On March 20, 2020, FERC denied rehearing of a February 2018 order accepting the Midcontinent Independent System Operator, Inc.’s (“MISO”) resource adequacy Tariff provisions (see March 5, 2018 edition of the WER). FERC noted that many of the arguments raised on rehearing sought to impose on MISO the rules and requirements used in the centralized capacity markets in the eastern Regional Transmission Organizations/Independent System Operators (“RTOs/ISOs”). FERC rejected those arguments, concluding that unlike the centralized capacity constructs used in the eastern RTOs/ISOs, MISO’s capacity auction is not, and never has been, the primary mechanism for Load-Serving Entities (“LSEs”) to procure capacity. Continue Reading FERC Denies Rehearing, Affirming MISO Resource Adequacy Program

On March 19, 2020, FERC authorized Jordan Cove Energy Project L.P.’s (“Jordan Cove”) Natural Gas Act (“NGA”) section 3 proposal to site, construct, and operate a liquefied natural gas (“LNG”) export terminal in Coos County, Oregon (“Terminal”) and Pacific Connector Gas Pipeline, LP’s (“Pacific Connector”) application under section 7(c) of the NGA and Parts 157 and 284 of FERC’s regulations that would allow it to construct and operate an interstate natural gas pipeline system connected to the Terminal (“Pacific Connector Pipeline”). The decision prompted a dissent from Commissioner Richard Glick, who argued that the majority’s decision did not adequately consider the impacts that the Terminal and Pacific Connector Pipeline will have on climate change and other environmental concerns. Continue Reading FERC Approves Jordan Cove LNG Export Project, Prompting Dissent From Commissioner Glick

On March 17, 2020, FERC accepted revisions to the PJM Interconnection LLC (“PJM”) Open Access Transmission Tariff (“Tariff”) to establish enhanced procedures for compliance with the North American Electric Reliability Corporation (“NERC”) reliability standard CIP-024-2.  A majority of FERC Commissioners found that the Tariff revisions, captured in a new proposed Tariff Attachment M-4, appropriately balanced transparency obligations in transmission planning with the need to maintain strict confidentiality regarding the names, locations, and vulnerabilities of CIP-014-2 facilities.  In a separate opinion, Commissioner Glick dissented, in part, arguing that the proposal inappropriately categorized Attachment M-4 projects as a subset of “Supplemental Projects” under the Tariff and PJM Operating Agreement. Commissioner Glick argued that the proposal improperly subjected such projects to non-regional cost allocation, contrary to cost-causation and other transmission planning principles expressed in Commission Order Nos. 890 and 1000.

Continue Reading FERC Accepts Separate Planning Process for CIP-014 Mitigation Projects in PJM

On February 20, 2020, FERC staff issued a letter to the licensee for the FERC-licensed Anderson Dam Project (“Project”), directing the licensee to immediately initiate a full drawdown of the Project’s reservoir by October 1, 2020. The Project is located south of San Francisco and serves as an important water supply resource, but has long been identified as vulnerable to flooding and seismic events that could result in the catastrophic spilling of floodwaters into Silicon Valley.  As such, the licensee has been operating the Project at a restricted reservoir level (as low as 58% of capacity in 2020) to mitigate flooding and seismic risks. Continue Reading FERC Requires that Anderson Dam Drain Reservoir

I. Summary of NOPR

On March 19, 2020, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) proposing to revise its electric transmission incentive policy under Federal Power Act (FPA) Section 219[1] “to stimulate the development of transmission infrastructure needed to support the nation’s evolving generation resource mix, technological innovation and shifts in load patterns.”[2] FERC’s NOPR includes a number of changes to its transmission incentives policy and seeks comment from industry participants.

FERC’s NOPR proposes to shift the focus in granting transmission incentives from an approach based on the risks and challenges faced by a project to an approach based on economic and reliability benefits to consumers.

The NOPR intends to replace the current policy of limiting incentives to the base rate of return on equity (ROE) zone of reasonableness with a 250-basis-point cap on total ROE incentives. The NOPR proposes that transmission providers should be allowed to seek removal of the ROE zone-of-reasonableness restrictions placed on previously-granted incentives and to replace them with the hard cap.

FERC proposes to increase the ROE incentive for joining and remaining a member of a Regional Transmission Organization (RTO), an Independent System Operator (ISO) or other Commission-approved transmission organization (collectively hereinafter, “RTO”) from 50 basis points to 100 basis points, and to make the incentive available regardless of whether such participation is voluntary.

