CAISO said it will kick off an initiative to refine its generation interconnection process later this year as part of an ongoing effort to accommodate renewables and keep its rules updated.
The grid operator is in the beginning stages of its Interconnection Process Enhancements 2018 program but wants to hear from stakeholders about what its scope should be. CAISO spokesman Steven Greenlee told RTO Insider that the enhancements are part of an open interconnection initiative that began in 2013. The initiative in the past has led to minor but useful modifications in the generator interconnection process, and is meant to ensure the process reflects current grid conditions and that rules are updated appropriately.
“It’s not that we have found anything major and are looking to broaden the scope; it’s just an opportunity for stakeholders to bring up things that may need tweaking or exploring more,” Greenlee said.
CAISO is in Beginning Phases of Interconnection Changes | First Solar Desert Sunlight Plant Source: Wikimedia
CAISO said that a future market notice will outline a schedule for the new enhancements, leading up to filing at FERC. In a January 2016 update filed with the commission, the ISO said its “overriding goal has been to tailor its procedures to promote California’s energy goals while ensuring that they continue to be grounded in principles of cost-causation, fairness and non-discrimination.”
The state’s renewable portfolio standard and rapid changes in generation development make it increasingly important to have an efficient interconnection queue process. As a single-state ISO, CAISO must adhere to a more unified set of policy goals compared with other ISOs and RTOs across the country — specifically, the State Legislature setting aggressive renewable generation goals to combat climate change.
Generators Must Comply With CAISO Rules to Interconnect to the Electric Grid | PG&E Moss Island Plant Source: Wikimedia
Generation developers that want to connect to the CAISO grid must submit an interconnection request that triggers an ISO interconnection study. One of the most significant problems with the process is that many projects sit in the queue for up to a decade after slowing or stopping their progress. While some of the delays are outside the developer’s control, they can result in the holding of capacity, transmission, deliverability and bus positions that hinder other projects.
In March 2016, FERC approved 10 changes to the interconnection process, including new timelines for projects in the queue. Last year CAISO had 44 projects in its queue — representing 17% of the total — with commercial operation dates more than seven years from their interconnection requests.
The ISO is seeking comments on the scope of the new initiative by Aug. 30.
A $40/ton carbon charge in New York state would have “a relatively small impact” on customer costs, ranging from a −1% to +2% change in total customer electric bills, according to an analysis released by NYISO and the state Department of Public Service on Friday.
The much-anticipated report by the Brattle Group on pricing carbon into generation offers and reflecting it in energy clearing prices was prompted by the Public Service Commission’s decision to subsidize upstate nuclear plants through zero-emission credits (ZECs). Fossil fuel generators would incur a penalty based on their level of carbon emissions.
| NYISO
The study is meant to develop an approach to value carbon in the wholesale energy market as an instrument of state policy while “providing appropriate price signals to incentivize investment and maintain grid reliability,” NYISO CEO Brad Jones and PSC Chairman John B. Rhodes said in the preface.
Costs and Benefits
Although average wholesale energy prices would increase under a $40/ton carbon adder, about 50% of the cost could be offset by returning carbon revenues to customers; another 18% by reduced prices for renewable energy credits and ZECs; and an additional 23% by “dynamic effects on investment signals,” the report said.
While more economic gains from the program would go to producers than to consumers, customer costs would not rise significantly, the report said. A supplemental carbon charge would increase wholesale electric energy prices beyond the rises prompted by New York’s Clean Energy Standard and the Regional Greenhouse Gas Initiative. However, “returning carbon revenues to customers and other factors would offset most of the customer cost impact. The exact magnitudes are uncertain, but the net impact on customer costs remains relatively small under all assumptions considered.”
The $40/ton adder would reduce CO2 emissions by 2.6 million tons per year, or 8% of today’s emissions, by incentivizing cost-effective market responses not available through the CES and RGGI alone — and the analysts said the estimate of CO2 emission reduction “is probably conservatively low.”
Gavin Donohue, CEO of the Independent Power Producers of New York, lauded the report in a statement: “Incorporating the value of carbon into the marketplace ultimately benefits ratepayers and demonstrates that private investment is best for the continued success of New York’s energy markets. Though this process is only in the early stages, what we accomplish here could be a model on the national stage.”
