FERC has approved a settlement between PJM, Exelon and the Illinois Commerce Commission over abandonment costs for the canceled Mid-Atlantic Power Pathway (MAPP) transmission project.
Under the uncontested settlement accepted by FERC on Thursday, Exelon subsidiary Baltimore Gas and Electric’s pricing zone will bear more costs of the project while the Commonwealth Edison zone’s responsibility will not exceed $75,000 — less than half of the costs it was originally assigned. FERC said PJM must disburse refunds if the ComEd zone has already paid more than $75,000 (ER17-1016-001).
| Pepco Holdings Inc.
Proposed more than a decade ago, the $1.05 billion, 500-kV MAPP project would have extended about 230 miles from northeastern Virginia through southern Maryland and Delaware, crossing beneath the Chesapeake Bay and Choptank River to southwestern New Jersey.
In 2009, PJM assigned BGE two baseline upgrades for the project, but the RTO’s Board of Managers canceled the project in 2012, saying it was no longer needed to maintain reliability. The line was originally included in PJM’s 2007 Regional Transmission Expansion Plan.
Early last year, PJM submitted Tariff revisions on BGE’s behalf so the utility could recover about $1.2 million in abandoned plant costs.
The ICC protested, arguing that ComEd should not have to bear the costs of a canceled line that never stood to benefit its Midwestern territory. ComEd’s zone stood to incur 13.43% of the cost of BGE’s upgrades under PJM’s postage stamp cost allocation methodology.
“Given that MAPP is a canceled project, the ComEd zone does not derive any benefits from the MAPP project. … The load in the ComEd zone did not contribute to the reliability factors that caused PJM to add the MAPP project to the RTEP in the first place. The beneficiaries and cost causers of the MAPP project are located on the East Coast and that is where the commission should allocate the costs,” the ICC wrote.
The ICC also pointed to rulings by the 7th U.S. Circuit Court of Appeals, which twice remanded FERC’s approval of PJM’s regionwide postage stamp cost allocation for new 500-kV+ transmission projects (See Despite Lengthy Negotiations, PJM Cost Allocation Settlement Still Finds Detractors.) The 7th Circuit said that PJM’s high-voltage lines are “all located in PJM’s eastern region, primarily benefit that region and should not be allowed to shift a grossly disproportionate share of their costs to western utilities on which the eastern projects will confer only future, speculative and limited benefits.”
FERC on Tuesday approved MISO’s proposed cost recovery schedules for its new category of smaller interregional transmission projects with PJM. The commission did not order any changes (ER18-867).
The commission said the tariff schedules for MISO and its transmission owners for recovery of costs on targeted market efficiency projects (TMEPs) is effective April 18.
FERC said the schedules “help to ensure that the transmission owners that construct TMEPs, whether located in MISO or PJM, will have the opportunity to recover the costs of doing so.”
The approved schedules assign MISO’s share of the project costs to all transmission pricing zones that receive a congestion contribution benefit from the project of at least $5,000 or 1% of the total share per zone. Any zones that don’t meet the $5,000/1% threshold would have their costs reallocated to the remaining zones that do. FERC approved MISO’s TMEP cost allocation methodology in October.
TMEPs are small interregional transmission projects meant to address historical congestion along MISO and PJM’s seams.
The RTOs’ boards approved the first TMEP portfolio last year, consisting of five congestion-relieving upgrades in Illinois, Indiana, Michigan and Ohio. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined. On average, the projects’ costs will be allocated 69% to PJM and 31% to MISO based on projected benefits, which are expected to reach $100 million.
Regulators from MISO South challenged the recovery schedules, as they similarly challenged MISO’s regional cost allocation plan. The Arkansas, Louisiana, Mississippi and Texas public service commissions, and the New Orleans City Council, asked FERC to require MISO clarify that the TMEP schedules do not apply to South. They also wanted a commitment that MISO will create a new TMEP cost allocation methodology before the December expiration of the five-year transition period that limits cost-sharing in South.
