SACRAMENTO, Calif. — A key California State Assembly committee on Wednesday advanced a Senate bill requiring publicly owned utilities in the Los Angeles Basin to support deployment of distributed energy resources and energy storage.
The Committee on Appropriations approved SB 801, which now goes to the full Assembly for a vote.
The legislation was drawn up by State Sen. Henry Stern (D) in response to the 2015 leak that resulted in the closure of the Aliso Canyon natural gas storage facility. Many area residents are trying to get the facility closed permanently, but owner Southern California Gas recently resumed gas withdrawals after a court battle. (See Aliso Canyon Resumes Injections.)
Stern noted that investor-owned utilities Southern California Edison and San Diego Gas & Electric deployed energy storage quickly after the blowout, which threatened to compromise fuel deliveries to the region’s gas-fired generators.
“However, publicly owned utilities in the area have not yet adopted the same aggressive approach to clean energy storage and other safe reliability solutions in response to Aliso Canyon,” Stern said.
If passed, the measure would require the Los Angeles Department of Water and Power (LADWP), which serves 250,000 customers, to make data available that would help DER providers identify solutions to increase reliability in the region. It also requires LADWP to maximize use of demand response, renewables and energy efficiency in the area where reliability has been impacted by the Aliso Canyon outage.
The bill would allow LADWP to offset any ratepayer expenses with fines or fees levied over the leak against SoCalGas and its parent company Sempra Energy.
It would also require LADWP to study deployment of 100 MW of energy storage and oblige SCE to deploy 20MW of storage by June 1, 2018.
Stern has called the reopening of Aliso Canyon “premature and unnecessary.” California Energy Commission Chairman Robert Weisenmiller has said the facility should be closed permanently.
The committee also suspended until Friday a vote on SB 100, which mandates that the state’s utilities procure 100% of their electricity from zero-carbon resources by 2045. The Senate in May approved the legislation introduced by Senate President pro Tempore Kevin de León, a Los Angeles Democrat. (See California Senate Passes Bill Mandating 100% RPS.)
FERC on Tuesday approved a MISO pilot program allowing the RTO to share information on power plants’ gas use with pipeline operators (ER17-1556-001).
Starting in December, MISO will share day-ahead hourly burn estimates from gas-fired generators with a trio of gas operators: Northern Natural Gas, ANR Pipeline and DTE Energy. The RTO says the program will help ensure adequate fuel supplies for gas plants.
DTE’s Washington 10 Complex near Detroit | DTE Energy
FERC agreed that the program complies with the communications permitted in Order 787.
“We find that MISO’s proposal to extend the information sharing provisions to LDCs [local distribution companies] and intrastate natural gas pipeline operators will help ensure and optimize the reliable operation of the grid, particularly during the winter months where demand for natural gas is strongest,” the commission said.
The commission noted that Order 787 encouraged grid operators to make Tariff filings “to facilitate greater sharing of nonpublic, operational information with entities such as local distributions companies.”
“We note that the proposed revision will improve communication and coordination among MISO and operating personnel of the interstate natural gas pipeline companies in the MISO region to ensure that MISO and interstate natural gas pipeline control room operators have better information on which to base operating decisions,” FERC said.
The acceptance comes after FERC in June issued MISO a deficiency letter in response to an earlier version of the proposal. The letter noted that the pilot lacked a no-harm clause and that the RTO failed to justify its reason for sharing confidential information with LDCs, which FERC must approve on case-by-case basis. (See FERC: MISO Gas Data Sharing Plan Falls Short.)
In response, MISO amended its filing with language borrowed from PJM that expressly states that any shared information will not be used “to the detriment of any natural gas and/or electric market.” MISO also contended communication with LDCs is crucial because about 25% — or 12,511 MW — of the RTO’s gas-fired capacity is served by the companies.
FERC accepted both responses, saying that MISO’s use of nondisclosure agreements and restrictions placed on shared data “minimizes the opportunity that the information can be used in an unduly discriminatory or preferential manner by the recipient or to the detriment of the market.”
