Page 1048 – RTO Insider

September 18, 2020November 30, 2023

FERC Opens RTO Markets to DER Aggregation

In a long awaited order, FERC on Thursday ordered RTOs and ISOs to open their markets to distributed energy resource aggregations now largely limited to providing demand response (Order 2222, RM18-9).

The commission voted 2-1 in favor of the order at its monthly opening, with Democratic Commissioner Richard Glick joining Republican Chairman Neil Chatterjee. Republican Commissioner James Danly dissented, saying the order intrudes on state jurisdiction.

The commission said that existing RTO and ISO rules are unjust and unreasonable because of their barriers to broader participation by aggregated DERs in capacity, energy and ancillary service markets. DERs are generally too small to meet the minimum size requirements to participate in the markets and also may be unable to meet certain qualification and performance requirements because of their operational constraints, the commission said.

Removing the barriers will improve competition and allow grid operators to avoid the dispatch of more expensive resources to meet system needs, FERC said. DERs can locate where price signals indicate they’re most needed, reducing congestion costs, it added.

The final rule largely follows the commission’s November 2016 Notice of Proposed Rulemaking (RM16-23, AD16-20). That NOPR also led to Order 841, which removed barriers to energy storage, in February 2018. The commission said then that it needed more information before it could take action on DERs, ordering a technical conference for later that year. (See FERC Rules to Boost Storage Role in Markets.)

100-kW Threshold

Order 2222 defines DERs as resources located on the distribution system or a distribution subsystem, or behind a customer meter, including energy storage, thermal storage, intermittent generation, distributed generation, DR, energy efficiency and electric vehicles and their charging equipment.

It requires RTOs and ISOs to allow DER aggregators to register as market participants under participation models that accommodate their physical and operational characteristics. Grid operators must set minimum size requirements for DER aggregations of no more than 100 kW.

Their revised tariffs must cover technical issues such as:

- - locational requirements for DER aggregations;
  - distribution factors and bidding parameters;
  - information and data requirements;
  - metering and telemetry requirements;
  - coordination among the regional grid operator, the DER aggregator, the distribution utility and the relevant electric retail regulatory authority (RERRA);
  - modifications to aggregations; and
  - market participation agreements.

Chatterjee called the order “a landmark, foundational rule that paves the way for the grid of tomorrow.”

“DERs can hide in plain sight in our homes, businesses and communities across the nation. But their power is mighty,” he said during the open meeting. “Some studies have projected that the United States will see 65 GW of DER capacity come online over the next four years, while others have even projected upwards of 380 GW by 2025. While these estimates and analytical frameworks vary, there is no doubt that investments in these advanced technologies will only accelerate in the years to come, continuing the seismic shifts we’re seeing in our energy landscape.”

Chatterjee also cited the potential for EVs to eventually provide energy, spinning reserves or frequency regulation while plugged in.

No Opt Out

The commission declined to allow local or state regulators to prohibit DERs from participating in the wholesale markets through an opt-out, citing the D.C. Circuit Court of Appeals ruling upholding the commission’s similar position regarding behind-the-meter storage under Order 841. (See FERC Storage Order Survives State Challenge.)

But in recognition of potential cost impacts, the commission created an opt-in mechanism for small utilities, similar to that in Order 719-A for DR. It says RTOs/ISOs must not accept bids from aggregations that include DERs that are customers of utilities that distributed 4 million MWh or less per year unless the RERRA allows it.

The commission also declined to assert jurisdiction over the interconnection of DERs to distribution facilities for aggregations. It “does not require standard commission-jurisdictional interconnection procedures and agreements or wholesale distribution tariffs in connection with DER aggregations,” FERC staff said in a presentation at the meeting. “Rather, state or local law would govern distribution-level interconnections for DERs participating in RTO/ISO markets.”

“If we granted all state regulators the option [to prevent DER aggregation], we’d have a checkerboard approach where some states in an RTO would opt out and some wouldn’t, and it would artificially limit the amount of DER energy and capacity participating in these markets,” Glick said at the meeting. “States still have significant authority to protect distribution system reliability. States will continue to exercise their jurisdiction over interconnection of aggregate DER facilities. … I believe this is a fair compromise.”

Danly Dissent

Danly said he dissented because “regardless of the benefits promised by DERs, the commission goes too far in declaring the extent of its own jurisdiction and because the commission should not encourage resource development by fiat.”

“Why promulgate a rule at all?” Danly asked. “Reluctance to govern by fiat is counseled particularly in a case like this in which the generation resources the majority seeks to promote, by their very nature, inevitably will affect the distribution system, responsibility for which is assigned, with no ambiguity, to the states. We should allow the RTOs and ISOs (or the states or the utilities) to develop their own DER programs in the first instance. If the promises of DERs are what they purport to be, the markets will encourage their development. And if those programs result in wholesale sales in interstate commerce, then the question of the commission’s jurisdiction will be ripe. Commission directives are unnecessary to encourage the development of economically viable resources. I have greater faith in the power of market forces and in the discernment of the utilities and the states.”

The rule will become effective 60 days after publication in the Federal Register, with RTO and ISO compliance filings due nine months after publication.

Reaction

Reaction to the order was generally positive.

Louis Finkel, senior vice president of government relations for the National Rural Electric Cooperative Association, said the group — which had challenged Order 841 before the D.C. Circuit — was happy that FERC included the opt-in for small utilities.

“It is important that the commission has recognized the challenges that this order could pose for small utilities, including virtually all distribution co-ops,” Finkel said. “We look forward to carefully reviewing FERC’s decision in the coming days with the hope that it does indeed preserve state and local regulatory authority over retail electricity sales and local distribution service. Local control is critical, because every co-op is different and is uniquely positioned to meet the specific needs of the community it serves.”

