Page 1140 – RTO Insider

February 6, 2020

Exelon Challenges PJM Monitor’s ComEd FRR Analysis

By Christen Smith

VALLEY FORGE, Pa. — Exelon said Wednesday that a report from the PJM Independent Market Monitor uses faulty assumptions and anti-subsidy rhetoric to exert undue policy influence and cast a negative light on the fixed resource requirement (FRR) alternative some members may pursue in the face of an expanded minimum offer price rule (MOPR).

The Monitor himself responded to concerns at a Market Implementation Committee meeting when he presented his analysis of how capacity prices would change if Commonwealth Edison’s zone opted for FRR instead of participating in PJM’s capacity auctions.

ComEd, a subsidiary of Exelon, supplies more than 4 million customers across northern Illinois. The state is one of several in PJM that could consider the FRR construct to shield its portfolio of subsidized resources from the new MOPR rules. Exelon’s Quad Cities plant, one of five nuclear facilities in the state, began receiving zero-emission credits (ZECs) in 2017 — the very type of subsidy that FERC Extends PJM MOPR to State Subsidies.)

Exelon itself has been a vocal proponent of state legislation that would value resources based on emissions attributes, implement rate caps to better protect consumers and support expanding Illinois’ ZEC program to the four other nuclear plants. Exelon’s merchant generation subsidiary owns all five facilities.

Exelon PJM FRR — Jason Barker, Exelon | © *RTO Insider*

The Monitor’s report “really isn’t a credible or useful tool for understanding the value of an FRR for Illinois customers,” said Jason Barker, director of wholesale development for Exelon. “It’s telling that no one asked the IMM to develop this report.”

Monitor Joe Bowring noted that there had not been an explicit request for the report. The Monitor “routinely creates reports in order to provide facts and objective analysis to the market participants so that they can make reasonable decisions,” he said. “We plan to do additional analyses of the impacts of the MOPR order, including additional FRR analyses.”

Bowring’s report concludes that net load charges would increase 23.6% if ComEd procured all of its capacity obligations outside of the Base Residual Auction at the same rate as the offer cap — $254.40/MW-day — assigned to the zone in the 2021/22 delivery year.

In a second scenario, the Monitor calculated that ComEd’s load charges would decrease just 5% if the price negotiated for its capacity were equal to the zone’s 2021/22 BRA clearing price of $195.55/MW-day. In the report, Bowring said that the first scenario seemed more reasonable, “given Exelon’s assertions that the current total revenue from energy, ancillary and capacity markets is not adequate for its nuclear plants.”

The report also found that carving ComEd’s load delivery area out of the auctions would reduce capacity payments across the rest of the RTO, regardless of the prices charged in the FRR area.

Barker pushed back against the report’s methodology and argued that it ignored the political situation in Illinois, as well FRR rules that don’t dictate a single price be paid to resources with “different attributes.”

“These faulty assumptions and repeated anti-ZEC rhetoric indicate that the purpose of the report is to cast a negative light on the development of a ComEd FRR and its impact on customers, rather than to objectively and independently analyze potential policy outcomes,” Barker said. “The report confuses debate instead of advancing it.”

‘Reasonable Range’ Sought

In response to Exelon’s assertion that the specifics of the state’s varied FRR legislative packages had not been included in the report, Bowring said, “We very consciously and explicitly tried not to incorporate the details of the various forms of draft legislation.

“We were not trying to tell Illinois what to do,” he said. “Who knows what may happen? What we did was very simple. We tried to define a reasonable range of the impacts of the FRR option. We think we did that in a clear and non-rhetorical way.”

Bowring reiterated that the report was meant to educate and that he was open to doing additional sensitivity analyses for Exelon or any other market participant.

“Our primary point about the FRR option is that once you’ve chosen to do that, you are giving some degree of market power to the owners of that capacity,” he said. “The state will have to negotiate with one or two generators to set the compensation for the generation that the state requires for reliability.

“We are not saying we know what the exact compensation would be; we are just showing what the impact of taking ComEd out of the auction would be for a range of prices,” Bowring added. “Ultimately the price paid would be a function of the price negotiated between the owners and the state entity. We think market power is an issue in the creation of any FRR.”

February 6, 2020

ISO-NE Capacity Prices Hit Record Low

By Rich Heidorn Jr.