In a blog post, Jackson Morris of the National Resources Defense Council said, “The concept of a carbon adder is laudable and worth exploring. And it has clear potential to cut carbon pollution — but only if the state and NYISO get the design right and, in the process, avoid some important legal and policy pitfalls.”
The report concludes by suggesting topics of further study. For example, market design affects carbon charges, and different designs create new models of revenue allocation and border adjustment. Also implied are potential refinements “to REC and ZEC procurement for allocating the risk of future changes in carbon prices between customers and suppliers,” the report said.
NYISO and the DPS will hold a conference on Sept. 6 to solicit stakeholder feedback on the reasonableness of modeling assumptions, especially their dynamic effects. The report said that although New York has no specific emissions reduction target for the electricity sector, the state’s commitment to reducing carbon emissions from power generation “is expressed monetarily in its ZEC payments to upstate nuclear plants … starting at $43/ton CO2 today and rising to $65/ton by 2029.”
Relative cost of reducing emissions with Upstate and Downstate Wind | NYISO
The ZECs are part of the CES, which mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. It also calls for renewables to meet 50% of the state’s energy needs by 2030.
ZEC Challenges
The Electric Power Supply Association and several of its members had filed suit against New York’s ZEC program, claiming that it intruded on FERC’s authority over interstate electricity sales. A federal judge in New York on July 25 dismissed all claims in the suit, finding the state’s ZEC program constitutional. Earlier in July another federal judge had dismissed similar challenges to Illinois’ program. (See New York ZEC Suit Dismissed.) EPSA has appealed the Illinois ruling and plans to challenge the New York dismissal as well.
Jones previewed the Brattle report in May at a FERC technical conference devoted to the issue of reconciling public policy and wholesale electricity markets in New England, New York and PJM, and also at a congressional energy hearing in July. He said New York hoped to implement the plan in the markets within three years. (See RTOs to Congress: Don’t Lose Faith in Markets.)
PJM also is considering a similar mechanism, while New England has rejected carbon pricing as impractical and overly expensive. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
Some stakeholders who oppose NYISO’s carbon pricing plan have already questioned the current market design, particularly regarding capacity markets. Before and after the technical conference in May, FERC asked for comment on five potential paths toward harmonizing public policies and wholesale electricity markets, including the path chosen by New York. (See We Read 79 FERC Comments so You Don’t Have to.)
Economist James F. Wilson said the commission should eventually phase out the capacity constructs or convert them to voluntary mechanisms. Cliff Hamal, managing director of Navigant Economics, said “the most fundamental assumption” underlying capacity markets — setting capacity prices based on the cost of building new gas-fired generation — may no longer be valid.
Environmental and consumer activists Wednesday accused Ameren Illinois of attempting to bypass energy efficiency targets set by the state’s new clean energy law.
The Illinois Clean Jobs Coalition, with Illinois Rep. Elaine Nekritz and representatives from the Citizens Utility Board (CUB) and Natural Resources Defense Council (NRDC), held an Aug. 9 teleconference to criticize Ameren for setting low energy efficiency goals and urge state regulators to reject the utility’s plan. CUB, NRDC and the Environmental Defense Fund filed joint testimony opposing Ameren’s plan, which also attracted criticism from many others (17-0311).
According to a July report from the NRDC, both Commonwealth Edison and Ameren filed their initial four-year energy efficiency plans with the Illinois Commerce Commission, but Ameren’s plan contained lower energy efficiency goals than required by the Future Energy Jobs Act, which includes performance-based incentives that reward utilities for surpassing efficiency targets and penalize them if they fall short. (See Illinois Lawmakers Clear Nuke Subsidy.)
“It’s important to understand that everyone benefits from energy efficiency,” said CUB Executive Director Dave Kolata, who asserted that Ameren provided no evidence, as required, for not being able to meet the goals.
“In essence, they filed a bloated and inefficient plan” by claiming energy efficiency is more expensive, Kolata said. While the NRDC says ComEd’s portfolio meets the new law’s four-year target of 11.8% savings, Ameren Illinois’ plan “does not meet any of its statutory cumulative annual persisting savings targets — all of which were lower than ComEd’s — over the four-year period.”
