Transmission Issues For New Nuclear Generation

Gerald Garfield, Eric Runge and Lynn Fountain, Energy and Utility Department, Day Pitney

NEW NUCLEAR GENERATION RAISES OLD challenges and presents new challenges to developers and system planners and operators. Getting such generation interconnected to the grid and delivered to load will be among those challenges. More specifically, those challenges will include: whether the standardized generator interconnection rules will accommodate the length of time needed to build nuclear and put it in service; how the transmission network will be expanded to deliver remote generation to load, especially with rapidly increasing transmission needs of renewable generation to meet renewable portfolio standards (RPS); and how the costs of major transmission upgrades to support the interconnection and delivery of new nuclear generation will be allocated.

Generator Interconnections

Commencing in 2003, standardized generator interconnection rules were put in place by the Federal Energy Regulatory Commission (FERC). All FERC jurisdictional transmission providers were required to adopt these standardized procedures and agreements or justify any deviations from them. These standardized rules, as embodied in the Large Generator Interconnection Procedures (LGIP) and Large Generator Interconnection Agreement (LGIA), will require close coordination between nuclear developers and transmission providers, and close adherence to the project schedule and deadlines contained in the LGIP/LGIA. Under the LGIP, an interconnection customer must request an interconnection to be completed by an identified in-service date that, generally, can be no more than the seven years after an interconnection request absent demonstration that the engineering, permitting and construction will take longer than seven years. The LGIP further provides that the time between the interconnection request and the in-service date cannot exceed ten years absent agreement between the developer and the transmission provider. These time limitations will put added pressure on nuclear generation development, which could take in excess of ten years from interconnection request date to in-service date. Similarly, transmission planners will be under pressure both from nuclear project developers for reasonable extensions of time to complete the interconnection process, and from other developers with a lower queue position who want the slower moving nuclear projects to get out of the way.

Additionally, as more renewable generation is proposed, there is an increasing pressure to move projects through the interconnection queue faster even if that means moving others out of the way. At the FERC's December 11, 2007 technical conference on generator interconnection queue issues this point was made by several participants. Commissioners attending that conference seemed prepared to entertain specific transmission provider proposals to modify the interconnection process rules to allow for more rapid interconnection of renewable projects. Proposed changes to the interconnection queue rules may include milestone requirements or changes to the deadlines that currently exist in the pro forma rules. Development of nuclear projects takes significantly longer than other types of generation. Developers of such projects will need to participate in the creation of new queue rules to ensure that the changes accommodate the time required to build new nuclear generation.

Interconnection queue positioning will also present challenges for both developers and transmission providers. Large nuclear units in the queue would have a major impact on what studies get done, what transmission upgrades would be needed and the costs of those upgrades. If a nuclear project fails to meet the LGIP requirements during the interconnection process or proposes a material modification to the project, the project would lose its queue position. Loss of that queue position could profoundly impact other developers and the studies of those projects lower in the queue. That potential impact will increase not only generation development risk but transmission planning risk as well.

The costs of interconnecting new nuclear will be a challenge. The last round of nuclear generation was built by vertically integrated utilities whose customers paid such costs. Under the LGIA, a new nuclear plant developer would be required to pay initially for all interconnection costs. These costs are likely to be high both because of the substantial transmission capacity needed for new nuclear facilities (new facilities are expected to be 1000 MW or larger) and because many new nuclear plants are likely to be built in remote locations away from the load centers they will serve. The costs of such upgrades will comprise a significant component of the up-front development costs for a new nuclear plant. While under the pro forma LGIA, network upgrade costs may be recovered in the form of transmission service credits once the network upgrades are completed, they add to the development risks. Moreover, these general rules for crediting interconnection cost payments back to the generator do not always apply, particularly in ISO/RTO regions of the country. For example, in New England all costs of the generator interconnection are allocated to the generator without a provision for crediting back, but instead the generator receives rights associated with the financial transmission rights market.