FERC said the regulators’ requests were beyond the scope of the proceeding. The commission said last month in a separate docket that MISO has already committed to filing a new regional cost-sharing method for its share of TMEP costs after the transition period. (See Rehearing Denied on MISO South Cost Allocation.)
The Mississippi PSC had also argued for a four-year limit on TMEP cost recovery; FERC declined to order such a provision.
New TMEPs in 2019?
At an April 18 MISO Planning Advisory Committee meeting, Eric Thoms, manager of interregional planning and coordination, said MISO and PJM are evaluating the need for a new TMEP study this year.
Thoms said that MISO is leaning in favor of a study, as the RTOs have experienced about $500 million in congestion payments on more than 200 market-to-market flowgates from 2016 to 2017.
“All indications are at this point that it would be prudent to proceed with a TMEP study this year,” Thoms said.
By May, the RTOs will also make an announcement on whether they will begin a traditional two-year coordinated system plan study to identify more expensive seams projects. The RTOs have yet to approve a major seams transmission project under their interregional market efficiency project category.
MISO on Wednesday challenged a 2017 NERC assessment that found two areas in the RTO would “experience transmission challenges during an extreme event” involving a disruption of natural gas delivery.
Late last year, NERC released the results of an assessment that studied 24 “geographic clusters” that contain more than 2,000 MW of gas-fired generation and said 18 of them “demonstrated the need for additional follow-up and analysis, based on power flow and stability issues” of the “extreme cases” it ran. (See NERC: Natural Gas Dependence Alters Reliability Planning.)
| NERC
“Most of the risks were on the East Coast or in the Southwest, but there were two in MISO,” Senior Policy Studies Engineer Jordan Bakke said, referring to an area on the Missouri-Illinois border and the Amite South load pocket in southeast Louisiana.
MISO told the April 18 Planning Advisory Committee meeting that those two areas have access to alternative fuel sources and are not at risk of N-1 contingencies.
“We think the method employed in this study was not the most optimal. … These risks that were found are not necessarily reasonable in MISO,” Bakke said. “MISO has assessed the two regions and found that they were not single-source … issues, and do not account for a generator’s ability to procure fuel from an alternate pipeline connection.”
Bakke said MISO, which has discussed the study results with NERC, will proceed with its own usual natural gas analyses, though it plans to add a feature to verify that dual-fuel units can access their second source of fuel. By November, MISO also plans to release results of an in-progress study on the impact that large gas pipeline contingencies may have on its system. (See “Sign-of-the-Times Studies,” MISO in 2018: Storage, Software, Settlements and Studies.)
MISO said it has been studying natural gas disruptions as part of its reliability planning since 2015 and currently uses 31 gas contingencies to evaluate “transmission needs and system risk.” MISO has repeatedly reported that only one planning scenario — the long-term loss of the largest natural gas pipeline for the entire summer peak season —would “slightly” elevate a regional loss-of-load risk.
Minnesota Public Utilities Commissioner Matt Schuerger asked if NERC’s assessment or MISO analyses had any merit when considering the natural gas generation outages during the extreme cold that hit the RTO in January. MISO staff said virtually all the gas generation outages involved generators with interruptible transportation, and little of the generation experiencing outages had back-up fuel plans.
NYISO on Monday presented two options for pricing carbon emissions in the ISO’s wholesale market, saying the approach the ISO favors would not require changes to its commitment/dispatch software or the frequency of settlements.
“The cost of carbon will be known ahead of time, will be known to market participants,” said ISO staffer Nathaniel Gilbraith, who delivered the report to the Integrating Public Policy Task Force (IPPTF), which is jointly run by NYISO and the state’s Department of Public Service. The April 16 discussion was part of issue “Track 2” in the group’s five-track effort to price carbon emissions.
