Compliance filings to implement the regional planning and cost allocation provisions of Order No. 10001 have been submitted to the Federal Energy Regulatory Commission ("FERC" or the "Commission") since October. These filings, FERC's review of them, and their implementation will reveal more fully the implications of Order No. 1000, including the expansion of the nation's transmission network and related cost responsibilities. This article briefly summarizes why industry stakeholders should be interested in the implementation of Order No. 1000 and what stakeholders can do to protect their interests.
I. Commission Developments to Date
On July 21, 2011, the Commission issued Order No. 1000, amending the transmission planning and cost allocation requirements established in Order No. 890. Those amendments required public utility transmission providers to revise their tariffs to reflect regional and interregional transmission planning and cost allocation. FERC also stated that Public Policy Requirements must be considered as part of regional and local transmission plans. Public Policy Requirements include – Order No. 1000 also required removal of the right of first refusal ("ROFR") to construct new transmission facilities selected in a regional transmission plan for purposes of cost allocation from Commission jurisdictional tariffs and agreements. (For more discussion of Order No. 1000, please see the Paul Hastings client alert dated August 2011 that discusses Order No. 1000 in greater detail.)2
On May 17, 2012, the Commission issued Order No. 1000-A, affirming Order No. 1000 and granting certain clarifications. On October 18, 2012, the Commission issued Order No. 1000-B granting certain further clarifications and affirming Order No. 1000.3 Compliance filings including regional transmission plans and cost allocation methods were due from public utility transmission providers by October 11, 2012, although several entities sought and obtained extensions of that deadline. Interregional transmission coordination plans and cost allocation methods are due by April 11, 2013.4 Comments are due on some of the initial Order No. 1000 Compliance Filings as early as November 26 (for those filings submitted on October 11) and December 10 (for filings submitted October 25).
As Order No. 1000 set forth principles for transmission planning and cost allocation, rather than mandate specific methods, the submitted compliance filings and their implementation will reveal the practical implications of Order No. 1000. These practical implications include how entities outside of regional transmission organizations ("RTOs") and independent system operators ("ISOs"), RTOs/ISOs, non-public utilities, and merchants will participate in Order No. 1000 processes, how to propose projects for inclusion in regional plans, cost allocation, and the stakeholder/enrollee distinction.
II. Compliance In Regions Outside of RTOs/ISOs
Order No. 1000 required public utility transmission providers in non-RTO regions to reach agreement on transmission planning and cost allocation.5 Such transmission providers may be working with several transmission planning entities and owners, within an area encompassing a number of different states, in order to reach a single greatly expanded regional planning process. Some such non-RTO regions may also include non-public utility transmission providers, ("NTPs").
Entities outside of non-RTO regions face unique challenges in implementing Order No. 1000. As one such example, the Mid-Continent Area Power Pool ("MAPP") needed to cooperate with its members (all non-public utilities – with the exception of NorthWestern Corporation, or "NorthWestern") to address Order No. 1000 compliance. In NorthWestern's Order No. 1000 Compliance Filing, NorthWestern stated that it understood that most, if not all, of the other MAPP members would not be making Order No. 1000 compliance filings at this time because of their NTP status.6
Further, as illustrated by NorthWestern, the MAPP region includes states that also fall within the Western Electricity Coordinating Council and MISO regions, including Iowa, North Dakota, South Dakota, Minnesota, and Nebraska. This may prove significant as MAPP completes its compliance filing to meet the Commission's interregional planning and cost allocation reform.