The Need for New Transmission

Similar to much of the new renewable generation that is remote from load centers, new nuclear generation that is not built on existing sites will also need to be located away from the existing load centers it serves to be politically and socially acceptable. Although current applications for new nuclear generation are at existing nuclear sites, any new sites for nuclear are likely to be remote from load. Adequate high voltage transmission, often over substantial distances, will be essential to deliver this new nuclear generation to load. Building such transmission will present additional challenges that need to be considered and planned for by the generator when financing and constructing new nuclear generation. For instance, developers and transmission planners will have to determine what existing transmission facilities could be accessed by their proposed plants, and whether it makes sense to interconnect such plants directly to the AC network or build dedicated high voltage, direct current (HVDC) facilities that could bring nuclear power to load under long term contracts. If an HVDC technology is chosen as the appropriate transmission for a new nuclear facility, developers and transmission planners will have to determine which type of HVDC technology is best suited to deliver the output of the plant and integrate it with the rest of the bulk power system. Choice of HVDC technology could allow for more dedicated delivery of the plant to particular load centers but could also affect cost allocation decisions.

Even where new nuclear plants are built at existing sites, major new transmission may be needed not only to interconnect the new plant but to deliver its output. Thus, the new nuclear plants and the transmission upgrades needed for them will have to be part of the regional transmission planning process that is required of every jurisdictional transmission provider under FERC's Order No. 890. Through that process developers, transmission providers (including ISOs/RTOs), state entities, and all other interested stakeholders will have to work together to determine how the transmission needs of new nuclear generation will fit together with the rest of the region's needs, including access to renewable generation resources.

Transmission Cost Allocation

Beyond the costs of interconnecting new nuclear generation are the large costs of building new high voltage transmission to deliver the output of that generation to load, especially where the two are far apart. Some regions of the country have well developed costs allocation rules that allow for the socialization of such costs where a benefit to the entire region can be demonstrated, with bright-line voltage tests for determining such regional benefits. Other regions are in the process of developing transmission cost allocation rules, as required under the FERC's Order No. 890. Since the transmission cost allocation rules vary by region, a developer of new nuclear generation will need to be aware of the region's rules and how such rules might be evolving, and will need to determine how such rules impact the costs and financing of the project.

Even where costs of high voltage network transmission projects are socialized across a region, an attempt to socialize the costs of building a large transmission highway to a new nuclear power plant could face so much opposition that it would effectively make the project infeasible. As a practical matter development of new nuclear generation and the transmission to deliver its output may well require long-term financial commitments of load to purchase the output. Thus, a particular group of beneficiaries (load in high energy price load pockets in a larger region) could end up funding the development of the new transmission that will be needed for new nuclear in return for relatively low cost, stable energy pricing. This "back-to-the-future" scenario can already be seen developing in some retail access states that previously required divestiture of generation by electric utilities but that are now allowing or requiring those utilities to get back into long-term power supply procurement.

Several areas of the US, including Texas and California, are identifying and developing Competitive Renewable Energy Zones to better identify, limit and allocate the risks and challenges inherent in building new transmission in areas remote from the established load centers. Similar projects on a conceptual basis have been proposed to allow New England access to renewable and proposed new nuclear generation in the Maritime provinces of Canada. These conceptual projects include new HVDC facilities that would link Canada and New England. It is likely we will see a variety of regulatory constructs and cost allocation mechanisms for getting new transmission built to access remote generation, including new nuclear generation.

Impact on System Reserves

In the last nuclear generation construction cycle, the large nuclear units in many regions of the country became the single largest contingency and increased the size of required installed and operating reserve margins. The advent of new, large-scale nuclear facilities could again increase the size of the single largest contingency for a region, further increasing required installed and operating reserves margins and the costs of such reserves that must be allocated. The prospect of increased costs of reserves for a control area will further increase pressure on developers, transmission planners and operators to make the right decisions about new nuclear projects.

Conclusion

Aside from the challenges of siting, permitting, financing and constructing new nuclear generation, developers and transmission planners will be faced with additional difficult challenges. Those challenges include working with the standardized generator interconnection rules, developing the projects in the overall regional system planning process, choosing the right transmission technology, achieving a cost allocation for interconnection upgrades and network transmission that allows the project to be viable, and paying attention to the impact on system reserves that a new nuclear facility can create. Nuclear developers and transmission planners need to think through these issues and have a plan for how to address them in their particular regions so that the benefits of nuclear power to the nation's electricity system, and thereby to the nation's security, can be increased.