The commission rebuffed Indianapolis Power and Light’s protest against the pilot. The utility asked that MISO not be allowed to “grant itself the ability to provide proprietary data to anyone without the expressed consent of the generation owner.” FERC, however, noted that Order 787 did not require “three-way communications” for such programs.
Some MISO stakeholders earlier this year voiced opposition to the pilot, saying it could affect reliability if participating gas operators make burn rate decisions relying solely on partial day-ahead data. (See MISO Stakeholders Question Electric-Gas Info Sharing.)
A new study prepared for the American Coalition for Clean Coal Electricity (ACCCE) spotlighting the “resiliency” of coal-fired generators echoes the findings of a U.S. Department of Energy report released earlier this month.
Although the study by PA Consulting Group concludes that “no single electricity resource has all of the attributes necessary for a reliable and resilient grid” and that “a mix of resources is the best strategy,” it lauds coal generation for its “many critical attributes,” including stable fuel prices and an on-site fuel supply that can act as a hedge against potentially volatile natural gas prices, interruptible fuel deliveries and intermittent renewable and demand response resources.
Coal stockpile | Worldcoal.org
The study’s release may prove to be an early salvo in the possible “fuel wars” predicted by one former senior FERC official who said that new FERC commissioners could break with agency tradition by each acting as advocates for favored types of resources. (See Coal Seeks ‘Resiliency’ Premium; FERC ‘Fuel Wars’ Coming?)
The study ranked generation resources on 11 attributes, giving coal high marks in all but black start capability.
The report is effectively a response to a study done by The Brattle Group for the American Petroleum Institute (API), which concluded that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes identified in that study. (See NG Lobby Goes on Offensive vs Coal, Nukes.)
The API/Brattle report ranked coal as only “neutral” on two categories for which ACCCE claimed a full score — frequency response and ramp rates (referred to as “ramp capability” by ACCCE).
API did not score three categories in which ACCCE said coal had an advantage over gas: on-site fuel supply, reduced exposure to a single point of disruption and price stability.
“This new report shows the coal fleet is essential to help maintain the reliability and resilience of the electricity grid,” said ACCCE CEO Paul Bailey. “For that reason, we are especially supportive of DOE’s recent recommendation that policymakers need to establish criteria to value attributes, such as on-site fuel, that help protect the grid against low probability events that have extreme consequences.”
Bailey said he looked forward to “working with policymakers to implement DOE’s recommendation as quickly as possible” that RTOs begin valuing on-site fuel storage as a measure of “resiliency.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Natural Gas Criticisms
The report took particular aim at natural gas-fired generation, coal’s biggest competitor. According to the report, coal generators on average stockpiled 82 days of bituminous coal and 73 days of subbituminous coal on site over the last five years. It compared that to the position of “vulnerable” gas-fired plants, which last year on average had about 60 days of fuel in storage reserves and rely on interruptible deliveries via pipeline.
| ACCCE
It also pointed out that low-probability, high-impact events like earthquakes can cause supply shocks in the gas distribution network. More than 50% of gas storage capacity is located in five states — Michigan, Texas, Louisiana, Pennsylvania and California — PA Consulting warned, and 18 states in the continental U.S. have “no material storage capability,” including New England and North Carolina, South Carolina, Georgia and Florida.
The study also said that because most U.S. coal is used for electricity, coal-fired generation “does not compete with higher-priority uses” and will not have to be forcibly curtailed. It also pointed out that “all but two lignite coal-fueled plants [in the U.S.] source their coal from mines within 30 miles of the plant.”
The popularity of gas-fired generators relies on the continuation of low-cost shale natural gas, the study contends.
“The current investment boom in natural gas-fired plants is driven in part by an expectation of continued low natural gas prices of approximately $3-4/MMBtu,” the study said. The 77 GW of gas-fired capacity built since 2009 might be a result of an “over-focus on short-term price signals,” the authors contend.
Over the last decade, monthly average natural gas prices have “repeatedly seesawed” from $3/MMBtu to more than $12/MMBtu, reaching $100/MMBtu in some markets during the so-called “polar vortex” of 2014, the study noted. It also pointed to dramatically fluctuating gas prices during 2015’s Aliso Canyon leak and an extreme cold front in Texas in 2011 that caused 193 generating plants to either fail outright or experience weak output.