The NOPR also offers a 50-basis-point ROE incentive for transmission projects that meet a pre-construction benefit-to-cost ratio in the top 25 percent of projects examined over a sample period, and an additional 50 basis points for projects that meet a post-construction benefit-to-cost ratio in the top 10 percent of projects studied over the same sample period.

FERC further proposes a 100-basis-point ROE incentive for transmission technologies that enhance reliability, efficiency and capacity, as well as improve the operation of new or existing transmission facilities. The NOPR also proposes an incentive of up to 50 basis points for projects that demonstrate reliability benefits by providing a quantitative analysis, where possible, or a qualitative analysis.

Finally, FERC plans to retain several existing non-ROE incentives, including those related to Construction Work In Progress (CWIP), hypothetical capital structure, accelerated depreciation for rate recovery, and regulatory asset treatment, that remain vital in removing regulatory barriers and other impediments to transmission investment.

Commissioner Richard Glick dissented in part from the NOPR.

The NOPR seeks comment on these proposed reforms 90 days from the date of its publication in the Federal Register.

II. Summary of Proposed Revisions

A. Benefits Test

FERC proposes to revise its existing transmission incentives policy and corresponding regulations (Transmission Incentives Regulations) to incorporate a benefits test that applicants must satisfy in order to receive transmission incentives. The benefits test would replace the currently-effective nexus test.[3] The NOPR proposes to focus the Commission’s decision to grant incentives on the benefits to consumers of transmission infrastructure investment as identified by Congress in FPA Section 219, specifically ensuring reliability and reducing the cost of delivered power by reducing transmission congestion.[4]

The NOPR envisions separate analyses for determining eligibility of distinct ROE incentives for a transmission project’s economic or reliability benefits. For an economic benefits showing, an applicant must demonstrate that the incentives it seeks meet a specified benefit-to-cost threshold. For a reliability benefits showing, an applicant must provide a significant and demonstrable reliability enhancement.[5]

FERC plans to eliminate the current requirement that an applicant seeking a transmission project-specific ROE incentive must demonstrate that the base ROE or non-ROE incentives are insufficient to adequately address the needs of these transmission projects before seeking an ROE incentive.[6] Under the proposed benefits test, no such demonstration would be required for an applicant to request a project-specific ROE incentive.

Applicants seeking incentives remain able to seek expedited declaratory orders on incentive proposals before submitting a filing for approval under FPA Section 205 for inclusion of the incentives in their transmission rates.[7]

B. Incentive ROE Reforms

The NOPR proposes a series of transmission ROE incentives designed to ensure that returns on equity attract investment in the kinds of transmission infrastructure that provide high economic benefits to consumers through congestion relief or that enhance reliability.

1. ROE Incentive for Economic Benefits

As detailed in the NOPR, applicants may seek ROE incentives for transmission projects that provide sufficient economic benefits, as measured by “the degree to which such benefits exceed related transmission project costs.”[8] The NOPR would to allow a 50-basis-point ROE incentive for transmission projects that meet an ex-ante benefit-to-cost threshold, described below, and 50 additional basis points for transmission projects that demonstrate on an ex-post basis that they are able to satisfy a higher benefit-to-cost threshold when constructed.[9]

FERC proposes to calculate economic benefits of a transmission project based upon the adjusted production costs or similar measures of congestion reduction or certain other quantifiable benefits that are verifiable and not duplicative. The NOPR provides that, in addition to adjusted production cost modeling, types of load cost savings, capacity benefits, and avoided local transmission project costs approaches could be used to satisfy the economic benefits test. The NOPR further establishes a rebuttable presumption that economic benefits measured in benefit-to-cost ratios derived by RTOs for transmission projects within their footprints should be included in an applicant’s transmission project’s benefits, and measured at the time the RTO finalizes its analysis of potential economic transmission projects within its region for purposes of the ex-ante evaluation. The NOPR invites comment on these net benefits measurement approaches, as well as on RTO practices regarding the dissemination of production cost modeling information and the derivation of benefit-to-cost ratios.[10] In non-RTO regions, the NOPR invites comment on the availability and accessibility of adjusted production cost and similar economic benefit measurement data that applicants could use to analyze the economic benefits of a transmission project for purposes of seeking an ROE incentive.[11]

