Page 1126 – RTO Insider

July 19, 2020March 6, 2026

RTOs Move Closer to Full Order 841 Implementation

PJM, CAISO and SPP took a step closer Thursday to the full implementation of Order 841 with FERC’s partial acceptance of their Tariff revisions.

Order 841, issued in February 2018, directed RTOs and ISOs to remove barriers to the participation of energy storage resources (ESRs) in their wholesale electric markets.

The commission accepted PJM’s compliance filing — its third in response to the order — subject to yet another revision, calling for the Tariff to state that the RTO will not charge a distribution-connected ESR for charging energy if the distributor is unwilling or unable to net out any retail energy purchases associated with the ESR’s wholesale charging activities from the host customer’s retail bill (ER19-469).

FERC said PJM did not follow the proposed language in its second order on compliance, instead filing Tariff language specifying that the provision only applies to an ESR that is “co-located with end-use load.”

“We are concerned that this language could exclude a distribution-connected energy storage resource that is not directly on the site of end-use load but nonetheless receives a retail bill because it is located behind a distribution utility meter,” the commission wrote.

The commission directed PJM to submit a further compliance filing to either clarify how its proposed Tariff provisions prevent all distribution connected ESRs from paying twice for the same charging energy or propose Tariff revisions to ensure the outcome. The RTO has 90 days to make the filing.

FERC did accept PJM’s proposal to modify its participation model to more appropriately account for an ESR’s state of charge, maximum state of charge and minimum state of charge by using bidding parameters incorporated into its day-ahead and real-time market clearing engines. It also accepted the RTO’s proposal to add Tariff definitions of bidding parameters that include: minimum and maximum charge limit; minimum and maximum discharge limit; and charge and discharge ramp rate.

The provisions in the compliance filing are effective retroactively to Dec. 3, 2019, with a limited number of revisions to become effective March 31, 2024, subject to the further compliance filing.

CAISO Compliance

CAISO also edged closer to full acceptance of its energy storage market participation rules when FERC approved nearly all the provisions included in the ISO’s second Order 841 compliance filing (ER19-468).

The commission approved CAISO’s energy storage participation model last November (becoming effective Dec. 3, 2019) but directed the ISO to:

revise its Tariff to include a “basic description” of its metering methodology and accounting practices for storage resources;
explain how the metering and accounting practices allow storage resources to participate in both wholesale and retail markets, or revise its Tariff to allow storage resources that provide retail services to also participate in CAISO’s wholesale market; and
revise its Tariff to explain that if an ESR’s host utility is unwilling or unable to net out any energy purchases associated with the resource’s wholesale charging activities from the resource’s retail bill, then CAISO would be prevented from charging wholesale rates for charging energy for which the resource is already paying retail rates.

FERC on Thursday approved of CAISO’s proposal to address the first shortcoming by creating a new Tariff section, 10.1.3.4, which describes the metering and accounting for storage resources, including provisions meant to ensure that resources avoid double-billing for retail and wholesale participation.

The section also contains an explanation that resources can elect to become either: “metered entities,” which pay higher upfront costs for a more complex certification process that helps resources avoid ongoing costs related to meter data validation and avoid certain penalties because they are being instantaneously metered by CAISO; or “scheduling coordinator metered entities,” which must comply with several initial and ongoing requirements to meet Tariff requirements but can avoid some upfront costs and are allowed to propose “unique, complex metering configurations” for ISO approval.

FERC Order 841 Implementation — Invenergy’s Grand Ridge Battery Storage Facility in Illinois | *BYD*

The commission also accepted related Tariff provisions giving both types of metered entities flexibility in how they configure their metering systems to avoid “commingling” of retail and wholesale meter data.

“CAISO states that electric storage resources — especially those that may participate in retail and wholesale markets simultaneously — have highly variable metering needs, local regulatory requirements and configurations,” FERC wrote. “CAISO states that by including simple, flexible Tariff provisions, CAISO will avoid a one-size-fits-few approach and instead be able to review each storage resource’s proposal to ensure CAISO receives settlement quality meter data for wholesale charges only.”

The only sticking point in the compliance filing: CAISO’s solution for resources unable to net out wholesale energy purchases from their retail bills. While FERC approved a proposed requirement that a host utility distribution company or retail utility verify in writing to the ISO when it is unable or unwilling to net out from its retail billing any wholesale energy purchases, the commission pointed out that the provision applies only to a “non-generating resource” (NGR), a resource type created by CAISO to accommodate market participation by resources that can both inject or withdraw energy from the grid.

“We note that this provision only applies to NGRs, and therefore does not apply to all electric storage resources, as required by the commission’s directive in the first compliance order,” FERC wrote, directing CAISO to submit a third compliance filing that clarifies the rule will apply to storage resources participating in the market as other resource types.

SPP Compliance

FERC accepted and rejected in part SPP’s second attempt to comply with Order 841, requiring yet another compliance filing within 90 days (ER19-460).