ISO-NE’s 2020 capacity auction cleared at a record low of $2/kW-month, a nearly 50% drop from $3.80/kW-month in 2019.

ISO-NE Capacity Prices — ISO-NE Forward Capacity Auction prices (2013-2020) | *ISO-NE*

Forward Capacity Auction 14, which began Monday, cleared 33,956 MW of capacity for 2023/24 after five rounds of bidding. That gives the region a 1,466-MW surplus over the net installed capacity requirement of 32,490 MW, at a total cost of about $980 million.

ISO-NE noted that auction rules allow it to acquire less than the capacity target or more if it can ensure “enhanced reliability at a cost-effective price.”

More than 600 MW of new resources cleared the primary auction, including 317 MW that received their capacity obligations under the renewable technology resource (RTR) designation, which allows a limited amount of renewables to participate in the auction without being subject to the minimum offer price rule.

The exempt resources included land-based and offshore wind, solar PV, and solar PV paired with batteries. About 19 MW remain under the exemption for the 2021 auction, which will be the last to include the RTR.

Generation represents 85% of the capacity acquired, followed by demand resources (e.g., energy efficiency, load management, distributed generation) at 12% and imports from New York, Québec and New Brunswick at 3%.

Some 42,219 MW, including 34,905 MW of existing capacity and 516 new resources totaling 7,314 MW, qualified to participate in FCA 14.

“New England’s competitive wholesale electricity markets are producing record low prices, delivering unmistakable economic benefits for consumers in the six-state region,” Robert Ethier, ISO-NE vice president for system planning, said in a statement.

Auction rules allow existing resources interested in retiring to trade their capacity supply obligations with new state-sponsored resources that did not clear in the primary auction. But no such trades occurred, the RTO said.

Before the auction, 258 MW of resources submitted retirement bids, and another 21 MW filed permanent delist bids to leave the capacity market. All of the bids cleared before the auction.

Outside of the auction, ISO-NE has contracted to keep Exelon’s Mystic 8 and 9, which had been slated for retirement, operating for fuel security in 2023/24.

The RTO said the results are preliminary. Final results, with resource-specific results, will be submitted for approval by FERC by the end of February.

The results of FCA 13 became effective “by operation of law” Sept. 24 because FERC was unable to muster a quorum following the departure of Commissioner Cheryl LaFleur and the recusal of Commissioner Richard Glick. (See FCA 13 Results Stand Without FERC Quorum.)

Reaction

Generators tried to put the best face on the low prices, with the Electric Power Supply Association calling it “great news.”

“With one of the cleanest generation fleets in the US, the region should enjoy reliable, clean, cost-competitive power for years,” said Dan Dolan, president of the New England Power Generators Association.

Dolan said the prices were depressed because of the Inventoried Energy Program for reliability and the retention of the Mystic station, noting that neither program is expected to be in place for next year’s auction.

Dolan said the Competitive Auctions with Sponsored Policy Resources (CASPR) program was not needed this year because of the Mystic plant, the RTR renewables exempt from MOPR, and “ongoing siting challenges for state-sponsored projects.”

“Next year’s auction may provide a clearer window of the efficacy of the CASPR program. Longer term, NEPGA continues to believe that the region should move toward a meaningful price on CO₂ emissions to match environmental and clean energy goals.”

Other observers were ready to call CASPR a bust.

“Well NE governors,” tweeted Joe LaRusso, the EE and DR finance manager for the city of Boston. CASPR “which was supposed to `balance state public policies [supporting increasing renewable generation] with the competitive wholesale electricity market’ has failed. What will you do?”

“So much for @isonewengland approach to [accommodating] state policy,” agreed consultant Rob Gramlich, executive director of Americans for a Clean Energy Grid (ACEG). “CASPR approach cleared 0 MW this time and 50 MW (for $0) last time. Meaning renewables are not getting paid for the capacity they provide and consumers are paying twice. #MOPRmadness.”

February 6, 2020

SPP Sets 71.3% Wind Penetration Mark

SPP set a new record for the amount of wind energy in its resource output mix early Monday morning when it recorded a penetration level of 71.3%.

