Docket No. RM22-14-001

I concur with Order No. 2023-A,[1] which largely sustains the findings and determinations of its predecessor, Order No. 2023.  I write separately to highlight two issues in the order, which I previously discussed in my concurrence to Order No. 2023.[2]

Enumerated Alternative Transmission Technologies (Section II.E.2.a.iii)

Order No. 2023-A sustains the determination in Order No. 2023 that transmission providers have the sole discretion in determining whether to use an alternative transmission technology, or grid-enhancing technology (GET), in the interconnection process.  As I explained in my concurrence to Order No. 2023:

A GET may hold the potential of squeezing more juice – literally – out of the existing transmission grid.  By increasing the capacity of the existing grid, a GET could reduce or even eliminate the need for the future construction of new transmission assets.  So the potential for cost-savings from the use of GETs is too important to ignore.[3]

I emphasized, however, that GETs are operational applications, which should be deployed when and where their efficacy can be proven, and should not be mandated as planning assumptions or as potential substitutes for network upgrades caused by interconnection requests.[4]  I also noted the different financial incentives at play:  transmission owners will typically favor the construction of costly new transmission assets over deploying GETs, whereas companies who sell GETs and generation developers—particularly those in RTOs/ISOs that use participant funding to pay for the costs of network upgrades caused by the interconnecting customers—want GETs to be mandated.[5]  Therefore, it was crucial to strike the right balance in the order.[6]

And Order No. 2023 did just that.  Order No. 2023 required the evaluation of certain listed GETs in the interconnection studies process but did not require that a GET must be deployed as an alternative to a necessary network upgrade.[7]  Further, and most importantly, Order No. 2023 made clear that the determination in each case was to be made at the sole discretion of the transmission provider (i.e., RTO/ISOs or non-RTO transmission providers).[8]  This is crucial because transmission providers are responsible for resolving the reliability issues caused by a particular interconnection, and there is a risk that a GET could fail, prompting a later, potentially more costly, network upgrade.[9]  And, of course, for that subsequent reliability upgrade, consumers would likely get stuck with the bill, not the generation developer.

Order No. 2023-A rightly sustains the discretion that Order No. 2023 affords transmission providers in determining whether to use a GET.  This level of discretion continues to be justified because:

(1) the transmission provider is responsible for determining whether using any of the enumerated alternative transmission technologies is an appropriate and reliable network upgrade that allows the interconnection customer to flow the output of its generating facility onto the transmission provider’s transmission system in a safe and reliable manner; (2) the requirement to make such a determination before allowing for the use of the enumerated alternative transmission technologies addresses concerns that their use may impinge on reliability, delay network upgrades instead of reducing the need for them or obviating the need for them altogether, or fail to address all transmission system issues that a traditional network upgrade would address; and (3) there is a need to avoid time-consuming delays and costly disputes or litigation over interconnection costs that could arise as a result of this reform.[10]

Order No. 2023-A also clarifies that transmission providers must explain their evaluation of GETs for feasibility, cost, and time savings as an alternative to a traditional network upgrade in their applicable study report(s), and their use determinations must be consistent with good utility practice, applicable reliability standards, and applicable laws and regulations.[11]  Thus, as I observed, Order No. 2023 “strikes the appropriate balance between requiring the evaluation of GETs, but not mandating the use of a GET in specific cases unless the transmission provider – and only the transmission provider – determines it would work from a real-world applicability standpoint.”[12]  And Order No. 2023-A preserves that balance.

Inappropriate Allocation of Certain Costs to Consumers

I remain concerned that study delay penalties on RTOs/ISOs and the costs of transmission provider heatmaps used as a tool for interconnection customers will be inappropriately allocated to consumers even though they both appear to provide much more of a benefit to generation developers than consumers.[13]  I address each in turn.