The commission found that the RTO’s proposed Tariff revisions partially complied with the order’s requirements on registering ESRs. It said it was “concerned” that SPP’s provisions requiring ESRs certify that their wholesale market participation “is not precluded under the laws or regulations of the relevant electric retail regulatory authority” could be interpreted “to include an opt-out that the commission declined to provide, which would be inconsistent with Order Nos. 841 and 841-A.”

Other than that, FERC said, SPP’s revisions describing ESRs’ metering methodology and accounting practices “provide additional guidance to market participants and appropriately reference additional documents that provide implementation details.”

SPP made its first compliance filing in December 2018. FERC last October accepted and rejected it in part, ordering a second compliance filing. (See FERC Partially OKs PJM, SPP Order 841 Filings.)

The grid operator in December asked to delay the Tariff revisions’ effective date, citing issues with software implementation and its settlement management system. The commission set an effective date of Aug. 5, 2021. It rejected a subsequent SPP request to set another date.

July 19, 2020

CAISO Edges Closer to Order 845 Compliance

CAISO moved a step closer to meeting Order 845 requirements last week when FERC accepted most Tariff revisions included in a second compliance filing after the ISO’s first attempt met a raft of rejections in February (ER19-1950).

Two inland West utilities, Public Service Company of Colorado (PSCo) and Deseret Generation & Transmission Cooperative, also nearly reached compliance with the order, which FERC issued in 2018 to amend its pro forma large generator interconnection agreement and large generator interconnection procedures to increase the transparency and speed of the interconnection process.

RTOs, ISOs and utilities have struggled to fully comply with the order, with most facing FERC directives to submit second — and even third — compliance filings. (See CAISO, NYISO, Companies Win Partial OK on Order 845.)

The commission on Thursday approved the majority of CAISO’s proposed revisions in the second round, including those dealing with:

transparency around study models and assumptions, with CAISO planning to maintain an Open Access Same-Time Information System link to a secured section of its website containing interconnection base case data;
interconnection study deadlines, with CAISO incorporating FERC’s pro forma language into its Tariff to describe how the ISO will provide summary statistics on the processing of interconnection studies;
provisional interconnection service, with the ISO removing language restricting the use of limited operation studies to instances when a transmission owner is unable to complete facilities by the interconnection customer’s commercial operation date; and
surplus interconnection service, with FERC agreeing to CAISO’s plan to rely on existing Tariff provisions to memorialize the transfer of such service.

But FERC only partially accepted a proposal outlining the ISO’s planned response to an interconnection customer’s request to incorporate a technological advancement into a project after that project has entered the queue, which could trigger the need for additional studies ahead of a final interconnection study.

While CAISO’s second compliance filing offered no revisions to the plan FERC originally rejected in February, the filing did provide additional details explaining the ISO’s approach. CAISO explained that its “material modification assessment process” enables interconnection customers to make modifications to their projects without losing their place in the queue. Additionally, the ISO offers a “permissible technological advancement process” as a faster, cheaper alternative for “simple” modifications.

“Rather than create a limited, rigid list of permissible technological advancements, CAISO created a list of known permissible advancements and allowed for any other advancements that meet CAISO’s definition of permissible technological advancement,” FERC noted.

CAISO FERC Order 845 — Wind farm near Palm Springs, Calif. | © *RTO Insider*

Under the proposed Tariff provision, customers seeking to make technological changes to their projects would need to advance CAISO a flat $2,500 fee to cover the costs of studying the impacts of the changes. The commission accepted the fee but found that the ISO had not complied with Order 845 requirements and the compliance directives in the February 2020 order “with respect to the requirement that CAISO provide a more detailed explanation of the studies that CAISO will conduct to determine whether the technological advancement request will result in a material modification and determine whether or not a technological advancement is a material modification within 30 calendar days of receipt of the initial request.”

FERC also found that the CAISO Tariff’s use of the terms “conditionally assigned network upgrades” and “precursor network upgrades” — instead of the term “contingent facilities” — does not comply with Order 845 and the February compliance directive with respect to interconnection facilities.

“While CAISO states that it will apply the terms ‘conditionally assigned network upgrades’ and ‘precursor network upgrades’ to all facilities identified in the interconnection customer’s study reports, it is unclear how these terms, which by their own names and definitions relate to network upgrades, address interconnection facilities that may also be contingent facilities pursuant to the pro forma LGIP definition of ‘contingent facilities,’” FERC wrote.

The commission directed the ISO to submit a further compliance filing within 120 days addressing the technological changes issue and how it will identify interconnection facilities that are contingent facilities “in light of the fact that the two terms with which CAISO proposes to replace the term ‘contingent facilities’ do not by definition include interconnection facilities.”

Utilities Near Compliance

The commission on Thursday accepted nearly every provision of PSCo’s Order 845 compliance filing but ordered the utility to revise its tariff to explicitly state that it will take no more than 30 days to determine whether an interconnection’s technological change request actually qualifies as a “material modification” requiring additional study (ER19-1864).

Utah-based Deseret similarly came within a hair’s breadth of compliance, with the commission ordering the co-op to specify the deposit that interconnection customers must provide to cover additional studies when submitting a technological change request (ER19-902).