Under the law, ComEd and Ameren are required to achieve 21.5% and 16%, respectively, in cumulative annual savings through 2030 ― figures that both utilities had to sign-off on, according to Nekritz, chief sponsor of the law.
By 2021, Ameren should meet a 9.8% cumulative persistent annual savings, but the utility is planning for 8.24% savings. If Ameren’s plan is allowed, the utility could gain $36 million in incentives while failing to abide by the law’s requirements, the groups said.
Ameren Illinois President Richard J. Mark vehemently rejected the allegation. “They state that Ameren is seeking a $36 million bonus if we achieve lower goals. This is a false statement. In the unlikely event that Ameren earned the ‘maximum bonus,’ it would amount to approximately $1.3 million in the first year of the plan and $10.1 million in total during the four-year plan.”
Mark noted that the filed plan only covers the next four years and is not an indication that the company won’t reach the 16% target by 2030.
Nekritz said Ameren should not be allowed to “exploit a loophole” and pointed out that Ameren was already given a lower standard in the law than ComEd.
“Just a short seven months later, Ameren is already backing away from their weak commitment. … Ameren broke their word,” Nekritz said. She said while Chicago and Northern Illinois will benefit from electricity savings, Central and Southern Illinois will lose out from Ameren “lowering the goalposts.”
Josh Mogerman, NRDC media director, said the law could add 7,000 jobs annually, boosting the state’s economy by $700 million per year. “Every time I go home to my parent’s in Springfield and see that old refrigerator running in the garage, I’m reminded that there are opportunities all over the state. … Come on, Ameren, don’t let down your customers,” Mogerman said.
Ameren said its plan is tailored to serve its more sparsely populated customer base. “ComEd serves 3.8 million customers within a territory spanning only 11,400 square miles, or 333 customers per square mile. Ameren Illinois serves 1.2 million electric customers in a service territory that covers 43,700 square miles, or 27.5 customers per square mile,” Mark said in a statement to RTO Insider. “There is significantly less energy saving potential in the Ameren Illinois service territory.”
Ameren Illinois Service Territory | Ameren Illinois
Mark said that Ameren’s plan calls for $112 million in spending annually on low-income programs for the next four years — the maximum allowed under the law. “We’re focusing on assisting moderate- to low-income customers who pay for energy efficiency programs every month and deserve the opportunity to receive the benefits,” Mark said.
The ICC could decide on Ameren’s proposal as soon as early fall.
A New York appellate judge on Wednesday blocked the Public Service Commission from limiting energy service companies’ (ESCOs) ability to contract with low-income people in the state.
The temporary restraining order from Justice Christine Clark, of the Appellate Division’s Third Judicial Department, continues the legal see-sawing on the commission’s efforts to protect poor New Yorkers from paying excessive rates for electricity.
The restraining order will remain in effect pending the court’s ruling on a motion to stay a July 5 state Supreme Court order. Clark ordered the PSC to appear at a show cause hearing on Aug. 23. (New York’s Supreme Court is the trial-level court in the state, with the Appellate Division hearing appeals of its decisions. The state’s highest court is the Court of Appeals.)
Robert Abrams Building for Law and Justice, home of the New York Appellate Division Third Judicial Department | New York Supreme Court
Craig Goodman, president of the National Energy Marketers Association, said that Wednesday’s ruling paved “the way for appellate review of the PSC’s efforts before they are implemented. We look forward to participating in the process to gather real data and analysis that can drive policy to achieve New York’s energy goals as opposed to restricting consumer choice based on unsupported claims and faulty numbers.”
“We look forward to the opportunity to be heard by the Appellate Division justices as New York continues to protect consumers and ratepayers from paying too much for their electric and gas service,” PSC spokesman James Denn responded in a statement.
On June 30, Supreme Court Justice Henry Zwack ruled that the PSC has “the very broadest of powers” to regulate ESCOs and utility rates, especially when seeking to prevent the overcharging of low-income customers, dismissing a case filed against the commission by NEMA and three ESCOs, as well as a similar suit by the Retail Energy Supply Association. (See Court Backs NYPSC on Regulating Retail Sales.)
The PSC on Aug. 2 had rebuffed a trade group seeking to head off upcoming evidentiary hearings related to the commission’s ongoing investigation of ESCOs. (See NYPSC Pushes Ahead with ESCO Investigation.)
