Analysis of Order No. 1000 Transmission Planning and Cost Allocation

I.     TRANSMISSION PLANNING

A.    REGIONAL TRANSMISSION PLANNING PROCESS

1.     EXPANSION OF THE REGIONAL PLANNING PRINCIPLES

Order: The Commission is expanding the applicability of the regional planning principles that it adopted in Order No. 890. In Order No. 890, the Commission required public utility transmission providers to share system plans and identify system enhancements to relieve congestion or integrate new resources, and to respond to stakeholder requests for studies of potential upgrades, in order to confirm the simultaneous feasibility of transmission facilities proposed in local transmission plans. However, Order No. 890 did not require transmission providers to proactively identify potential regional solutions to meet the region's transmission needs or to evaluate potential regional upgrades in the absence of stakeholder requests. Order No. 1000 requires public utility transmission providers to evaluate, in consultation with stakeholders, alternative transmission solutions and non-transmission alternatives to determine whether they might meet the needs of the region more efficiently or cost effectively than solutions identified in local planning processes. If the regional process determines that an alternative transmission solution is more efficient or cost effective than the facilities identified in the local transmission plans, the facilities identified in the regional plan can be selected for regional cost allocation. (P 147-148.) The Commission requires public utility transmission providers to adopt the following Order No. 890 principles in the regional planning process: coordination, openness, transparency, information exchange, comparability, dispute resolution and economic planning.

Analysis: The Commission did not impose specific requirements concerning the way in which transmission providers must comply with the regional planning principles. However, following Order No. 890 the Commission issued a large number of orders requiring compliance filings with respect to regional planning. It is likely that the Commission will make similar careful analyses of transmission providers' compliance with Order No. 1000 and will impose detailed and specific requirements, to be implemented in a compliance filing, if it determines that a transmission provider has not adequately reflected the principles in its tariff.

2. CONSIDERATION OF NON-TRANSMISSION ALTERNATIVES

Order: Order No. 1000 requires consideration of non-transmission alternatives as part of the regional planning process. However, the order does not establish minimum requirements governing which non-transmission alternatives should be considered or the metrics to measure them against transmission alternatives. Nonetheless, since the procedures that transmission providers adopt for the consideration of non-transmission alternatives will be included in the regional plan, the Commission will evaluate them for compliance with the "comparability" principle. The order does not address cost allocation for non-transmission alternatives, which the Commission concluded is beyond the scope of the proceeding. (P 153-155.)

Analysis: The Commission has not previously addressed the issue of how to determine whether non-transmission alternatives are considered on a comparable basis with transmission alternatives. It seems likely that proponents of non-transmission alternatives will seek to have the Commission give more emphasis to their projects, both through rehearing requests and in protests to compliance filings. Therefore, this issue will be the focus of some controversy until the Commission has established principles in its orders on transmission providers' compliance filings.

3. APPLICABILITY TO NEW TRANSMISSION FACILITIES

Order: Order No. 1000 applies only to facilities that are subject to evaluation or re-evaluation in the local or regional planning process after the effective date of the transmission provider's compliance filing in response to the Order. Compliance filings must explain how transmission providers will determine which facilities are subject to the Order. (P 63.)

4. MERCHANT TRANSMISSION PROJECTS

Order: Merchant transmission project developers need not participate in the regional planning process for purposes of determining the allocation of transmission costs. However, they must provide information to allow the public utility transmission providers in the region to assess the potential reliability and operational impacts of the proposed transmission facilities on other systems in the region. The Commission also noted that merchant transmission providers are responsible for the cost of network upgrades that are caused by the interconnection of their projects with the grid. (P 163-165.)