July 19, 2020

FERC Tweaks Orders on Mystic Contract

FERC clarified some aspects of its orders approving ISO-NE’s cost-of-service contract with Exelon’s Mystic Generating Station and ordered the company to make additional compliance filings in three rulings Thursday.

The RTO signed the two-year, $400 million contract to preserve the region’s reliability after Exelon announced plans to shutter the plant when its existing capacity supply obligations expire in 2022.

The commission on Thursday granted limited clarifications on its July 2018 (ER18-1639-001) and December 2018 orders (ER18-1639-002) approving ISO-NE’s agreement for Mystic Units 8 and 9, including payments to the company’s Everett LNG facility. (See FERC Approves Mystic Cost-of-Service Agreement.)

Supporting the rulings were Chairman Neil Chatterjee and Commissioners Bernard McNamee and James Danly. Commissioner Richard Glick, who had opposed the 2018 orders, dissented.

In ruling on rehearing requests on the July order, the commission granted the Massachusetts attorney general’s request for clarification that Mystic must prove its capital expenditures are just and reasonable to recover their costs.

Authority over LNG Terminal Challenged

But the commission majority disagreed with contentions by the AG and New Hampshire Public Utilities Commission that FERC had asserted jurisdiction over Exelon’s Everett LNG facility — the sole source of Mystic’s fuel — by approving the power plant’s fuel costs.

“Review and approval of the fuel supply charge … can include consideration of whether it is just and reasonable for Mystic to include in its rates charges traceable to specific costs that Everett incurred and that are included in the fuel supply charge. The commission’s findings may affect or have implications for Everett but do not constitute an assertion of jurisdiction over (i.e., regulation of) Everett or Everett’s incurrence of costs,” the commissioners said. “We thus disagree with the New Hampshire PUC that the commission is proposing to regulate the rates of an LNG import terminal.”

Mystic Generating Station contract — Exelon’s Mystic Generating Station, on the Mystic River in Everett, Mass. A wind turbine owned by the local water authority to power a pumping station is on the right.

In his dissent, Glick said, “I do not believe that the commission can or should use its authority over wholesale sales of electricity to bail out a liquefied natural gas import facility. …

“Because Everett does not rely on the interstate pipeline grid to acquire natural gas (instead receiving it via ship), it can provide another source of natural gas for the region when the pipeline system becomes constrained, as may happen during stretches of cold weather when heating needs cause demand for natural gas to surge. But Everett apparently depends on its sales to Mystic to remain financially solvent, and letting Mystic retire could indirectly lead Everett to close,” Glick wrote. “It is Everett, not Mystic, that, in fact, provides the purported fuel security benefit underlying this proceeding. Accordingly, the commission has chosen to use its authority under the [Federal Power Act] to retain Mystic in order to keep Everett from going under.”

December 2018 Order

In ruling on challenges to the December 2018 order, the commission rejected concerns regarding anticompetitive behavior as beyond the scope of the proceeding.

“For similar reasons, we find that the issues raised on rehearing about market manipulation and the general functioning of natural gas and electric markets also are beyond the scope of this proceeding. Thus, the commission did not err in failing to take into account potential market manipulation as it relates to the Mystic agreement because sufficient protections exist to protect against this behavior. We reiterate that the commission will continue to monitor, as always, the New England natural gas and electricity markets during the term of the Mystic agreement for anticompetitive behavior and market manipulation.”

The commission rejected Mystic’s claim that a true-up mechanism was unnecessary to protect consumers. “We continue to find that the true-up requirement is not administratively inefficient; rather, it is appropriately transparent to render the rate just and reasonable,” FERC said.

But the commission granted Mystic’s request for clarification regarding the timing of capital expenditure projects.

Clawback Mechanism

In a third order, the commission accepted in part Mystic’s compliance filing on true-up and clawback mechanisms but required the company to make an additional filing regarding the accounting for its purchase price of the plant (ER18-1639-003). The clawback mechanism would require Mystic to refund capital expenditures if the generator chooses to continue participating in ISO-NE’s markets after the termination of the cost-of-service contract.

In a bid to extend Mystic’s contract for an additional year, Exelon last month accused ISO-NE of violating its Tariff by prematurely culling bids received in response to its Boston competitive transmission solicitation. (See Exelon Challenges ISO-NE RFP in Bid to Extend Mystic.)

July 19, 2020

OMS Continues to Press for MISO Dynamic Line Ratings

The Organization of MISO States continues to signal its grid operator that regulators are ready for dynamic transmission line ratings in the footprint.

OMS invited an ERCOT executive to explain the benefits of dynamic line ratings (DLRs) at its board of directors meeting Thursday.

ERCOT Senior Director of System Planning Warren Lasher said DLRs provide value, “especially in off-peak conditions like spring and fall, when you’re likely to see more wind on the system.”

The Texas grid operator now uses dynamic ratings in 60 to 70% of its circuits, Lasher said. He said it uses data lookup tables from transmission owners coupled with local weather data to assign ratings.

“We’ve seen a significant amount of benefits, in two ways really. … We’ve seen reduced congestion, and we’re able to get more lost cost power to our customers. But we also see in our reliability studies that we can schedule more maintenance outages in the spring and fall,” Lasher told regulators.

