Interregional planning under FERC Order 1000
Johannes Pfeifenberger and Judy Chang are principals of The Brattle Group. Delphine Hou is a former Brattle associate. This article is based on work undertaken for the Southwest Power Pool’s Regional State Committee and the associated report, Seams Cost Allocation: A Flexible Framework to Support Interregional Transmission Planning, April 2012, available at www.spp.org and www.brattle.com. The authors acknowledge sole responsibility for the content of this article.
Now that the U.S. regional transmission planning groups have explained how they will comply with the region-internal transmission planning and cost allocation provision of the Federal Energy Regulatory Commission’s Order 1000, their focus has shifted to the order’s interregional requirements. This broader focus provides an opportunity to significantly improve transmission planning near and across regional boundaries, which up to now has lagged region-internal efforts. An effective framework for interregional planning and cost allocation will be flexible enough to accommodate the often significant differences across regions and types of transmission projects.
The current lack of clarity on joint planning and cost allocation for interregional projects has created what some have called a “demilitarized zone” or gap of transmission investments near or across market seams. Because there isn’t a single transmission planning entity that considers all benefits or knows how costs would be recovered from multiple regions, it’s important to clarify up-front in the planning process how neighboring regions will evaluate interregional transmission projects, consider all project-related benefits in the respective regions, and use such benefits to determine cost allocation.
These ideas weren’t lost on FERC when it issued new rules in July 2011. In fact, FERC Order 1000 explicitly recognizes that “the lack of coordinated transmission planning processes across the seams of neighboring transmission planning regions could be needlessly increasing costs for customers of transmission providers, which may result in rates that are unjust and unreasonable and unduly discriminatory or preferential.” In an attempt to avoid such an outcome, the order requires the development of interregional planning processes that identify the transmission needs across regions and a method to allocate costs associated with interregional solutions to meet those needs.
Interregional cost allocation is especially challenging given the barriers associated with the planning and analyses of interregional transmission projects. Planning-related challenges often start with limited staff resources to evaluate and consider interregional projects, which can be exacerbated by a lack of sufficiently detailed and current multi-region planning data and models to conduct joint system analyses. Uncertainty as to how or when a neighboring system will evaluate and consider interregional projects as part of its regular planning processes can cause significant delays in the development of interregional projects. Also a gap between bottom-up and top-down planning studies can lead to an inability to identify beneficial projects. Qualification criteria for an interregional project often are unclear. Transmission benefits and metrics often aren’t articulated with sufficient detail to allow for cost allocation based on clearly identifiable benefits to each entity. Moreover, individual interregional projects might offer a very different mix of benefits (e.g., reliability, market efficiency, and public policy benefits) to each of the neighboring regions and its transmission owners, which further complicates cost allocation efforts. Finally, the lack of sufficiently detailed, actionable, but flexible principles and guidelines creates yet another hurdle to interregional planning and cost allocation. This barrier is magnified if cost allocation isn’t aligned with ownership interests and the assignment of transmission rights.
Recognizing that interregional transmission planning has lagged region-internal planning efforts, market operators, transmission planners, and policy makers established various initiatives to address these barriers.
Framework for Success
Recent analysis performed for the Southwest Power Pool Regional State Committee—including a review of project case studies and various U.S. and European transmission planning and cost allocation efforts—showed that a successful interregional transmission planning process requires both a planning framework with clear objectives and criteria and a cost allocation methodology based on well-defined benefit metrics. Along with satisfying the requirements of FERC Order 1000, a successful interregional planning framework will need to:
- Define a clear cost allocation methodology that provides sufficient guidance for planners, regulators, and stakeholders to determine fair outcomes;
- Be flexible enough to be used by all neighboring regions, which can consist of both FERC jurisdictional and non-jurisdictional entities;
- Accommodate both bilateral and multilateral agreements between regional transmission operators to address multi-party seams;
- Be applicable to individual projects or groups of projects, identified either unilaterally or jointly by the regions; and
- Be robust enough to accommodate transmission projects that serve different purposes and offer different types of benefits to the different regions.
The analysis also identified seven building blocks that can support an effective interregional planning and cost allocation process (see Figure 1). Specifically, a successful interregional planning and cost allocation process will need to: 1) institute regular interregional planning meetings; 2) regularly exchange planning data and models; 3) define the processes under which interregional projects can be proposed and will be analyzed; 4) define a comprehensive but flexible set of project evaluation criteria and benefit metrics; 5) specify principles and guidelines on how these benefits and metrics will be used to derive interregional cost allocations; 6) specify the “payment mechanisms” that allow for the actual sharing of project investment costs or project revenue requirements across the regions’ boundaries; and 7) integrate interregional planning and cost allocation provisions into each region’s internal planning cost recovery processes.