Kelly Speakes-Backman, CEO of the Energy Storage Association, said the order builds on the foundation of Order 841 for distributed energy storage.

“Energy storage is increasingly located on local electric grids, in households and businesses, and is often integrated with distributed generation and controllable loads,” she said. “Enabling these flexible resources to participate together as ‘virtual power plants’ in wholesale markets is a victory for enhancing grid reliability, enabling a more resilient grid and lowering costs for consumers.”

The Advanced Energy Management Alliance said “a participation model for consumers and distributed energy resources enables crucial cost savings, flexibility, resilience and environmental benefits to the grid. … AEMA has been working through ISO stakeholder processes to encourage development of distributed energy resource participation but has also worked with state regulators and utilities to develop solutions through retail and state markets.”

Gregory Wetstone, CEO of the American Council on Renewable Energy, praised the ruling but said the commission was working at cross purposes by “continuing to erect barriers to the entry of new technologies in PJM and NYISO through the use of minimum offer price rules.”

“While today’s order on distributed energy resources follows in the forward-thinking footsteps of Order No. 841 on energy storage, no market can be free until arbitrary resource-specific price floors are eliminated,” he said.

September 16, 2020

NERC RSTC Briefs: Sept. 15, 2020

NERC’s Reliability and Security Technical Committee (RSTC) is planning a follow-up meeting for an undetermined date to finish the remaining agenda items from its regularly scheduled conference call on Tuesday.

The committee managed to complete only about half of the regular agenda because of an extended debate over its plan for taking over the work of the Planning, Operating and Critical Infrastructure Protection committees, which disbanded in March. (See NERC RSTC Briefs: June 10, 2020.)

The RSTC Subgroup Organization and Notional Work Flow Process proposals met with little concern from committee members when presented for approval. However, contention arose when Marc Child, information security program manager for Great River Energy, presented the scope document for the Security Integration and Technology Enablement Subcommittee (SITES). As presented in the scope document, the goal of SITES is to recommend “practices for incorporating cyber and physical security aspects” into utilities’ business activities.

NERC — Carl Turner, Florida Municipal Power Agency | © *ERO Insider*

Though Childs emphasized that the document is still a work in progress and not expected to be finalized until the RSTC’s next scheduled meeting in December, several members expressed surprise at the direction. Carl Turner, engineering services director at Florida Municipal Power Agency, called the document a “pretty dramatic shift” from the purpose of SITES expressed in previous meetings, which he had understood to be about “[ushering] in transformative technologies that change the way we do business.”

“This (presentation) really is … very heavily focused on cybersecurity and security, and those types of applications,” Turner said. “And we may need that, but I think we all definitely need to absorb this. … What happened to some of that ‘reforming the grid’ and thinking about future technologies? I don’t see a lot of bullet points on it — it seems like kind of an afterthought right now, and I thought … last meeting, that was a major forefront of this.”

Brian Evans-Mongeon of Utility Services Inc. backed Turner’s concerns, saying he had “difficulty signing off” on the document and that the committee needed “time to digest” the transition plan. In light of the dispute, Duke Energy’s Greg Stone moved that the committee approve the first two proposals but table the SITES document for further discussion. This was approved, with some participants reminding the committee that some issues will inevitably be discovered once operations begin.

“Until we start intaking work and start working through that, we can’t really lay out all of the specifics at this point in time,” said Christine Hasha of ERCOT. “And so we need to have, basically, a pilot or proof of concept that we can start working through to get some momentum … and start to really refine the structure.”

SARs, Guidelines to be Covered Later

In addition to the SITES document, a number of other scheduled items were not covered in the meeting. These included several approvals and endorsements that were part of the consent agenda but pulled out for further discussion as a result of a motion by Evans-Mongeon:

Standard authorization request (SAR) for MOD-025-2 — Unit verification and modeling
SAR for revisions to PRC-023 -4 — Transmission relay loadability
Reliability guideline: Gas and electrical operational coordination considerations — posting for 45-day comment period
Reliability guideline: Distributed energy resource verification — posting for 45-day comment period
White paper on assessment of DER impacts on NERC reliability standard TPL-001

Discussion of these items would have followed the approval of the transition plan documents, but because the meeting ran out of time, this was postponed to a later date. Also delayed were a number of reports from committee staff, including an update on the Geomagnetic Disturbance Task Force’s data collection program and a NERC white paper on ensuring resource adequacy, along with reports from the North American Generator Forum and the North American Transmission Forum.

RSTC members discussed adding these items to the agenda for their next meeting, scheduled to be held via teleconference Dec. 15-16, but agreed that this would be too long of a delay because some material might be time-sensitive; in addition, attendees feared overburdening the schedule and causing further delays. Committee staff agreed to poll members in coming weeks to determine an appropriate time for the follow-up meeting.

Guidelines, Subcommittee Leaders Approved

The committee did take action on several items, including the approval of a reliability guideline on DER data collection for modeling in transmission planning studies and endorsing the compliance implementation guidance on reliability standard PRC-019-2 for submittal to the ERO. Chair Greg Ford also solicited volunteers to review a white paper on “possible misunderstandings of the term ‘load loss’”; the final team included Turner and:

Chris Shepherd, Gannett Fleming;
Edison Elizeh, Bonneville Power Administration;
Todd Lucas, Southern Co.; and
Wesley Yeomans, NYISO.

In addition, Ford named Northwest Power Pool’s Greg Park as chair of the Resource Subcommittee, with Southern’s Rodney O’Bryant as vice chair. Ford also appointed Duke’s Brantley Tillis to chair the Performance Analysis Subcommittee, with David Penney of Texas Reliability Entity serving as vice chair.

September 16, 2020

MISO IMM Rebuts Uneconomic Coal Commitment Studies

Uneconomic self-commitments of coal resources in MISO’s footprint are not occurring at the clip that critics imagine, the RTO’s Independent Market Monitor said in new findings this week.