Analysis: The Commission has attempted to address concerns expressed in comments on the NOPR that merchant projects could adversely affect the cost and reliability of service on incumbents' transmission systems. However, it is not clear that by simply requiring the merchant transmission developer to provide information, but not participate in the regional planning process, the Commission has gone far enough to address those concerns. If merchant projects have no responsibility to participate in and be bound by regional planning, they could "cherry pick" transmission projects (including projects that are proposed by other transmission providers in the regional planning process) or propose projects that could adversely affect projects that are being considered in the regional planning process. The Commission's statement that merchant transmission providers are responsible for upgrades on the existing system that are necessitated by their projects in all likelihood does not provide sufficient protection for incumbent transmission providers. If transmission providers seek rehearing on this issue, they should include in their pleadings specific explanations of how merchant projects could adversely affect the system. They also should point out that despite the language in Order No. 1000, the Commission has never previously required a transmission provider to compensate another transmission provider for upgrades caused by the first transmission provider's impacts on another system. Transmission providers should consider asking the Commission to require merchant developers to participate in all aspects of the planning process other than the cost allocation process and establish clear principles for the allocation of costs of upgrades to merchant transmission developers who do not include their projects in the regional planning process.

5. PUBLIC POLICY REQUIREMENTS

Order: The Commission requires public utility transmission providers to amend their OATTs to describe procedures that provide for the consideration of transmission needs driven by Public Policy Requirements in local and regional transmission planning. Public Policy Requirements are those that are driven by federal and state laws and regulations. The Commission declined to broaden the scope of the requirement or to specify any public policy objectives or principles. (P 214.) Stakeholders must be given an opportunity to provide input on what they believe are the transmission needs that are driven by the Public Policy Requirements. (P 203.) This requirement consists of two obligations: (i) to identify, in consultation with stakeholders, transmission needs driven by Public Policy Requirements; and (ii) to evaluate potential solutions to meet those needs. Transmission providers must establish procedures under which the transmission needs will be identified and evaluated, and must post on their websites an explanation of which transmission needs will be evaluated and why other suggested transmission needs will not be evaluated. However, a failure to comply with a Public Policy Requirement does not constitute a violation of the OATT.

Analysis: It appears that the Commission has taken a reasonable "middle ground" approach to the Public Policy Requirement issue, which has proven to be fairly controversial. It has avoided creating an open-ended definition of Public Policy Requirements that could have resulted in endless debate and likely litigation. On the other hand, it has required transmission providers to proactively consider Public Policy Requirements rather than allowing them to continue simply responding to specific requests for transmission service, which can result in an ad hoc and uncoordinated response to the changes in the need for transmission facilities.

B. NONINCUMBENT TRANSMISSION PROVIDERS

1. ELIMINATION OF THE RIGHT OF FIRST REFUSAL FOR REGIONAL PROJECTS

Order: The Commission requires the removal from FERC-jurisdictional tariffs and agreements provisions that grant incumbent transmission providers a federal right of first refusal ("ROFR") to construct transmission facilities that are selected in a regional transmission plan for purposes of cost allocation. (p 253.) The requirement does not apply to local transmission facilities, which are facilities that are located solely within a transmission provider's retail service territory or footprint, and that are not selected for regional cost allocation. (P 258.) The Commission states that it is taking this step because it is "concerned that the existence of federal rights of first refusal may be leading to rates for jurisdictional transmission service that are unjust and unreasonable" because incumbents might favor their own projects over proposals by new entrants that may be more efficient or cost-effective. (P 256.)

The Commission rejected the principal objections to elimination of the ROFR. It held that the incumbent's obligation to build to serve the needs of its customers does not depend on the right to prevent other entities from building transmission facilities. It also held that the incumbent transmission provider's obligation to meet reliability standards does not justify retention of the right of first refusal, but it addressed this concern by requiring transmission providers to specify how they will re-evaluate the regional plan if development of a transmission facility that is selected in a regional plan for purposes of cost allocation is delayed. (P 264.)

The Commission stated that it has the authority to require the removal of provisions that grant a federal ROFR to incumbent transmission providers under the broad remedial provisions of Section 206 of the Federal Power Act. (P 284.) The Commission noted that elimination of the federal ROFR does not regulate state-jurisdictional matters such as transmission construction, ownership or siting, and it acknowledged that other laws or regulations may restrict construction by nonincumbents.

Analysis: The Commission has the authority to require the elimination of the ROFR from FERC-filed tariffs and agreements. The Commission has not adopted other aspects of the ROFR proposal that were contained in the NOPR and that appeared to be outside the scope of its jurisdiction. Those issues are discussed below.