The ISO’s preferred approach would have suppliers embed the carbon charges into their all-in day-ahead and real-time energy offers, as they currently do with emissions costs under the Regional Greenhouse Gas Initiative.
Under the second approach, suppliers would submit emissions information for each segment of energy offers (start-up, no-load and incremental energy in dollars per megawatt-hour) with the ISO incorporating the information to calculate a carbon shadow price. It would require software changes. [Editor’s Note: An earlier version of this article incorrectly stated that neither approach would require software changes.]
Under both options, the ISO would dispatch units as it currently does to minimize production costs subject to system constraints. In either case, carbon charges might also need to be trued up, Gilbraith said.
The carbon price for generators subject to RGGI would be the social cost of carbon determined by the New York Public Service Commission minus the RGGI price. Generators not subject to RGGI, such as fossil fuel plants of less than 25 MW, would pay the full social cost.
The ISO could estimate emissions for the generators but would prefer to let suppliers self-report, said IPPTF co-chair Nicole Bouchez, NYISO principal economist. “We thought it made sense to have the companies who have the best information about their plants to do all that math instead of the ISO having to do, by necessity, approximations of it,” she said.
Another complexity is that emissions vary based on a plant’s heat rate, fuel type and where in the output range they are, she said.
“In order to really know the carbon output, you need to know the exact heat rate as well as the fuel that’s being used at that moment and what the carbon content of the fuel is,” Bouchez said. “Then there’s the question of start-up and no-load carbon emissions as well.”
Bouchez walked stakeholders through the ISO’s current bid and settlement process and how it might change under a carbon pricing regime.
Besides the current day-ahead and real-time market settlements, ““the carbon charge would introduce an additional generator settlement line item, which is based on the actual emissions that day times the applicable price in dollars per ton,” Bouchez said. “[This] gives the dollar carbon charges that would be charged to that generator, and that is based on the actual physical output of the plant.”
Loads would continue to pay the applicable locational-based marginal price (LBMP) for energy withdrawals. The process would also create a carbon charge “residual,” a dollar amount to be paid to load-serving entities to minimize the increase in retail electricity prices. The allocation of residuals will be discussed at a future task force meeting.
Price Transparency
Couch White attorney Michael Mager, who represents a coalition of large industrial, commercial and institutional energy customers known as “Multiple Intervenors,” asked what would be included in the market price. “Would the final market price be the LBMP plus carbon adder, minus the amount that’s passed back to load-serving entities? What would be transparent and public for every hour?”
Because many end-use customers have supplier contracts based on the market prices, “I think the customers are going to want to know that any money that’s passed back to LSEs at the wholesale level actually gets passed back to the consumers at the retail level, so I think they’re going to need transparency in terms of that price as well,” Mager said.
“The LBMP is still going to exist as the primary cost of a unit of energy,” Gilbraith said. “Similar to today, there are other associated charges, uplift or whatnot, that are allocated to loads. The joint staff team will be working through in June a proposal on how to allocate the carbon residuals back, and that’s a great issue to bring up in that venue, what data and what is made public through that process and at what level of granularity.”
Real-time Emissions
“These calculations are going to be done separately for day-ahead and real-time, and so all of this charging and reconciliation would be done separately for each market. Is that accurate?” asked Howard Fromer, director of market policy for PSEG Power New York.
| NYISO
“Day-ahead and real-time LMBPs will continue to exist as they do today, and so they will be developed based on day-ahead and real-time offers,” Gilbraith responded. “However, energy is only physically produced pursuant to a real-time schedule, so the only way a bill [for the carbon charge] will occur is … based upon a real-time schedule. … It’s based on actual, physical electricity production and the emissions associated with that production.”
The task force next meets on April 23 at NYISO headquarters.
FERC on Thursday approved rules to prevent malware from infecting “low impact” computer systems through transient electronic devices such as laptops and thumb drives (RM17-11, Order 843).
