FERC, in an order issued on July 11, accepted, subject to condition, the cost responsibility assignments that PJM Interconnection set forth for certain baseline upgrades that were included in the recent update to the Regional Transmission Expansion Plan (RTEP) that the PJM Board of Directors approved.
FERC also directed PJM to submit a compliance filing within 30 days of the order’s date.
As noted in the order, PJM on Jan. 15, as amended on Feb. 12, under section 205 of the Federal Power Act (FPA), filed amendments to Schedule 12-Appendix A of the PJM Tariff. The tariff revisions incorporate cost responsibility assignments for 34 baseline upgrades included in the recent update to the RTEP.
FERC noted that PJM files cost responsibility assignments for transmission upgrades that the PJM Board approves as part of PJM’s RTEP, in accordance with Schedule 12 of the tariff and Schedule 6 of the operating agreement.
Types of reliability projects selected in the RTEP for purposes of cost allocation include regional facilities, which as a general matter are AC facilities that are single-circuit 500-kV or double-circuit 345-kV and above, necessary lower voltage facilities, and lower voltage facilities, FERC added.
The cost allocation method for transmission projects selected for purposes of cost allocation in the RTEP is set forth in Schedule 12 of the PJM tariff, FERC said, adding that for regional facilities and necessary lower voltage facilities, 50% of the facility’s costs is allocated on a region-wide, postage stamp basis and the other 50% is allocated under the solution-based distribution factor (DFAX) method. For lower voltage facilities, 100% of the facility’s cost is allocated under the solution-based DFAX cost allocation method, FERC said.
PJM stated that four of the 34 upgrades will operate at or above 500 kV, or will be double-circuit 345-kV facilities. PJM said that the cost responsibility assignments for those four regional facilities are based on the FERC-approved regional cost allocation method, which allocates 50% of the costs on a region-wide, postage stamp basis and the other 50% to specifically identified beneficiaries.
Among the designated regional facilities is baseline project “b2665,” included in the RTEP to address a Dominion Resources Service Inc., transmission owner local planning criterion.
As noted by FERC Commissioner Cheryl LaFleur in her July 11 statement dissenting in part, project b2665 is a rebuild of the Cunningham–Dooms 500-kV line.
PJM said that the 30 remaining upgrades are lower voltage facilities needed for reliability, FERC noted in its order.
Dominion opposed assigning 100% of the costs of baseline project b2665 to the Dominion zone, arguing that, at the time of the filing, the then-effective tariff language allowed PJM to allocate costs of transmission projects to address end-of-life transmission owner local planning criteria regionally and under the solution-based DFAX method, and that any changes should be prospective.
FERC added that according to Dominion, transmission projects require new capital investment, and cost allocation principles drive investment decisions. Dominion requested that FERC accept the filing, or at least tie it to the outcome of other proceedings, FERC said.
FERC said that while PJM followed the cost allocation provisions set forth in Schedule 12 of the tariff at the time that PJM made the filing, FERC has since accepted the PJM Transmission Owners’ proposal to allocate 100% of the costs of transmission projects that are included in the RTEP solely to address individual transmission owner Form No. 715 local planning criteria to the zones of the individual transmission owners whose Form No. 715 local planning criteria underlie each project.
Therefore, FERC added, the currently effective tariff allocates the costs of transmission projects like baseline project b2665 that are included in the RTEP solely to address transmission owner Form No. 715 local planning criteria to the zone of the individual transmission owner whose local planning criteria underlie the project.
“Accordingly, we reject PJM’s proposed cost responsibility assignment for project b2665, and direct PJM to file, within 30 days of the date of issuance of this order, a compliance filing to reflect the appropriate cost responsibility assignment for project b2665, consistent with the applicable tariff on file,” FERC said.
PJM directed to amend operating agreement to define immediate-need reliability project
FERC also noted that it informed PJM in April that the Jan. 15 filing, as amended by the Feb. 12 filing, was deficient and requested additional information related to certain projects that were also listed on PJM’s 2015 information filing as immediate-need reliability projects for which PJM stated that proposal windows were infeasible. PJM on May 12 filed a response to the deficiency letter, explaining that it did not establish a proposal window for those projects because the condition assessment of the facilities indicated that they had already reached their end-of-life, and needed to be replaced as soon as practical.
FERC said that PJM’s deficiency letter response highlights an inconsistency in PJM’s operating agreement.
“We agree that it is proper for PJM to use the date a reliability need must be addressed rather than the expected in-service date of the project chosen to address that need to calculate whether a transmission project qualifies as an immediate-need reliability project,” FERC said. “However, the language of the PJM operating agreement creates ambiguity, as written, with the PJM Order No. 1000 compliance proceeding that the commission accepted.”
FERC noted that in the Order 1000 compliance proceeding, FERC stated that the “immediate-need reliability project must be needed in three years or less to solve reliability criteria violations” and found that “defining immediate-need reliability projects as projects needed in three years or less to solve a reliability violation strikes a reasonable balance.”
However, PJM’s operating agreement appears to have inconsistent definitions of immediate need projects. FERC added that PJM defines an immediate-need reliability project as “a reliability-based transmission enhancement or expansion with an in-service date of three years or less from the year the Office of the Interconnection identified the existing or projected limitations on the Transmission System that gave rise to the need for such enhancement or expansion….”
That definition is inconsistent with the language of the operating agreement describing the immediate-need reliability project process, which states the reliability needs must be addressed within three years or less, FERC said. To remedy that ambiguity consistent with FERC’s findings in the Order 1000 compliance proceeding, FERC said that it proposes to require PJM to amend Section 1.15A of the PJM operating agreement to define an immediate-need reliability project as “a reliability-based transmission enhancement or expansion that the Office of the Interconnection has identified to resolve a need that must be addressed within three years or less,” which is consistent with Schedule 6 of the PJM operating agreement.
In the alternative, PJM must show cause why its operating agreement should not be amended, FERC said.
PJM’s response, LaFleur’s dissent
A PJM spokesperson on July 15 told TransmissionHub of the order: “We view this is a positive determination on an issue on which we had sought clarification. The commission has provided specific direction and we intend to comply.”
LaFleur on July 11 dissented in part, saying in her statement that while she generally supports the calls in the order, she disagrees “with the order’s rejection of the cost allocation for project b2665, a rebuild of the Cunningham–Dooms [500-kV] line. I believe that … high-voltage transmission lines in PJM have inherent regional benefits that warrant some measure of regional cost allocation.”
She said that she would apply PJM’s FERC-approved cost allocation methodology for double-circuit 345-kV and 500-kV and above transmission projects that allocates 50% of the project’s costs on a postage stamp basis, and 50% through a solution-based DFAX analysis.
Beyond the merits of the order, she said, the record in the case potentially raises another issue regarding which she recently expressed concern at FERC’s technical conference on competitive bidding: whether, as a reaction to Order 1000’s competitive requirements, incumbent transmission owners may be delaying action on transmission upgrades until those projects are needed in the near-term and therefore not subject to competitive bidding.
“It is important that incumbent transmission owners report their transmission needs to PJM in a timeframe that allows PJM to meet them in a timely manner, and open them to competitive bidding requirements if they are not in fact immediate,” LaFleur said. “If it appears over time that incumbent transmission owners may be postponing identification of transmission needs to avoid competitive bidding, further action may be needed to ensure that customers receive the intended benefits of Order No. 1000 planning processes.”