“Retaining existing coal-fueled power plants can help insulate ratepayers against rising and possibly volatile natural gas prices,” the report said.
NYISO locational-based marginal prices (LBMPs) have averaged $36.35/MWh for the year through July, a 12% increase from a year earlier, COO Rick Gonzales told the Management Committee during its Aug. 30 meeting. Natural gas prices were up 13.1% over the same period.
LBMPs averaged $35.84/MWh during July, up 13% from June and down 10% from July 2016. Last month’s daily sendout averaged 498 GWh/day, compared with 532 GWh/day a year earlier.
July natural gas prices and distillate price averages gained from the previous month, with Transco Z6 NY gas up 4% to $2.44/MMBtu, jet kerosene Gulf Coast up 9% to $10.49/MMBtu and NY Harbor ultra-low sulfur No.2 diesel up 7% to $10.85/MMBtu. Distillate prices increased 11.1% from the same period a year ago.
| NYISO
Average uplift costs — not including NYISO cost of operations — were down to -43 cents/MWh for the month, compared with -37 cents/MWh in June. The local reliability share fell 4 cents to 11 cents/MWh. The statewide share of -54 cents/MWh came in 2 cents below June. July’s total uplift costs were also lower than in June.
The monthly peak load of 29,699 MW occurred July 19, far short of the all-time summer peak of 33,956 MW recorded on July 19, 2013.
NYISO Evaluates Energy Market Offer Cap
The ISO is continuing to evaluate its energy market offer cap to prevent differences in regional offer caps from interfering with economic and reliability-driven interchange scheduling, according to a report presented by NYISO Senior Vice President for Market Structures Rana Mukerji.
NYISO’s control room | NYISO
Under FERC Order 831 issued last November, NYISO is required to cap each resource’s incremental energy offer at the higher of $1,000/MWh or that resource’s verified cost-based incremental energy offer, and cap verified cost-based incremental energy offers at $2,000/MWh when calculating LBMPs. The grid operator last December filed a request for clarification/rehearing on the issue with FERC and submitted a compliance filing in May.
Mukerji also noted that the ISO is working to improve forward horizon coordination of real-time constraints (RTC) and real-time dispatch (RTD). NYISO aims to improve modeling consistency between RTC and RTD and evaluate improvements in look-ahead evaluations to facilitate more efficient scheduling and price convergence.
Pending issues include possible proposals to allow market participants to buy and sell reserves and regulation service between NYISO and adjacent control areas and to develop a market mechanism to assign external parties with the costs associated with congestion rent shortfalls resulting from external transmission outages.
The ISO is also examining the reciprocal elimination of fees on export transactions in order to increase interregional transmission scheduling efficiency. Rate pancaking between NYISO and ISO-NE has already been eliminated.
Interconnection Queue Improvements Approved
The committee approved steps intended to improve the efficiency of the interconnection queue process while maintaining needed reliability evaluations.
The proposed changes clarify and update existing practices and procedures, except for the transmission interconnection procedures, which are still pending FERC acceptance. Transitional rules would allow projects currently in the interconnection process to benefit from the proposed changes. (See “Committee Advances Interconnection Queue Improvements,” NYISO Business Issues Committee Briefs: Aug. 9, 2017.)
NYISO expects to file associated Tariff changes with FERC in late September following board approval.
New York Easily Handles Solar Eclipse
NYISO easily met operational reliability criteria throughout the solar eclipse Aug. 21, despite a 1,010-MW reduction of net load that exceeded predictions by nearly 300 MW, according to a report from NYISO Vice President of Operations Wes Yeomans.
The ISO did not experience the slight projected load increase early in the eclipse, possibly because of lower loss of behind-the-meter solar than originally anticipated, as well as public reaction to the event. He attributed the higher-than-expected net load increase later in the eclipse to high humidity.
New York experienced a partial solar eclipse from 2:30 to 2:45 p.m., with peak obscuration ranging from 80% in Chautauqua County, to 75% in New York City and Long Island and 67% in Clinton County.
California utilities and state agencies are cooperating on developing plans to manage the effects of global climate change on the electricity grid, an issue that looms especially large for the state.