IMM David Patton released an analysis showing that most of the footprint’s coal self-commitments are lucrative. The Monitor found that 90% of 6,300 coal resource commitments from 2016 to 2018 were profitable. In 2019, 83% of coal self-commitments were economic. Patton said the 2019 percentage was lower because overall energy prices drifted downward during the year.

“Generally, our coal resources are starting when it’s economic to start, despite some recent concerns and studies saying otherwise. We don’t find those studies to be credible,” Patton told MISO board members during Tuesday’s virtual Markets Committee meeting. “In fairness to the authors of those studies, they don’t have access to some of our cost data.”

MISO coal — MISO IMM David Patton | © *RTO Insider*

The report is a response to increasing scrutiny around coal plants’ self-scheduling and studies that have reported that customers shell out more in rates as a result. The Union of Concerned Scientists has said Xcel Energy, DTE Energy, Cleco Power and Consumers Energy are MISO’s worst offenders. (See UCS Analysis Knocks Coal Self-commitments.)

The Monitor said that when coal self-commitments were unprofitable, it was sometimes because of decisions based on MISO’s day-ahead market prices that didn’t pan out. Had day-ahead pricing prevailed, Patton said, less than 10% of coal commitments between 2016 and 2019 would still have been made at economic losses.

“While this indicates room for improvement, we find that the vast majority of coal resource commitments were efficient,” Patton wrote. “Overall, we believe that the decisions of the owners of coal resources to start them or to keep them online have been efficient, even when they are not profitable and generating negative operating net revenues.”

The Monitor did find that merchant coal generation tends to operate more economically than its integrated counterparts. “A small share of integrated utilities operate much less efficiently than others,” Patton said.

He urged those utilities to take extended outages in shoulder seasons and consider economically offering their resources more frequently in the day-ahead market. Patton said that “economic offers that are discounted to reflect the costs of cycling would allow the day-ahead market to economically evaluate whether to keep the resources online for the following day.”

Patton also suggested MISO consider publishing more hours of future pricing data. He noted that while the grid operator’s day-ahead market evaluates commitments and schedules over 36 hours instead of 24, it does not release the prices for the additional 12 hours beyond the following day. Patton said those additional 12 hours of data could “provide valuable insight to coal resource owners seeking to make the most efficient dispatch decision possible for the following day.”

September 16, 2020

NEPOOL Transmission Comm. Briefs: Sept. 15, 2020

The Northern Maine Independent System Administrator (NMISA) is asking New England transmission owners to eliminate through-and-out (TOUT) transmission charges for transactions between it and ISO-NE, similar to the reciprocal discount currently used by the RTO and NYISO.

NMISA CEO Ken Belcher and consultant Steve Garwood of PowerGrid Strategies outlined the proposal to the New England Power Pool Transmission Committee on Tuesday, saying it would eliminate pancaked transmission charges between the two regions, “consistent with FERC’s longstanding policy of eliminating seams issues where possible.”

NMISA, which serves a peak load of about 138 MW in Aroostook, Washington and Penobscot counties, is not directly interconnected with the rest of New England. Its two regions — Versant Power’s Maine Public District (MPD) in the north and the Eastern Maine Electric Cooperative in the south — connect to ISO-NE through the transmission facilities of New Brunswick’s NB Power. (Versant Power was formerly known as Emera Maine.)

Officials said the change would result in a “de minimis” impact on transmission rates for both regions while improving market efficiency and liquidity and increasing generation competition by reducing the costs for Northern Maine to access ISO-NE generation and for the RTO to use the region’s wind resources.

Had the proposal been in effect during 2019, it would have increased the June 1, 2020, regional network service rate by 4 cents/kW-year (0.03%), NMISA said, while MPD would see a 1.3% increase.

Northern Maine currently purchases about 70,000 MWh annually from ISO-NE, producing $67,000 in transmission revenue not subject to the discount. By reducing the seams costs, that could rise to 659,000 MWh, producing non-discounted charges of $633,000, NMISA said.

Increasing south-to-north transactions also would reduce congestion at the Orrington-South interface, potentially reducing curtailments of Northern Maine’s wind power exports to the RTO, the ISA said.

Northern Maine’s renewable exports are currently worth $2.5 million in renewable energy credits. That could increase by $750,000 through scheduling optimization, NMISA said. “Also, there is potential for further development of renewables up to 100 MW in Northern Maine for delivery to New England based on unused existing transmission capacity. Exporting the energy from these new resources to ISO-NE is unlikely to occur absent implementation of the proposed discount,” it said.

In its first presentation on the proposal at the joint Transmission/Reliability committees meeting in August, NMISA said MPD would have lost $164,546 in TOUT revenue had the charge been eliminated in 2019. In response to a question, it acknowledged that the revenue would have been $874,546 had MPD not already been discounting its export point-to-point rate. “However, absent continuation of the discount, it is unlikely that the same level of transactions would occur as occurred during 2019,” NMISA said.

Garwood said Northern Maine will ask ISO-NE’s Participating Transmission Owners Administrative Committee (PTO AC) at its Sept. 22 meeting to issue a notice of intent to eliminate the TOUT.

ISO-NE Proposes Tariff Revision on Transmission Charge Exemption for Storage

ISO-NE shared proposed Tariff revisions it intends to include in its third compliance filing on FERC Order 841 after the commission last month said the RTO had failed to demonstrate that a storage resource that is self-scheduled to charge at a fixed megawatt quantity is providing a service that warrants exempting it from transmission charges. (See FERC OKs Most of ISO-NE 2nd Storage Compliance.)

