By Rory D. Sweeney

FERC on Thursday signaled a change in its thinking about how RTOs should allocate costs for projects that improve grid stability, reopening proceedings regarding PJM’s controversial Bergen-Linden Corridor (BLC) and Artificial Island projects in New Jersey.

For reliability projects, PJM assigns 50% of the costs of regional facilities (500-kV lines or higher and double 345-kV lines) and “necessary” lower-voltage facilities required to support regional lines on a load-ratio share basis. The other 50% is allocated using the solution-based distribution factor (DFAX) method. All costs of lower-voltage facilities not supporting regional lines are allocated via DFAX.

Complaints against both projects argued that the DFAX method failed to align allocations with benefits.

In addressing requests for rehearing of complaints about cost allocations for the BLC project, FERC on Thursday ordered settlement judge procedures to urge the parties into settlement, saying the underlying facts in the complaint “have significantly changed” (EL15-67-003, et al.).

FERC also granted rehearing of its April 2016 order rejecting a complaint by Delaware and Maryland regulators, who argued that the DFAX method, as applied to Artificial Island, does not produce an allocation of Regional Transmission Expansion Plan project costs roughly commensurate with the benefits (EL15-95-003).

BLC

The commission urged a settlement of the BLC dispute rather than rule on a rehearing request over its April 2016 order denying a complaint from Linden VFT over the projects and two others totaling $1.3 billion. Linden, Consolidated Edison, the New York Power Authority and Hudson Transmission Partners — the operator of another merchant transmission line into New York City — requested rehearing of the decision.

Since then, one of the projects was canceled and the costs for another were reassigned entirely to Public Service Electric and Gas, so that only the allocations for BLC, totaling $1.2 billion, remain in contention.

Linden’s complaint was that the reliability issues upon which the projects were based are not related to power flows, so PJM’s solution-based DFAX method, which identifies beneficiaries based on flows, did not align costs with benefits. While the formula is split 50/50 between load-ratio share and DFAX, the allocation ends up weighted toward the DFAX. Of the $1.3 billion in allocations Linden initially complained about, approximately $400 million was allocated on a load-ratio share basis and $900 million based on DFAX.

Even though BLC is in PSE&G’s zone, the company was allocated only about $88.4 million of the costs. Con Ed was allocated approximately $720.4 million, Linden $9.6 million and Hudson $103.2 million.

FERC denied Linden’s complaint, ruling that the company failed to prove the DFAX method was unjust and unreasonable. In urging a settlement before ruling on rehearing, the commission said, “the circumstances regarding the cost responsibility assignments … have significantly changed.”

In May 2017, Con Ed canceled a wheeling agreement with PSE&G that had made the wheel part of cost responsibility assignments in the RTEP. With the wheel eliminated, PJM reassigned the costs that had been allocated to Con Ed.

In December, FERC granted Linden’s and Hudson’s request to convert their firm transmission withdrawal rights to non-firm rights, allowing the merchant facilities to escape RTEP cost allocations. PJM subsequently reassigned to PSE&G the costs Hudson and Linden had been allocated. (See PSE&G on the Hook for Bergen-Linden Costs.)

The chief judge has 15 days to assign a settlement judge, who will report back in 30 days after being appointed. The chief judge will then allow more time if a settlement remains unfinished or inform FERC that there’s an impasse that can’t be settled.

Artificial Island

As in the Linden complaint, the commission initially rejected the Delaware and Maryland regulators’ complaint over the use of the DFAX cost allocation for Artificial Island. The project would add new transmission between New Jersey and Delaware to address stability limits on generation at the Salem and Hope Creek nuclear plants and transmission constraints that sometimes prevent the generators from exporting power at full capacity.

About $242 million (87%) of the cost of the project was assigned under DFAX and the remaining $38 million assigned based on load-ratio share.

The state commissions requested rehearing in April 2016, along with the states’ public advocates, Old Dominion Electric Cooperative, Easton Utilities and the Delaware Municipal Electric Corp. LSP Transmission Holdings also requested rehearing separately.

In granting a paper hearing, FERC said it now believes the DFAX method is unjust and unreasonable for projects that address stability-related reliability issues. The commission cited a statement from PJM in the docket that “stability is analytically unique compared to voltage or thermal overloads” because it results from “an imbalance of generation and load caused by a sudden event on the transmission system where the rotational inertia of the generator could cause the generator to lose synchronism with the rest of the transmission system.”

Generators oscillate to re-establish balance, but the severity of the oscillation is dependent on the strength of the transmission system, FERC said. A weaker transmission system will cause the issues to last longer and be more severe, which could ultimately result in damage to the generator and cause additional outages of other system elements. Stability-related projects “provide additional outlets” for generators to address the issues.

FERC established a paper hearing to consider an appropriate alternative. Stakeholders have 60 days to provide their comment on proposals from PJM and Exelon. The PJM proposals were filed in the docket by the state commissions after the RTO unveiled them last year. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)

The first alternative, which PJM called a “direct extension” of the DFAX, would reduce Delmarva Power & Light’s responsibility to about 7% while raising the bill for PSE&G to more than 42%. New Jersey’s other utilities — Jersey Central Power & Light and Atlantic City Electric — would pick up 13% and 7.3%, respectively. PECO Energy would shoulder about 20% of the costs.

PJM’s second “stability deviation method” would allocate 19% to PSE&G, 15% to PECO, 12.5% to PPL, 12.4% to JCP&L, 10.4% to Delmarva Power & Light, 7.2% to ACE and about 5% to Met-Ed.

Exelon presented its proposal as comments in the docket. Its “hybrid method” could assign some portion of cost responsibility for benefits identified by flows on transmission projects that address stability issues in proportion with the benefits identified by PJM’s approaches.