OMS has recently been in discussions with MISO Independent Market Monitor David Patton about implementing DLRs. OMS President and Minnesota Public Utilities Commissioner Matt Schuerger said in June that the RTO’s ratings are overly conservative, inconsistent and not transparently formed.

MISO Dynamic Line Ratings — | © *RTO Insider*

MISO TOs have also been meeting with Monitor staff to discuss dynamic and ambient temperature-adjusted line ratings, Otter Tail Power’s Stacie Hebert said last month.

The Monitor made implementing DLRs one of five new recommendations late last month in its annual State of the Market report. (See IMM Issues 5 Recs in MISO State of the Market Report.)

During this month’s Market Subcommittee meeting, Patton said the annual value of MISO’s real-time congestion routinely exceeds $1 billion, due in part to “very conservative, static ratings by most transmission operators.”

“I think more are becoming aware of this problem,” Patton said, citing last year’s FERC technical conference and OMS’ interest.

Patton said a “broad adoption” of ambient-adjusted ratings could have reduced congestion costs by as much as $150 million in 2018 and 2019. Over those two same years, had TOs just provided short-term emergency ratings, an additional $114 million could have been saved in congestion, he said.

However, Patton said he’s had little luck so far trying to convince individual TOs to use the technology.

OMS Executive Director Marcus Hawkins said the group will present a position statement in August on the subject. He said he believes MISO’s systems are advanced enough to accommodate the technology.

July 19, 2020

FERC OKs COVID-19 Waiver for MISO LMRs

FERC on Thursday approved MISO’s request for a one-time waiver giving market participants the opportunity to replace load-modifying resources affected by the coronavirus pandemic.

The waiver will permit market participants that manage an affected LMR to register new resources with MISO to fulfill capacity obligations. FERC said the temporary measure will help ensure reliability during the pandemic (ER20-2156).

“We find that the requested waiver addresses a concrete problem because, absent this waiver, market participants whose accredited LMRs will otherwise be unable to meet their performance requirements for the 2020/21 auction,” FERC said.

MISO requested the waiver in late June, saying that some LMRs that cleared the 2020/21 Planning Resource Auction may not be able to perform because of closures of businesses that would otherwise be used to control load. (See MISO Drafts COVID-19 Waiver for LMRs.) The waiver is considered effective July 15, and market participants have 90 days to register replacement LMRs.

FERC said MISO’s plan is reasonable and doesn’t carry unintended consequences for third parties. No parties protested the RTO’s request.

“The waiver will provide certain market participants affected by the COVID-19 pandemic additional flexibility to satisfy their LMR performance requirements; market participants who have registered planning resources that are not affected by the COVID-19 pandemic will not be impacted by this waiver,” the commission said.

This is MISO’s second filing for a waiver of Tariff requirements as the pandemic plays out. Some interconnection queue customers now have longer to secure proof-of-land use for their proposed generation projects. FERC granted MISO’s request for a 60-day extension of its June 25 site control demonstration deadline in May, when the pandemic locked up government offices and held up construction plans (ER20-1794).

July 19, 2020

NYPSC Approves $700 Million for EV Chargers

The New York Public Service Commission on Thursday approved just over $700 million in spending over the next five years to install more than 50,000 light-duty electric vehicle charging stations throughout the state and to prepare pilot programs to accommodate medium- and heavy-duty vehicles (18-E-0138).

The PSC’s order modifies the EV infrastructure development program included in a white paper published last month by it and the New York State Energy Research and Development Authority (NYSERDA). The paper, on the state’s Clean Energy Standard, recommended installing EV charging stations within 10 miles of disadvantaged communities, which the PSC deemed inadequate, so the commission ordered the stations be built within 1 mile of such communities downstate and within 2 miles in the rest of the state.

New York EV Chargers — Projecting the number of DC Fast Chargers required in NY State between now and 2030. | *DPS*

“I think it’s smart that the order places the incentives on site location choice, mainly up to developers who have skin in the game,” PSC Chair John B. Rhodes said. “This order finds that make-ready investments by utilities can support and complement charging investments by private developers.”

Most of the money is allocated to the major utilities in New York for a “Make-Ready Program” of incentives for the installation of light-duty EV Infrastructure for both Level 2 and DC fast-charger stations. The investor-owned utilities are Central Hudson Gas and Electric ($21 million), Consolidated Edison ($234 million), New York State Electric and Gas ($64 million), Niagara Mohawk Power ($112 million), Orange and Rockland Utilities ($19 million) and Rochester Gas & Electric ($31 million).

“Today’s action shows that New York is serious about promoting electric vehicles. The scale of this program is beyond any prior efforts, and it recognizes the need to install vehicle chargers widely around the state. It is a huge step for EVs — and for New Yorkers that are thinking about buying an EV,” Anne Reynolds, executive director of the Alliance for Clean Energy New York, said in a statement.