Jennifer Wolfson, an attorney for ISO-NE, presented the revisions on behalf of the RTO and PTO AC. Addressing FERC’s concern with self-schedules, she said that “a charging self-scheduled” storage dispatchable asset-related demand (DARD) provides similar services as “a charging pool-scheduled” storage DARD.

ISO-NE and the PTO-AC contend that all charging megawatts of a self-scheduled storage DARD supply voltage support and reactive control. “A self-scheduled resource is required to follow ISO dispatch instructions, without delay, to consume at the requested megawatt level; therefore, when it charges it provides real-time balancing of supply and demand and operating reserve,” they say. “A charging self-scheduled storage DARD, in contrast to other load, helps address reliability concerns given that the ISO can dispatch the load off if needed to address a contingency.”

The Tariff revisions state that storage will be exempt from transmission charges only if its charging load does not include station service load or any other load and “is providing one or more of the following services: reactive power voltage support, operating reserves, regulation and frequency response, balancing energy supply and demand, or addressing a reliability concern.”

The Transmission Committee will vote on the proposed Tariff revisions on Oct. 27, with a Participants Committee vote expected Dec. 3.

Last week, RTO officials outlined their plans for responding to two other directives from FERC’s Aug. 4 order. (See “Order 841 Compliance Update,” NEPOOL Markets Committee Briefs: Sept. 8, 2020.)

The compliance filing is due Dec. 7.

September 16, 2020February 19, 2025

FERC Nominees Bob and Weave Through Senate Hearing

President Trump’s nominees to FERC, Allison Clements and Mark Christie, said just enough to satisfy senators on both sides of the aisle during their confirmation hearing Wednesday.

Neither nominee gave away how they might decide on the commission’s thorniest issues, including carbon pricing, capacity markets and downstream greenhouse gas emissions from natural gas pipelines. Instead, they both said they did not want to “prejudge” any matters before they are sworn in and repeatedly committed to considering each matter that came before them on a case-by-case basis.

Both Republican and Democratic members of the Senate and Energy Natural Resources Committee were pressed for time because of votes on the Senate floor and did not press the nominees further for more clues. They gave no indication that they would oppose either nominee.

Clements, a Democrat and energy policy adviser for the Energy Foundation, and Christie, a Republican and chair of the Virginia State Corporation Commission, were nominated by Trump in late July. (See McNamee Leaves FERC.)

“Both nominees made multiple references to the need for objectivity, the importance of reliability and resiliency, and the central duty of the commission to ensure just and reasonable rates for consumers,” ClearView Energy Partners said. “We thought both nominees were circumspect in their responses … and steered clear of any remarks that might be construed as potentially prejudging an issue pending before the commission.”

President Trump’s nominees to FERC, Virginia SCC Chair Mark Christie and Energy Foundation consultant Allison Clements, are sworn in before their confirmation hearing Sept. 16. | Senate ENR Committee

Several Republicans, most notably Sen. Cory Gardner (Colo.), did focus on Clements and her previous work for the Natural Resources Defense Council’s Sustainable FERC Project. When Gardner asked her to “name an issue” on which she disagreed with her former colleagues, Clements without hesitation answered nuclear generation, which she said “plays an important role in providing carbon-free, reliable power to the system. That’s a place where many of my very well studied and smart colleagues might disagree with me.”

“Could you name another one, perhaps?” Gardner replied. He tried to get Clements to say whether she disagreed with the NRDC on its “fossil fuel agenda,” but she wouldn’t bite.

Democrats, meanwhile, tried to determine where Christie would side on the GHG dispute, which has caused tension at FERC. Democratic Commissioner Richard Glick has repeatedly dissented from the commission’s approvals of natural gas infrastructure, contending that they ignore a D.C. Circuit Court of Appeals ruling that said it must consider the effects of downstream GHG emissions in its environmental impact statements.

Senate ENR Chair Lisa Murkowski (R-Alaska) | Senate ENR Committee

Christie, however, demurred, telling Sen. Martin Heinrich (N.M.) that he did not “want to prejudge that issue because that is a legal question about what does the law require and what does the D.C. Circuit opinion require.” He often sounded like McNamee, a fellow Virginian, repeatedly stressing the importance of “the law and the facts,” a phrase that the former commissioner often used in his public appearances.

One of the few mentions of the RTOs came when Christie answered to a question about market manipulation from Sen. Maria Cantwell (D-Wash.). Christie acknowledged that Washington has been considering whether to allow its utilities to join an RTO with CAISO and advised that, having “lived in PJM world for the past 16 years, it is absolutely essential that you have an Independent Market Monitor in these RTO capacity markets. … We have an outstanding market monitor in PJM, Dr. [Joe] Bowring.”

Christie was president of the Organization of PJM States Inc. in 2007 when it pressed FERC to separate PJM’s Market Monitoring Unit into an IMM. In March 2008, FERC approved the current monitoring structure, with Bowring as head of his own independent firm.

Committee Chair Lisa Murkowski (R-Alaska) said she hopes to have both nominees confirmed before Congress adjourns at the end of the year. ClearView expects that to happen, albeit most likely after Election Day. “We did not observe any statements by either nominee that would appear to imperil their eventual confirmation,” ClearView said. “That said, we cannot foretell how a potentially contested presidential race could impact the day-to-day functioning of the U.S. Senate in a lame duck session.”

If confirmed, Clements’ term would end in June 2024 and Christie’s in June 2025.

September 16, 2020

MISO, SPP Respond to Monitors’ Seams Studies

MISO, SPP Regulators Mull Seams Recommendations.)

After hearing from MISO’s Jeremiah Doner and SPP’s Casey Cathey, the Seams Liaison Committee (SLC), comprising regulators from the Organization of MISO States and SPP’s Regional State Committee, offered up suggestions on potential SLC actions.

“We need to get serious about starting to prioritize these [recommendations],” said North Dakota Public Service Commissioner Julie Fedorchak, one of the more vocal regulators during the SLC’s web meeting Monday.