CARMEL, Ind. — Market participants remain skeptical of a MISO plan to integrate external resource zones into its annual capacity auction, employing single clearing prices for each balancing authority, even as the RTO is introducing changes and speaking one-on-one with stakeholders about the proposal.
| MISO
MISO Executive Director of Strategy Shawn McFarlane has initiated about “20-odd” conversations with stakeholders to explain the proposal and hear suggestions after last month’s stakeholder motion to delay its implementation. Market participants instead favor a more immediate capacity transfer rights proposal that would give equal treatment to long-term supply arrangements involving both external and internal planning resources. MISO is under no obligation to honor the July motion. (See MISO Members: Court Rebuff May Reduce External Zone Chances.)
“Our reaction was, ‘Let’s go have some conversations with people one-on-one,’” McFarlane said during an Aug. 9 Resource Adequacy Subcommittee meeting. “We probably understand some concerns that we didn’t understand before.”
The RTO plans to make final modifications at the Sept. 13 RASC meeting and continue stakeholder outreach, he said.
“The bottom line is we’re still not where we’d like to be in terms of stakeholder alignment,” he added.
MISO has changed its original proposal in an attempt to address some stakeholder questions, including about how it will treat border external resources and how excess auction revenues will be doled out to external resources with historical capacity arrangements.
The proposal now says that an external resource bordering the RTO that qualifies in more than one local resource zone must designate its zone two years in advance of a capacity auction and keep that designation and its associated pricing for two years.
“That’s not something we expect to see a lot of. MISO doesn’t have a lot of border resources,” said Laura Rauch, MISO manager of resource adequacy coordination.
For external resource zones that connect to more than one MISO local resource zone and require a blended price, shift factors will be calculated annually and posted in the second quarter ahead of next year’s auction, Rauch said.
MISO is also proposing to scrap a pecking-order approach to distributing excess auction proceeds to historical capacity arrangements to cover generation-to-load price separation. Under the plan, agreements initiated before the impending creation of external resource zones and resources impacted by zonal boundary changes will be just as eligible for credits as older, grandfathered contracts made before the start of the MISO capacity market.
Indianapolis Power and Light’s Ted Leffler asked if essentially all external resources are eligible to receive historical supply arrangement credits as a refund for price separation, what was the point of external pricing at all?
MISO will distribute revenues only to “long-term and consistently used” agreements, Rauch answered. The goal of external zone pricing will be the same as the Planning Resource Auction overall: to minimize total system costs, she said.
Last month, stakeholders warned MISO officials that if there isn’t consensus on the proposal, a recent appellate court ruling banning FERC’s suggested changes on PJM’s 2013 minimum offer price rule could adversely impact the commission’s ability to approve the changes.
FERC staff on Wednesday accepted MISO’s pro forma pseudo-tie agreement with a warning that a full-strength commission could in the future reject the proposal.
MISO’s accepted filing fleshed out details in response to multiple questions posed by FERC staff in May regarding the original proposed agreement.
Still, FERC staff said the updated agreement could still be found to be discriminatory by the commission and is subject to refunds (ER17-1061). (See FERC Seeks More Details on MISO Pseudo-Tie Proposal.) The pro forma became retroactively effective March 15.
In answer to FERC staff’s question about the extent of MISO’s coordination with PJM in developing the agreement, the RTO said the two RTOs engaged in ongoing discussions through MISO’s Pseudo-Tie Issues Task Team “over several months in 2016 and restarted again in first quarter of 2017.”
“These discussions are continuing today,” the RTO noted.
MISO also cited the RTOs’ recent, twin filings to alter their joint operating agreement to better manage pseudo-tied resources. (See “MISO and PJM File JOA Pseudo-Tie Rules,” MISO Reliability Subcommittee Briefs: Aug. 3, 2017.)
The RTO also defended its stance on excluding PJM as a signatory on the pro forma, contending that the agreement should be strictly between MISO and the market participant.
“While the agreement is between the market participant and MISO, the relevant RTOs will coordinate to ensure that the pseudo-tie is implemented safely and reliably and in a manner consistent with applicable regulatory requirements,” the RTO said.