Focus on Environmental Justice

Kathy Harris of the Natural Resources Defense Council said in a blog post that “the order puts a much-needed focus on ensuring that all New Yorkers have access to clean transportation by developing a $85 million competitive program for innovative projects that will increase clean transportation in environmental justice communities. The investment will consider programs such as electric car sharing and ride sharing, something that was recommended specifically by NRDC and Sierra Club.”

Commissioner Diane Burman voted for the order but said she did not favor having the PSC look to the Climate Action Council to define environmental justice.

“As it may or may not affect the utilities and others that we regulate, and what we are doing from a financial perspective for access to ratepayer dollars, it is really premature and inappropriate for us to say that whatever they decide on the environmental justice definition is good by us,” Burman said.

The Climate Action Council was created under the Climate Leadership and Community Protection Act. It works with regulators, state agencies and NYISO to transition the state’s power sector and entire economy away from fossil fuels and toward renewable energy. (See NY Climate Action Council Looks at Deep Decarbonization.)

The estimated aggregate EV Make-Ready Program budget of $582 million through 2025 represents approximately 70% of the total anticipated make-ready costs of $828 million, the PSC said. The 70% figure represents the anticipated overall program reimbursement when factoring in projects at both the 90% level and the 50% level, the rate depending on meeting program criteria.

The utilities will recover program costs through a combination of rate base and surcharges. In addition, program costs will be allocated to all customer classes based on transmission and distribution revenues, the order said.

Not So Fast

Commissioner John Howard echoed Burman’s remarks on the need for continued diligence on overseeing program implementation and said that planning five years out for “massive EV adoption, in this case an additional 800,000 new vehicles in four years, and millions by 2040,” may not be the best approach in a fast-changing industry.

“The goal is not more EV infrastructure, but rather the goal is more EVs,” Howard said. “While this initiative is important, and big in scale, it is just a component of a larger electric transportation policy that needs to be built out in its entirety, because certain aspects of moving toward an electrified transportation system will impact other aspects of the system.”

Howard said that most experts agree that in the near term, 80 to 90% of EV charging will be done at home or at a convenient workplace location.

“Given that EV technology is changing rapidly, I want to emphasize that this is an enormously dynamic technology, particularly in regard to the range of light-duty vehicles, most of which in the next 18 to 24 months will have a range of at least 250 miles per charge,” Howard said.

He also cautioned on one of the biggest issues confronting the future of EV remote charging, which is the handling of the actual purchase of energy at remote charging stations.

“Currently, the Department of Agriculture and Markets oversees the regulation of devices dispensing fuel for vehicles; however, unlike liquid fuels, which are physically measurable as to the exact quantity and quality of the fuel purchased, electric sales offer unique technical challenges,” Howard said.

In addition to the inspection and enforcement associated with the new EV program, there also is a derived authority that is given to counties and New York City, he said.

“I believe we will have to spend a great deal of time bringing those entities up to speed to match the commerce that we expect,” Howard said. “We are intending to install tens of thousands of new places of commerce that will need to be inspected and monitored. To that extent, I do appreciate the inclusion of a multiagency working group to review the current practices and give guidance to the commission on future actions regarding commerce.”

July 17, 2020

FERC Rejects Net Metering Challenge

FERC on Thursday rejected a request by a purported ratepayer group that could have ended net metering for rooftop solar generation, prompting relief among state regulators and renewable power advocates (EL20-42).

The commission unanimously rejected the New England Ratepayers Association’s (NERA) petition for declaratory order asking it to essentially outlaw net metering by ruling that FERC has exclusive jurisdiction over sales of rooftop solar power.

NERA asked FERC to assert jurisdiction over energy sales from rooftop solar facilities and other distributed generation located on the customer side of the retail meter whenever their output exceeds the customer’s demand or the energy from such generators is designed to bypass the customer’s load.

The association said such transactions were wholesale sales in interstate commerce, which should be priced at the utility’s avoided cost of energy if the sale is made under the Public Utility Regulatory Policies Act of 1978 or a just and reasonable wholesale rate if the sale is made pursuant to the Federal Power Act. Making such sales subject to the FPA might have required individual homeowner-generators to have a rate on file with FERC, a mandate that critics said would virtually eliminate net metering.

FERC Net Metering — Solar panels line the roof of a turkey barn in Iowa. | *Iowa Farm Bureau*

The commission said it was using its discretion in declining to address the issues raised by the petition. “We find that the issues presented in the petition do not warrant a generic statement from the commission at this time,” it said, adding that the petition “does not identify a specific controversy or harm that the commission should address in a declaratory order to terminate a controversy or to remove uncertainty.”

FERC also said NERA did not meet the requirements for an enforcement action under PURPA because such actions are limited to electric utilities and qualifying small power production and cogeneration facilities.

Widespread Opposition

Thousands of individuals and groups filed comments urging FERC to reject the petition. State officials and others alleged it would upset two decades of legal precedent supporting state and local policies used by 2.3 million net metering participants in 49 states. (See Thousands Oppose Bid to Undo Net Metering.)

Other commenters complained NERA was a front for investor-owned utilities and the fossil fuel industry and said its funding made it akin to a trade group.