Ted Thomas, chair of both the Arkansas Public Service Commission and the SLC, proposed the committee break the recommendations and staff and stakeholder feedback into four buckets: actionable items, further analysis, planning topics and affected-system studies.

MISO SPP seams — SPP’s Casey Cathey (left) and MISO’s Jeremiah Doner participate in a 2018 panel discussion. | © *RTO Insider*

Topping the list of actionable items is market-to-market (M2M) coordination, in which the RTOs’ manage congestion by using least-cost generation redispatch. The grid operators have been engaged in the M2M process since 2015, with SPP piling up more than $93 million in settlement payments for congestion on its system caused by MISO.

MISO’s Independent Market Monitor, Potomac Economics, said the RTOs could reap up to $30 million in annual benefits by improving congestion management, noting that many changes would be incremental and only require coordination between the grid operators.

Cathey, SPP’s director of system planning, said the RTOs have been working to improve the process and asked for more time to let the changes take hold.

“If we see still lost opportunities … or reliability concerns after those enhancements are in place, we will have to prioritize some of those [IMM] suggestions,” Cathey said. “We absolutely would like to fix some of the issues we see in market-to-market.”

Potomac’s analysis of interface pricing generated more discussion than any other item. The Monitor viewed the RTOs’ current interface pricing mechanism favorably but noted a flaw in how congestion is charged. FERC Orders Tech Conference on MISO-SPP Congestion.)

Doner, MISO’s director of seams coordination, said the grid operators agree improvements can be made to the pricing mechanism’s design and methodology. He said resolving the issue would require changes to MISO’s market systems, which won’t be fully implemented until 2022. SPP plans to address the issue with a couple of projects that won’t begin until that same year.

“There’s a value to evaluating the interface pricing,” Doner said. “At this point, it’s too early to say what that should be.”

“This is a very complex issue. Whatever we do will take a lot of thinking and additional analysis,” Cathey said. With more than 250 tie lines along the MISO-SPP seam, he asked, “How can you properly send the right signal for imports or exports?”

Potomac President David Patton called in to dispute what he was hearing.

“The overall time frame, the complexity … this has been studied for almost 10 years, including a study on unintended consequences,” he said. “This can be done in a simplified form in a much quicker time frame. The flawed interfacing pricing that exists is generating costs. To say we’re going to leave it for three, four or five years … is not an appropriate action.”

Cathey said it’s a misconception that there’s “a lot of money on the table” and “efficiencies to be gained” by fixing the interfacing pricing. He said ramp limits and make-whole payments for exports are among the issue’s barriers. Both he and Doner said they would be happy to work on interface pricing with the monitors.

“Both RTOs are paying for congestion relief on their neighbor’s system. We’re paying transactors to relieve constraints that neither one has a way to recover, and it ends up being uplifted to the customers,” Patton said. “When people transact at inefficient levels, the overall market results are inefficient and that can hurt generators and load. We should be motivated enough to fix it.”

Doner said MISO stakeholders consider coordinated transaction scheduling (CTS), the third item on the actionable list, to be a low-priority item and have placed its implementation in the Integrated Roadmap process’s parking lot. MISO and PJM have been using CTS on their seam since 2017, he said.

“We’re seeing that the volume of transactions that leverage that product is very small,” Doner said. “What we hear from stakeholders and [transmission] customers is that’s because of transmission service charges and the uncertainty [around] that pricing. Transmission service charges on the PJM seam are even smaller than they are on the SPP seam.”

The RTOs said CTS implementation costs could be as high as $10 million, effectively negating the SPP Market Monitoring Unit’s projection of $9.4 million to $11.2 million in benefits.

The SLC’s leadership has suggested that rate pancaking, unreserved use charges and joint dispatch need further analysis. The monitors’ study on rate pancaking and unreserved use focused on real-time transactions, for which both RTOs already offer heavily discounted transmission service. The analysis did not evaluate the effect on long-term transmission service or day-ahead transactions.

“It would be worthwhile to get [the monitors’] response to those things at some point,” Fedorchak said.

The IMM’s study of joint dispatch found few benefits, noting that dispatching two systems that are already optimized separately yields little incremental production cost benefits. The SLC pointed out that the monitors did not analyze other benefits, such as reliability, reduced unit cycling or reduced reserve margins.

The SLC hopes to present a list of recommendations by the end of 2020 on how the RTOs can improve coordination across the seam.

September 15, 2020

MISO, SPP to Conduct Targeted Transmission Study

MISO and SPP on Monday announced a yearlong transmission study to identify projects with “comprehensive, cost-effective and efficient upgrades” after their staffs once again failed to agree on an interregional project this year.

The RTOs said the joint study will focus on solutions they believe will “offer benefits to both [the] interconnection customers and end-use consumers” of their members. The study’s expanded scope will include projects near the RTOs’ seam that support both organizations’ interconnection processes.

MISO SPP transmission — SPP CEO Barbara Sugg | © *RTO Insider*

Cost allocation will be addressed “once there’s a better sense of the types of projects and benefits that might result,” an SPP spokesman said. Previous MISO-SPP studies that have evaluated interregional projects’ cost allocation have failed to produce any new transmission.

“A fundamental issue facing grid transformation is the lack of transmission at requested connection points,” SPP CEO Barbara Sugg said in a statement. “Working together, MISO and SPP can target those areas where there are mutual benefits on both sides of our [seam].”

In doing so, the RTOs tacitly acknowledged stakeholder frustration over their inability to identify joint projects under their Joint Operating Agreement. MISO in August all but admitted the grid operators will once again come up empty after a fourth joint study in six years. (See MISO, SPP Close to Ruling out Joint Projects Again.)