III. Round Up - Initial Order No. 1000 Compliance Filings In Regions With RTOs/ISOs
A very brief overview of the compliance filings by RTOs and ISOs is included below. For greater detail, please review the compliance filings made by these entities. Also, note that the Southwestern Power Pool, Inc. ("SPP") obtained an extension until November 12 for its Order No. 1000 compliance filing.7
As illustrated below, a number of these filings assert that much of the RTO's and ISO's existing tariffs meet Order No. 1000's requirements. They also introduce various updated approaches to cost allocation and planning, as well as ROFR reform. Changes to the cost allocation included in several Order No. 1000 compliance filings must also be closely reviewed. Once accepted by the Commission, those cost allocation rules will apply to that transmission provider's transmission planning and cost allocation process. As a result, if an entity later objects to the cost allocation methodology that has been approved as part of the Order No. 1000 compliance process, then it is up to that entity to file a Section 206 complaint with FERC to demonstrate why the methodology is unjust and unreasonable. This may be difficult, because the presumption is that the methodology is just and reasonable based on the Commission's previous acceptance of the methodology.
In addition, certain RTOs and ISOs have argued in their filings that Mobile-Sierra8protects them from making certain revisions to their transmission owner agreements.
A. PJM
The first Order No. 1000 compliance filing for PJM included the filing by PJM's Transmission Owners ("TOs") in Docket No. ER13-90-000 on October 11, 2012. Soon after, on October 25, 2012, PJM's separate Order No. 1000 compliance filing followed in Docket No. ER13-198, adopting and building on the revisions by the PJM TOs. PJM provides that the revisions it has proposed together with the PJM TOs reflect a compromise to resolve the cost allocation issues in dispute since 2007, including those reviewed in Illinois Commerce Comm'n v. FERC, 576 F.3d 470 (7th Cir. 2009). PJM's filing also reflects fundamental changes to its transmission planning and cost allocation process.9
PJM has revised its cost allocation for Regional and Necessary Lower Voltage facilities subject to regional cost allocation, by introducing a 50% postage stamp and 50% use-based allocation method. In addition, PJM's revisions would make double-circuit 345 kV projects, as well as those 500 kV and above, eligible for inclusion as part of the regional transmission planning process. Further, PJM has introduced a process for competitive solicitation. There would be three categories of projects in this competitive solicitation process: Long Lead Projects (which would be in-service within five years); Short-Term Projects (which would be in-service within three to five years); and Immediate Need Projects (which would be in-service within three years). Entities selected to build and finance the project would be characterized as "Designated Entities" under PJM's proposal.10 The PJM Designated Entity process appears separate from PJM's enrollment process, which requires membership status, as discussed below. Also, PJM's exceptions to elimination of ROFR would be time-based rather than what PJM characterized as the "solution based" exceptions of Order No. 1000 (although PJM argues this results in negligible difference).
Under PJM's proposed revisions, its ROFR would continue to apply where PJM determines that there is not enough time to go through the competitive solicitation process (so that ROFR could not apply to Long-Lead Projects). The PJM TOs note, however, that Mobile-Sierra protects the PJM TO ROFR.11 PJM also introduced qualification criteria for a project's eligibility in the regional plan. Finally, PJM added a state agreement process which provides that states may propose projects to address Public Policy Requirements12 and voluntarily agree to responsibility for the project costs.
B. CAISO
CAISO submitted its compliance filing on Order No. 1000's local and regional planning and cost allocation requirements in Docket No. ER13-103-000.13 CAISO argued that much of the changes required under Order No. 1000 were submitted two years ago when it substantially reformed its planning process and added consideration of Public Policy Requirements to its review process. CAISO noted that it uses a competitive solicitation process in its transmission planning. CAISO stated that its, "tariff allocates the cost of high voltage transmission upgrades included in the transmission plan, which benefit the entire ISO region, to customers throughout the region; whereas, the costs of low voltage facilities, which provide primarily local benefits, are allocated to the participating transmission owner that builds them and then recovers the costs through its transmission owner tariff from its customers that use them."14
CAISO explained that its Order No. 1000 compliance filing expands on its recent revisions to its tariff. Those changes include elimination of the ROFR for incumbent transmission owners ("TOs") to build and own new transmission facilities with costs allocated regionally. CAISO proposed clarifying tariff revisions that participating TOs retain an ROFR to build and own local transmission facilities (under 200 kV) located within the existing retail service territory or footprint of the TO. CAISO disagreed with stakeholders arguing that Order No. 1000 does not require elimination of the ROFR for TOs to build facilities on their existing rights-of-way. Other tariff revisions include clarifications on CAISO's competitive solicitation process.