Rising sea levels, reduced snowpack, more wildfires and extreme weather events such as drought and severe rain are predicted for California, which experts say will be more affected by global warming than other states because of its warm climate and extensive coastline.
Partnership between state officials, local government and utilities was the theme at a Tuesday workshop hosted by the California Energy Commission. Participants discussed the physical impacts of climate change on the grid, geophysical changes, temperature trends and the challenges facing vulnerable populations.
State law requires the CEC to assess and forecast the state’s energy production, supply and demand, and develop policies that conserve resources. The agency is studying climate change impacts on the energy grid as part of its 2017 Integrated Energy Policy Report process, which is updated every year and adopted every two years.
Pacific Gas and Electric is a critical infrastructure company with 16 million customers and a “critical responsibility,” said Melissa Lavinson, vice president of federal affairs and policy. The company is getting more requests from local governments for information on its efforts to prepare for climate change, she said.
PG&E favors a regional approach to the issue that would help with coordination, rather than going community by community. The utility has proposed a “climate resilience clearing house” to aggregate information and a regional governing body to coordinate local governments.
“We are far from the end of this process. We are at the beginning of this journey,” she said.
San Diego Gas & Electric is in the midst of a “Climate Vulnerability and Adaptation Options” study consisting of both electric grid and natural gas tracks, Sempra Energy Meteorologist Brian D’Agostino said. The electric analysis looks only at the effect of the rising water level and flooding on the coast where many of the company’s power plants are located, while the natural gas program also looks at climate hazards inland. The report also highlights downstream impacts on customers, electricity demand and the economy.
Historic and Project State-Wide Temperature | California Energy Commission
PG&E is working with the University of California, Berkeley and the California Department of Water Resources on a program to deploy wireless remote sensors to study moisture, temperatures and snowpack and more effectively manage hydro assets, said Gary Freeman, the company’s principal hydrologist. The company closely studies weather and increasing “atmospheric rivers,” which are columns of moisture that occur in the atmosphere and can dump large amounts of rain.
Atmospheric rivers hundreds of miles wide occur in California because of the Pacific Ocean and mountains that cool the air as it travels inland. The formations provide up to 50% of the annual precipitation on the West Coast, and their increasing activity is another example of how climate change affects grid planning and reliability in a region with extensive hydroelectric capacity.
Gov. Jerry Brown in April 2015 signed an executive order that set 2030 greenhouse gas reduction targets that were recently codified into law. (See California Lawmakers Extend Cap-and-Trade.) The state has also developed online tools providing climate change data, including climateconsole.org and cal-adapt.org.
American Transmission Co. has agreed to pay a federal fine and undergo a year of monitoring after failing to properly report more than 60 agreements and transactions to FERC over the past 16 years.
Under an agreement reached with FERC’s Office of Enforcement, Milwaukee-based ATC will pay a civil penalty of $205,000 to the U.S. Treasury and submit semi-annual compliance monitoring reports for one year detailing any further violations (IN17-5).
ATC headquarters in Milwaukee | Mortenson Construction
The office found that ATC repeatedly failed to seek approval to merge or acquire FERC-jurisdictional facilities and to file “timely” contracts and agreements relating to rates and charges for jurisdictional service.
“Enforcement determined that, although ATC’s violations did not result in quantifiable market harm, they created a lack of transparency in the market by failing to have all of ATC’s jurisdictional agreements on file with the commission, and by consummating purchases of commission-jurisdictional assets without commission authorization,” the commission said.
In an internal review of its filing processes during 2014 and 2015, ATC discovered 63 instances in which it failed to either properly report or file information starting in 2001.
Those include several agreements that it failed to file pursuant to Federal Power Act obligations, relating to operations, transmission design on shared 345-kV projects, pole replacements, repairs on jointly owned substations, transmission line relocation and ownership, and cost-sharing for jurisdictional facilities. ATC in some cases also neglected to file notices to terminate existing agreements. The company has already paid $1.4 million to several affected parties in time-value refunds.
The company also identified 21 jurisdictional facilities it acquired without gaining FERC approval. The facilities range in value from $1,513 to $1.2 million. FERC retroactively approved each transaction after ATC sought permission between 2014 and 2015.