The NOPR provides that transmission projects should offer substantially more net economic net benefits than the average transmission project to be eligible for an incentive premised upon economic benefits. To that end, the NOPR proposes to establish separate benefit-to-cost thresholds for economic incentives based on the cost of the transmission project, with $25 million serving as the dividing line between small system modifications and significant transmission facility expansions. For small transmission system modifications to be eligible for an ex-ante economic benefits ROE incentive, the NOPR proposes that the benefit-to-cost ratio must exceed the ratio for the 75th percentile of transmission projects studied, which was 33.91. For significant transmission facility expansions, the NOPR proposes a benefit-to-cost threshold of 3.98 based on the observed ratio at the 75th percentile level of transmission projects studied.[12]

The NOPR also offers an additional 50-basis-point incentive for economic benefits as measured on an ex-post basis. To be eligible for an incentive based on ex-post economic benefits, a transmission project “must exhibit a benefit-to-cost ratio in the top 10 percent of transmission projects at the time of transmission project completion based on applying their actual costs to the projected benefits.”[13] Based on the study period used in the NOPR, the 90th percentile for all transmission projects in the three regions greater than $25 million would be 5.17, and 77.04 for transmission projects equal to or less than $25 million.[14]

2. ROE Incentive for Reliability Benefits

The NOPR proposes an ROE incentive of up to 50 basis points for transmission projects that produce significant and demonstrable reliability benefits above and beyond the requirements of the North American Electric Reliability Corporation (NERC) reliability standards. As non-exclusive examples, the NOPR lists transmission projects that: (i) significantly increase import or export capability between balancing authorities; (ii) result in an Interconnection Reliability Operating Limit being downgraded to a routine System Operating Limit; (iii) improve the bulk power system’s ability to operate reliably during foreseen and unforeseen contingencies beyond the NERC transmission planning requirements or other local planning criteria; (iv) reduce the complexity of the transmission system by eliminating the need for one or more remedial action schemes; or (v) use network management technologies, such as dynamic line ratings, power flow controls, or transmission topology optimization.[15]

Applicants will need to support their requests for ROE incentives based on reliability benefits by providing a quantitative analysis of a transmission project’s potential reliability benefits, including reduced loss of load probability, reduced unserved energy under various contingencies, reductions in reliability unit commitments, increases in import or export capability, and improvements in voltage stability. The NOPR provides that, if an applicant is not able to provide a quantitative analysis, the Commission would consider qualitative demonstrations that a transmission project provides one or more significant and demonstrable reliability benefits to address specific reliability needs.[16]

C. Ensuring Reasonableness of ROE

The NOPR proposes to change the current policy of interpreting FPA Section 219 to require that the ROE, inclusive of any incentives, remains within the base ROE zone of reasonableness. To that end, the NOPR proposes to allow transmission ROE incentives to exceed the zone of reasonableness when added to the base ROE; however, the NOPR proposes to cap total transmission-based ROE incentives to a total of no more than 250 basis points because “base ROE and transmission ROE incentives serve different functions.”[17] Where the base ROE is rooted in the “financial and regulatory risks of an investment,” the incentive ROE is intended “to satisfy discrete policy objectives.”[18]

D. Non-ROE Incentives

FERC plans to continue non-ROE incentives, which are available to “all transmission projects that demonstrate that they either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.”[19] These incentives include: Abandoned Plant Incentive, CWIP Incentive, hypothetical capital structures, accelerated depreciation for rate recovery, and regulatory asset treatment. The NOPR provides that applicants for non-ROE incentives will remain eligible for the rebuttable presumptions that transmission projects which are approved through regional transmission planning processes or state siting approvals ensure reliability or reduce the cost of delivered power by reducing congestion. The NOPR further proposes to allow applicants to request a hypothetical capital structure and will continue to evaluate such requests on a case-by-case basis based on a demonstration that the proposed hypothetical capital structure is suited to the unique circumstances of the transmission project. Additionally, in the transmission planning and selection context, the NOPR proposes to change the effective date for the Abandoned Plant Incentive from the date that the Commission issues an order granting 100 percent recovery of abandoned plant costs to the date that transmission projects are selected in a regional transmission planning process for the purposes of cost allocation.[20]

E. Incentives Available to Transcos

Citing Commission belief that the stand-alone transmission company (Transcos) business model has not enhanced the deployment of transmission infrastructure sufficiently to justify incentives based on this business model beyond those incentives available to all public utilities, the NOPR proposes to eliminate the Transco ROE Incentive and the Transco ADIT Adjustment going forward.[21]