Only a handful of groups — Americans for Tax Reform, Californians for Green Nuclear Power, CAlifornians for Renewable Energy, Citizens Against Government Waste, Competitive Enterprise Institute and the Heartland Institute — supported the petition.

Questions over Net Metering Remain

Although the commission was unanimous in rejecting the petition on procedural grounds, Commissioners Bernard McNamee and James Danly issued concurrences expressing concern over the substantive issues raised.

“The commission’s order is not a decision on whether the commission lacks jurisdiction over the energy sales made through net metering; nor is it a decision on the merits of the issues raised by and contained in the petition,” McNamee said. “I also note that, as a general proposition, I think it is best to decide important legal and jurisdictional questions, like the ones raised in in the petition, when applying the law to a specific set of facts, such as in a Section 206 complaint, or through a rulemaking proceeding.”

Danly said the petition raised “difficult legal questions,” including the rate treatment for excess generation and the boundary between federal and state jurisdiction.

“I have yet to reach any conclusion regarding either rate treatment or jurisdictional boundaries, but I am certain that these are questions of profound importance and the commission will eventually have to address them,” Danly said. “I am concerned that dismissing the petition on procedural grounds may well result in a patchwork quilt of conflicting decisions if the questions raised in the petition are instead presented to federal district courts across the country. While the federal courts are more than capable of adjudicating pre-emption claims, they are not steeped in the history of the Federal Power Act nor in matters of national energy policy. Confusion, delay and inconsistent rules — some of which will apply to individual states or parts of states — will be the inevitable result.”

NERA President Marc Brown said while he was disappointed by FERC’s decision, he agreed with McNamee’s and Danly’s comments. “We will review the decision to determine the appropriate course of action we will take in order to ensure that ratepayers are protected from the billions of dollars in cost-shifts unwittingly and unfairly paid by ratepayers to support the rooftop solar industry,” he said in a statement.

States, Renewable Supporters Rejoice

State officials and solar power backers nonetheless rejoiced at the ruling.

“This decision is a victory for state regulators and for anyone with a vested interest in net metering policy,” said Mississippi Public Service Commissioner Brandon Presley, president of the National Association of Regulatory Utility Commissioners. “The timing of this decision is also excellent, as NARUC and our members can prepare for next week’s National Policy Summit knowing that we have been able to uphold a core principle of state utility regulation.”

“FERC made the right call,” said Joseph L. Fiordaliso, president of the New Jersey Board of Public Utilities. “New Jersey has relied on FERC precedent for 20 years as we’ve advanced our net metering programs. As we explained in our pleading, net metering is a retail billing method.”

“As the leader of a coalition of conservative groups, solar advocates, state regulators and elected officials from both sides of the aisle in opposition to this petition, [the Solar Energy Industries Association] applauds FERC’s unanimous decision to dismiss this flawed petition,” said SEIA CEO Abigail Ross Hopper. “We are grateful to the state utility commissions and many other partners who strongly opposed this petition. We will continue working in the states to strengthen net metering policies to generate more jobs and investment, and we will advocate for fair treatment of solar at FERC where it has jurisdiction.”

Gregory Wetstone, CEO of the American Council on Renewable Energy, said moving net metering from state to federal jurisdiction “would have severely limited its appeal by lowering participants’ compensation rate.”

“While we are gratified that today’s decision respects the Federal Power Act, we will continue to stay vigilant about protecting forward-looking state energy policies that deliver the pollution-free renewable power Americans want,” Wetstone said.

“Had FERC taken up NERA’s arguments, it would not only have upended the legal basis for net metering programs but would also have severely hampered ongoing efforts by numerous states to develop programs that value [distributed energy resources] with greater accuracy,” the Institute for Policy Integrity at New York University School of Law said.

July 17, 2020

FERC Proposes Tougher Hydro Safety Rules

Responding to the 2017 Oroville Dam incident, FERC on Thursday proposed tougher safety standards for commission-regulated hydropower projects, including a two-tier safety inspection process (RM20-9).

The Notice of Proposed Rulemaking would change part 12 of FERC’s regulations to codify existing guidance requiring certain licensees to develop dam safety and public safety programs and update regulations regarding incident reporting.

The two-tier inspection structure would include a comprehensive assessment and a periodic inspection.

As under current rules, an inspection by an independent consultant would continue to be required every five years, but the scope would alternate between a “comprehensive” assessment and a “periodic” inspection. These inspections will be in addition to FERC staff’s safety inspections.

The alternating two-tier structure is similar to those used by the Bureau of Reclamation and the U.S. Army Corps of Engineers. “The comprehensive assessment would require a more in-depth review than the current part 12 inspection, would formally incorporate the existing potential failure modes analysis process and would require a semiquantitative risk analysis,” FERC said. “The periodic inspection would have a narrower scope than the current part 12 inspection and focus primarily on the performance of project works between comprehensive assessments.”

FERC Hydro Safety Rules — Oroville Dam on Feb. 17, 2017 | *California Department of Water Resources*

FERC also would change how it evaluates the qualifications of the consultants to ensure those conducting inspections have sufficient expertise for site-specific conditions under what is known as the Part 12D Program.