Section 203 of the FPA requires public utilities to file for FERC authorization to merge or acquire jurisdictional facilities, and Section 205 requires public utilities to file “all contracts which in any manner affect or relate to such [jurisdictional] rates, charges, classifications and services.”
FERC said that, since discovering the violations, ATC has taken steps to “strengthen its compliance policies and procedures and to prevent noncompliance in the future regarding jurisdictional agreements,” holding employee training seminars, updating training documents and developing an internal review process to make sure the company has proper authorization.
CARMEL, Ind. — Now that it has completed a seven-month evaluation of its existing system, MISO says it will provide a detailed decision on how it would rebuild its computer-based market platform in 2019.
The RTO’s near-term focus: to protect and extend the life of the existing market system while exploring and discussing upgrade options with vendors, according to MISO General Counsel Andre Porter.
MISO will present a business case for the making the upgrade at a Sept. 6 workshop on the status of the market platform. MISO’s Board of Directors in June urged RTO officials to provide stakeholders with upgrade details — and a plan — in order to solicit comments. (See MISO: $130M Needed for New Market Platform.)
“Stakeholder participation is critical for the market system enhancement program,” Porter said, urging stakeholders to bring questions to the workshop.
At an Aug. 24 meeting of the board’s Technology Committee, Director Baljit Dail praised the RTO’s stakeholder outreach, but stressed that it should make the upgrade information easier to understand.
MISO expects to select an upgrade option and confirm a vendor in 2019, with roll-out of the new platform targeted for no later than 2024. Officials plan to finalize a budget in October for the estimated $65 million needed to preserve the existing system for another five to seven years, while another $65 million would be allocated to build a new modular platform. The budget will also include a total contingency amount equating to up to 25% of the project cost.
Director Thomas Rainwater commended MISO for being able to finish the evaluation stage of the project on time. “We think that’s a bellwether of what’s to come,” he said.
“The progress you all have made is phenomenal, and you guys should be very proud of this. As a committee, we want this project to be successful. It has the potential for a huge payout,” Dail said, urging officials to provide frequent updates on the project.
As MISO completes the platform rebuild, officials will also explore the intellectual property rights of the software. A deeper discussion on possible copyrights was saved for a closed session of the Technology Committee.
The existing market system, designed by General Electric, was built from scratch in 2005 for $245 million. To incorporate the ancillary services market in 2009, MISO spent $75 million. It spent an additional $30 million to expand the platform upon integration of MISO South in 2013. In any given year, MISO invests about $6 million to $9 million in maintenance and improvement costs, Vice President of System Operations Todd Ramey said.
“The system we use today, and have used since the start of our markets in 2005, is really based on infrastructure used in the late 1990s. This system has started to show signs of its age,” Ramey said.
Several Market Roadmap design changes have been put on hold because of the aging infrastructure, Ramey said. MISO has growing concerns about security and, in some cases, market participants must use older versions of web browsers to view web pages.
ISO-NE and PJM also use GE-designed platforms. Both RTOs will undergo “common” upgrades using a staged approach in the next few years, said Jeff Bladen, MISO executive director of market design.
“In some respects, we’re catching up [with other RTOs], but we have a plan to go beyond what’s done today,” Bladen said during an Aug. 23 Advisory Committee meeting.
Ramey noted that MISO would eventually be forced to change to its platform because GE plans to phase out IT support for the aging software.
The computer overhaul will mostly affect MISO’s day-ahead market and Energy Management System programs. The RTO’s settlement software system is being rebuilt in a different project launched in 2014. The RTO is currently completing system testing and expects to launch the new settlements platform sometime in the fourth quarter, in time for the early spring 2018 roll-out of five-minute settlements.
VALLEY FORGE, Pa. — PJM and MISO staff provided updates on their proposed pro forma pseudo-tie agreements, the “freeze date” on transmission rights and targeted transmission upgrades at their Joint and Common Market meeting Aug. 22.
MISO’s Kevin Vannoy told stakeholders that FERC accepted the RTO’s pro forma pseudo-tie agreement Aug. 9 with an effective date of March 15, though it was approved in a delegated order and could be subject to further review and refunds now that the commission has a quorum (ER17-1061). (See FERC Conditionally OKs MISO’s Pseudo-tie Pro Forma.)
