(Washington, DC) The Federal Energy Regulatory Commission’s 195-page order released late Friday afternoon requires PJM or its transmission owners to make additional filings to achieve full compliance with Order 1000. Those tasks, which largely involve changes to the Open Access Transmission Tariff (OATT) and Operating Agreement (OA), are listed below, along with references to the relevant paragraphs in the order (docket #s ER13-198, ER13-195 and ER13-90).
The order is broken into three categories (click to jump to that section):
Transmission Planning
Schedule for implementing Order 1000 changes
To Do:
- Establish a start date for the next 12-month and 24-month planning cycle during which PJM’s proposed revisions will be effective or provide an alternative effective date and explain why it is appropriate.
- Provide further information regarding PJM’s transition to the revised transmission planning process and explain how PJM will evaluate transmission projects currently under consideration. (P 34)
Background:
FERC said PJM Manual 14B was unclear regarding whether the planning cycle starts in January or the prior December. The commission said it expects PJM to implement the Order 1000 changes at the beginning of the next planning cycle, saying “we do not believe that it is necessary to delay the effective date of the proposed revisions until every issue in this proceeding has been resolved.” (P 32)
Comparability
To Do:
Explain how PJM will continue to comply with the requirement that it evaluate transmission, generation, and demand resource alternatives on a comparable basis when seeking solutions to transmission constraints and reliability problems. (P 53)
Background:
Order 1000 builds on the transmission planning principles of Order 890, which requires that transmission planners consider generation and demand response proposals as well as new transmission lines when developing assumptions used in the planning process.
PJM has proposed removing language in Schedule 6 of its Operating Agreement which relate to procedures for stakeholders seeking to propose alternative transmission solutions. The commission said it relied on these sections when it found PJM in compliance with Order 890’s comparability principle in 2009. (P 46)
The commission also took issue with PJM’s position that participants in the regional transmission planning process must be a member or associate member of PJM. “This appears to be a misstatement by PJM,” the commission wrote, noting that such a requirement would conflict with Order No. 890 and the PJM Operating Agreement. (P 55)
The commission rejected a request by a coalition of environmental groups that said that PJM’s planning procedures fail to ensure comparable treatment of demand response. The groups asked FERC to require PJM to collaborate with the Independent State Agencies Committee and other stakeholders to develop more specific procedures and metrics on how PJM will evaluate all options on a comparable basis and select more efficient or cost-effective solutions.
The commission said the issue of cost recovery for non-transmission alternatives is beyond the scope of Order No. 1000. The commission also rejected the organizations’ request that it require PJM to provide technical assistance or funding to such groups. (P 53-54)
Identifying More Efficient or Cost-Effective Transmission Solutions
To Do:
None
Background:
The commission rejected as outside the scope of Order 1000 Clean Line Energy Partner’s request that PJM include participant-funded merchant projects in the Regional Transmission Expansion Plan (RTEP). (P 66) Clean Line said allowing study of merchant projects in the RTEP “rather than waiting several years for an interconnection agreement,” would support the commission’s goal of identifying the most cost-effective solutions to transmission needs. (P 63)
Incorporating Public Policy Requirements
To Do:
- Revise the tariff to describe the process through which PJM will determine which public policy requirements identified by stakeholders at the assumptions stage of the RTEP will be incorporated into transmission studies. (P 115)
- Explain how the transmission-owning members of PJM are addressing public policy requirements in their local transmission planning processes. (P 123)
- Revise the tariff and OA to include laws or regulations passed by local governments (e.g., municipalities and counties) in the definition of public policy requirements. (P 113)
- Post on the PJM website an explanation of those public policy requirements that PJM adopted at the assumptions stage of the RTEP and why other public policy requirements introduced by stakeholders were excluded. (P 116)
Background:
The commission said it was unclear whether PJM intends to incorporate all public policy requirements identified by stakeholders into its transmission studies, or whether it will consider only a subset of requirements. The commission also said it was unclear what information PJM intended to post on its website regarding inclusion of public policy needs or how PJM transmission owners have incorporated Order 1000 requirements in their local transmission planning processes.
State Agreement Approach
To Do:
Identify the entity that determines whether a “Supplemental Project” will be included in the RTEP. (P 145)
Background:
Under PJM’s “State Agreement Approach,” states can submit to PJM for inclusion in the RTEP projects that address public policy requirements even if the project doesn’t qualify as a reliability or market efficiency project. The project will be included in the RTEP as a state public policy project or a “Supplemental Project” if the states voluntarily agree to pay for them. Costs for such projects cannot be allocated to any state that does not agree to those costs.