MISO’s filing clarified that it will pull the plug on a pseudo-tie upon termination of an agreement or a lapse in firm transmission service without identical service replacement. The RTO also vowed that it worked with PJM to arrive at a practice of terminating new and existing pseudo-ties when a market-to-market flowgate is not within a 2% generator-to-load distribution factor within either MISO or a neighboring market. The RTO said it would revisit that value with PJM as needed.
Additionally, MISO told FERC that it does not intend to retain operational responsibility of a pseudo-tied resource, saying that the attaining balancing authority is responsible for the dispatch and operational control.
The mandatory agreement requires pseudo-tie owners to provide congestion, settlement, deployment and load data to MISO and maintain firm transmission service from the source to the sink for the life of the pseudo-tie. It also makes pseudo-ties subject to the approval of transmission providers and stipulates that pseudo-tie owners must register as the RTO’s market participants and provide six months’ notice to terminate the agreement.
MISO also retains “final authority to establish and enforce protocols” for any pseudo-ties and “make all final determinations whether to implement or terminate” them, according to the agreement. Additionally, the RTO can suspend the pseudo-tie if it determines that a pseudo-tie owner has failed to provide necessary data.
FERC staff’s measured approval of the pro forma comes after MISO asked FERC to convene a pseudo-tie technical conference to clear up several lingering issues industry-wide. (See MISO Asks FERC for Pseudo-Tie Technical Conference.)
ISO-NE on Tuesday advanced the idea of excluding competitive new resources from functioning as demand in a proposed “substitution” capacity auction, which is designed to enable generators with retirement bids that cleared in a primary Forward Capacity Auction to transfer their obligations to subsidized resources that did not clear because of the must-offer price rule.
The grid operator proposed the exclusion to help keep Forward Capacity Market prices competitive and maintain its “cash for clunkers” framework for retiring aging fossil fuel generators.
Real-Time Marginal Units by Fuel Type | ISO-NE
ISO-NE economist Christopher Geissler presented the RTO’s conceptual approach to Competitive Auctions with Sponsored Policy Resources (CASPR) to the New England Power Pool Markets Committee, which met Aug. 8-10 at Cape Neddick, Maine.
CASPR is designed to accommodate the entry of “sponsored” resources — such as resources mandated by a renewable portfolio standard or other state policy — into the FCM over time, while maintaining competitively based capacity prices for other resources. The RTO’s latest proposal comes in response to stakeholders concerned that sponsored policy resources could unfairly reduce primary FCA prices and crowd out competitive generation. (See Public Power Skeptical of ISO-NE Two-Tier Capacity Auction.)
Share of Native Electricity Generation by Fuel Type | ISO-NE
Part of the grid operator’s Integrating Markets and Public Policy (IMAPP) initiative, the latest proposal is intended to head off stakeholder concerns about competitive resources “walking down the demand curve” of the FCA by ensuring that the substitution auction coordinates entry of sponsored resources and exit of older generators.
To limit the potential ability of public entities to reduce consumer costs by sponsoring lower-cost (e.g., combined cycle/combustion turbine) resources, stakeholders had suggested imposing additional restrictions on the types of capacity eligible to participate as supply or requiring additional documentation to show that the resource was being built to meet a public policy need.
ISO-NE said it does not plan to propose rules that would require the RTO to evaluate whether a sponsored resource meets public policy needs. The grid operator said its two-tier auction proposal “incents the continued participation of competitive new resources in the FCM, when market conditions allow.”
IMM: Spring 2017 Energy Costs up on Gas Prices
Higher natural gas prices drove ISO-NE wholesale market costs up 26% this spring compared with a year earlier, to $1.3 billion.
Wholesale Market Costs and Average Natural Gas Prices by Season ($ billions and $/MMBtu) | ISO-NE
ISO-NE Director of Market Monitoring and Compliance Robert Laurita presented the Internal Market Monitor’s Spring 2017 Quarterly Markets Report, attributing most of the gas price increase to March, when gas prices jumped 127% from the same month in 2016 because of significantly colder temperatures.
Gas prices averaged $3.59/MMBtu, up 54% compared with spring 2016, which saw unusually low prices because of increased production, above-average storage and low heating demand during the winter. Spring 2017 gas prices were 18% below 2015 levels.
