frequent auctions.
Another development at PJM relates to participation by new utilities. The creation of GridCo, the independent transmission company (ITC) proposed by AEP, Commonwealth Edison, and Illinois Power is currently stalled as these utilities reassess the idea. However, all three utilities are proceeding in their efforts to become part of PJM even if it turns out they join as transmission owners, not as part of an ITC. In a similar vein, PJMSouth is halted in its tracks owing to strong opposition by the Virginia Public Utility Commission (PUC) and legislature. The concern is possible rate impacts. The state government does not want Dominion to turn over the control of its assets to PJM and, more importantly, fall under FERC jurisdiction. Whether this impasse is resolved remains to be seen.
The Southern RTOs
All three of the RTOs in the Southeast are facing stiff opposition from state governments. Federal/state jurisdictional issues associated with participation in the RTOs or adoption of SMD combined with concerns about regional rate impacts have caused great controversy in many southern states. GridSouth is still in a stalled mode and it appears increasingly unlikely to move forward. Whether or how the three investor-owned utilities behind the GridSouth RTO will regroup and join one of the other RTOs is unclear at this time. SeTrans Grid is still in the process of negotiating the final details of the arrangements with its independent system operator. SeTrans expects to file with FERC more of the details of its RTO sometime this spring. Right now, SeTrans does not anticipate being operational until 2005. More importantly, SeTrans is not making significant investments to move forward until the state jurisdictional issues are settled. GridFlorida, which was approved by the Florida Public Service Commission (PSC), was recently stopped in its tracks owing to an appeal of that approval to the Florida Supreme Court. The Florida Office of Public Counsel is appealing on the grounds that the PSC cannot relinquish its ratemaking authority over any aspect of electric rates. Comments are due by late February by all parties, and a court decision may be made in six to nine months.
The Tennessee Valley Authority (TVA) and several associated public utilities are slowly continuing their efforts on figuring out how they can work with surrounding RTOs and coordinate their markets. Various memorandums of understanding are being developed with the Midwest ISO (MISO), Entergy, and Southern as well as others to resolve market issues. At present, there is no indication that TVA will either create or join any RTO.
The MISO/Southwest Power Pool (SPP) merger is virtually complete, although many of the SPP transmission owners still need to gain approval from their state commissions to transfer control of their assets from SPP to MISO. MISO is currently developing its market rules and has filed three sets of rules with FERC to create a day-ahead/real-time market, set up FTRs, and handle market settlements. MISO anticipates going live with its market by the end of 2003. Its current challenge is to go out to private debt markets to raise the roughly $100 million needed to launch its market design. Amidst the efforts to implement a day-ahead/real time market, MISO continues its coordination with PJM. In addition, MISO is working out the details for three of the five ITCs still in the process of becoming operational.
The Texas Public Utility Commission (PUC) launched an effort to examine whether changes should be made to the market rules for the Electric Reliability Council of Texas (ERCOT) market. Based on the discussions at a PUC meeting February 13, it is far from clear how significantly ERCOT’s market rules will change or how soon. However, it is assumed that some adjustments in its current zonal pricing system will be made.
The Western RTOs
Aside from the attention to myriad details needed to fully develop each of the western RTOs, the biggest challenge is to create a consistent market design across the region. Efforts to work on planning coordination and market monitoring, among other issues, for the entire West are being developed by the three RTOs. The three regions have made a significant time investment to work out the details. The hope is to complete West-wide planning proposals by the third quarter and at least define how market monitoring will be approached by the second quarter of this year. WestConnect, which was granted provisional approval as an RTO last fall, does not expect to adopt any type of real-time market/LMP pricing system, but rather to continue to rely on bilateral contracts. An additional reason for not adopting a day ahead/real time market and other associated SMD features is that more than half of the WestConnect transmission assets within are nonjurisdictional assets. At present, WestConnect is taking a minimalist approach to RTO development through such actions as using existing control centers initially. Whether WestConnect continues to develop or splinters up to join other RTOs is still a question.
RTOWest was also conditionally approved by FERC last fall. Similar to WestConnect, it is grappling with the tricky issues associated with having so many nonjurisdictional assets within the RTO. RTOWest is determining key details such as:
“- which facilities will be included in the RTO;
“- figuring out how existing contracts will be converted over time so that a sufficiently liquid market can develop to cover any congestion management program; and
“- how to ensure equal treatment of all market participants.