The order approves a requirement outlined in the commission’s October Notice of Proposed Rulemaking directing NERC to modify reliability standard CIP-003-7 to mitigate the risk of malicious code that could result from third-party devices that frequently connect to and disconnect from low-impact systems. (See FERC Seeks Cyber Controls on Portable Devices; Sets GMD Plans.)
The commission reiterated the concerns it raised in the NOPR that the NERC standard “lacks a clear requirement to mitigate the risk of malicious code” that could result from third-party transient devices. “Accordingly, we direct NERC to develop a modification to the reliability standard to provide the needed clarity. Such modification will better ensure that registered entities clearly understand their mitigation obligations and, thus, improve individual entity mitigation plans,” the commission said.
However, the commission declined to adopt a proposal requiring NERC to “provide clear, objective criteria for electronic access controls” for low-impact systems. NERC tiers its cybersecurity requirements based on classifications of high-, medium- and low-impact Bulk Electric System (BES) cyber systems.
The commission said comments from NERC and others convinced it that the reliability standard already “provides a clear security objective that establishes compliance expectations.”
Instead, FERC ordered NERC to conduct a study within 18 months to assess the implementation of the standard to determine whether the electronic access controls adopted by responsible entities “provide adequate security.” The study was proposed in a joint filing by the American Public Power Association, Edison Electric Institute and National Rural Electric Cooperative Association, identified in the order as “trade associations.”
Reversal
NERC said that the standard requires responsible entities to “document the necessity of its inbound and outbound electronic access permissions and provide justification of the need for such access.”
The trade associations, Electric Consumers Resource Council (ELCON) and Transmission Access Policy Study Group said the proposal would be burdensome and ineffective. While it “appreciates the value establishing more tangible criteria for adequate low-impact BES cyber system controls … the additional requirements that the commission proposes would do nothing to harden a low-impact facility against the rapid evolution in cyber warfare,” ELCON said.
The trade associations urged a risk-based approach to allow responsible entities to focus their resources on assets that have a higher impact on reliability.
“Given NERC’s statements, we believe that there will be adequate measures to assess compliance with reliability standard CIP-003-7,” FERC concluded. “We expect responsible entities to be able to provide a technically sound explanation as to how their electronic access controls meet the security objective.”
Mitigation of Malicious Code
The trade associations and ELCON also opposed the NOPR’s proposal to require responsible entities to prevent malicious code from entering their systems via transient electronic devices used by contractors and other third parties. The trade groups said risk mitigation is implicitly required under Section 5 of the standard.
But FERC said the standard doesn’t go far enough. “While commenters agree that, at least implicitly, the mitigation of malicious code is an obligation, the lack of a clear requirement could lead to confusion in both the development of a compliance plan and in the implementation of a compliance plan,” the commission said. “In addition, although NERC contends that the proposed directive may not be necessary, NERC agrees that modifying reliability standard CIP-003-7 to address the mitigation of malicious code explicitly could clarify compliance obligations.”
FERC said the new standard also will improve reliability by requiring responsible entities to have a policy for declaring and responding to “exceptional circumstances” — defined by NERC as a natural disaster, civil unrest or a situation that threatens to impact BES reliability or presents a risk of injury or death.
WASHINGTON — Congress will be watching FERC’s review of its policy on licensing natural gas pipelines very closely if the commission’s appearance before the House Energy Subcommittee on Tuesday is any indication.
Any changes FERC makes are unlikely to please all members, however.
At a hearing attended by all five FERC commissioners, both Republican and Democratic representatives complained that the commission has been too willing to approve pipeline projects and insensitive to landowners in their paths. Others, however, said the commission must speed up its approval process.
Energy and Commerce Committee Chairman Greg Walden (R-Ore.) said he hopes the commission’s review of its 1999 policy statement on certifying new interstate pipelines, announced in December, will “result in more efficient and timely decisions.” (See FERC to Review Gas Pipeline Approval Process.) FERC Chairman Kevin McIntyre said the commission will outline its plans for the review at Thursday’s open meeting (PL18-1).