F. Incentives for RTO Participation

FPA Section 219(c) requires FERC to “provide for incentives to each transmitting utility or electric utility that joins a Transmission Organization.”[22] In Order No. 679, FERC found that the incentive for participation in an RTO (RTO Participation Incentive)[23] should be granted on a case-by-case basis to utilities that “join and/or continue to be a member” of an RTO, in recognition of the benefits of such membership and the fact that continuing membership is generally voluntary.[24] In the NOPR, FERC states its belief that the RTO Participation Incentive has encouraged the formation of and participation in RTOs, and has resulted in significant benefits for consumers[25] while at the same time compensating utilities for the ongoing duties and responsibilities of RTO membership.[26] FERC also notes that the duties and responsibilities of RTO membership have increased since Order No. 679, and that these responsibilities persist regardless of whether participation in the RTO is voluntary.[27]

The NOPR proposes that all transmitting utilities that turn over their wholesale transmission facilities to an RTO would receive a fixed 100-basis-point RTO Participation Incentive adder.[28] This incentive would apply both to transmitting utilities joining an RTO for the first time, and to transmitting utilities that may already receive an ROE adder for RTO participation.[29] FERC proposes to apply this incentive regardless of whether the utility’s participation is voluntary or mandated by law.[30] FERC explains that standardizing and increasing the level at which the RTO Participation Incentive is awarded will recognize the increased customer value, as well as increased duties and responsibilities associated with RTO membership since Order No. 679 was issued.[31] FERC also states that it will not withhold the RTO Participation Incentive from entities that are required to join an RTO by law, explaining that the benefits from RTO membership are significant regardless of whether participation is voluntary,[32] and that doing so would create an uneven playing field and distort investment decisions within interstate corporate families and within multistate RTOs.[33]

FERC proposes to continue to permit utilities to recover the prudently incurred costs associated with RTO participation in their jurisdictional rates.[34] FERC requests comment on this proposal, including what process it should adopt to implement the 100-basis-point RTO Participation Incentive for existing transmitting utility rates.[35]

G. Incentives for Transmission Technologies

FPA section 219(b)(3) directs FERC to encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve transmission facility operation. Currently, FERC considers the incorporation of advanced technologies as part of the risks and challenges of a transmission project that may warrant an ROE increase. But rather than using a standalone incentive, FERC currently evaluates deployment of advance technologies as part of its overall nexus analysis.[36]

In the NOPR, FERC explains that this approach to incentivizing transmission technologies has not been effective,[37] and proposes two new incentive rate treatments, intended to work in conjunction, for transmission technologies that: enhance reliability, efficiency, capacity, and improve the operation of new or existing transmission facilities; and that meet the economic benefits ROE incentive benefit-to-cost threshold proposed in the NOPR.[38] These incentives include: (1) Transmission Technology Incentive and (2) Deployment Incentive.[39]

1. Transmission Technology Incentive

FERC proposes to permit utilities to apply for a 100-basis-point ROE Transmission Technology Incentive based on the cost of the specified transmission technology project, and to apply this incentive to technologies deployed on either a new or existing transmission facility, subject to the overall 250-basis-point cap.[40] Because this proposed incentive is only applicable to the costs of the particular transmission technology (including costs awarded regulatory asset treatment), FERC proposes that the amount included in the 250-basis-point limit will be calculated on a weighted average based on the cost of the technology relative to the cost of the entire transmission project.[41]

FERC seeks comment on: the amount of this incentive; its limitation to the cost of the specified transmission technology project only; its inclusion in the 250-basis-point cap on a weighted average; its proportionality to the benefits offered to consumers by eligible transmission technologies; and its sufficiency in attracting investment in such transmission technologies.[42]

2. Deployment Incentive

FERC proposes to permit up to two years of initial costs for the installation and operation of an eligible transmission technology that would traditionally be expensed in the year incurred to be deferred as a regulatory asset and amortized over a five-year period.[43] The two-year period of cost eligibility will begin at the procurement stage, exclusive of planning activities, and the incentive will be permitted only one time per technology per applicant.[44]