The change follows a recommendation by the Federal Emergency Management Administration that “the inspection team should be chosen on a site-specific basis considering the nature and type of dam … [and] should comprise individuals having appropriate specialized knowledge in structural, mechanical, electrical, hydraulic and embankment design; geology; concrete materials; and construction procedures.”

FERC said the change “reflects the reality that, for many of the hydropower projects under the commission’s jurisdiction, a single independent consultant will not possess the appropriate degree and diversity of technical proficiency necessary to evaluate all aspects of the project.”

The current requirement that an independent consultant be a licensed professional engineer with a minimum of 10 years’ experience in “dam design and construction and in the investigation of the safety of existing dams” would remain. “However, as proposed, this requirement would apply only to the designated independent consultants and not to other supporting members of the independent consultant team,” FERC said.

Oroville Dam Failure

The commission said the proposed changes are the product of recommendations that resulted from an analysis of the February 2017 incident in which the Oroville Dam in California saw major damage to its primary spillway and the first activation of its auxiliary spillway. About 180,000 people were forced to evacuate the surrounding area.

An independent forensics team concluded there was no single cause of the failure of the dam’s spillway. “The incident was caused by a complex interaction of relatively common physical, human, organizational and industry factors, starting with the design of the project and continuing until the incident,” the report said. (See Report: Regulatory Failure Caused Oroville Incident.)

FERC said the changes were “substantially complete” before the failures of the Edenville and Sanford dams in Michigan in May, which it said remain under investigation. About 10,000 central Michigan residents had to evacuate after the failure of the Edenville Dam after heavy rainfall. FERC revoked the dam owner’s license in 2018 over concerns about the facility not being able to handle floods. (See Michigan Dam with Prolonged Safety Issues Fails.)

Comments on the NOPR are due 60 days after publication in the Federal Register.

The commission also said it plans to update and add new chapters to its engineering guidelines document. Drafts will be issued in four advisory dockets: AD20-20 (Supporting Technical Information Document); AD20-21 (Part 12D Program); AD20-22 (Potential Failure Modes Analysis); and AD20-23 (Level 2 Risk Analysis).

July 17, 2020March 6, 2026

FERC Briefs: July 16, 2020

FERC issued a flurry of orders Thursday in its last open meeting before September. (The commission does not meet in August.)

The commission:

CAISO

Ordered additional briefing concerning the calculation of the return on common equity for the DATC Path 15 upgrade to reflect the commission’s revised ROE methodology in Opinions 569 and 569-A. The 84-mile, 500-kV transmission line was built to relieve congestion on the existing Path 15 corridor between northern and southern California (ER17-998-001).
Upheld the result of its January 2020 order that denied Pacific Gas and Electric’s request to recover 100% of the costs from its abandoned Central Valley Power Connect Project (ER19-2582-001).

ISO-NE

Rejected a complaint by Liberty Power Holdings alleging that ISO-NE inappropriately refused to correct a $200,000 billing error resulting from Eversource Energy’s reporting to the RTO load for the Smith & Wesson plant in Western Massachusetts that was mistakenly attributed to Liberty. The commission said Liberty waited too long to seek a correction (EL20-27).
Approved Paper Birch’s request to make wholesale sales of electric energy, capacity and ancillary services at market-based rates in the NYISO and ISO-NE markets. The order said the commission intends to release affiliate information for which Paper Birch requested privileged treatment (ER20-1120).

MISO

Approved an uncontested settlement on Entergy Arkansas’ tariff revisions to ensure the return of excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 (ER18-1247-001).
Upheld the result of its November 2019 order denying the Louisiana Public Service Commission’s complaint alleging that Entergy Services’ off-system sales of energy to third-party power marketers and others for the benefit of Entergy Arkansas violated its generation and transmission pooling arrangement (EL19-50-001). (See La. PSC Complaints Denied in Entergy System Disputes.)

NYISO

Approved in part and denied in part Alcoa Power Generating’s requests for waivers of the requirements for the company’s Tapoco and Long Sault Divisions to have open-access transmission tariffs, maintain an Open Access Same-Time Information System, and comply with the Standards of Conduct and other regulations (ER20-1580).