The new mark came at 3:15 a.m., when wind served 17,346 MW of the total 24,329-MW load, breaking the record of 68.8% on Oct 19. It also backed up Senior Vice President of Operations Bruce Rew’s 2018 prediction that SPP had a “good chance” of breaking the 70% threshold.

Rew was at it again during January’s governance meetings in Santa Fe, N.M.

“We predict wind will overtake coal as the region’s No. 1 energy source in 2021,” he said during SPP’s joint quarterly stakeholder meeting.

SPP currently has 22.5 GW of installed wind capacity, much of it on the plains of Oklahoma and Kansas. Rew told stakeholders that both states have recently seen multiple days when they produced more wind energy than was necessary to meet their load.

— Tom Kleckner

February 5, 2020April 10, 2025

FERC Approves SPS Request to End QF PPAs

FE R C last week approved Southwestern Public Service Co.’s request to terminate its obligation to enter into new power purchase contracts with qualifying cogeneration or small power-production facilities (QFs) with a net capacity greater than 20 MW (QM1 9 -4).

The commission found that QFs greater than 20 MW within SPS’ service territory enjoy nondiscriminatory access to sell capacity and energy into wholesale markets, in this case, SPP’s Integrated Marketplace. FERC based its Jan. 31 decision on a 2008 order that determined SPP’s markets satisfy the requirement of the Public Utility Regulatory Polices Act of 1978 (PURPA) to give QFs nondiscriminatory access to a market.

Construction crews work on an SPS substation in New Mexico. | Xcel Energy

FERC’s Order 6 88 in 2006 found that the nation’s commission-approved wholesale energy markets meet PURPA’s criteria for relief from the purchase obligation. It also established a rebuttable presumption that QFs greater than 20 MW have nondiscriminatory access to those markets.

The commission rejected complaints from renewable developers GlidePath Development and Leeward Renewable Energy that transmission constraints that existed in 2008 still persist today. SPS told FERC that it has invested $2.1 billion in transmission facilities subject to SPP’s Tariff and that the RTO’s transmission-owning members have invested $8.3 billion in facilities subject to the Tariff.

Xcel Energy filed the request with FERC on Sept. 5, 2019, on behalf of SPS, its subsidiary, and fellow SPP TO members Oklahoma Gas & Electric, Public Service Co. of Oklahoma and Southwestern Electric Power Co. The order is effective on that date.

— Tom Kleckner

February 5, 2020March 12, 2025

FERC Rejects Genbright Waiver on FCA14

By Rich Heidorn Jr.

FERC on Monday rejected a solar aggregator’s request for a waiver to offer 14 distributed energy resources into ISO-NE’s 2020 Forward Capacity Auction despite a dispute over the projects’ interconnection status (ER2 0 -366).

Genbright had asked FERC to allow its seven solar PV generating facilities and seven storage facilities to participate in FCA14, which opened Monday.

ISO-NE rejected their participation because the developers had failed to file interconnection requests with the RTO.

Genbright said it believed it had met the interconnection requirement by applying to Eversource Energy under the utility’s Massachusetts-approved tariff.

But ISO-NE said the company should have filed interconnection requests under the RTO’s Tariff because the point of interconnection is under FERC jurisdiction.

Genbright, which was acq u ired by ENGIE North America last May, said ISO-NE’s FCA 14 training material required a valid interconnection request “regardless of the jurisdictional status of the project’s proposed interconnection.”

ENGIE solar farm | ENGIE North America

Genbright contended that the seven PV generators should not be subject to FERC jurisdiction because it will sell all its output to Eversource as a qualifying facility participating in the Solar Massachusetts Renewable Target.

It said “at least three, and perhaps all seven” of the storage facilities also are not subject to the RTO’s interconnection process.

Genbright said Eversource erroneously stated that the distribution line into which each project is interconnecting is subject to FERC jurisdiction because there is a pre-existing QF on the distribution line registered with ISO-NE as a settlement-only generator.

Genbright said neither Eversource nor ISO-NE informed it that Genbright had filed incorrect interconnection requests even though Eversource knew that the projects intended to participate in the RTO’s market.

Eversource and ISO-NE both opposed the waiver request.

Eversource said Genbright was asking for a substantive legal ruling on what causes a distribution-level interconnection to fall under commission jurisdiction rather than merely the correction of a one-time error. It said the company should have sought a declaratory order or rulemaking.