PJM’s filing specifies that Supplemental Projects are not subject to PJM board approval but doesn’t identify which entity determines whether such projects will be included in the RTEP. A Supplemental Project is one that the Office of the Interconnection deems not required for compliance with PJM’s system reliability, operational performance or economic criteria.
Nonincumbent
Transmission Developer Reforms
Federal Rights of First Refusal
To Do:
Revise or eliminate any provisions in the OATT and agreements “that could be read as supplying a federal right of first refusal” (ROFR) for any transmission projects selected for regional cost allocation. (P 221)
Background:
The commission sought to clarify its ruling in the Primary Power Rehearing Order, in which it found that PJM’s rules allow a nonincumbent transmission owner to receive cost-based or cost-of-service compensation for an economic transmission project. The commission said it now believes that PJM’s OATT and agreements “are ambiguous and open to interpretation and potential undue discrimination.” The commission said PJM’s revisions must also comply with its Atlantic City ruling by addressing any provisions “that could purport to preclude the section 205 filing rights of nonincumbent utilities without their consent.”
—-
To Do:
Remove proposed language reserving to incumbents:
- Transmission projects that are proposed on a transmission owner’s right of way when that project would alter the owner’s “use and control of its existing rights of way under state law” or
- Projects “when required by state law, regulation or administrative agency order.” (P 231)
Background:
The commission said the two exceptions improperly establish federal rights of first refusal.
The commission acknowledged that Order 1000 did not require PJM to remove from its tariffs and agreements references to state or local laws regarding the construction and siting of transmission facilities. “However, PJM’s proposal goes beyond mere reference to state or local laws or regulations; it references state and local laws and then uses that reference to create a federal right of first refusal,” the commission said.
Similarly, Order 1000 did not alter incumbents’ use and control of its existing rights-of-way. “However, the Commission did not find that … a public utility transmission provider may add a federal right of first refusal for a new transmission facility built on an existing right-of-way.”
Transmission Upgrades
To Do:
Clarify PJM’s definition of a transmission “upgrade.” (P 234)
Background:
Order 1000 reserved construction of transmission reliability upgrades — which it defined as including tower change outs and reconductoring — to incumbent utilities. The commission said PJM’s OATT and agreements contain references to several types of upgrades and it is unclear which PJM intends to include in the Order 1000 definition.
Short-term and Long-lead Projects
To Do:
Revise the OA and OATT to:
- List and explain the criteria that PJM will use to determine whether to change the default proposal window for Short-term and Long-lead projects. (P 239)
- Clarify into what category in the transmission project proposal process a market efficiency project can be proposed. (P 237)
- Explain how PJM will determine whether there is insufficient time for re-posting and reevaluation, and how such a determination requires that an incumbent transmission owner be assigned to build a Long-lead project. (P 241)
Background:
FERC approved PJM’s proposal to establish three categories of transmission projects for evaluation: Immediate-need reliability projects, Short-term projects and Long-lead projects.
Immediate-need projects and certain short-term projects would be assigned to incumbents. The commission said these “time-based” exceptions to the elimination of the federal ROFR are permissible for urgent reliability projects in which there is insufficient time to conduct open solicitations. (PJM proposed a 30-day proposal window for Short-term projects; if the first set of proposals does not address all of the reliability violations required to be solved, PJM will designate that work to the incumbent.)
The commission said PJM’s proposals made it unclear whether economic projects would be classified like reliability projects as Short-term or Long-lead.
Immediate-need Reliability Projects
To Do:
Explain how its designation of Immediate-need reliability projects complies with five criteria created by the commission. (P 248)
Background:
The commission said the criteria were needed to ensure that the ROFR exceptions “will be used in limited circumstances.” The criteria are:
- The Immediate-need Reliability project must be operational in three years or less to solve reliability criteria violations.
- PJM must post a public explanation of the reliability need and why it is time-sensitive.
- The process used to assign an Immediate-need project to an incumbent must be outlined in PJM’s OATT. PJM also must provide stakeholders a written explanation of the decision to assign the project to an incumbent, including a description of other transmission or non-transmission options that the RTO considered and an explanation of why the reliability need was not identified earlier.
- Stakeholders must be permitted time to provide comments in response to the description in criterion three and such comments must be made publicly available.
- PJM must maintain and post a list of prior year designations of all projects for which the incumbent transmission owner was designated as the entity responsible for construction and ownership.