C. NYISO
NYISO's compliance filing was submitted in Docket No. ER13-102-000.15 NYISO's compliance filing emphasized how much of its tariff already complied with or surpassed the local and regional planning and cost allocation requirements in Order No. 1000 on local and regional planning. It also submitted certain revisions to Attachment Y of its tariff to comply with the Order No. 1000 local and regional requirements. Those changes are described in Section V of the NYISO filing and include (i) the addition of consideration of Public Policy Requirements; (ii) directives on criteria for qualification for inclusion in the regional planning process; (iii) monitoring; and (iv) consideration of more efficient or cost-effective planning solutions.16
NYISO also highlighted several unresolved issues arising in its Stakeholder meetings. Those issues included: (i) whether to eliminate NYISO's requirement that a project receive 80% approval by project beneficiaries for the project to be selected as a solution to congestion (see Section IV.A.1.c.i. of NYISO's filing); (ii) whether the definition of Public Policy Requirements went too far by including New York Public Service Commission ("NYPSC") directives (see Section V.A.1.a. of NYISO's filing); (iii) the role of NYPSC and NYISO (see Section V.A.1.c. of NYISO's filing); (iv) the role of the Long Island Power Authority ("LIPA"), which argued that it should be responsible for Public Policy Requirement planning relating to transmission needs in the Long Island Transmission District (see Section V.A.2.d. of NYISO's filing); and (v) concerns with NYISO's proposed compliance plan for choosing efficient and cost-effective planning solutions in a non-discriminatory manner (see Section V.B.1.a. of NYISO's filing).
D. MISO
MISO submitted its Order No. 1000 compliance filing through two submissions in FERC Docket Nos. ER13-186 (revising the rules on Baseline Reliability Projects ("BRPs")) and ER13-187 (its primary Order No. 1000 filing). Under MISO's revisions, BRPs would be entirely local and all of their costs would be allocated to the MISO pricing zone where they are located. As local projects, ROFR would also continue for BRPs. Market Efficiency Projects and Multi-Value Projects would be those eligible for MISO regional cost allocation. In addition, while MISO proposed ROFR reforms on a contingent basis, it also articulated arguments why it believes Mobile-Sierra protects its Transmission Owners Agreement from modifications relating to non-incumbent developers.17
E. ISO-New England, Inc.
ISO-New England, Inc. ("ISO-NE") submitted its compliance filings in Docket Nos. ER13-193 and ER13-196. ISO-NE conditionally introduces a competitive process into its transmission planning procedures. This dual phase submission process would include within Phase I higher-level pre-qualified submissions and in Phase II projects selected for further development. ISO-NE's revisions are conditioned upon FERC's rejection of its Mobile-Sierra claims. ISO-NE argues, like MISO, that its Transmission Owner's Agreement is protected by Mobile-Sierra from revision.18
IV. Stakeholder – Enrollee – TO Member Distinction
In Order No. 1000-A, the Commission explained that it is requiring public utility transmission providers to include a clear enrollment process, defining how entities (including non-public utilities) may become part of the transmission planning region.19 Non-enrollees can participate as stakeholders. In practice, this may lead to the creation of three types of participants in regional transmission planning processes – stakeholders, enrollees, and TO members of RTOs/ISOs (or TOs where there is no RTO or ISO).