“If Genbright’s views on jurisdiction were correct, they would have far-reaching impacts on auction eligibility, jurisdiction over existing interconnection agreements and the appropriate queue for yet-to-be interconnected generators,” Eversource said.

ISO-NE said it welcomes DER in its markets. “Genbright’s resources, like any other eligible resources in New England, may fully participate in the ISO’s markets, but they must do so in accordance with the same rules that apply to all resources,” the RTO said. “The petition, however, seeks an arbitrary exemption from the Tariff on behalf of Genbright’s projects, an exemption Genbright simply has not justified.”

In denying the request, FERC said Genbright had failed to show the request was limited in scope. “Genbright’s requested waiver would allow the projects to avoid ISO-NE’s complex interconnection study process, including the system impact study, which is ISO-NE’s comprehensive reliability evaluation.”

Results of FCA 14 are expected as early as Wednesday.

February 5, 2020

Judge Approves PG&E’s Deal with Bondholders

By Hudson Sangree

The federal judge in charge of Pacific Gas and Electric’s Chapter 11 reorganization set a timeline for it to exit bankruptcy Tuesday and approved its recent agreement with the bondholders that had been trying to take over the state’s largest utility.

PG&E deal bondholders — Judge Dennis Montali | *Commercial Law League of America*

“I’m going to issue the order that … approves the [restructuring agreement with bondholders],” Montali told lawyers in the U.S. Bankruptcy Court in San Francisco. He did so despite a lone objection from wildfire survivor William Abrams, who represented himself in court and insisted that PG&E’s reorganization plan should include safety reforms.

“They are here for their short-term payouts,” Abrams said of the bondholders and other parties that have settled with PG&E. Abrams said he was looking at the long-term consequences of the restructuring agreement.

Thousands of other fire victims, represented by the case’s official Tort Claimants Committee, have agreed to a settlement with PG&E that would fund a $13.5 billion trust to pay them and government agencies that incurred costs from wildfires started by PG&E equipment in 2015, 2017 and 2018.

The catastrophic blazes included the Camp Fire, which killed 86 people and destroyed 18,804 structures in Paradise, Calif., in November 2018. And even though it denies liability, PG&E agreed to settle claims from the Tubbs Fire, which killed 22 residents and burned 5,636 structures in Napa and Sonoma counties in October 2017.

The bondholders, led by several powerful East Coast hedge funds, had offered their own reorganization plan that proposed injecting billions of dollars in cash while wiping out the equity of PG&E’s current shareholders and seizing control of the utility. The group settled with PG&E in January in exchange for the utility agreeing to pay some of its notes and to renegotiate others. (See PG&E Settles with Bondholders; Governor Objects.)

PG&E has also settled with insurance companies and other holders of subrogation claims for $11 billion and with local governments for $1 billion.

With all major stakeholder groups in agreement, Montali set a schedule Tuesday for confirmation proceedings to weigh and rule on PG&E’s plan. The process is set to begin this week with the utility filing disclosure statements that describe its plan in language the public can more easily understand. Those affected by the bankruptcy, including fire victims, will then have an opportunity to comment on and object to the disclosures.

Montali scheduled a hearing on the disclosures for March 10 and set May 27 as the start of PG&E’s confirmation hearing.

The California Public Utilities Commission must also approve PG&E’s bankruptcy plan. It opened a formal proceeding in September and scheduled evidentiary hearings starting Feb. 19 at its headquarters in San Francisco. The commission is charged with determining if the utility’s proposals meet the safety requirements of Assembly Bill 1054, a measure that creates a $21 billion wildfire insurance fund for utilities that qualify.

PG&E must exit bankruptcy by June 30 to participate in the wildfire fund.

Gov. Gavin Newsom has said that PG&E hasn’t met the requirements of AB 1054 and repeatedly threatened a state takeover of the troubled utility. Newsom remains the biggest opponent to PG&E’s reorganization plan.

Though he doesn’t have authority over the bankruptcy court, he may have sway with the CPUC. Newsom appointed the commission’s new chair, Marybel Batjer, in July, naming her at the signing ceremony for AB 1054.