PJM’s pro forma agreement, filed on Aug. 11, awaits FERC approval. The grid operators filed revisions to their joint operating agreement to address PJM’s pro forma on Aug. 1.
The grid operators next plan to address the “congestion overlap” that is causing some congestion to be charged twice and has led to complaints at FERC. The issue, which occurs when an associated market-to-market constraint binds in both markets, will require a two-phase solution.
“It’s a complex solution” that can’t be done in a single implementation, PJM’s Tim Horger explained.
The first phase, which the grid operators hope to have implemented by Dec. 1, would include JOA changes to better model the impacts of firm-flow entitlements before the day-ahead dispatch is modeled. This will allow day-ahead LMPs for pseudo-tied resources to more accurately reflect expected real-time congestion. The balancing authority receiving the power will receive credit for the flow from the generation unit to the border, while the source balancing authority will model its impacts as loop flows.
“We think it’s a major step and will remove most of the overlap,” Horger said.
The second phase will allow for mitigating day-ahead charges either through refunds or virtual transactions to align transmission usage charges with available financial transmission rights hedges.
The RTOs plan to file JOA changes implementing market-to-market adjustments in September, with implementation of the phase one solution by the end of December. Dec. 1 is the target date for filing additional JOA and tariff changes. Phase two is scheduled for implementation by June 1, 2018.
The grid operators have been using an April 1, 2004, “freeze date” to determine firm rights on flowgates, but issues with that date have “become prominent” over time, the RTOs said. They have developed a two-phase alternative that would be in place by June 1, 2019, MISO’s Ron Arness explained.
The changes would affect designated network resources that came on after the freeze date, which currently are dispatched on a pro rata basis. The new rules would eliminate the pro rata allocation and have them dispatched in the order of their service date.
They also affect “freeze date” transmission service requests, which currently are treated as net imports or exports based on the local balancing authority. The new rules would provide “gross accounting” for imports and exports — generation-to-load LBA calculations would not include generation sourcing TSRs or load served by TSRs — with adjustments that will make the TSR sensitivity factors align with market flow sensitivity factors.
The RTOs plan to complete a whitepaper on the issue by next spring with implementation of phase one in the summer.
PJM’s Chuck Liebold said there has been no targeted market efficiency project (TMEP) study in 2017 because the RTOs are awaiting FERC approval of regional cost allocations for the new category. MISO filed for regional allocation Aug. 4 (ER17-2246), and PJM filed its allocation on April 11 (ER17-1406).
Commission staff tentatively approved the TMEP category in a delegated order in June but said the decision was subject to review by the commission once it regained the quorum it lost in February (ER17-721). (See FERC Tentatively OKs New MISO-PJM Project Type.)
The TMEP proposals are designed to be quick, inexpensive fixes to address historical congestion. Five projects have been identified so far. At an estimated cost of $17.5 million, they are expected to create $99.6 million in benefits.
The RTOs are waiting on FERC approval before submitting the project recommendations to their boards. The benefit allocation for three of the five projects leans heavily toward PJM, with 88% of the $7 million Burnham-Munster project, 89% of the $1 million Bayshore-Monroe project and 90% of the $4.6 million Michigan City-Bosserman project. MISO shoulders most of the allocation on the other two, with 59% of the $150,000 Reynolds-Magnetation project and 76% of the $4.5 million Roxana-Praxair line.
Two-Year System Plan Study
The RTOs have completed regional benefits analysis for the eight interregional projects that were proposed for the solicitation that ended Feb. 28. Only one project — Northern Indiana Public Service Co.’s proposed new line between its Thayer and Morrison 138-kV substations in northwestern Indiana — is expected to provide more benefits than costs. (See 1 of 8 MISO-PJM Proposals Pass Initial Test.)
Liebold said the cost-benefit was not the only factor in recommending projects, but “for a project to be promising, you would expect to see benefits above costs.”
The RTOs will make recommendations to their respective boards on the proposals around November or December.