“[Stakeholders] have told us that we need a better solution that prioritizes projects that address these gaps,” MISO CEO John Bear said in a statement. “Collaborating in this way gives us the opportunity to explore potential improvements within our own interconnection processes while informing longer-term regional transmission planning efforts in both MISO and SPP.”

Clean Energy Groups Cheer

The American Wind Energy Association, Clean Grid Alliance and Advanced Power Alliance applauded the RTOs for what they labeled “a game changer.” The organizations released a joint statement that said the study will be a “new milestone” in coordination between the RTOs, their leadership, state regulators and other stakeholders.

“Working together, the two [RTOs] can enable and expedite needed transmission development on their seam and address related generation interconnection challenges,” the organizations said. “This forward-thinking partnership includes an aggressive, but achievable, timetable, and we pledge to provide any assistance necessary to support this effort. Coordinated transmission planning will allow consumers across the country to harness the economic and environmental benefits of renewable energy.”

The RTOs expect the joint study to begin in December and will include opportunities to share information with stakeholders and solicit their input. The grid operators’ respective boards will have to approve any identified projects before they can move forward, as the study will be done outside their tariffs.

Aubrey Johnson, MISO’s executive director of system planning and competitive transmission, told a meeting of the RTOs’ state regulators that some of the study’s details are still being worked out but that its initial focus will be identifying issues that have benefits and should be pursued.

“The effort is an attempt to perform an alternative approach to address the historical challenges in targeted areas of the seam,” Johnson told a meeting of the Organization of MISO States and SPP Regional State Committee’ Seams Liaison Committee. “It’s a little bit different from some of the things we’ve done under the JOA. We’re trying to do this outside all the other work we’ve done.”

SPP Vice President of Engineering Antoine Lucas told the committee that the study “creates some flexibility to see if there are some potential solutions … to get over the hurdles and challenges we’ve had in the JOA studies.”

September 15, 2020

FERC Refuses Complaint over Wabash’s DG Rules

FERC has sided with the Wabash Valley Power Association in a skirmish with a cooperative member over its distributed generation rules.

Tipmont Rural Electric Membership Cooperative must continue to abide by Wabash’s Distributed Generation Policy, FERC ordered Friday. The commission said Wabash’s policy is effective as of June 29 (ER20-1683-001).

The rural co-op in eastern Indiana has taken issue with Wabash’s DG supply contract since 2018, when it requested early termination of its obligations under it. Tipmont earlier this year said that Wabash’s freshly filed Distributed Generation Policy under a new tariff section was anticompetitive because it establishes Wabash as the “exclusive buyer of power from its potential distributed competitors” and limits Tipmont’s energy purchases to distributed resources of 10 kW or less, or up to 25 kW with Wabash’s approval. Tipmont is under an all-requirements wholesale power supply contract with Wabash with the exception of the small, distributed energy allotments through 2050.

FERC batted away the distribution co-op’s complaints over the contract.

“We are not persuaded by Tipmont’s interpretation of its contracts and related arguments about the anticompetitive effects of the Distributed Generation Policy. Tipmont contracted to purchase from Wabash all required electric power to operate Tipmont’s system. As Tipmont executed all-requirements contracts with Wabash, there are no provisions allowing Tipmont to transact with distributed resources,” FERC said.

However, FERC acknowledged that Tipmont is the only one of Wabash’s two dozen members that has neither adopted a resolution agreeing to abide by the DG policy nor authorized Wabash to file an implementation plan under the Public Utility Regulatory Policies Act on its behalf. Because of that, FERC directed Wabash to add language to its contract specifying that the policy only applies to non-qualifying-facility DG. The commission said the upcoming compliance filing should apply to Tipmont and “any other member who has chosen to retain its PURPA purchase obligations.”

Otherwise, FERC disagreed with Tipmont’s claim that Wabash’s distribution supply contracts only stipulate that Wabash supplies Tipmont’s “electrical needs as measured at the wholesale delivery point.” The commission said it found nothing in the contracts to support the co-op’s argument.

“We note that under this interpretation, if Tipmont were able to purchase its total energy requirements from generation located on Tipmont’s distribution system, Tipmont would no longer have any obligation to purchase energy from Wabash. This would undermine the purpose of a long-term, all-requirements contract, in which Tipmont elected to purchase all needed energy from Wabash, and Wabash agreed to fulfill Tipmont’s energy needs by making long-term arrangements,” FERC said.

September 15, 2020January 17, 2024

ISO-NE Challenged on Wind, Solar, Storage Revenues

New England Power Pool stakeholders proposed changes to Forward Capacity Market (FCM) parameters and rules regarding the timing of delist bids during a marathon Markets Committee meeting Sept. 8-10.

Several of the proposed changes concerned ISO-NE consultants’ estimates of the revenue potential of wind, solar and storage resources. Others concerned the inputs for the calculation of the net cost of new entry (CONE).

The committee will vote on the parameters and proposed amendments next month, but the votes are advisory under sections 8 and 11 of the NEPOOL Participants Agreement.

Abigail Krich and Alex Worsley of Boreas Renewables presented RENEW Northeast’s critiques of the revenue figures proposed by Concentric Energy Advisors (CEA) and Mott MacDonald, two consulting firms hired by ISO-NE to update the FCM parameters for the 2025/26 capacity commitment period.

The key parameters — net cost of new entry (CONE) and offer review trigger prices (ORTPs) — can determine whether certain resources are competitive in the auction. Net CONE estimates the capacity revenue a new generator needs in in its first year of operation to make it economically viable; it is based on a “reference unit” — the most profitable commercially available generation technology for new entry in New England — currently General Electric’s 7HA.02 gas-fired combustion turbine.

ORTPs are estimates of the low end of competitive offers for other classes of technology. New supply offers above the ORTP are presumed to be competitive and not an attempt to suppress the auction clearing price. An offer below the price is subject to a unit-specific review by the Internal Market Monitor to verify the resource’s cost.