While a number of these building blocks are already addressed in existing agreements between regions,they would benefit from better specification. For example, regular interregional planning meetings (Building Block No. 1) would benefit from direct participation by regulators from states affected by the seams between planning regions. Such involvement by state commissions in interregional planning meetings likely would facilitate the more-efficient development of interregional projects and the associated cost allocations, so that they are more easily acceptable to each of the states involved in the permitting and—where applicable—rate recovery of the selected projects.
Other improvements to existing processes include the development of jointly validated and endorsed load-flow cases and planning models for the combined footprint and planning horizon (Building Block No. 2). That would allow each region to accurately analyze the neighboring system to prepare credible initial evaluations of potential interregional projects. Finally, interregional planning and cost allocation will also need greater coordination with region-internal processes, including planning for generation interconnection and transmission service requests, which can affect the overall benefits of projects (Building Block No. 7). Each region also will need to ensure that the allocated costs of interregional projects can be recovered from transmission service customers within each region through its transmission tariff.
Proposing and Analyzing Projects
Building Block No. 3 specifies a process that would be used by all entities to propose and analyze interregional projects. While many interregional projects likely will be developed jointly, the planning process should allow the regions to propose seams projects unilaterally, subject to pre-specified requirements for supporting documentation and analysis.
For example, unilateral project proposals would include: a detailed description of each project; a qualitative discussion of its project’s purpose and benefits to both regions (which could differ on either side of the seam); a preliminary analyses (e.g., power flow studies) of the project’s benefits to both entities (documenting results, assumptions, and data consistent with the planning methods and metrics of each entity as specified in the agreement); and a proposed preliminary cost allocation consistent with specified cost allocation principles and benefits identified in screening analyses. Once these requirements are met, the two regions would be committed to jointly complete a full analysis of proposed projects.
With respect to the types of projects that should qualify for interregional cost allocation, the use of minimum thresholds such as voltage level, total cost, or total benefits is discouraged because even small projects might offer substantial benefits. The definition of an interregional project should also include projects that either cross the seam (as interregional projects are defined in Order 1000), or are located wholly within one region as long as the projects provide clear benefits to both regions. Phase angle regulators that manage power flows across regional boundaries are a good example of this second category.
A key function of any successful cost allocation framework is the articulation of seams project evaluation criteria and benefit metrics (Building Block No. 4). Benefits can include meeting policy goals, cost reductions, avoided costs, and achieving other system improvements and savings. The specified metrics are used to capture these benefits in either monetary or non-monetary terms.
In some cases, the respective regions reviewing an interregional project might already have agreed jointly to use criteria and benefit metrics for project evaluation that are common to both regions. However, such an approach tends to disadvantage interregional projects because the jointly agreed-upon criteria and metrics generally will tend to represent the least common denominator subset of the criteria and metrics used in the adjoining regions. To avoid such bias, each region at a minimum should evaluate its share of an interregional project’s benefits by including all types of benefits considered in its internal transmission planning efforts. In addition, each region also should have the option—but not the obligation—to consider some or all of the benefits and metrics used by the other region, even if these benefits and metrics aren’t currently used in its internal planning process. This way, benefits and metrics can cover comprehensively all reliability, operations, public policy, and economic benefits considered in both regions, even if these benefits aren’t defined and measured the same way across the regions.
Moreover, interregional planning processes should recognize that projects might offer unique benefits beyond those currently considered in either region’s internal transmission planning process, such as incremental wheeling revenues or benefits from increased reserve sharing capability. It should also be recognized that interregional projects might serve to avoid or delay the cost of other upgrades, such as projects already included in each region’s existing plans, or upgrades that might be needed in the future to meet local or regional needs, or to satisfy generation interconnection or transmission service requests.
Cost Allocation Principles
Cost allocation across regional boundaries, Building Block No. 5, is perhaps the number one hurdle for successful development of interregional projects. FERC Order 1000 provides a list of six cost allocation principles. The exploration of case studies and review cost allocation methodologies in different U.S. regions and Europe suggests these principles should be expanded. (See sidebar “Cost Allocation Principles: An Expanded List.”)
Several of the principles in the expanded list (Nos. 4, 5, and 7) go beyond the requirements of Order 1000. For example, principle No. 7 addresses the fairness concerns that arise when one region uses a more comprehensive definition of benefits than its neighbor does. The principle requires that benefits to each region be greater than its allocated costs, consistent with the region’s internal planning criteria. That will ensure a net gain in benefits for each region, such that the cost allocation outcomes in each region remain more attractive than either pursuing the project without cost sharing or not pursuing the project at all—and thus not realizing any of its benefits.