Some regions, such as CAISO, MISO, and PJM have collapsed the enrollee and TO distinction, so that an enrollee must be a TO to sponsor projects for cost allocation purposes in a transmission planning process. CAISO's process treats TOs as enrollees and appears to utilize the process for becoming a TO, as the process to enroll. Notably, CAISO also stated, "Nothing in Order No. 1000-A suggests that transmission costs cannot be allocated to a transmission customer that has not enrolled in a transmission planning region."20 MISO states that participation as an enrollee requires TO membership, execution of the Transmission Owners Agreement, and turning functional control of transmission facilities over to MISO. PJM created a category of "Designated Entities" which upon meeting the necessary criteria (such as financial resources) may propose projects for cost allocation and be selected with responsibility for financing and constructing the project. However, PJM also notes in Appendix I of its filing in Docket No. ER13-198 state that only PJM members may be enrollees. Under PJM's filing, it appears that enrollment requires PJM membership as a precursor to being selected as a Designated Entity.
NYISO and ISO-NE, on the other hand, seem to permit non-TOs to be enrollees. NYISO's compliance filing included language at Section 31.2.4.1 of the NYISO tariff regarding eligibility, stating "The ISO shall consider the qualifications of each entity in an evenhanded and non-discriminatory manner, treating Transmission Owners and Other Developers alike." ISO-NE created a category of "Qualified Transmission Project Sponsors" that seems to allow for non-TOs to enroll.
The main distinctions between enrollees/TOs and stakeholders are as follows (although these distinctions may be blurred in compliance filings):
- Enrollees are subject to regional and interregional cost allocation.
- Non-enrollees, who have load in the region where a project is sponsored, are not eligible for cost allocation in the transmission planning process (i.e., cannot recover costs of their projects through the regional process). Order No. 1000-A, at P 418.21
- Non-enrollees, who have no load in the region where a project is sponsored, may sponsor projects for cost allocation. Order No. 1000-A, at P 419.22
- Enrollees/TOs may have voting rights in the transmission planning process, although FERC did not require it. Order No. 1000-A, at fn. 322.
- Non-enrollees are still permitted to participate as stakeholders in the planning process to the same extent as any similarly situated stakeholder. Order No. 1000-A, at P 276.
- The regional transmission planning process is not required to consider the needs of non-enrollee stakeholders. Id.
- If a non-enrollee non-public utility transmission provider is a customer of a public utility transmission provider in the region, the transmission provider must plan for that customer's needs, as it would for any other customer. Id.
V. Non-Public Utility Participation
Non-public utilities need to carefully consider whether to enroll in transmission planning regions or to participate as stakeholders. Order No. 1000 does not require non-public utilities to participate in Order No. 1000, but it does encourage them to do so. See e.g. Order No. 1000, at PP815-822; and Order No. 1000-A, at P 774. Also, for purposes of reciprocity, FERC states that a safe harbor tariff must comply with Order No. 1000, though FERC makes clear it has not changed the reciprocity requirements of Order No. 890. See e.g. Order No. 1000, at P 815; and Order No. 1000-A, at P 772.
Order No. 1000-A makes clear that the enrollment process is geared towards helping to clarify the extent of participation by non-public utilities and other entities in Order No. 1000 processes. Order No. 1000-A, PP 274-277. The potential pros and cons of enrolling in transmission planning regions are discussed above, and a non-public utility's decision whether to enroll may depend on whether it has load in the region where it seeks to sponsor a project and how the enrollment process operates in nearby regions.
The Order No. 1000 compliance filings submitted for the various regions have illustrated the extent to which many non-public utilities are choosing to enroll in transmission planning regions and participate in the Order No. 1000 process. As discussed above, NorthWestern's initial compliance filing, states that NorthWestern understood that the other members of MAPP (non-Commission jurisdictional entities) would not be submitting initial Order No. 1000 Compliance Filings at this time. Also, NorthWestern's filing describes an unenrollment process for non-public utilities, which (i) provides that only those who enroll can sponsor a project for purposes of cost allocation; and (ii) notes that a Transmission Planning Committee ("TPC") Member that withdraws from enrollment (and therefore is not an enrollee) may continue to be a TPC Member. TPC Members may vote at TPC meetings on the regional plan, while other stakeholders may not. See NorthWestern Compliance Filing, at p. 8.