Study Delay Penalties on RTO/ISOs (Section II.D.1.c.iii)

Order No. 2023-A sustains the imposition of penalties on transmission providers who miss study deadlines.  As I expressed in my Order No. 2023 Concurrence, I have concerns about assessing study penalties on RTOs/ISOs, which are not-for-profit entities with no stockholders.[14] 

Order No. 2023 left open the question of how RTOs/ISOs will recover those study delay penalties that are not automatically imposed on a transmission-owning member by explaining that RTOs/ISOs may submit an FPA section 205 filing to propose a cost recovery scheme for these penalties.[15]  Unfortunately, Order No. 2023-A continues to punt this question, stating that it will address any future RTO/ISO section 205 proposal to recover the costs of study delay penalties on case-by-case basis.[16]  I urge that any such RTO/ISO filing make protections to consumers paramount.  In any scenario, the costs of penalties should not be imposed on retail customers, for the obvious reason they are not the cause of the penalties.  I would add that the fact that Order No. 2023-A still fails to answer the fundamental question of “who pays?” illustrates the legal and policy flaws in the penalty scheme as applied to RTOs/ISOs.  No doubt we will continue to hear more about this issue.

Cost of Heatmap (Section II.C.1.c)

In addition, although I support the heatmap requirement, I remain concerned over its potential funding through transmission rates.[17]  Order No. 2023-A sustains the determination that transmission providers must bear the costs associated with their heatmaps or recover them through transmission rates to the extent they are recoverable consistent with Commission accounting and ratemaking policy, finding that interconnection customers are not the sole or primary beneficiaries of the heatmap requirement.[18]

I agree with this rationale only with respect to those regions in which transmission providers which do not use participant funding—i.e., in those regions where the transmission provider’s load ultimately reimburses (or more accurately, subsidizes) interconnection customers for their interconnection costs.  As heatmaps serve to identify viable points of interconnection and improve queue efficiency, they help to reduce interconnection costs.  Thus, ceteris paribus, heatmaps will indirectly reduce the magnitude of the reimbursements of interconnection costs paid by load to interconnection customers.

On the other hand, in regions in which the transmission provider uses participant funding—such as in PJM and MISO—I fail to see how interconnection customers are not the sole or primary beneficiaries of the heatmap requirement.  In those regions, as interconnection customers are ultimately responsible for interconnection costs—with the exception of MISO’s (questionable, in my opinion) assignment to load of 10% of the cost of network upgrades 345 kV and above—the savings that heatmaps provide would inure to generation developers.  I question, therefore, whether the recovery of the cost of heatmaps from load in those regions would be just and reasonable.  As I stated in my Order No. 2023 Concurrence:

Commission policy may dictate that interconnection queue efficiency benefits transmission customers; however, that should not result in the costs of a requirement that best benefits interconnection customers, and really prospective interconnection customers that may ultimately not seek to interconnect, being recovered from consumers through transmission rates carte blanche.[19]

For these reasons, I concur.



[1] Improvements to Generator Interconnection Procedures and Agreements, Order No. 2023-A, 186 FERC ¶ 61,199 (2024).

[2] Improvements to Generator Interconnection Procedures and Agreements, Order No. 2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC ¶ 61,054 (2023) (Christie, Comm’r, concurring at P 1) (Order No. 2023 Concurrence),

[3] Id. P 2.

[4] Id. P 5 (footnote omitted).

[5] Id. PP 6-7.

[6] Id. P 8.

[7] Id. P 9.

[8] Id. P 10.

[9] Id. P 11.

[10] Order No. 2023-A, 186 FERC ¶ 61,199 at P 618 (citations omitted).

[11] Id. P 619 (citation omitted); see also id. PP 626-627.

[12] Order No. 2023 Concurrence at P 12 (emphasis added).

[13] Id. P 17.

[14] Id. P 18.

[15] Id. P 20.

[16] Order No. 2023-A, 186 FERC ¶ 61,199 at P 465 (citation omitted).

[17] Order No. 2023 Concurrence at PP 21-22.

[18] Order No. 2023-A, 186 FERC ¶ 61,199 at P 106.

[19] Order No. 2023 Concurrence at P 22 (emphasis in original).

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