TransConnect, the ITC associated with RTOWest, is in a holding pattern waiting to see how the details of FERC’s SMD policy evolve and how RTOWest sets up its policies.
The California ISO (CAISO) is also completing its own market design process. Although FERC has approved some components, key elements such as the design of its congestion revenue rights, its network model, and how it will set up an integrated forward market remain to be finished. The hope is to implement its new market system by the summer of 2004. Perhaps most important is to complete the investigations of the California market problems and shift the focus to implementing a more workable market.
Finalizing SMD: Resolving the issues
Despite the controversy swirling around the FERC SMD, most of the opposition can be traced to a fight over state vs. federal jurisdiction. Based on the comments filed at FERC over the past few months, much of the SMD content is not challenged. According to Chairman Pat Wood’s remarks at CERAWeek 2003 in Houston, February 13, FERC appears to be headed in the direction of allowing regional differences in several key areas:
“- the timing of implementation,
“- determination of resource adequacy,
“- allocation of FTRs,
“- transmission planning, and
“- RTO governance (which FERC has already indicated in recent rulings).
In the April White Paper FERC will be issuing on SMD, it is expected that the final proposed policies will be laid out for one more round of comment. As FERC has indicated in statements at various technical meetings, the concessions to state jurisdiction will most likely be done so as not to jeopardize a coherent market. In CERA’s view, the next draft of the SMD policy may take the following approach:
“- Resource adequacy may be left to each state to determine, but FERC may still require regional coordination of resource plans.
“- Congestion management systems will be required, although the form may be flexible.
“- Beneficiary pays policy will be included, but revised to reflect concerns about its application possibly undercutting new investments.
“- Strong incentives to encourage RTO participation, divestiture of transmission assets, and investments in the grid (as proposed by FERC in January 2003) will be included.
“- Liability limits will be added to SMD and probably will extend to gross negligence for assets turned over to RTO control.
“- Day ahead/real-time markets may not be required, but RTOs will be encouraged to gradually move toward this approach.
“- Many of the other details in the SMD intended to improve market efficiency will remain essentially intact.
Gaining perspective on transmission policy changes
Despite the focus on SMD since July 2002 and the associated controversy about certain elements of the proposed policy, it is valuable to step back and look at what is occurring across the country. Standardization of transmission markets is being implemented—with or without the SMD ruling. Some of the key efforts changing the face of the U.S. transmission industry include:
“- adoption of the majority of the Order 2000 requirements including RTO creation, scope, independent governance, planning protocols, market monitoring and more;
“- creating uniform interconnection rules for large and small generators;
“- voluntary adoption of many core SMD provisions (LMP, day-ahead/real-time markets/congestion management mechanisms) in much of the United States including PJM, NY-ISO, ISO-NE, MISO, CAISO, with others to follow;
“- development of large regional markets with efforts to reduce seams issues and other barriers to competition; and
“- creation of ITCs—seven are currently proposed or operating nationwide.
The combined impact of these measures will reshape transmission markets regardless of whether SMD is issued or not.
What’s the focus for 2003?
Although the key focus will be settling the details of SMD by the end of the year, several other issues also need attention. For the RTOs, many details need to be established simply to become fully operational. One key focus during the year will be setting up the details of expansion planning policies. This will have a major impact on not only what gets built but also who builds it. A variety of financial barriers to participation in RTOs and to investment in the grid also need to be addressed. Some may be handled by SMD or in separate FERC policies, such as addressing liability limits and developing the right financial incentives. Other financial barriers will need to be handled by Congress, such as changing the private use policy hampering participation by public utilities. Another important issue is changing the capital gains tax treatment so that utilities wishing to divest their transmission assets are not penalized. Such a legislative change would make it easier to create ITCs.
This year promises to put some of the last major policies in place for a transformed grid. The hope is that the result will facilitate wholesale market operation and encourage investments to resolve any potential grid problems. In light of the importance of these remaining details, it will be key to track their development carefully.
Robertson is a senior consultant for Cambridge Energy Research Associates (CERA), Cambridge, Mass. CERA services include an Electric Transmission Advisory Service that provides critical insights in the North American transmission business including ongoing analysis of RTO and standard market design developments. Contact Gil Rodgers, director, Transmission Advisory Service at 617-866-5910 or email@example.com for more information.