2. RETENTION OF LIMITED RIGHT OF FIRST REFUSAL

Order: The Commission stated that it has modified the provision that it had proposed in the NOPR to address concerns that allowing nonincumbents to construct facilities would change the transmission planning process from a collaborative one into a competitive, sponsorship-driven one. First, as noted above, the Commission has limited the requirement to remove federal ROFRs so that it applies only to facilities that are selected in the regional plan for purposes of cost allocation. Therefore, local transmission facilities and other facilities that are not selected for regional cost allocation may still be subject to a ROFR in FERC-filed tariffs and rate schedules. (P 318.) Second, the federal ROFRs can continue to apply to upgrades to the incumbent's own transmission facilities. Third, the requirement does not alter the incumbent's right to use and control its existing rights of way, which will continue to be governed by existing laws and regulations. (P 319.) The Commission also did not mandate a competitive bidding process for selecting project developers. (P 321.)

Analysis: The Commission has jurisdiction to require the elimination of ROFRs from FERC-filed tariffs and agreements that address local transmission facilities. However, it chose not to exercise that jurisdiction in this proceeding. While the Commission did not provide a detailed explanation of its decision, it is likely that it considered extending the elimination of the ROFR with respect to local facilities to be outside the scope of the proceeding, which addresses regional transmission facilities, and also was concerned that there was no record to support the elimination of the ROFR with respect to local facilities. The Commission's decision to not require the elimination of ROFRs for existing transmission facilities was a practical one: it is at best inefficient and could be inconsistent with reliability to have two or more entities constructing and owning portions of the same transmission facility. Finally, the decision to not require competitive bidding for the selection of project developers defers to the regional planning process with respect to the basis on which project developers will be chosen. While that decision may not eliminate controversy, it will at least defer it until a specific project is at issue and the regional planning entity's decisions on who should construct the project can be analyzed.

3. COMPLIANCE OBLIGATIONS

Order: The Commission imposed the following requirements with respect to nonincumbent rights to construct transmission facilities that are selected in a regional plan for purposes of cost allocation:

i. Transmission providers must revise their OATTs to demonstrate that the regional planning process has established appropriate qualification criteria for determining an entity's eligibility to propose a project for selection in the regional plan for purposes of cost allocation. The Commission allows each region to develop its own qualification criteria, rather than imposing one-size-fits-all criteria. (P 324.)

ii. Transmission providers must revise their OATTs to identify the information that must be submitted by a prospective transmission developer in support of a project that it proposes in the regional planning process and the date by which it must be submitted for consideration in a transmission planning cycle. All transmission providers in a region must have the same information requirements. (P 325.)

iii. Transmission providers must revise their OATTs to describe a transparent and not unduly discriminatory process for evaluating whether to select a proposed transmission facility in a regional plan for purposes of cost allocation; and to describe the processes for re-evaluation in the event that delays in the development of a selected transmission facility affect their ability to meet their reliability needs or service obligations. (P 328-329.)

iv. Nonincumbent transmission developers' projects must have the same eligibility for regional cost allocation as incumbents. (P 335.)

Analysis: The Commission's compliance obligations are consistent with its intention to eliminate ROFRs for regional projects that are selected for regional cost allocation, and do not overreach.

4. NONINCUMBENTS' RIGHTS

Order: The Commission decided not to require transmission providers to revise their OATTs to provide for the right of nonincumbents to own and construct a transmission facility. The Commission also decided not to allow transmission developers to retain the right to build and own projects that they have proposed but that are not selected. (P 338.) While the Commission acknowledged that not granting that right imposes some risk for transmission developers' who disclose information about their projects, but it concluded that the negative impact that such a provision could have on regional planning would outweigh any benefits of such a provision.

Analysis: The Commission's decisions on these two issues reasonably retreated from the NOPR provisions, which were likely beyond the scope of its jurisdiction. While the Commission has the authority to require the elimination of ROFRs from FERC-filed tariffs and agreements, the Commission has no authority with respect to the permitting, siting or construction of transmission facilities. Therefore, the NOPR provisions for transmission developers to have the right to own and construct transmission facilities that they propose, and to retain that right for projects that are not initially selected, were vulnerable to attack on the ground that the Commission did not have the authority to impose those requirements.