FERC explains that the Deployment Incentive is intended to ease the implementation burden for transmission technologies and to provide additional cash flow in the form of an immediate earned return. According to FERC, consumers will receive increased efficiency and congestion savings when these technologies are deployed. FERC seeks comment on: (1) the types of costs that are not currently capitalized and not eligible for the recovery of prudently-incurred pre-commercial operation costs that should be eligible for regulatory asset treatment; (2) the duration of the regulatory asset treatment; (3) the total amount of costs for deploying certain eligible transmission technologies; and (4) whether these proposed incentives are sufficient to overcome obstacles to the first deployment of an eligible transmission technology.[45]

3. Eligibility and Requirements

In order to obtain either of the transmission technology incentives, FERC proposes to require public utilities to submit an application that includes a transmission technology statement. The statement should demonstrate: how the technology enhances reliability, efficiency, capacity, and improves the operation of new or existing transmission facilities; the expected benefits of deployment; the cost of the transmission technology project; the cost of the overall transmission project (if not a stand-alone technology project); the expected useful life of the asset; and that the technology meets the NOPR’s proposed economic benefits threshold.[46] Public utilities granted a transmission technology incentive will also be required to submit an annual informational filing for three years after the incentive is granted, detailing the progress of the technology, obstacles to its deployment and efforts to overcome them, lessons learned, and any quantifiable data measuring the benefits of the transmission technology project.[47]

In addition, FERC proposes to allow pilot programs[48] for eligible transmission technologies to receive a rebuttable presumption of eligibility for the Transmission Technology Incentive and the Deployment Incentive. Utilities that have completed a pilot program for an eligible transmission technology but have not moved to deployment will be eligible for the rebuttable presumption if they meet the pilot program criteria and demonstrate a plan for higher deployment. FERC seeks comment on the limitations of pilot programs—specifically, on the percentage of deployment and duration of the pilot.[49]

H. Disclosure of Anticipated Incentives

FERC seeks comment on whether it would be useful to require a public utility seeking incentives to disclose all reasonably anticipated incentives to transmission planning regions as part of the utility’s transmission project proposal, and whether such a requirement should apply to all incentive applications, or only to incentive applications for an increased ROE.[50]

I. Program Management

1. Form 730 Proposed Format Changes

Under the NOPR, public utilities that have been granted incentive rate treatment will still be required to file a Form 730[51] on an annual basis. FERC proposes to make certain formatting changes to the Form 730 in order to make the form easier to interpret, and the reporting requirement less burdensome.[52] FERC explains that the information collected with the current Form 730 is insufficient to determine the effectiveness of individual incentive grants, or to evaluate its overall incentives program.[53] The NOPR proposes, and invites comment on, the following formatting modifications:

  • Require Table 1 data to display project-by-project data instead of aggregated data.
  • Identify each transmission project by a public utility-created transmission project code in each record of Table 1 and Table 2 to aid in merging the tables.
  • Add the report year to each record of Table 1 and Table 2.
  • Add the aggregate of actual spending on each transmission project prior to the report year to determine total actual spending on each transmission project for each year.
  • Add the aggregate of projected spending on each transmission project more than five years beyond the report year to estimate projected spending on each transmission project for each year.
  • Include a new column entitled “Notes on Table 1” that permits a 60-character text string, so public utilities can explain any issues in the data, and/or to add a footnote to describe issues in as much detail as necessary.
  • Include Project Voltage as a field in Table 2.
  • The data in Table 2 must be known as of midnight on December 31 of the record year.
  • Modify the data in the column titled, “If Project Not On Schedule, Indicate Reasons For Delay” in Table 2 to a 60-character text string. Public utilities may also add a footnote to explain the reasons in more detail.
  • Report Form 730 data in eXtensible Business Reporting Language (XBRL) format.[54]

2. Scope of Public Utility Reporting Obligation

Currently, FERC requires utilities to report information on the Form 730 only if the project costs $20 million or more.[55] In order to make Form 730 a more comprehensive forecast tool, FERC proposes to eliminate the $20 million threshold, and to require all public utilities that receive an incentive, other than the RTO Participation Incentive, to submit information on the Form 730 regardless of the project’s size. Public utilities receiving the RTO Participation Incentive will be required to report only for transmission projects that cost more than $3 million. FERC seeks comment its elimination of the $20 million threshold and the $3 million partial retention for some public utilities.[56]

3. Benefits Reporting in Form 730

In order to effectively evaluate the benefits and monitor the progress of transmission projects that have received incentives, FERC proposes to require transmission projects that are $25 million or more to report on expected and actual transmission project benefits for the first five years of the project’s implementation.[57] FERC proposes the following modifications to the Form 730, and requests comment on the burden to public utilities to provide this information:

  • Add a new column to Table 1 for the expected annual benefits of each transmission project.
  • Add a new Table 3 to record actual estimated benefits for each year for up to five years after the date of completion of the transmission project.
  • Incorporate the data in Tables 1 through 3 of Form 730 as new schedules in Form 1.
  • Report estimated annual economic benefits of each transmission project under construction that receives any transmission incentive using the same methodology that would have been used to justify an economic transmission incentive regardless of whether that transmission project actually received an economic transmission incentive. Where possible, calculate such benefits using the same methodology as the RTO.
  • Report actual annual economic benefits of completed transmission projects that received any transmission incentive using actual data calculated using the same methodology that would have been used to justify an economic transmission incentive regardless if that transmission project actually received an economic transmission incentive. Where possible, calculate such benefits using the same methodology as the RTO.[58]

III. Commissioner Glick Partial Dissent

In a separate statement, Commissioner Glick states his support for FERC’s proposal to eliminate Transco-specific incentives, and for FERC’s proposal to award incentives based on a transmission facility’s benefits, rather than its risks and challenges.[59] However, Commissioner Glick expresses concern regarding the NOPR’s application of the benefits test, its failure to address transmission projects serving public policy purposes, its retention and expansion of the RTO Participation Incentive, its 250-basis-point cap on total ROE incentives, and on what Commissioner Glick argues are inadequate incentives to deploy advanced transmission technologies.

With respect to the NOPR’s proposed focus on project benefits, Commissioner Glick argues that FERC will in effect be providing handouts to projects with certain characteristics deemed beneficial, without requiring any showing that the incentive will result in more projects with that particular characteristic.[60] Commissioner Glick also argues that the proposed benefits test directs too much focus on quantitative benefits of transmission projects that are already likely to be selected in regional transmission planning processes, and fails to incentivize transmission projects that may bring more qualitative benefits that are not currently receiving adequate attention.[61] Commissioner Glick encourages commenters to discuss the NOPR’s proposal to create a rebuttable presumption that the measures used to evaluate an economic transmission project’s benefit-cost ratio in a regional transmission planning process should be used to determine its benefits when awarding incentives, expressing concern that this presumption could result in incentives being allocated disproportionately.[62]

Commissioner Glick also expresses concern with what he terms the “elephant in the room”—that the NOPR fails to address transmission projects serving public policy purposes.[63] Commissioner Glick encourages commenters to address this issue, stating that a record on how to develop such incentives will be important going forward, even though such incentives have been omitted from the NOPR.

Next, Commissioner Glick suggests that FERC tailor incentives for transmission owners considering joining an RTO, rather than offering an RTO Participation Incentive to transmission owners that join or remain in an RTO, whether that membership is voluntary or mandated by law.[64] Commissioner Glick argues that doing so would adhere more closely to the statutory text of FPA Section 219(c) and would avoid offering “gratuitous handouts at customers’ expense.”[65]

With respect to the proposed 250-basis-point cap on overall ROE, Commissioner Glick states that the record supporting such a change is “thin, to put it mildly,” and encourages commenters to address whether such a cap is appropriate to protect customers and ensure resulting rates remain just and reasonable.[66]

Finally, Commissioner Glick expresses concern regarding the NOPR’s “tepid” incentives for transmission and grid-enhancing technologies, arguing that such technologies have the potential to reduce congestion and enhance reliability at a fraction of the cost of conventional solutions, and that FERC’s proposal to create an ROE adder for these technologies is unlikely to create the impetus needed to deploy such projects.[67] In addition to the “carrot” ROE adder for such projects, Commissioner Glick encourages commenters to address how FERC might employ the “stick” by requiring deployment or mandating formal consideration of such projects in regional transmission planning processes.[68]

[1] DISCLAIMER: THIS SUMMARY IS PROVIDED FOR INFORMATIONAL PURPOSES ONLY AND DOES NOT CONSTITUTE LEGAL ADVICE ON ANY PARTICULAR QUESTION, NOR SHOULD IT BE CONSTRUED TO CREATE AN ATTORNEY-CLIENT RELATIONSHIP.

[2] Electric Transmission Incentives Policy Under Section 219 of the Federal Power Act, 170 FERC ¶ 61,204 (2020) (hereinafter “NOPR”).