Hourly electricity demand averaged 12,853 MW, comparable to last spring because of similar weather conditions, the report said. March was unseasonably cold, while April and May saw slight reductions in load compared to the same months in the previous year.
Day-ahead and real-time energy market prices at the New England Hub averaged $30.78/MWh and $31.92/MWh, respectively, up 32% and 44% from last spring. Energy prices continued to closely track underlying natural gas prices. The positive deviation in real-time prices for the period was driven by several days with high loads and unit outages during early April, as well as two days in mid-May when high temperatures resulted in higher loads than forecasted. In addition, several units experienced forced outages.
Northern Discounts
Energy prices among the load zones deviated only in Maine, New Hampshire and Vermont, which had lower average prices than the hub. These discounts were the largest — in both dollar and percentage terms — over the two-and-a-half-year period assessed by the Market Monitor. Discounts from the hub ranged from 6% in Vermont to 16% in Maine.
The report attributed the differentials to the prevalence of renewable generators in those export-constrained areas, as well as “various planned and unplanned line reductions or outages during the period that further reduced the transmission capability available to export power to the rest of the system.” The discounts were “less pronounced” in the day-ahead market.
Real-time reserve payments for the season totaled $8.9 million, well more than last spring’s total of $700,000 and 33% above the 2015 total of $6.7 million. This spring’s payments primarily accrued over May 18-19, which accounted for 54% ($4.8 million) of the credits. Those two days saw the grid operator frequently redispatch generation to maintain reserves. Deficiencies several times triggered the reserve constraint penalty factors for 10-minute spinning reserves and 30-minute operating reserves.
FCA Payments Stable
Spring 2017 coincided with the last three months of the commitment period associated with FCA 7, in which the NEMA-Boston zone cleared at $15/kW-month for new resources and $6.66/kW-month for existing resources, while Rest-of-Pool cleared at the floor price of $3.15/kW-month. Capacity payments for the season totaled $287 million and were within 1% of spring 2016 payments. Peak energy rent adjustments remained relatively high at $26 million because of the high real-time energy prices occurring in August 2016.
ISO-NE in April held the forward reserve auction for the summer 2017 delivery period, which saw supply offers exceed the requirements for both the 30-minute operating reserve and 10-minute non-spinning reserve, with no pivotal suppliers. The clearing prices for offline 30- and 10-minute reserves for the control area were $1,000/MW-month and $2,000/MW-month, respectively. Summer 2016 10- and 30-minute reserves cleared at $2,000/MW-month and $2,498/MW-month, respectively. Of the three local reserve zones, only NEMA/Boston had a different price than the control area. Because of inadequate supply (meaning all suppliers were pivotal suppliers), the 30-minute reserve price for NEMA/Boston was set to the auction’s offer price cap of $9,000/MW-month, the same outcome as the summer 2016 auction.
FERC staff have accepted CAISO’s implementation agreement for Canadian energy marketer Powerex to join the Western Energy Imbalance Market (EIM) but cautioned that the arrangement could be subject to further scrutiny once the commission meets after restoring its quorum.
“Preliminary analysis indicates that CAISO’s proposed implementation agreement has not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” FERC staff said in its delegated order (ER17-1796).
The order’s language suggests that the commission could compel the ISO to address certain EIM stakeholder concerns about the agreement. FERC’s quorum was restored Thursday with the swearing in of former Pennsylvania Public Utility Commissioner Robert Powelson, joining former Senate Republican aide Neil Chatterjee, whom President Trump named acting chairman. (See Chatterjee Named Acting FERC Chair as Quorum is Restored.)
Powerex, which markets hydroelectric generation from parent BC Hydro, finalized the agreement with CAISO in May after announcing its intention to join the West’s only real-time energy market. (See Powerex Slated to Become First Non-US EIM Member.) The company’s membership would provide the EIM increased access to about 17,000 MW of generating capacity, about 12,000 MW of which is hydro. Powerex currently markets power across the U.S. and as far south as Mexico.
Powerex markets BC Hydro output from assets such as the Mica Dam on the Columbia River
In filings with the commission, some commenters raised concerns about “the principles set forth to guide the negotiation and implementation of additional agreements necessary for Powerex’s EIM participation,” as well as potential changes to the EIM framework that would be required to integrate the company into the market, FERC said.