Offshore Wind

Krich told the committee Wednesday that the consultants’ estimates of offshore wind costs are “totally outside and above the range of other estimates.”

The RTO proposed using $5,876/kW (2019$) for the overnight capital cost for offshore wind, resulting in an ORTP of $32.31 to 32.51/kW-month, almost double the highest clearing prices on record and well above $2 to $7.03/kW-month range for the five auctions since 2016.

Krich said the assumption “is significantly higher than commercial expectations,” based on RENEW’s analysis of executed OSW contracts in New England and other publicly available data.

The RTO “used a bottom-up methodology for determining the capital cost assumption but has not presented cost-based benchmarking that supports any element of that analysis or the final capital cost assumption,” she said.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

One reason the RTO’s estimates are too high is because its $70 million interconnection cost “does not align with cost estimates in completed ISO-NE interconnection studies for projects almost identical to the proposed project,” Krich said.

She noted that the average interconnection cost for the 13 OSW projects studied by ISO-NE is $35.5 million, with only three of the projects having costs of $70 million or more, she said.

“Choosing the highest costs for projects studied by ISO-NE is not representative of what developers will typically face and should not be used in the determination of an ORTP,” she said.

Krich also challenged the RTO’s $4.2 billion engineering, procurement and construction cost estimate for an 800-MW OSW project, saying it should be closer to $2.1 billion.

RENEW will ask stakeholders to reduce OSW’s capital cost assumption to $2,900/kW (2019$). At that cost, Krich said, OSW shows an almost $4/kW-month surplus based on its energy revenues and renewable energy credits, meaning it doesn’t need capacity revenue to cover its costs and should have an effective ORTP of $0.

“Prices have been dropping really precipitously” in the last few years, she said. “We honestly don’t understand where the higher numbers from ISO New England come from.”

Deborah Cooke, ISO-NE’s principal analyst for market development, who presented the RTO’s proposed on net CONE and ORTP calculations, declined to comment on the discrepancies between RENEW’s and the consultants’ estimates.

Operating Lifetime

Krich also challenged the RTO’s proposed 20-year asset life for all generation technologies in its ORTP model, saying lifetime expectations for wind and solar have increased beyond 20 years since the last ORTP recalculation.

“This leads to higher ORTP values, unnecessary review and potential mitigation simply because [the RTO] is not recognizing the full life expectancy of these technologies,” she said. “If certain technologies’ expected revenues beyond 20 years are being neglected in the [minimum offer price rule] implementation, the capacity auction could clear at prices higher than equilibrium.”

Battery EAS Revenues

Krich and Worsley said CEA was overly conservative in estimating batteries’ energy and ancillary service (EAS) revenues.

ISO-NE proposed using $1.87 to 2.67/kW-month (2019$) in energy and reserves revenue, which RENEW contends “underrepresents what a competent battery developer could earn in the New England markets” and fails to follow the guidelines the External Market Monitor recommended in December 2019.

RENEW proposed an ORTP value of $4.53 to 4.86/kW-month, compared to the RTO’s $4.92 to 5.78/kW-month.

Worsley said the RTO’s estimate shows no effort to optimize dispatch using available data at the time of dispatch, such as day-ahead market prices, and that its assumed charging timing is often suboptimal. It assumes no ability to respond to forecasted market conditions or to change strategies through the year, making it unable to capture daily, monthly or seasonal market changes, he said.

Using the EMM “continuous information” approach, Worsley said, the batteries would have 52% higher energy and reserve revenues than assumed by CEA. RENEW recommended the RTO adopt a more conservative calculation by the Massachusetts Attorney General’s Office, which would result in a 41% increase.

“A competent [energy storage resource] owner should be assumed to use publicly available information known prior to dispatch,” he said. “These are common and not difficult to implement, and we believe [they] should have been appropriately within CEA’s scope of work.”

Ben Griffiths, an energy analyst for the attorney general, said the deterministic spreadsheet model CEA used resulted in “materially lower” EAS revenues than the basic linear optimization model he used. “It’s the wrong modeling tool for batteries,” he said of CEA’s choice.

The CEA model assumed the battery charges only during fixed windows, rather than when prices are expected to be lowest, Griffiths said. It also assumes it discharges when prices reach a fixed threshold — not adjusted for time-of-day or season — that often misses higher values later in the day. It also limited cycling to once-per-day, even if when it would be advantageous to cycle more than once, he added.

“EAS revenue estimates for ORTPs should not be based on the rosiest of predictions, but neither should they [be] based on the assumption of bumbling incompetence,” Griffiths wrote in a memo summarizing his research.

Inputs for Reference Unit Net CONE Calculation

Bruce Anderson of the New England Power Generators Association (NEPGA) identified several changes the group wants ISO-NE to make to input variables for the reference unit net CONE calculation.

Anderson called for using a historical premium on intraday gas costs during those hours when the reference peaker unit is dispatched in real time, as well as including the costs of firm gas delivery and sellback costs and imbalance charges for gas nominated but not consumed.

He also challenged the RTO’s proposal to use the lower heating value (LHV) for the nominal heat rate, saying it should use the higher heating value (HHV), on which gas prices are based. (HHV is the total heat obtained from combustion of a specified amount of fuel at 60 degrees Fahrenheit. The LHV is the HHV minus the latent heat of the water vapor formed by the combustion of the hydrogen in the fuel. HHV is typically about 11% higher than the LHV.)

NEPGA said the RTO’s proposal that the reference unit be located in New London County, Conn. — within 2 miles of both the Algonquin interstate gas pipeline and a 345-kW transmission line — is unrealistic because there are no greenfield sites permitted for industrial use that meet the criteria. It said it should extend the lateral and radial lengths to 5 miles to reflect the difficulty in finding suitable parcels.