5. RELIABILITY COMPLIANCE OBLIGATIONS

Order: The Commission stated that the construction of transmission facilities by nonincumbents does not itself create reliability concerns. It also noted that when a nonincumbent becomes a transmission provider or operator, it will be subject to NERC reliability standards. However, if a nonincumbent abandons a transmission project that is needed for reliability purposes, the incumbent transmission provider will not be subject to enforcement action if it identifies the reliability standard that will be violated and submits a mitigation plan to NERC. (P 342-344.)

Analysis: Evidently, the Commissioners did not agree on this issue. Commissioner Moeller evidently believes that a transmission provider should be able to retain a ROFR for projects that affect the reliability of its own system. His statement on the order hints that this is the case.

C. INTERREGIONAL COORDINATION

1. SCOPE OF THE INTERREGIONAL PLANNING OBLIGATION

Order: The Commission requires each public utility transmission provider, through its regional planning process, to establish formal procedures with each of its neighboring planning regions within its interconnection to coordinate and share the results of the regional plans to identify possible interregional transmission facilities that could address transmission needs more efficiently or cost-effectively than separate regional transmission facilities. The procedures should provide for the sharing of information and the identification and joint evaluation of interregional facilities. (P 396, 415, 435.)

A developer of an interregional project must first propose its project in the regional planning process of each region in which it is to be located. That proposal will trigger the joint evaluation, which must take place in the same general timeframe as the intra-regional planning. (P 436.) Each region must develop procedures that will identify and resolve differences between regions in data, models, assumptions and criteria that could interfere with meaningful joint study of a project.

The Commission declined to impose more specific obligations with respect to regional planning such as specific planning horizons or scenario analyses or a distinct interregional planning process. The Commission also declined to require the interregional evaluation of the effects of a new facility that is located in only one planning region on other planning regions because it did not want to mandate interconnection-wide planning. However, it stated that it believes that the exchange of data will assist planners in understanding the interregional impacts of facilities that are located in only one region. (P 416.)

The Commission did not permit the costs of an interregional project that are incurred in one region to be involuntarily imposed on another region. To be eligible for interregional cost allocation, an interregional facility must be selected in the regional plan for purposes of cost allocation in each region in which it is proposed to be located. (P 442-444.)

Analysis: The Commission appears to have taken a middle ground on the issue of interregional planning and cost allocation. It adopted interregional planning principles, but stated that it does not want to be too prescriptive with respect to interregional planning because it might inadvertently impose restrictions that are not appropriate for a particular region. The Commission's statement is reminiscent of the early stages of open access transmission, when it stated that it was open to alternative ways of providing open access transmission service. After a year or so of allowing alternatives to develop, the Commission tightened the rules by establishing a pro forma tariff in Order No. 888. It is too early to state whether the Commission will follow the same approach with respect to interregional planning, but it is likely that it will provide more guidance and decrease flexibility when it evaluates transmission providers' compliance filings.

The Commission's decision to not require interregional cost allocation unless each region where a project is located selects the project for regional cost allocation also takes a middle ground. However, its decision is likely to create controversy in the future as projects that are intended to transmit renewable energy to distant load centers enter the planning stage. Regions where the renewable resources are located will continue to be reluctant to select for regional cost allocation transmission projects that wheel renewable energy out of their regions unless the receiving regions agree in advance to pay cost of those projects. It is not at all clear that a voluntary process will lead to the construction of all needed interregional facilities.

2. DATA EXCHANGE

Order: Public utility transmission providers must exchange planning data and information interregionally at least once a year. (P 454.) However, the Commission did not dictate the specific procedures or the level of detail required.

Analysis: This provision is consistent with the rest of the order, which establishes processes but is not prescriptive with respect to the details of those processes.

3. TRANSPARENCY

Order: Public utility transmission providers must maintain websites or e-mail lists for the communication of information related to interregional coordination procedures. (P 458.)

4. STAKEHOLDER PARTICIPATION

Order: The Commission declined to require a formal stakeholder process for interregional coordination, stating that stakeholder participation in each region's process provides an adequate opportunity for stakeholder input. However, stakeholders must have the opportunity to provide input into the development of the interregional transmission coordination procedures. (P 465, 466.)