Walden cited reports that New England relied on two LNG shipments from Russia to get through the winter, fuming: “While cross-border trade with our neighbors in Canada and Mexico may be a win-win, we should never have to be reliant on the Russians for imports again.”
Speaking next, Rep. Frank Pallone (D-N.J.), the committee’s ranking member, said that he is concerned that ratepayers will be billed for unneeded projects and that landowners have no way to fight them. He called on the commission to conduct regional reviews of pipeline needs rather than evaluating each project individually.
Rep. Leonard Lance (R-N.J.), who is not a member of the subcommittee, attended the hearing nonetheless to tell the commission of his complaints over its approval in January of the PennEast pipeline project in Pennsylvania and New Jersey. The New Jersey attorney general went to court last month to prevent the project developer from condemning more than 20 properties acquired under open-space and farmland preservation programs.
Lance also questioned whether FERC was conducting “robust economic analysis” in using contracts with pipeline affiliates as evidence of a project’s need.
“It’s my considered judgment that this [project] is not in the best interests of the United States and certainly not in the best interests of New Jersey,” Lance said.
Rep. Morgan Griffith (R-Va.) said “the frustration level in Virginia is so high” over FERC’s pipeline reviews that he has teamed up with Democratic Sen. Tim Kaine (D-Va.) on legislation he said would increase the transparency of FERC’s licensing process (H.R. 2893, S. 1314). “Tim Kaine and I don’t generally agree,” he noted.
Griffith complained that surveyors for a pipeline appeared unannounced in his district recently and said the commission had rejected his request for additional public hearings to make travel to the sessions less burdensome for his constituents. He suggested putting two or more pipelines into the same corridor to minimize impacts on landowners. “FERC can do a better job,” he said.
LNG Exports
Rep. Pete Olson (R-Texas) said some Gulf Coast LNG projects have fallen behind schedule because of delays in receiving FERC approvals. “I’ve heard rumors that FERC has only six to eight employees [responsible] for approving these … permits. I’ve heard you actually approached the [Department of Energy] for new [employees] to help out with the backlog of approving LNG permits,” he said. “Is that true?”
McIntyre did not answer the LNG staffing question but acknowledged the commission is planning to add staff to the Office of Energy Projects to process LNG and pipeline applications.
“It’s consuming an enormous amount of attention and manpower within the agency,” he said. “If there’s any suggestion that we are somehow not giving it our full effort right now, I can assure you that is not the case at all.”
The pipeline review was just one of the issues the committee addressed during the three-hour hearing, which Walden said was the first with the full commission since 2015. Also discussed were the commission’s grid resilience inquiry, the financial struggles of coal and nuclear generation, the Public Utility Regulatory Policies Act, cybersecurity, and last week’s technical conference on distributed energy resources. (See related story, Ready to Act on DERs, FERC Tells Congress.)
The closure of four nuclear plants in Pennsylvania and Ohio would result in substantial increases in electricity bills and carbon dioxide emissions, among other air pollutants, while cutting jobs and economic productivity, according to a Brattle Group report released on Monday.
The report, commissioned by Nuclear Matters, a bipartisan pro-nuclear advocacy group, focuses on the Three Mile Island unit Exelon said last year it will close and the three plants FirstEnergy Solutions announced on March 28 it was closing: Davis-Besse and Perry in Ohio and Beaver Valley in Pennsylvania. (See FES Seeks Bankruptcy, DOE Emergency Order.)
The closures would trigger price increases of up to $2.43/MWh for Ohioans and $1.77/MWh for Pennsylvanians and eliminate the environmental benefit of all the zero-emissions generation installed in PJM over the past 25 years, according to the report. The four plants’ 4,745 MW generated 38.7 MWh of electricity in 2017, surpassing the 35 million MWh generated by wind, solar, and hydro resources in PJM, the report concluded. It would take 14 years for zero-emissions generation to recover to its 2017 level, Brattle said.