Anderson also said the RTO improperly assumed there would be no compression or lateral upgrade costs to ensure gas delivery.

NEPGA also disputed the monetization of bonus depreciation, saying the proposed net CONE value is insufficient incentive for a sale lease back financing agreement or other tax equity financing. It also asked for a lower debt/equity ratio than the 55/45 proposed by ISO-NE to reflect merchant market risk and the inclusion of “reasonable estimates of owner’s cost and contingency,” which were omitted by the RTO.

LS Power’s Mark Spencer complained that Mott MacDonald had failed to provide information he said he had been requesting for three months regarding several of the company’s inputs and assumptions.

“We’re looking to have a vote next month, and the questions are still unanswered, so I don’t know what else to do other than to register an objection that it doesn’t seem like the information is forthcoming,” Spencer said.

Calpine’s Brett Kruse predicted the disputes over the assumptions will result in litigation before FERC and potentially federal court.

“They’re going to have to stand on their data as opposed to hiding behind the cloak of secrecy here. … My hope is that the ISO and Concentric are really riding herd on Mott MacDonald. Quite frankly, I have not been impressed with what I’ve seen from them.”

CEA’s Danielle Powers, who led its presentation s on CONE and ORTP calculations, declined a request to respond to the criticism.Mott McDonald referred a request for comment to ISO-NE.

Change to Delist Bid Threshold

Sigma Consultants President Bill Fowler presented a proposal on behalf of Calpine and Vistra Energy, and Vistra’s Dynegy unit, to address the disadvantage he said is faced by resource owners having to lock in static delist bids four months before the Forward Capacity Auction.

The IMM is proposing that the dynamic delist bid threshold (DDBT) be set equal to its expectation of the next auction clearing price. All delist requests above this level must become static bids.

Fowler said locking in prices for statics is much riskier and more expensive than a dynamic bid, creating a disincentive to offer at prices only slightly above the DDBT. “Failing to recognize this will bias offers and may lead to clearing prices below competitive levels,” he said.

The lock-in means resource owners cannot account for market and regulatory changes that occur between October and February, including the installed capacity and local sourcing requirements, waiver requests, and state and federal regulatory actions, including FERC action on FCM questions, Fowler said.

Resources making static delist offers will add a risk premium to account for these costs and risks, Fowler said. If the resource’s competitive price is greater than the DDBT but less than the DDBT plus the margin, he said, resource owners are incented to not bid the competitive price, and instead bid the DDBT minus 1 cent.

“The resource owner has to hope that his offer to exit at DDBT minus 1 cent clears. If it doesn’t, the resource is stuck with a CSO [capacity supply obligation] at a price it didn’t want.”

It also means the Monitor and market will never see the true competitive offer; the resource may take on a CSO it doesn’t want; and the FCM may clear at an uncompetitive level, he added.

Fowler noted the RTO’s analysis of the new DDBT method found it misses the actual clearing price by 25%. At a $2 clearing price, a 25% margin equals 50 cents; at a $4 clearing price, it is $1.

As a result, Fowler said the DDBT should be set at a “reasonable margin” — 50 cents to $1/kW-month — above the expected clearing price. “A margin of this size would help address this inaccuracy,” he said.

September 15, 2020

MISO Market Subcommittee Briefs: Sept. 10, 2020

Stakeholders would prefer MISO use RTO-specific data as much as possible as it considers whether and how to update its value of lost load (VoLL), Michael Robinson, principal adviser of market design, told the Market Subcommittee on Thursday via teleconference.

MISO’s VoLL is currently a flat $3,500/MWh and is used to set the upper value of the operating reserve demand curve and LMP cap. It essentially determines at what price customers would prefer interruption to paying the marginal cost of service. The RTO has been considering how it can vary the value to account for differences in season, time of day, region and load type, among other factors. (See MISO Revisits Scarcity Pricing Rethink.) Robinson opened the discussion with a lengthy analogy about trying to find the right type of ax for felling a tree, but only having other types of axes.

The RTO proposed several options for refining the VoLL. Robinson said stakeholders showed little to no interest in using previous studies that did not use Midwest-specific data, including one done by London Economics on ERCOT’s VoLL.

Rather, they prefer that any analysis use the most recent data available out of MISO, including the possibility of doing a completely new study. This approach, however, would likely take up to a year and a half, Robinson said, and be “extremely expensive to conduct.”

Customized Energy Solutions Ted Kuhn asked whether the effort would be “a waste of time.”

Independent Market Monitor David Patton chimed in, saying updating the VoLL is “as far from a waste of time as any [effort] I can think of.” He said MISO needs to ensure the value of reliability is embedded in its prices and that scarcity prices “are not close to being right.”

“This is critically important work,” Patton said.

MISO will continue to narrow down its potential approaches based on stakeholder feedback, which is due Sept. 30, and further discuss the issue at the subcommittee’s meeting next month.

Fall Seasonal Outlook

MISO expects adequate resources for the upcoming fall season, though planned generator outages are expected to rise this year because of delays related to the COVID-19 pandemic.

The National Oceanic and Atmospheric Administration is predicting higher-than-usual temperatures for MISO South and parts of the RTO’s eastern footprint this fall, Eric Rodriguez, resource adequacy coordinator, told the subcommittee. The RTO’s preliminary expected peak load for the season is 113 GW, compared to an expected 152 GW of available capacity.

Planned outages are expected to peak in mid-October, as they usually do, but MISO expects them to be slightly higher this year, as generators rescheduled their spring maintenance during the height of the pandemic, Rodriguez said. Still, the highest risk for a maximum generation event is in September, when a worst-case scenario of higher-than-expected forced outages and demand could lead the RTO to narrowly exceed its 14.6 GW of available load-modifying resources and operating reserves.