CAISO said that the specifics of Powerex’s participation in the EIM will be detailed in separate filing to FERC before the company is integrated. The ISO has told FERC that concerns about the way Powerex is integrated are beyond the scope of the proceeding and can be addressed in future filings.
The footprint of CAISO’s Western Energy Imbalance Market is growing rapidly | CAISO
“The implementation agreement does not establish binding terms for Powerex’s participation in the EIM but merely commits the CAISO and Powerex to work in good faith to reach agreement on an acceptable framework,” CAISO said in a July 14 answer to filed comments. As a Canadian entity, Powerex has unique legal and regulatory circumstances, but that does not mean that it will be subject to a different set of rules than other EIM participants, CAISO said.
EIM participants Pacific Gas and Electric and Southern California Edison did not oppose the Powerex integration and did not ask for it to be modified.
Market participants are concerned, however, about a provision in the agreement that allow it to be modified to include additional parties, which they say is unique to the Powerex integration. CAISO would be required to make additional filings to explain why the agreement should be modified to allow additional parties, which the grid operator said is not currently being contemplated.
In a joint filing with FERC, EIM participants — including PacifiCorp, Idaho Power, Portland General Electric, Puget Sound Energy and NV Energy — said that Powerex’s entry is a new model because it is a merchant market participant that is not located within or pseudo-tied with any EIM participant. They were concerned about provisions in the agreement that enable Powerex to enter into non-EIM transactions after submitting its base schedules to the market.
EIM entities that enter into transactions after the submission of base schedules can be subject to energy imbalance charges. The companies said CAISO should explain whether Powerex will be subject to the same bidding deadlines and charges, “or will be the only merchant participant permitted to enter modifications to base schedules as if it were an EIM entity.” They said they “look forward to the development of subsequent agreements with Powerex and BC Hydro that demonstrate uniform (not just compatible) market rules are applied to all market participants.”
The implementation agreement becomes effective Aug. 15, with Powerex slated to join the EIM in April 2018.
RENSSELAER, N.Y. — NYISO’s Business Issues Committee on Wednesday approved steps intended to improve the efficiency of the interconnection queue process while maintaining needed reliability evaluations. The committee voted to recommend that the Management Committee approve the changes at its next meeting on Aug. 30. NYISO foresees filing associated Tariff changes with FERC in late September following Board of Directors approval next month.
Thinh Nguyen, NYISO interconnection projects manager, led an Aug. 9 presentation detailing changes to increase administrative efficiency and speed up the interconnection study process. Those changes should allow developers to move through the queue more quickly, particularly the Class Year Study phase, which evaluates the cumulative impact of a group of projects that have reached similar milestones. New rules that bifurcate the class year to allow some projects to advance have the potential to shave nine months off the phase.
| NYISO
The proposed changes clarify and update existing practices and procedures, except for the transmission interconnection procedures, which have already been filed with FERC and are still pending acceptance.
NYISO proposed effective dates and transitional rules that would allow projects currently in the interconnection process to benefit from the proposed changes. Proposals requiring Tariff revisions will become effective the date of the FERC order accepting the revisions, unless otherwise specified.
Market mitigation analyst Lorenzo Seirup assisted with the presentation, as did Market Manager Gregory R. Williams and Zachary T. Smith, installed capacity (ICAP) market operations supervisor.
ICAP Manual Changes for Demand Curve Reset Updates
The BIC approved ICAP manual revisions needed to reflect the process changes stemming from the ISO’s demand curve reset.
Smith presented the proposed revisions, which reflect Tariff changes that lengthen the period between demand curve resets and implement an annual update process.
The initial updates to the manual include quadrennial reviews of both the demand curve adjustment process and the annual update process. NYISO also removed language that merely repeated what is stated in the Tariff.
Changes also indicate that the results of each annual update will be posted on or before Nov. 30 of the year prior to the start of the capability year for which updated ICAP demand curves will apply. Based on a stakeholder comment at the July 27 ICAP Working Group meeting, language was added stating that NYISO will present the results to stakeholders.
NYISO Prepares DER Pilot Program Framework
The BIC also heard about NYISO’s pilot program to test the ability of the Bulk Electric System to adapt to distributed energy resources. The two-year pilot is slated to begin in April 2018.