5. TARIFF PROVISIONS AND AGREEMENTS

Order: The Commission did not adopt the proposal in its NOPR to require that coordination between regions be reflected in agreements that are filed with the Commission. Instead, public utility transmission providers must develop the same language, to be included in each OATT, which describes the interregional coordination procedures. The Commission concluded that including the language in OATTs would accomplish the same objective and could facilitate participation by non-public utility transmission providers. (P 475-476.)

II. COST ALLOCATION

A. NEED FOR REFORM

Order: The Commission concluded that the absence of clear procedures for cost allocation is interfering with efficient and cost-effective transmission planning because transmission providers and customers will not support new transmission construction unless they know how the costs will be allocated. (P 495.) The Commission stated that Order No. 890 is no longer adequate to ensure just and reasonable rates. It also noted that it had approved participant funding for several transmission providers under Order No. 890. Although it did not at that point state that participant funding is no longer acceptable, it discussed the need to align the benefits of new transmission facilities with the allocation of the costs of those facilities. (P 496, 499.)

Analysis: The Commission is sending a clear signal that participant funding will not be an acceptable method of cost allocation in the future. It will expect transmission planners to identify the beneficiaries of projects and allocate costs in rough proportion to those benefits.

B. LEGAL AUTHORITY FOR REFORM OF COST ALLOCATION

Order: The Commission rejected challenges to its authority to order reforms of cost allocation for transmission facilities. It stated that challenges on the ground that the Commission only has the authority to approve changes in rates by a public utility to its customers with which it has a contractual relationship are not consistent with the Federal Power Act, which contains no such restriction. The Commission also reiterated the concern it expressed in Order No. 890 with respect to "free ridership" on transmission facilities, and stated that the cost causation principle on which much of its ratemaking is based requires allocation of costs of regional transmission facilities on a regional basis. (P 530-535.)

Analysis: It seems likely that the issue of the Commission's authority to order regional cost allocation will be appealed to the Court of Appeals. However, it also seems likely that those appeals will not be successful since the court is likely to be persuaded of the need to interpret the Federal Power Act broadly to address the regionalization of the grid.

C. PRINCIPLES FOR REGIONAL AND INTERREGIONAL COST ALLOCATION

1. COSTS MUST BE ALLOCATED IN A WAY THAT IS ROUGHLY COMMENSURATE WITH BENEFITS.

Order: The Commission stated that in determining the beneficiaries of regional and interregional projects, the planning process may consider factors including but not limited to reliability, reserve sharing, production cost savings, congestion relief and/or meeting Public Policy requirements. (P 622.) The Commission declined to prescribe a particular definition of benefits or beneficiaries, stating that those issues would be evaluated in compliance filings. However, it stated that cost causation is the foundation of an acceptable cost allocation method. (P 626.) It also declined to permit costs of a facility that is located entirely in one region to be involuntarily allocated to another region. (P 628.)

Analysis: The principle is consistent with the prior decisions of the Commission and the courts, including the decision in Illinois Commerce Commission v. FERC, 576 F.3d 470, which remanded a regional cost allocation decision to the Commission for further proceedings on the ground that the Commission had not adequately addressed the issue of whether the allocation of Midwest ISO transmission costs was roughly commensurate with benefits.

2. ENTITIES THAT RECEIVE NO BENEFIT FROM TRANSMISSION FACILITIES IN THE PRESENT OR FUTURE SHOULD NOT INVOLUNTARILY BE ALLOCATED THE FACILITIES' COSTS.

Order: The Commission concluded that this principle is consistent with the principle of cost causation. However, it also noted that every cost allocation method should allocate all of a project's costs, in order to prevent stranded costs. (P 640.) The Commission also clarified that the cost allocation principles could be applied either on a project-by-project basis or in the aggregate.

Analysis: The Commission's decision to allow cost allocation based on aggregate benefits of a group of projects is consistent with its decision with respect to Multi-Value Projects in Midwest ISO, which has been challenged on the ground that it does not adequately align costs and benefits. The Commission approved Midwest ISO's treatment of a group of facilities as multi-value projects, despite objections that some of the facilities provided only local benefits, on the ground that the group of projects as a whole provided regional benefits. The Commission may not be able to sustain that position on appeal. The Commission is on much safer ground if it requires each project to demonstrate regional benefits before aggregating those projects for purposes of benefit analysis and cost allocation.