CAISO is close to finalizing a long-running effort to reduce exceptional dispatch of generation to resolve transmission constraints and comply with reliability standards, but market participants have raised last-minute questions about the proposal.
During an Aug. 21 call on the Contingency Modeling Enhancements (CME) draft final proposal, some stakeholders said they wanted more detail about where CAISO would apply a proposed “preventative-corrective constraint” tool. But the ISO, which is preparing to present a final plan to the Board of Governors next month, said it has provided enough transparency.
CAISO kicked off the CME initiative three years ago to address a Western Electricity Coordinating Council reliability provision requiring grid operators to return a critical transmission path to its system operating limit within 30 minutes of a destabilizing event, such as the loss of a generator or transmission line. The ISO’s present approach to managing those contingencies relies on out-of-market interventions coupled with day-ahead market measures that procure a “bucket” of responsive capacity resources based on a flat megawatt rating of the line.
WECC has since retired that standard, but CAISO still needs to comply with NERC standards requiring a return to normal operations in 30-minute and four-hour time frames.
Under the proposal, resources contributing to restoring normal operations would receive both an energy payment and a payment for reserve “corrective capacity” set aside by the ISO, the cheapest way to provide needed generation if needed because of a contingency, CAISO says.
“The goal here is to reflect the real reliability constraint in the market,” said Perry Servedio, CAISO senior market design policy developer. “We believe the proposal improves transparency related to these constraints by improving the pricing and dispatch.” The latest version has “a hodgepodge of final tweaks to the policy.”
CAISO is Trying to Resolve Temporal Transmission System Reliability Constraints in its Market | CAISO
Southern California Edison had previously raised concerns over the complexity of the proposal, while Calpine and NRG Energy were supportive but said that the mechanism should allow participants to bid for corrective capacity. The ISO said that the proposal “fully captures and compensates” for capacity needed to meet any restraints on the system.
During the call, some stakeholders questioned why CAISO had not specified on which transmission paths the constraint tool would be applied. SCE said there is not enough transparency around how the paths would be selected, making it difficult to analyze the benefits.
For SCE, “the benefits are very limited. We don’t see any incremental benefit because you do have all the tools you have today,” Senior Project Manager Wei Zhou said. He added it will increase complexity in the market.
CAISO Principal George Angelidis responded that “I think we are getting bogged down in implementation details and we are missing the big picture here.” The fundamentals of the proposal have not changed, and it is “still a tool that will provide the ability to reduce constraints that are imposed by operators based on their judgement of system conditions,” he said.
“I don’t know why we are making a big issue on this trivial application change” of where the tool will be used, Angelidis said, adding that it would be used wherever it would provide a benefit.
Servedio said that “the selection criteria is: whatever we need to do to operate within our facility ratings.”
The grid operator is taking comment on the final draft proposal until Aug. 31.
CAISO has a separate and overlapping effort underway to resolve certain generator and transmission contingencies currently handled by out-of-market operations. (See Stakeholders Wary of CAISO Contingency Modeling.)
CARMEL, Ind. — A mid-July heat wave failed to drastically alter MISO’s monthly average load and energy price, stakeholders learned at an Aug. 22 Informational Forum.
July’s temperatures averaged near normal overall, MISO Executive Director of System Operations Renuka Chatterjee said.
Load averaged 87 GW during the month, up from an average 80 GW in June and “consistent with the summer weather conditions,” Chatterjee said. Load peaked for the year at 120.6 GW on July 20, close to last July’s peak. Day-ahead and real-time energy prices averaged $30/MWh and $31/MWh, comparable to a year ago, owing to natural gas prices that held steady below $3/MMBtu.
“Overall, this July was a typical summer month,” she said.
MISO experienced fewer forced outages this year but more planned outages when compared to last year. Forced generation outages decreased by about 3 GW from a year ago to about 11 GW, while planned outages were up 1 GW to about 6 GW. Real-time congestion stemming from forced outages led to “unanticipated higher prices” in MISO South on July 28, Chatterjee said.
| MISO
July boasted 2,277 GWh of total wind generation, a 7% decrease compared with last July. Meanwhile, MISO’s registered wind capacity increased from 15.9 GW to 16.8 GW year-to-year.