[3] NOPR at P 35. The currently-effective nexus test requires that “applicants demonstrate a connection between the total package of incentives sought and the proposed investment, in light of the risks and challenges facing a transmission project seeking incentives under FPA Section 219.”

[4] Id. at PP 34-36.

[5] Id. at P 37.

[6] Id. at P 39.

[7] Id. at P 40.

[8] Id. at P 42.

[9] Id. at P 43 (noting that both regional and local transmission projects are eligible for this economic benefits ROE incentive).

[10] Id. at PP 48-52.

[11] Id. at P 53.

[12] Id. at PP 56-58.

[13] Id. at P 59.

[14] Id.

[15] Id. at PP 65-72.

[16] Id. at PP 74-75.

[17] Id. at PP 76-78.

[18] Id.at P 78 (quoting Promoting Transmission Investment through Pricing Reform, Order No. 679, 116 FERC ¶ 61,057 (2006), on reh’g, Order No. 679-A, 117 FERC ¶ 61,345 at n. 19 (2006), on reh’g 119 FERC ¶ 61,062 (2007)).

[19] Id. at P 82.

[20] Id. at PP 82-84.

[21] Id. at PP 85-91.

[22] Id. at P 92.

[23] Although the Commission declined to create a generic ROE incentive for RTO membership in Order No. 679, “applicants have subsequently requested a uniform, 50-basis-point level for demonstrating they have joined an RTO or ISO, which the Commission has granted without modification.” Id.

[24] Id. (citing Order No. 679, 116 FERC ¶ 61,057 at P 326).

[25] FERC stated that these benefits include access to large competitive markets, optimization of the transmission system, regional transmission planning, reduction of the costs of carrying reserves, and increased access to an expanded set of diverse resources. Id. at P 93.

[26] Id. at PP 93-95.

[27] Id. at P 96. According to FERC, these duties include: loss of operational control of transmission facilities to a third party; an obligation to build new transmission facilities at the direction of the RTO; diminished decision-making control over assets while retaining the responsibility of maintaining the system; meeting reliability standards; obligations to obey RTO rules; and an obligation to provide electric service even when foundational agreements can change, thereby changing the terms and conditions under which the transmitting utility initially agreed to participate in the RTO. Id.

[28] FERC proposes to combine and modify Sections 35.35(b)(2) and 35.35(e) of its currently effective transmission incentives regulations into Sections 35.35(f) of its proposed revised transmission incentives regulations. Id. at P 97.

[29] Id.at P 99.

[30] Id. at PP 97-99.

[31] Id. at P 97.

[32] Id. at PP 94-95.

[33] Id. at P 98.

[34] Id.

[35] Id. at P 99.

[36] Id. at P 100.

[37] FERC explains that many transmission technologies are smaller in scale and do not face the same challenges as large, capital-intensive transmission projects (such as siting and regulatory approvals), and that many of the costs of transmission technologies are not currently capitalized and do not benefit from ROE incentives. Id. at P 100.

[38] See supra Section II.B.1. FERC gives a few examples of eligible technology types, including advanced line rating management, transmission technology optimization, and power flow control, but declined to list the types of technologies eligible for transmission incentives, instead explaining that it will make a case-by-case determination of eligibility based on the characteristics of the technology and the benefits offered. Id. at P 102.

[39] Id. at P 103.

[40] Id at P 105.

[41] Id. FERC provides the following example: “For instance, a developer with a $100 million transmission project that is awarded the Transmission Technology Incentive on a $10 million transmission technology project sub-component, would contribute 10 basis points to its 250-basis-point cap. Conversely, if a transmission project developer is awarded the Transmission Technology Incentive for a stand-alone transmission technology project, the incentive would contribute 100 basis points to its 250-basis-point cap.” Id. at P 106.

[42] Id. at P 107.

[43] Id. at P 108 (proposing to add Section 35.35(e)(2) to its transmission incentives regulations).

[44] Id. at PP 108-09.

[45] Id. at P 110.

[46] Id. at P 111 (proposing to add Section 35.35(e)(3) to FERC’s transmission incentives regulations).

[47] Id. at P 113 (proposing to add Section 35.35(e)(5) to FERC’s transmission incentives regulations).

[48] FERC defines a pilot program as “a public utility-led deployment of an eligible transmission technology, with costs under $25 million for each eligible transmission technology project, that has not been deployed to or operated on more than five percent of the applicant’s transmission system, and has a maximum duration of two years from installation to completion.” Id. at P 112.