PJM

FERC orders — DATC Path 15 tx line | *Duke-American Transmission Co.*

Accepted PJM MRC Briefs: Dec. 19, 2019.)
Upheld its January 2020 ruling allowing Potomac-Appalachian Highline Transmission to recover certain advertising and public advocacy costs incurred during its efforts to win approval for the canceled PATH project (ER09-1256-006). (See FERC Grants Recovery on PATH Project Costs.)
Upheld the result of its October 2019 order finding that Dominion Energy Virginia met its burden under Section 205 of the Federal Power Act to show that changing to the 12-coincident-peak transmission cost allocation method is just and reasonable because it is based on Dominion’s transmission planning (ER19-1661-002). (See FERC OKs New Dominion Tx Rate Structure.) (This order had not been posted to the commission’s website as of press time.)
Ordered hearing and settlement procedures in the North Carolina Eastern Municipal Power Agency’s complaint that Duke Energy Progress’ 11% ROE in the companies’ power supply agreement is excessive. It rejected Duke’s request to dismiss the complaint and set a refund effective date of Oct. 11, 2019 (EL20-4).
Ordered a paper hearing to determine a reasonable proxy for determining the capital structure and cost of capital for a merchant generator in response to a petition for a declaratory order seeking guidance on the commission’s cost-based methodology for compensating reactive power generators. The petition was filed by Ares EIF Management; Competitive Power Ventures; Invenergy Thermal Development; J-Power USA Development; Panda Power Generation Infrastructure Fund; Tenaska; and Vistra Energy (EL19-70).
Accepted PSEG Energy Resources & Trade’s tariff revisions to cancel reactive power service tariff records for the Yards Creek Generating Facility. PSEG has proposed selling its 50% interest in the facility, a 420-MW hydro facility in Warren County, N.J. (ER20-1441).
Ordered hearing and settlement procedures on the continued justness and reasonableness of Constellation Power Source Generation’s reactive supply and voltage control rates (ER17-801-006).

SPP

Reduced ITC Great Plains’ adder for being an independent transmission company from 100 basis points to 25 in response to a complaint by the Kansas Corporation Commission (EL19-80).

July 17, 2020

Xcel to Begin Seasonal Operation at 2 Coal Plants

Minnesota regulators this week approved Xcel Energy’s request to operate two of its four coal units on a part-time basis.

The Minnesota Public Utilities Commission’s order Wednesday allows Xcel to idle its Allen S. King Generating Station and Sherburne County Generating Station Unit 2 during the low-demand spring and fall shoulder seasons (20207-164928-02). Xcel asked in December for permission to implement seasonal operations.

Xcel spokesperson Matt Lindstrom said the utility expects to begin seasonal operations this fall.

The PUC said the move will save customers money and represents “a significant step toward meeting Minnesota’s greenhouse gas emission-reduction goal.” It opened a docket last year to investigate the self-scheduling of coal plants in the state.

“This is an important proposal, and I appreciate Xcel Energy bringing it forward,” Commissioner Matt Schuerger said in a release. “I think this highlights Xcel’s focus on saving their customers money, on meeting Minnesota’s environmental policies and in being responsive to the investigation the commission opened.”

The Union of Concerned Scientists applauded the order. The organization has blasted coal self-commitments as expensive and wasteful. In a recent UCS report, the group named Xcel subsidiary Northern States Power one of the worst offenders for uneconomic operation, saying it ran the two coal plants at a $56.9 million loss in 2018. (See UCS Analysis Knocks Coal Self-commitments.)

Xcel Energy coal plants — Sherco Generating Station | *Xcel Energy*

“Xcel Energy was identified as one of the most egregious actors in our analysis, but this news is a welcome change in behavior,” UCS Senior Energy Analyst Joe Daniel said in an emailed statement. “Xcel, like most utilities, was initially reluctant to recognize the costliness of uneconomic self-commitment. But now, both the utility and the state commission have codified a path forward that will save Xcel’s customers millions of dollars, not to mention the public health benefits of reduced pollution.

“Had all utilities given up their uneconomic coal plant operations in 2018, the average family in Minnesota would have saved $5/month on their electricity bills. Unfortunately, other utilities in Minnesota remain reticent when it comes to changing their operations,” Daniel said.

Xcel said its own analysis found the move could save its customers up to $1.45 million in 2020 and up to nearly $3.5 million by 2023. The commission said customer savings could be reflected in Xcel’s next rate case. The utility also estimated it will save about $13 million in operations and maintenance and another $7 million in capital costs through 2023.

Xcel also said seasonal operations would cut its greenhouse gas emissions by 4 million tons in 2020 and a little more than 7 million tons by 2023. The commission said the decrease could account for a quarter of Minnesota’s goal to reduce emissions 30% below 2005 levels by 2025.

“As we lead the clean energy transition with a plan to reduce carbon emissions 80% by 2030 and pursue our vision of 100% carbon-free electricity by 2050, we’ll pursue innovative ideas like seasonally operating our coal plants,” Xcel said in an emailed statement. “These changes will allow us to add more renewable energy for our customers, reduce carbon emissions and save money on fuel and operations costs, savings we can deliver to our customers.”

But even the seasonal operation will be finite, as both plants are slated for retirement by 2030. Xcel said the King plant will close in 2028 while all three Sherco units will shutter by 2030. The closures will make good on the company’s promise to quit coal by 2030 in its Upper Midwest service territory. (See Xcel Latest MISO Utility to Pledge Zero Coal.)

Lindstrom said that as Xcel idles coal plants, it’s focusing on avoiding workforce layoffs. He said the company will probably let some of the positions at its coal plants disappear as employees retire.

“As we look toward the future of our system and the eventual retirement of our coal plants, we are working with employees, communities and other stakeholders to develop specific plans for each area to determine how we can bring new jobs and capital investment to the region. We’ve transitioned coal plants in the past and believe we can do so without layoffs, by normal attrition and job retraining,” Lindstrom said.