“This means that the retirement of these four nuclear generators would more than undo the entire emissions benefits of all renewable generation investments made to date throughout the PJM region,” the report concluded.
Matching the emissions-free output expected in PJM at the current pace would require another two years and doubling the current growth of generation from renewables to 4.8 million MWh annually. Attempting to replace the environmental benefits of the four nuclear plants with renewables could cost around $2 billion annually, based on the Energy Information Administration’s (EIA) national average renewable cost estimates and would not stop the lost capacity from the nuclear closures being replaced by fossil-fuel generation. “We estimate that about 72% of the replacement would come from gas-fired generation and 28% from coal,” the report said.
The graph shows that replacing the emissions-free generation of the four nuclear plants currently slated for closure in PJM would take 14 years. Matching the emissions-free output expected in PJM at the current trajectory would require doubling the current deployment rate of renewables and another two years. | The Brattle Group
“Following [nuclear plant] Vermont Yankee’s shuttering in New England, we saw devastating effects. The loss of tax revenues forced local officials to make major budget concessions to the detriment of their residents, including cutting their municipal budget by 20%, drastically reducing police services, and raising their property taxes by 20%,” said Judd Gregg, a Nuclear Matters Advocacy Council member and former Republican senator from New Hampshire. “In the year following the closure, carbon emissions increased by 2.5% due to nuclear energy being replaced by emission-producing sources.”
Annual CO2 emissions would increase by more than 20 million metric tons if the plants closed and could create potential social costs of more than $900 million per year. It also would increase annual emissions of air pollutants such as sulfur dioxide, nitrous oxide, and criteria particulate pollutants by tens of thousands of tons, with potential social costs of $170 million per year.
Electricity bills would increase by $400 million for Ohio residents, $285 million for Pennsylvanians, and $1.5 billion across PJM annually, according to the report, due to increased clearing prices in the capacity and energy markets. At least 3,000 jobs would be “at risk” without including indirect jobs at the plants, and the closures would eliminate tens of millions of dollars in local tax revenues.
Other Voices
David Lochbaum, a nuclear safety engineer with the Union of Concerned Scientists, questioned the study’s economic conclusions, telling the Cleveland Plain Dealer that other plant closures have not led to economic disasters. “The unemployment in the other states is not rampant, despite the permanently shut down reactors. The price of electricity in the other states is not exorbitant, despite the permanently shut down reactors,” he said.
“So, why does Nuclear Matters believe the folks in Ohio and Pennsylvania cannot figure out what folks in other states have figured out?” Lochbaum asked.
Meanwhile, the American Petroleum Institute (API) sent President Trump a letter Friday, urging him to reject FirstEnergy’s request for an emergency order to save the nuclear plants. (See Perry Hints DOE Won’t Grant FES ‘Emergency’ Request.)
“The natural gas industry and the shale revolution are poster children for letting the markets work,” API President Jack Gerard said. “The energy abundance wrought by the shale gas revolution is a prime example of competition at work.”
Gerard said government intervention would jeopardize the “economic benefits delivered to consumers” by natural gas.
[EDITOR’s NOTE: Due to an editing error, an earlier version of this article mischaracterized API position on the FirstEnergy request.]
The Artificial Island (AI) transmission project could change or become unnecessary if the two nuclear plants it’s intended to support are shuttered, but retirement threats by plant owners aren’t sufficient to revise the project, the PJM Board of Managers said last week.
The board made the acknowledgement in response to concerns highlighted by the Delaware Energy Users Group in a March 12 letter. Michael K. Messer, the group’s president, urged the board to re-evaluate and potentially cancel the project following threats by owners of the plants, Exelon and Public Service Enterprise Group (PSEG), to close them. (See Del. Group Seeks to Block Artificial Island Project.)