PG&E recently offered a new reorganization plan that it said meets the requirements of AB 1054, but Newsom hasn’t said whether it goes far enough to satisfy his demands. (See PG&E Tries to Appease Governor with New Plan.)

February 5, 2020

SPP MMU: Reduce Self-Commitments, Improve Market

By Tom Kleckner

S P P‘s Market Monitoring Unit said it is not looking to end self-commitment but that a reduction in the practice would result in a more efficient market.

SPP — MMU Executive Director Keith Collins | © *RTO Insider*

“We do note that a high volume of make-whole payments [for self-commitments] is not considered desirable. It creates inefficiencies in the market,” Monitor Executive Director Keith Collins said Monday during a webinar on a report it released in December on self-commitments.

Collins capitalized on the previous day’s Super Bowl to put the issue into terms that might make more sense to his audience. “Imagine your favorite sports team, and imagine it’s the players who decide will play, rather than the coach,” he said. “The outcome you get may not be as efficient as the coach optimizing that for you.”

In the re p ort, “Self-committing in SPP markets: Overview, impacts, and recommendations,” the Monitor recommends SPP and stakeholders work to reduce the number of self-commitments to improve price formation and market efficiency. The Monitor also suggests SPP modify its market design by adding another day to the market optimization period.

MW dispatched by commitments, self-commit MWs by fuel type | *SPP MMU*

The report says a smaller distortion of prices and investment signals “will likely help market participants make better short-run and long-run decisions, which tends to coincide with improved profit maximization.

“Enhanced profit maximization, combined with effective regulation and monitoring, will likely lead to ratepayer benefits in the form of cost reduction,” the Monitor said.

Monitor staff studied offer behavior from March 2014, when SPP’s day-ahead Integrated Marketplace went live, to August 2019. They re-solved past market cases by running two simulation series of a week per month from September 2018 to August 2019, assuming all generation was offered in market status and that it could be started economically by the day-ahead market.

The analysis found that:

The volume of self-committed MW has declined over time but remains nearly half of the total MW volume generated during the study’s time frame.
Prices and production costs were systematically lower when at least one self-committed unit was on the margin.
In almost all cases, self-committed generators had lower revenues because of negative congestion prices. Market-committed generators typically had a more balanced congestion profile.
Resources with long lead times and/or high start-up costs tended to be self-committed instead of market-committed.
Self-committed units generally had much higher capacity factors than those that are market-committed. The largest portion of self-committed dispatch MW were from coal units, exceeding the second-largest fuel type by a 4-to-1 ratio.

In its simulations, the Monitor found that:

When the market made unit commitment decisions and lead times were unchanged, both market-wide production costs and market-clearing prices for energy increased.
When the market made unit commitment decisions and lead times were modified to allow the day-ahead market to commit the resources with long lead times, market-wide production costs were essentially unchanged and market-clearing prices for energy increased about 7% ($2/MWh) on average. Congestion prices fluctuated from -$1/MWh to $1/MWh on average.

Having the economic commitment process solve over a two-day period rather than one would optimize long-lead time resources’ participation in the market, the report says.

“Simply eliminating self-commitment without any additional changes could result in an increase in total production costs,” the report warns. “However, when lead times were shortened to reflect an additional day in the market optimization and self-commitment was eliminated, producers were paid more and production costs declined.”

The Monitor is taking its presentation on the road. Having already shared its recommendations with the Market Working Group, it also plans to meet with the Cost Allocation Working Group.

“We’ll be speaking in different committees and venues,” Collins said.

February 5, 2020

GridLiance Gains Entry into MISO

By Amanda Durish Cook

Transmission owner GridLiance Heartland has gained access to the MISO system through an acquisition of transmission lines in Illinois and Kentucky after an unsuccessful first attempt to join the RTO.

In a trio of orders Jan. 31, FERC conditionally approved GridLiance Heartland’s acquisition of eight transmission assets from Vistra Energy subsidiary Electric Energy Inc. (EEI) (E C 20-13), set an annual transmission revenue requirement at about $7.4 million (ER19-2 0 50-002) and OK’d a separate open access transmission tariff (OATT) for the two lines that won’t be under MISO functional control immediately (ER19-2092, e t al.).

