"Advanced Grid Technologies Act"; requires State oversight of supplemental projects and establishes expedited review for projects utilizing advanced transmission technologies.*
What changed between versions
Entire Section 7 was struck, eliminating the board's authority to establish cost recovery and deployment incentive mechanisms including shared-savings arrangements (where utilities retain a percentage of verified net benefits from ATT/ADT deployment) and performance-based incentives tied to measurable metrics like congestion reduction and capacity gains.
The provision prohibiting utilities from recovering third-party analysis costs through customer rates (Section 4(a)(3)) was removed, and the application fee for the standard review process was made explicitly recoverable through rates (Section 4(a)(5)).
New subsections 5(d) and 6(d) explicitly prohibit the board from conducting siting reviews or considering environmental impacts in its certificate determinations under both the expedited (Section 5) and standard (Section 6) review processes, confining the board's review to only the enumerated criteria.
Section 6(b)(2) changed the reliability and resilience factor from enhancing 'the bulk power system, considering any reliability determination from PJM' to enhancing 'the utility's transmission or distribution system,' narrowing the scope of what the board considers from a regional perspective to the individual utility's own infrastructure.
Federal preemption language in Section 9(e) was expanded to explicitly include 'determinations made pursuant to federal law by NERC, FERC, PJM, or the Secretary of Energy' and added that the board's consideration shall not constitute 'the exercise of planning authority over electric transmission facilities.' The reference to FERC Order No. 1920 was replaced with a broader reference to the Federal Power Act and FERC orders generally.
The evidentiary standard for demonstrating that ADTs address distribution-system needs was lowered from 'substantial evidence' to 'the preponderance of the evidence' in both Section 5(a)(1) and Section 6(b)(5), making it easier for utilities to meet the threshold.
Sections 5(a)(3) and 6(a)(3) now require that, with respect to distribution capital spending, the financing be aligned with the most recent approved distribution capital structure, adding a new financial consistency requirement.
The deadline for the board to issue its order under the expedited review process (Section 5) was extended from 90 days to 120 days after submission of a completed application, though the 30-day extension option remains.
The definition of 'supplemental transmission project' was narrowed by adding 'pursuant to PJM's Attachment M-3 process' as a qualifier and adding an exclusion for projects undertaken solely for routine maintenance of an existing transmission line. The definition of 'advanced power flow control technology' was narrowed from any software or hardware that balances overloaded lines to specifically 'power electronic-based devices' that change power flow without altering generator dispatch or network topology.
A new definition for 'NERC' (North American Electric Reliability Corporation) was added, and the grid performance benchmarks section now includes an explicit statement that it shall not conflict with federally-established benchmarks including NERC Reliability Standards or affect FERC's jurisdiction over transmission planning.
The definition of 'cost-effective' was expanded to include 'reductions in energy or capacity prices, and reliability and resilience improvements' as additional benefits that can justify project costs.
The restriction that the board's determination of which review process applies 'shall not be subject to interlocutory appeal' was removed from Section 4(b), potentially allowing parties to appeal that procedural determination before a final certificate decision.