NYISO Market Design Specialist Brian Yung presented a DER Pilot Program framework, which aims to assess the capability of DER to provide benefits to the wholesale market, develop performance measurement standards and establish and evaluate coordination between the ISO and DER aggregators.
| NYISO
The ISO’s DER Roadmap outlines its plans for integrating DER into its ancillary services, capacity and energy markets over the next five years and also pledges the grid operator to establish pilot programs. (See NY DER Question: Deployment or Markets First?)
The framework sets a statewide enrollment limit of 50 MW at any one time, with a maximum of 10 MW in enrolled capability serving a single transmission node. The limits are intended to minimize market and operational impacts at the node. NYISO also proposes a maximum of five individual pilot projects at any one time but will consider adjusting this limit based on staffing requirements and other factors.
The program limits individual pilot projects to a minimum of 100 kW of aggregated capability for energy and reserves, 200 kW for regulation service and a maximum of 10 MW of aggregated capability — and sets a 12-month cap on project duration. NYISO can either extend or stop an individual project to meet program objectives.
Resources participating in the wholesale markets — except for demand-side resources — will not be eligible to participate in the pilot program. NYISO will review wholesale market demand-side resource participation on a case-by-case basis to ensure the resource can meet its existing wholesale market obligations while participating in the pilot.
The ISO will select proposed pilots based on how well they can demonstrate energy and/or ancillary services, blend of resource types, technology maturity, DER and aggregation deployment experience, and testing availability. Preference will be given to proposals that can meet the desired six-second telemetry scan rate. The program will focus on testing the technical capabilities of aggregations rather than price signaling, NYISO said.
One market participant recommended that the grid operator work with the New York State Energy Research and Development Authority to market the program. Others said that a highly public rollout would improve the success of the program, and that the ISO should make clear whether the program includes aggregated storage.
SACRAMENTO, Calif. — While CAISO has in recent years made strides in incorporating demand response into its wholesale market, it was forced to recalculate its 2016 DR settlements because of missing performance data, the grid operator said Tuesday.
ISO representatives, DR companies, utilities and others industry participants met with state regulators to discuss the challenges associated with implementing more DR into grid operations and markets.
CAISO Infrastructure and Regulatory Policy Manager Jill Powers said the grid operator last year altered its market models to make DR registration and ISO modeling more efficient. But problems within the legacy DR system resulted in settlements that relied on incomplete and missing performance data.
The ISO reprocessed all 2016 DR performance data, which will be reflected on the next settlement recalculation statements for DR providers. Full resettlement is due to be completed by October. The ISO next year will replace its legacy DR process with “more robust systems,” she said.
“We have taken corrective actions for all the dates identified,” Powers said.
CAISO in 2015 implemented a program that allowed emergency-triggered DR to offer spinning reserve services into the ISO market. San Diego Gas & Electric began providing non-spin and spinning reserve market services through the program that same year.
The grid operator is currently managing a number of initiatives regarding integration of DR and distributed energy resources. The ISO’s Board of Governors last month approved a package of market rules that included new baselines to better reflect the performance of various types of DR. (See CAISO Flex Capacity Effort Targets Increased Variability.)
CAISO’s 2016 enhancements significantly reduced processing timelines and management of new DR resources. They also implemented new sub-load aggregation point boundaries and relaxed telemetry requirements, which lengthened the scan rate when providing telemetry to help lower costs for DR.
An uncertain market structure and frequent rule changes are inhibiting expansion of DR, as well as increasing complexity of integration, EnerNOC Director of Regulatory Affairs Mona Tierney-Lloyd said. There are inconsistencies between CAISO rules and Public Utilities Commission rules and frequent changes in program requirements, she said. EnerNOC supplies DR services around the world.
California Energy Commission Chair Robert Weisenmiller said that integrating DR is “a very challenging area.”
“We are moving to a system that is going to be highly decentralized, and we are going to need visibility and automation to manage it,” he said.
On Wednesday, the commission adopted new guidelines for ensuring that publicly owned utility resource plans comply with requirements from SB 350, the 2015 law that included new greenhouse gas emission reductions and increased renewables procurement for utilities.