“I can say with a degree of certainty that the retirement of one or more plants at the Artificial Island site would impact the scope of the transmission project,” PJM CEO Andy Ott, a board member, wrote. “However, at this time, absent announced retirements of either Salem or Hope Creek, the project assumptions remain intact.”
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
Exelon and PSEG have announced that they will cancel future capital investments at the two Salem nuclear units they co-own and shut the plants down if New Jersey doesn’t provide them financial support. The state legislature on Thursday passed a bill that would provide the plants with subsidies costing ratepayers about $300 million per year. (See NJ Lawmakers Pass Nuke Subsidies, Boosted RPS.)
The AI transmission project was developed to address transmission stability problems at Salem and the neighboring Hope Creek unit in southern New Jersey and allow them to operate at full power without a book-size compilation of operating constraints. PJM’s first competitive solicitation under Order 1000, the Artificial Island project has been long mired in controversy. In June, the RTO announced several cost allocation alternatives that would shift much of the $280 million price tag from Delaware ratepayers to those in New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
Ott confirmed Messer’s concerns but said any changes to the project would be considered during the system reliability analysis if either plant submits a deactivation notice. “I agree that the analysis proposed by your letter is analysis that PJM should undertake to determine impact to reliability should a plant announce retirement and subsequently impact the Artificial Island project,” he wrote.
KANSAS CITY, Mo. — SPP’s Markets and Operations Policy Committee last week failed to endorse a revision request that would have required non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.
The Market Working Group’s (MWG) recommended revision request (RR272) will likely be appealed to the Board of Directors for its April 24 meeting.
A roll-call vote resulted in 62.3% of members favoring the measure, short of the necessary two-thirds majority. Transmission-owning members Western Farmers Electric Cooperative and Westar Energy, last in alphabetical order, cast the final two votes opposing the change to seal its fate, at least temporarily.
“I’m not saying I’m going to submit one, but I have a feeling there will be [an appeal],” said American Electric Power’s Richard Ross, who chairs the MWG.
NDVERs converting to DVERs would need to ensure they have the proper communication systems in place and the technical capabilities to reduce their output.
Ross said the Tariff change will increase market efficiency through the reduction of manual out-of-merit energy orders to mitigate constraints. The addition of dispatchable resources will only increase reliability, he said.
“Any time you’re taking actions out of market, you are creating inefficiencies,” said SPP’s David Kelley.
The Market Monitoring Unit expressed strong support for the Tariff change, saying it would help reverse the recent growth of negative real-time pricing. The Monitor’s recent quarterly report noted the frequency of intervals experiencing negative prices increased from 2.6% in 2015 to 7% through November 2017. (See SPP Market Monitor: Negative Prices May Require Rule Changes.)
“Negative pricing is a significant issue in our market,” MMU Executive Director Keith Collins reminded members. “Something that increases flexibility is at a premium, which we will highlight in our next report. Having non-dispatchable resources becoming dispatchable is an important piece of that recommendation.”
Collins said an SPP operations study revealed that “the more flexibility you have, you end up increasing [energy market] pricing” by reducing the magnitude of negative prices.
“All resources will benefit from that change, which will allow the integration of more and more variable resources in the system,” he said.
But Westar said the change would hurt SPP’s “market reputation.”
“NDVERs were a condition of several [market participants] agreeing to transition from [the Energy Imbalance Service to the Integrated Marketplace],” the company said in written comments. “If we go back on our word, will other [market participants] lose confidence in the stability of SPP tariff grandfathering and agreements made to prospective balancing authorities, asset owners and market participants considering the benefits of [joining] SPP as a stable settlement and market platform?”
Members accepted a friendly amendment to the revision, extending the registration deadline to January 2021.
The revision request exempts about 2,000 MW of resources without direct interconnection agreements with SPP or registered as qualifying facilities under the Public Utility Regulatory Policies Act. That drew concerns from members over whether Mountain West Transmission Group entities would be able to acquire similar exceptions.