[49] Id. (proposing to add Section 35.35(e)(4) to FERC’s transmission incentives regulations).

[50] Id. at P 114.

[51] Section 35.35(i) of FERC’s transmission incentives regulations requires public utilities that have been granted incentive rate treatment to file a Form 730 on an annual basis. Id. at P 117. Order No. 679 created Form 730, which contains two reporting tables: Table 1 is an aggregate of the spending by a public utility over all the transmission projects that received incentives; Table 2 is a project-by-project status update. Id. at P 116.

[52] Id. at P 117.

[53] Id. at P 115.

[54] Id. at P 118. Regarding the change to XBRL format, FERC explains that this will increase efficiency, consistency, and flexibility. Moving to XBRL for the Form 730 is consistent with FERC’s planned change to XBRL data for Form 1 reporting; it is the international standard for digital reporting; and it provides an efficient way to exchange information while standardizing how the characteristics of the information are captured. Id. at PP 119-121.

[55] Id. at P 122 (citing Order No. 679, 116 FERC ¶ 61,057 at P 370).

[56] Id.

[57] Id. at PP 124-25.

[58] Id. at P 125.

[59] Electric Transmission Incentives Policy Under Section 219 of the Federal Power Act, 170 FERC ¶ 61,204, at P 2 (2020) (Glick, Commissioner, dissenting).

[60] Id. at P 4.

[61] Id. at PP 7-9.

[62] Id. at P 11.

[63] Id. at P 13.

[64] Id. at PP 18-25.

[65] Id. at P 25.

[66] Id. at PP 26-30.

[67] Id. at P 32.

[68] Id. at P 33.

On March 19, 2020, FERC granted Pacific Gas and Electric Company’s (“PG&E”), licensee for the Kilarc-Cow Creek Hydroelectric, Project No. 606 (“Project”), request for a Declaratory Order finding that the California State Water Resources Control Board (“California Board”) waived its authority to issue a water quality certification under section 401 of the Clean Water Act.  FERC’s recent opinion continues its application of the D.C. Circuit’s opinion in Hoopa Valley Tribe (see December 11, 2019 edition of the WER), which held that section 401 provides one year as the absolute maximum for a state to act on a water quality certification application and rejected an extension of the statutory deadline via a coordinated withdrawal-and-resubmission scheme between an applicant and the state certifying agency. Continue Reading Federal Energy Regulatory Commission Continues to Apply D.C. Circuit Ruling

On Thursday, March 19, in lieu of its monthly Commission meeting, FERC issued a Notice regarding its response to the Novel Coronavirus Disease (“COVID-19”) and the President’s March 13 declaration of a National Emergency.  Chairman Neil Chatterjee delivered comments about the Notice and the Commission’s operations in the coming weeks and months. Continue Reading FERC Issues Notice on Commission Operations During COVID-19 Emergency

On March 10, 2020, FERC granted rehearing of its November 9, 2018 order that accepted revisions to ISO New England Inc.’s (“ISO-NE”) Tariff modifying the calculation of the economic life of existing capacity resources seeking to retire or permanently leave the ISO-NE capacity market, to better reflect competitive market behavior. FERC determined the benefits of the Tariff revisions did not outweigh the disruption to capacity market participants’ settled expectations and, therefore rejected the economic life revisions in their entirety, effective August 10, 2018, and declined to rerun any Forward Capacity Auctions (“FCA”) to preserve market certainty.   Continue Reading FERC Reversal Rejects ISO-NE Proposal for Calculating De-List Bids

On March 10, 2020, FERC accepted and suspended Midcontinent Independent System Operator, Inc.’s (“MISO”) proposal to allow for the selection of a storage facility as a transmission-only asset (“SATOA”) in the MISO Transmission Expansion Plan (“MTEP”). FERC found that MISO failed to demonstrate that the proposal was just and reasonable and not unduly discriminatory, and directed staff to convene a technical conference to explore issues including:

  1. Evaluation and selection criteria for a SATOA in the MTEP;
  2. Permitted market activities for SATOAs and potential wholesale market impacts;
  3. How MISO’s current formula rate structure accommodates cost recovery for SATOAs;
  4. A SATOA’s potential impact on MISO’s generator interconnection queue; and
  5. Operating guidelines that will apply to a SATOA.

Continue Reading FERC Orders Technical Conference on MISO’s Proposal to Include Storage in its Transmission Planning Process