The third order also established settlement judge proceedings to examine the reasonableness of GridLiance Heartland proposing the MISO base return on equity in the OATT for non-MISO assets. GridLiance proposed a 10.32% ROE for the OATT, the ROE rate in use in MISO at the time of its filing in December 2018. FERC in late November adopted a new 9.88% return on equity for transmission owners. (See FERC Adopts ROE Methodology in MISO Complai n ts.)

The deal involves two 161-kV substations and six 161-kV transmission lines 8-10 miles in length that cross the Ohio River and connect to the EEI-owned Joppa Power Plant in southern Illinois. Vistra owns an 80% interest in EEI, with Kentucky Utilities controlling the remaining 20%. The assets are currently outside the MISO footprint. GridLiance said it would transfer all assets to MISO control by 2022: Four of the six lines will be turned over immediately to MISO, while two must wait for existing power supply agreements to run their course.

The six lines were originally constructed to power the U.S. Department of Energy’s now-defunct Padu c ah Gaseous Diffusion Plant uranium facility. EEI reconfigured its transmission system to disconnect from the Paducah plant in 2017. Four of the lines connect with TVA, while the other two connect with the Louisville Gas & Electric/Kentucky Utilities balancing authority area. The lines currently don’t serve any load.

GridLiance MISO — Paducah Gaseous Diffusion Plant | *U.S. Department of Energy*

MISO’s Board of Directors approved GridLiance Heartland’s application to join the RTO as a transmission-owning member in September 2018 subject to the outcome of the proposed transaction.

FERC had blocked the transaction in August, deciding GridLiance and EEI failed to prove the acquisition wouldn’t adversely affect MISO rates. (See FERC Blocks GridLiance’s Door into MISO.) The move will increase revenue requirements in the Ameren Illinois transmission pricing zone by about 2.6%.

GridLiance proposed rate mitigation credits to offset the $3.6-million difference between the projected revenue requirements of EEI and itself. The TO said the credits would appear in accounting as a fixed revenue credit and lower its revenue requirement every year for the five years after MISO takes control of the lines.

GridLiance said the credits “balance the risks and rewards for a start-up transco with a small initial rate base.” It also noted that it plans to participate in “proactive” planning studies on how the lines “may be optimized to solve documented transmission constraints.” The company said the lines may prove useful in lessening the strain on the transfer constraint linking MISO’s Midwest and South subregions.

GridLiance also noted that as a MISO member, it could help address “underinvestment” in transmission by MISO’s municipal and cooperative utilities.

Ameren Objects

The commission approved the deal over multiple objections from Ameren.

Ameren faulted GridLiance for using estimated, “snapshot in time” revenue requirements for its rate credits rather than actual amounts. It also said the commission was failing to consider that GridLiance would seek recovery of its $23.6 million regulatory asset that FERC approved last year. Ameren asked that FERC create further protections from the impact of GridLiance’s regulatory asset costs.

The company also said GridLiance’s claims of future benefits to MISO or the Ameren pricing zone were “tenuous.”

But FERC said GridLiance’s rate mitigation proposal addressed its concerns over the rate increase. The commission also said GridLiance Heartland is not to recover any amounts related to its regulatory asset during the first five-year rate mitigation.

“The regulatory asset is related to past development activities by GridLiance Heartland and not to costs that [EEI] would have incurred if it had retained ownership,” FERC warned.

FERC accepted GridLiance’s unorthodox rate mitigation proposal instead of the more commonplace five-year rate freeze based on the company’s assertation that forces out of its control could have increased even EEI’s revenue requirement, such as storm damage, or a new NERC requirement.

Ameren also protested the use of a stand-alone OATT for the non-MISO lines, saying it represented a “step backward in terms of the efficiencies created by having an RTO footprint.”

“We are not persuaded by Ameren’s argument that this proposal is a step backwards because GridLiance Heartland is eschewing the efficiencies of an RTO footprint. RTO participation is not mandatory and Order No. 888 requires that an OATT be on file in order to provide transmission service,” FERC responded.

GridLiance said it also plans to use the OATT to provide transmission service over “any future facilities it acquires in the MISO region but does not transfer to MISO’s functional control.”

FERC granted a one-time waiver of Order 1000’s competition requirements for the OATT. The commission said since GridLiance is proposing to transfer control of the lines and substations to MISO, it afforded no “practicable opportunity” for the TO to adhere to Order 1000. The commission noted the “unique circumstances” present in the transaction and said the waiver would be reassessed if GridLiance decides to build additional facilities under the same OATT.