VI. Merchant Participation
With regard to enrollment by merchant transmission projects, those costs are to be recovered through negotiated rates, rather than cost-based rates. As FERC finds that merchant transmission developers assume all the risk for development of these projects, and does not require merchant developers to participate in Order No. 1000 regional planning, as FERC stated that it is unnecessary to identify a merchant project's beneficiaries. See Order No. 1000, at PP 119, 163, 165; and Order No. 1000-A, at P 297. However, if transmission developers desire a cost-based rate recovery of their project costs from the regional transmission provider, then they must participate in the regional transmission process. See e.g., Order No. 1000-A., at P 275.
FERC has accepted negotiated rates for a transmission line projects. For example, in 2009, FERC accepted a construct that permitted the merchant Chinook and Zephyr projects to negotiate a rate with larger anchor shippers, and later have an open season for smaller shippers to subscribe. FERC noted that the existence of nearby entities with cost-based transmission rates was one of the mitigating factors that FERC looked at when evaluating whether to grant a negotiated rate. See Chinook Transmission Power, 126 FERC P 61,134 (2009), also discussed in the Commission's Proposed Policy Statement in Docket No. AD12-9-000.
VII. Continued Development of Interregional Transmission Plans
Although compliance filings with interregional transmission plans are not due until April 11, 2013, review of some of the materials posted by RTOs, ISOs, and other organizations helps to provide some guidance as to the types of interregional planning processes in development.
For example, entities such as MISO and SPP are considering the frequency that they should hold interregional planning studies, the scope of interregional transmission planning (such as to include tie-lines), and the types of projects to be included in interregional plans as they are identified under the current tariffs (such as MISO Baseline Reliability Projects and Market Efficiency Projects). MISO is working with SPP, MAPP, PJM, and potentially SRTPP (depending on the outcome of their compliance filing) to develop an interregional plan.23
VIII. Conclusion
The first phase of Order No. 1000 compliance filings provides helpful information as to how RTOs/ISOs and other transmission providers will implement their regional transmission planning processes and the related cost implications. Interested parties should carefully review this first set of filings, especially because a number of propose changes to the methodologies that will govern how costs of new transmission projects approved as part of the regional planning process will be allocated. In addition, the proposed processes for involving stakeholders in the planning process will be subject to FERC review as part of this first stage of compliance filings. All of these and the compliance filings due later this month are subject to comment and interested parties should assess their potential impact and consider intervening and providing comments to protect their interests. Once the cost allocation methodologies are accepted by FERC, subsequent challenges will be the burden of the objecting party, rather than the transmission provider. Parties which might be impacted by the various Order No. 1000 compliance filings submitted should consider filing interventions and comments to protect their interests. As stakeholders file comments on submitted compliance filings, FERC considers those compliance filings and issues related orders accepting, rejecting or requiring further changes. As, entities prepare their interregional transmission planning and cost allocation compliance filings, greater understanding regarding Order No. 1000 implementation will continue to develop.
Footnotes
1 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000. 76 FR 49842 (Aug. 11, 2011), FERC Stats. & Regs. ¶ 31,241, order on reh'g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh'g, Order No. 1000-B, 141 FERC ¶ 61,044.
2 William D. DeGrandis and Candice Castaneda, Significant Federal Energy Regulatory Commission Activity in Transmission Incentives, Planning and Cost Allocation, Paul Hastings available at http://www.paulhastings.com/assets/publications/1987.pdf (August 2011).
3 Several parties, including MISO TOs have sought further rehearing and clarification of Order No. 1000. In addition, certain entities such as the MISO TOs and the National Rural Electric Cooperative Association ("NRECA") have filed petitions for review.
4 Order No. 1000, at P 792
5 See Order No. 1000, at P 485.
6 NorthWestern Corporation – Order 1000 Compliance Filing (South Dakota), Docket No. ER13-62-000 (filed Oct. 10, 2012).
7 SPP – In June of 2012, in Docket No. RM10-23, SPP requested extension of the deadline to file its initial Order No. 1000 compliance filing through November 12, 2012, in order to finalize the filing at SPP's Board of Directors' meeting at the end of October. The Commission granted this extension, and therefore SPP's initial compliance filing can be expected by November 12, 2012.