3. A BENEFIT TO COST THRESHOLD FOR EVALUATION OF PROJECTS MUST NOT BE SO HIGH AS TO EXCLUDE FACILITIES WITH SIGNIFICANT NET BENEFITS FROM COST ALLOCATION. THE RATIO MUST NOT EXCEED 1.25 TO 1 WITHOUT FERC APPROVAL.

Order: The Commission clarified that it does not require the use of a benefit to cost ratio threshold. However, if one is used, it cannot be so high that it blocks inclusion of many worthwhile transmission projects. (P 647.)

Analysis: The Commission's establishment of a threshold net benefit ratio is within the scope of the Commission's discretion.

4. THE ALLOCATION METHOD MUST ALLOCATE COSTS SOLELY WITHIN THE REGION UNLESS ANOTHER ENTITY OR REGION AGREES TO ASSUME A PORTION OF THE COSTS.

Order: The Commission also requires that the planning process must identify consequences of a project for other regions, including upgrades that may be required. (P 657.) The Commission noted that while costs may not be allocated involuntarily, transmission providers may voluntarily agree to accept an allocation of costs of a project in another region. The Commission held that allowing involuntary allocations between regions would place too high a burden on stakeholders to monitor transmission planning processes in other regions.

Analysis: The Commission's refusal to allow involuntary allocation of costs among regions is consistent with the rest of the order, which establishes processes but is not overly prescriptive.

5. COST ALLOCATION METHODS AND DATA REQUIREMENTS MUST BE TRANSPARENT AND PROVIDE ADEQUATE DOCUMENTATION.

Order: The Commission concluded that transparency ensures that allocations are just and reasonable and not unduly discriminatory. It acknowledged the difficulty of developing pragmatic, accurate and unbiased methods of determining benefits and beneficiaries and concluded that transparency will help to achieve those objectives. (P 671.)

Analysis: This principle seems to be entirely unobjectionable.

6. REGIONS MAY CHOOSE DIFFERENT COST ALLOCATION METHODS FOR DIFFERENT TYPES OF FACILITIES.

Order: The Commission held that regions may choose different cost allocation methods for different types of facilities, such as facilities needed for reliability or congestion relief or to achieve Public Policy Requirements. (P 685.) However, the regions are not required to do so. The Commission noted that the states should have a particularly important role in the determination of how to allocate the costs of facilities that are intended to address Public Policy Requirements and encouraged them to participate actively in this issue.

Analysis: This provision also seems unobjectionable.

D. APPLICATION OF THE COST ALLOCATION PRINCIPLES

1. EXTRA HIGH VOLTAGE FACILITIES

Order: The Commission did not adopt a rebuttable presumption that extra-high voltage facilities should be allocated across a region, stating that doing so would be inconsistent with its objective of permitting regional flexibility. However, it stated that if a region reaches a consensus on that issue and extra-high voltage costs and benefits are roughly commensurate, it should submit the proposal to the Commission. (P 714.)

Analysis: The Commission undoubtedly was concerned that if it adopted a rebuttable presumption of regional benefit, it would not be able to meet the Court of Appeals' requirement in Illinois Commerce Commission (cited above), that costs be roughly commensurate with benefits. The far safer approach is to allow the regions to develop their own criteria for regional cost allocation and seek to demonstrate that they meet the "commensurate with benefits" test.

2. PARTICIPANT FUNDING

Order: The Commission does not permit participant funding as a regional or interregional cost allocation method. It concluded that permitting participant funding increases the likelihood that some potential beneficiaries will defer investment in the hope that others will value a project more and fund it. The Commission disagreed that prohibiting participant funding is inconsistent with cost causation, stating that cost causation principles do not foreclose transmission developers from voluntarily assuming the costs of new facilities. (P 724.) The Commission also noted that if a project is not selected for regional cost allocation, the developer could proceed on a "participant funding" basis.

Analysis: The Commission's decision will undoubtedly be strongly opposed, particularly in the Southeast. However, the decision seems reasonable and consistent with cost causation principles.