“If the current language excludes those, it does appear to leave questions about those who joined SPP with a previous interconnection agreement, but not one with SPP,” said The Wind Coalition’s Steve Gaw. “Will they have to comply with this [requirement], or does the language exempt them, including the generators in the Mountain West region?”
“That’s exactly right,” said Oklahoma Gas & Electric’s David Kays. “When you’re being prospective about anyone coming in afterwards … I think it creates a hole in the Tariff, and I’m not sure that’s something we should be doing intentionally.”
Ross said there is no specific provision to carve out the Mountain West entities. “They’ll have to be prepared to comply with these requirements when they’re integrated into the SPP system,” he said. The MWG fashioned the change so that “anyone who wants an exception can make a [Federal Power Act Section] 200-whatever filing from that [requirement] at FERC,” he added.
Kelley pointed out that ISO-NE and CAISO have gone through similar conversions. He said the revision would help a grid that has “grown exponentially in size” with new wind resources and continues to hit new wind-penetration peaks.
“I go back to the overall problems we’re trying to address, which is overall market efficiency and reliability,” Kelley said. “When you hit those [constrained] situations, it’s imperative that the operators and markets have the tools to make the most efficient decisions on a systematic basis, rather than take out-of-market actions.”
The vote followed one of several vigorous discussions that livened up what staff and members had expected to be a perfunctory MOPC meeting.
“If you’re not careful, you’ll have an MWG meeting break out,” Ross joked.
FOLSOM, Calif. — At its first public meeting with potential customers of its reliability coordinator (RC) services Thursday, CAISO divulged that most of the load in the West has signed letters of intent for the new program.
In response to a question, CAISO Regional Integration Director Phil Pettingill said he could not say publicly who has signed letters of intent and nondisclosure agreements to receive RC services.
“What I feel like I can say is, most of the load that is in the Western Interconnection has signed those agreements with us,” Pettingill said. “We are really talking to almost everybody.”
He added that the letters of intent are not binding and can be withdrawn. The notifications that have been sent to Peak Reliability from customers planning to depart its RC program are also nonbinding.
NERC’s reliability standards require balancing authorities and transmission operators to procure RC services, which include outage coordination, real-time situation awareness, and system restoration coordination and training.
CAISO on April 5 issued its initial proposal for RC services, which it hopes to have running by May 2019. The ISO and Peak are also developing competing proposals for new energy markets that could develop into a full RTO. (See Multiple Entities, Markets Now Beckon in West.)
CAISO is now developing prices for its supplemental, non-core RC services, such as hosting advanced applications and addressing certain critical infrastructure protection services, Pettingill said in a presentation.
The ISO says its RC services will be much cheaper than Peak’s, but Peak countered that the comparison is not straightforward because Peak has more RC experience and offers certain customer services such as the WECC Interchange Tool, the Enhanced Curtailment Calculator and the Peak Synchrophasor Project. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)
In developing the RC services, the ISO will issue straw proposals and gather feedback to revise the initiatives. The final proposal will be subject to approval by the Board of Governors and FERC.
CAISO hopes for the commission’s approval in October.
The goal is for potential RC customers to export their network models by August and begin data integration and system verification in January 2019. RC service agreements would be executed in November with much of the integration and testing occurring next year, Pettingill said.
CAISO will use its “activity-based costing system,” which has been used for all rate design initiatives since 2011, to determine the costs of RC services.
About 6% of CAISO’s annual costs would be allocated to RC services in the revenue requirement for 2019 and 2020 rates, CAISO CFO and Treasurer Ryan Seghesio said Thursday.
“The ISO is committed to a really level, stable revenue requirement,” Seghesio said. CAISO’s revenue requirement of $190 million to $200 million has been stable for about 11 years. There is a FERC-approved $202 million cap on the revenue requirement, he said, to prevent surprises for market participants.