8 United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332 (1956) ("Mobile"); Federal Power Comm'n v. Sierra Pacific Power Co., 350 U.S. 348 (1956) ("Sierra") ("Mobile-Sierra").
9 See Public Service Electric and Gas Company submits tariff filing per 35.13(a)(2)(iii: PJM TOs Revisions to the PJM Tariff to Modify Cost Allocation, at p. 19, Docket No. ER13-90-000 (filed Oct. 11, 2012); and PJM Open Access Transmission Tariff Revisions to Modify Cost Allocation for PJM Required Transmission Enhancements, Docket No. ER13-198-000 (Oct. 25, 2012).
10 PJM's Filing in ER13-198, at n. 144 states that Designated Entities are defined as, "[t]he entity designated by the Office of the Interconnection with the responsibility to construct, own, operate, maintain and finance Immediate-need Reliability Projects, Short-term Projects and Long-lead Projects pursuant to section 1.5.8 of this Schedule 6." PJM clarifies at id., n. 154, "An entity submitting a project proposal, who does not wish to be the Designated Entity, does not have to pre-qualify."
11 Indicated PJM Transmission Owners submits Order No. 1000 Compliance Filing Concerning Mobile-Sierra Protections for Right of First Refusal in PJM Agreements, Docket No. ER13-195-000 (Oct. 25, 2012).
12 Public Policy Requirements include transmission needs driven by public policy requirements established by state or federal laws or regulations.
13 California Independent System Operator Corporation Order No. 1000 Compliance Filing, Docket No. ER13-103-000 (Oct. 11, 2012).
14 Id., at p. 2.
15 New York Independent System Operator, Inc. submits tariff filing per 35: OATT Order No. 1000 Compliance Filing, Docket No. ER13-102-000 (filed Oct. 11, 2012).
16 Id., at p.2.
17 Midwest Independent Transmission System Operator, Inc, submits tariff filing per 35.13(a)(2)(iii: 10-25-12 BRP, Docket No. ER13-186-000 (submitted Oct. 25, 2012)) and Midwest Independent Transmission System Operator, Inc submits tariff filing per 35: MISO OATT Order 1000 Compliance Filing, Docket No. ER13-187 (submitted Oct. 25, 2012).
18 Central Maine Power Company submits tariff filing per 35: OATT Order 1000 Compliance Filing - ISO New England Inc, Docket No. ER13-193-000 (submitted Oct. 25, 2012); Central Maine Power Company submits tariff filing per 35: OATT Order No. 1000 Compliance Filing - ISO New England Inc. - Part II, Docket No. ER13-196-000 (submitted Oct. 25, 2012).
19 Order No. 1000-A, at P 275.
20 CAISO Filing, at n. 24.
21 Stating, "it would be fundamentally unfair and thereby may lead to an unjust and unreasonable or unduly discriminatory or preferential result to allow a transmission developer, whether it is a public utility transmission developer or a non-public utility transmission developer, to seek regional cost allocation for a proposed transmission project in a transmission planning region in which it or an affiliate has load, but where neither it, nor that affiliate, has enrolled in that region where its load is located. Such a result would permit a transmission developer to allocate the costs of its project to other entities in the region pursuant to that region's cost allocation method – without first enrolling itself or its affiliate in the transmission planning region in which its load is located and potentially being allocated costs for other transmission projects for which it is found to be a beneficiary."
22 Stating, "....We emphasize that an entity, including a non-public utility transmission developer, that does not have load within a transmission planning region may propose a transmission project for evaluation and potential selection in that region's transmission plan for purposes of cost allocation without enrolling in that region."
23 See e.g. Meeting Materials from MISO August 2, 2012 Meeting on Interregional Planning.
The content of this article does not constitute legal advice and should not be relied on in that way. Specific advice should be sought about your specific circumstances.