3. DIFFERENCES BETWEEN REGIONAL AND INTERREGIONAL COST ALLOCATION METHODS

Order: The Commission concluded that interregional cost allocation methods for two adjacent planning regions may differ from their regional cost allocation methods. The Commission noted that while a region may share the costs of regional facilities broadly it might be inappropriate to do so for interregional facilities that benefit only part of its region. (P 734.)

E. OTHER COST ALLOCATION MATTERS

Order: The Commission declined to reform generator interconnection procedures and cost allocation processes on the ground that those issues are outside the scope of the rulemaking. (P 760.) The Commission also refused to make new findings with respect to pancaked rates (P 764), transmission incentives (P 771), variable energy resources (P 774), joint ownership (P 776) or non-transmission alternatives (P 779).

III. COMPLIANCE AND RECIPROCITY REQUIREMENTS

A. COMPLIANCE

Order: The Commission extended the six-month compliance period that it had proposed in the NOPR to 18 months for interregional transmission coordination and cost allocation, and to 12 months for all other requirements. (P 792.) Transmission providers that believe that their existing OATTs comply with the order must make filings explaining how they do so.

Analysis: As was the case with respect to Order No. 890 compliance filings, it is likely that the Commission will carefully scrutinize the compliance filings and require most utilities to make additional filings to address the Commission's concerns. The broad flexibility that the Commission is offering in the order is likely to be significantly narrowed in the compliance phase, as the Commission gets a better sense of how transmission providers will implement the rule.

B. RECIPROCITY

Order: The Commission stated that to maintain a safe harbor tariff, a non-public utility must ensure that its tariff confirms to or is superior to the pro forma OATT as modified by Order No. 1000. It stated that it does not believe that it is necessary at this time to invoke its Section 211A authority, but that it could do so on a case-by-case basis. The Commission stated that it is up to each non-public utility to determine whether it wants to maintain its safe harbor status by adopting the Order No. 1000 requirements, and that it is not modifying the scope of the reciprocity provision. (P 815-816.) However, the Commission stated that under the reciprocity provision, if a public utility transmission provider seeks transmission service from a non-public utility transmission provider to which it provides service, the non-public utility provider must provide comparable service that it is capable of providing, and therefore must satisfy the reciprocity condition. (P 819.)

Analysis: At P 819, the Commission misstated the reciprocity provision. Under the reciprocity provision, a public utility transmission provider may elect to not provide transmission service to a non-public utility transmission provider if the non-public utility transmission provider does not agree to provide comparable service that it is capable of providing. However, the non-public utility transmission provider is not obligated to provide that service, and the public utility transmission provider is not obligated to refuse to provide service if the non-public utility transmission provider does not provide comparable service. APPA and NRECA have already raised this issue with the Commission Staff during the Staff briefings, and Staff has stated that it would clarify this issue on rehearing.

Despite the Commission's discussion of Section 211A, it seems unlikely that the Commission could require a non-public utility transmission provider to accept an allocation of regional transmission costs if it does not participate in the regional planning process. This is because Section 211A only permits the Commission to require unregulated transmitting utilities to provide to others service that is comparable to the service they provide to themselves, and Order No. 1000 goes well beyond that limited requirement.

Nonetheless, non-public utility transmission providers should recognize that Order No. 1000 represents the latest in a 15-year process of incremental increases in Commission control over the transmission service that they provide. As regional transmission planning takes on greater importance, non-public utility transmission providers will have to choose to become involved in that process or run the risk that new, regional transmission facilities will bypass them and that public utilities will be less likely to coordinate to accommodate necessary upgrades on the non-public utility systems. In addition, while non-public utility transmission providers can request transmission service from public utility transmission providers who participate in regional planning without themselves participating and receiving a direct allocation of transmission costs, the charges that they pay for transmission service will reflect the regional allocation of costs to the public utility transmission providers. Consequently, non-public transmission providers will at minimum participate indirectly in regional cost allocation in their capacity as transmission customers of public utility transmission providers. As a result, it may be to their advantage to participate in the regional cost allocation process in order to protect their interests, even though that may result in increased allocation of regional transmission costs.

To access a full copy of Order No. 1000 on the FERC website, please click here.

For more information, please contact Tom Blackburn at This e-mail address is being protected from spambots. You need JavaScript enabled to view it or 202-296-1500