February 5, 2020

New Agreement Swaps COTP Access for CAISO CRRs

By Robert Mullin

FERC approved an agreement that will allow the Transmission Agency of Northern California (TANC) to convert capacity on a key transmission line into “option” congestion revenue rights in the CAISO market (ER20-3 9 8).

The agreement covers use of TANC’s California-Oregon Transmission Project (COTP), a 340-mile, 500-kV line capable of delivering up to 1,600 MW of energy from Southern Oregon into Northern California. The line is jointly owned by the Western Area Power Administration and members of the Balancing Authority of Northern California (BANC), the BA for a handful of publicly owned California utilities located outside CAISO’s territory, including Sacramento Municipal Utility District.

Completed in 1993, the COTP was built to parallel the older Pacific AC Intertie (PACI). Together the lines comprise the California-Oregon Intertie (COI), a 4,800-MW transmission corridor linking Northern California with the hydro- and wind-rich Pacific Northwest. In 2013, PacifiCorp executed a similar CRR agreement with CAISO over use of the PACI portion of the COI, which CAISO manages as transmission operator.

The new agreement grants TANC access to “option” CRRs, a financial instrument that enables its holder to collect a positive revenue stream for allowing use of transmission capacity. The more common “obligation” CRRs come with risks, namely that they can provide holders with either a positive or negative revenue stream depending on the congestion pattern on a line.

The agreement stipulates that TANC will notify CAISO 30 days ahead of each calendar month regarding the volume of COTP transmission capacity the agency will release for conversion to the special type of CRRs. Capacity will be released on a directional basis (either north-to-south or south-to-north). CAISO will then issue TANC option CRRs that will source and sink at either Bonneville Power Administration’s Captain Jack substation or the Tracy 500-kV CAISO scheduling point, depending on the direction of the release.

The ISO will settle TANC’s CRRs as option CRR payments for intervals when the day-ahead market shows a congestion price difference between the source and sink, but payments will not be issued for real-time congestion. TANC capacity not converted to CRRs will remain as transactions subject to TANC’s transmission tariff.

CAISO’s Nov. 18 filin g touted the broad benefits of the agreement for its market participants.

“To the extent that TANC releases portions of the TANC capacity on the COTP for use by the CAISO, the ability of CAISO market participants to schedule transactions on the COI will increase and the CAISO will be able to address congestion more efficiently and reliably,” CAISO wrote. “The agreement provides CAISO market participants more transfer capability from the Pacific Northwest and an alternate path to the PACI. This is a more efficient outcome that increases flexibility.”

CAISO also said the agreement would not affect the financial position of existing CRR holders.

“The total amount of capacity that potentially could become TANC CRRs is equal to the total amount of capacity reserved for the TANC capacity. The agreement simply makes the available capacity easier to use by the entire CAISO market,” the ISO said.

PG&E Concerns Rebuffed

In approving the agreement on Jan. 31, FERC dismissed the concerns of Pacific Gas and Electric, which acknowledged the benefits for CAISO participants, while also contending that the monthly nature of the agreement differed from that of the deal with PacifiCorp and could incentivize TANC to release capacity in a manner that will maximize its own financial benefit.

The commission found no “meaningful distinction” between the TANC and PacifiCorp agreements despite that difference.

“As CAISO notes, the agreement provides an incentive to TANC to release transmission capacity during months when congestion revenue rights are most valuable, and it is during these months that the transmission capacity has the greatest potential to benefit market participants,” the commission said. “Further, TANC must commit to the capacity being released for the entire period.”

FERC also rebuffed PG&E’s argument that the agreement is predicated on modeling transmission capacity in a way that would effectively give priority to TANC to elect its CRR allocation before other participants in the normal election process. The commission noted that the agreement’s modeling of CRR options is consistent with how CAISO models options in the PacifiCorp agreement.

The commission additionally rejected PG&E’s request that the TANC agreement be limited to a two-year term and declined the utility’s recommendation for annual reporting to FERC.

“In light of the information on released transmission capacity available through CAISO’s OASIS, we find no need for CAISO to file similar information with the commission,” FERC concluded.