The commission also told PJM to explain why it proposed allowing the Office of the Interconnection authority to designate projects with an in-service date of longer than three years as Immediate-need projects and how PJM will exercise that discretion. (P 252)
Qualification Criteria
To Do:
Clarify that the selection criteria for those seeking to be awarded transmission projects, and the requirements for those awarded such projects (e.g., posting letters of credit) apply to both incumbent transmission owners and nonincumbent transmission developers. (P 276)
Background:
The commission said some of PJM’s language on the selection process and developer requirements was vague.
The commission rejected as beyond the scope of this proceeding suggestions by the PJM Market Monitor that PJM implement a competitive process for the procurement of capital. The commission also declined to require PJM to include additional criteria proposed by Duquesne Light Co., Exelon Corp. and the New Jersey Board of Public Utilities. The commission said the additional criteria were not necessary to comply with Order 1000 but said the parties could seek to add them through the stakeholder process.
Transmission Proposal Evaluation Process
To Do:
- Provide additional clarification regarding the evaluation of more efficient or cost-effective solutions. (P 310)
- Propose a process through which PJM will publicly provide generally applicable information arising from the RTO’s private discussions with incumbent and nonincumbent bidders. (P 311)
Background:
LS Power raised concerns that PJM has not provided enough detail about how it will determine which proposals provide the most efficient or cost-effective solutions.
LS Power also protested that confidential discussions between PJM and the incumbent transmission owner during the proposal window may lead to discrimination against nonincumbents. FERC declined to adopt LS Power’s proposal that only public discussions be permitted between PJM and stakeholders during the proposal window and evaluation process.
The commission also rejected the market monitor’s contention that a cost cap on transmission projects be required to prevent bidders from submitting unrealistically low bids to win the project and then seek more money later through change orders. FERC said such abuses should be policed by PJM’s requirement that bidders provide letters of credit in an amount of the difference between their bid and the next lowest bid.
Reevaluation Process
To Do:
Explain how PJM will determine whether to retain or remove a selected transmission project, or select an alternative transmission solution, under the reevaluation process. (P 318)
Background:
PJM will reevaluate projects in which the developer fails to meet its obligations (e.g., failure to provide a development schedule or letter of credit, or failure to meet a milestone that delays a project’s in-service date). Based on that reevaluation, PJM will decide whether or not to reopen the project to other developers or seek an alternative solution.
The commission said the lack of description regarding how PJM will decide a project’s fate “may allow PJM too much discretion in making this determination.”
Cost Recovery
To Do:
Explain how the various provisions of the OATT and agreements ensure that a nonincumbent selected to construct a transmission project can recover costs. (P 327)
Background:
FERC found that parts of the OATT and other agreements appear to conflict with each other and contain provisions “that appear to preclude nonincumbent transmission developers from filing for transmission cost-based rates prior to becoming a party” to transmission owners agreement.
Cost Allocation
Impacts on Neighboring Regions
To Do:
Revise the OATT to describe how PJM will identify the impact of a new transmission facility on neighboring regions and how costs will be allocated if PJM agrees to bear them for with any upgrades required in the other regions. (P 422)
Background:
FERC’s rules require PJM transmission planners to identify whether projects within PJM will require upgrades in neighboring regions. Because PJM cannot assess costs for such upgrades on other regions without their agreement, FERC said it must develop a way to allocate such costs within the RTO.
Direct Current Transmission Lines
To Do:
Establish criteria that consider DC and AC transmission in a comparable manner for qualification for regional cost allocation. (P 439)
Background:
The commission said that the Transmission Owners’ October 11 filing “may discriminate against DC transmission facilities” in its proposed definition of facilities qualifying for regional cost allocation. The filing would disqualify a DC facility that is not connected to at least one substation or switching station also connected to a minimum 500 kV or double-circuit 345 kV transmission line. The transmission owners put no such conditions on AC facilities.
Solution-based distribution factor analysis (DFAX)
To Do:
Provide more details explaining how the Solution-Based DFAX method is used to calculate assignments of cost responsibility. (P 428)
Background:
The commission agreed with Long Island Power Authority, Illinois Commerce Commission, and the Maryland Public Service Commission that PJM had not provided enough detail regarding how DFAX will be implemented. “While PJM has adequately shown how the DFAX values and usage of transmission facilities will be calculated, there is no detail regarding how these values will be utilized to calculate assignments of cost responsibility,” the commission said.