In addition to these principles, interregional planning and cost allocation agreements should also include cost allocation guidelines or illustrations of how benefit metrics would be applied accordingly. For example, the guidelines might specify that the costs of an interregional transmission project should be allocated based on the share of monetized benefits, in proportion to the present values of project benefits received by each entity. In the alternative, if the regions agree, then cost allocation for some seams projects can be based on more qualitative, non-monetized benefits and cost causation ratios, such as the following metrics:
- Need: Each region’s relative contribution to the need for the project. Examples of such allocations include applying load-ratio shares or shares of power flows that contribute to the need for a reliability-driven upgrade, or using the shares of the regions’ renewable requirements to allocate the costs of a renewables-integration driven project.
- Added Capability: Each region’s projected or allocated share of the project’s added transmission capability (e.g., allocated shares of increased flow-gate capacity).
- Physical Location: The project’s physical location within each region (e.g., shares of circuit miles or direct assignment of project segments).
Building Block No. 6 specifies the payment mechanisms to implement agreed-upon cost sharing between regions. These mechanisms can be based on either physical ownership or financial transfers. In other words, any entity sharing the cost of seams projects should, to the extent feasible and practical, also receive physical or financial rights for a commensurate share of the project’s added transmission capability (e.g., a share of increased flow gate capability).
Cost allocation through physical ownership can be implemented based on ownership of specific project segments or co-ownership of a project. In either case, the ownership shares would be assigned such that the respective shares of the investment and operating costs reflect the region’s benefits. The transmission owners within each region would then simply recover the cost of their portion of the seams project along with the cost of their region-internal transmission project. Such arrangements are used routinely for transmission cost allocation in the WECC.
Where ownership-based allocation of project costs is neither feasible nor practical, cost allocation can be implemented through financial transfers from one region to the other. These payments would reflect a share of the project’s revenue requirements and be recovered with the other revenue requirements of the region’s transmission owners.
To facilitate acceptance of such ownership shares or payments, they should be coupled with an assignment of physical or financial rights for a commensurate share of the project’s added transmission capability. Examples are rights to a share of added flowgate capacity or rights to the added transfer capability provided by a seams project. In market-based regions, such rights might involve auction revenue rights or capacity transfer rights, similar to the rights that RTOs already provide to the sponsors of “elected” or “participant funded” transmission upgrades. Without obtaining transmission rights, many non-RTO and non-jurisdictional entities might simply be unable to assume ownership obligations or make financial payments to the neighboring region.
Transmission planning processes that work well within regions haven’t proven very effective for interregional planning. A number of significant barriers still persist, and stem from the challenges of coordinating planning, differences in how regions consider projects and calculate benefits, and the lack of workable cost allocation principles, guidelines, and mechanisms.
Building on the experience to date, the proposed framework can help to address these barriers and yet retain the flexibility needed to accommodate the often significant differences between regions. Applying this framework to case studies of interregional projects in the work for the SPP RSC showed its effectiveness. With the industry now focused on compliance with FERC Order 1000, the framework can address the interregional gap that still impedes the transmission planning process.
1. FERC Order 1000, P 350.
2. Even before FERC issued its Order 1000, for example, SPP and the SPP RSC developed a draft whitepaper on seams cost allocation principles and have addressed interregional planning in joint operating agreements (JOA) with several seams neighbors. The authors’ work for the SPP RSC also documented the successes and limitations of similar planning and cost allocation efforts elsewhere, including: the seams cost allocation framework for reliability and market efficiency projects by MISO and PJM; the inter-area planning effort of NYISO and ISO New England; the interregional cost-allocation dispute over phase angle regulators in Michigan to address Lake Erie loop flows across MISO, PJM, NYISO and Ontario; the Northern Tier and ColumbiaGrid planning and cost allocation processes; the cost allocation principles developed by the Upper Midwest Transmission Development Initiative (UMTDI); the draft planning and cost allocation framework for public policy projects developed by the New England State Committee on Energy; and the European interregional transmission planning and inter-transmission system operators compensation (ITC) mechanisms. In addition, case studies of the planning and cost allocation efforts for several individual transmission projects identified both challenges encountered and lessons learned.
3. For example, Building Blocks Nos. 1, 2, and 7—shown as grey blocks in Figure 1—already exist in the joint operating agreements between SPP and its neighbors.
4. If the seams project is developed by a single corporate entity, the company could form a transmission-owning subsidiary in each of the neighboring regions, each of which would recover the costs associated with its ownership share of the interregional project through the respective entity’s existing regional or local cost recovery options.