LITTLE ROCK, Ark. — Kansas City Power & Light is making good on its promise to take legal action against SPP for how the RTO allocates costs to network customers after a new transmission owner joins an existing transmission zone.
The utility has joined with 11 other TOs to file a Section 206 complaint with FERC against a “loophole” in SPP’s Tariff that forces customers within an existing zone to pay a share of the legacy costs for transmission lines newly integrated into the zone. That practice, the complainants say, runs counter to the “no legacy cost shift” protections SPP has established to prevent cost shifting between zones.
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The Oct. 13 complaint says SPP’s Tariff is unjust and unreasonable and suggests the RTO modify its rules to ensure that facility costs are borne by customers for whom the facilities were planned.
Joining with KCP&L are American Electric Power (on behalf of subsidiaries Public Service Company of Oklahoma and Southwestern Electric Power Co.); City Utilities of Springfield, Mo.; KCP&L Greater Missouri Operations; Nebraska Public Power District; Oklahoma Gas & Electric; Omaha Public Power District; Southwestern Public Service (SPS); Sunflower Electric Power; Mid-Kansas Electric; Westar Energy; and Western Farmers Electric Cooperative.
The companies contend SPP’s zonal integration decisions create unjustified rate increases in the form of cost shifts between customers. Their complaint says the Tariff is unduly discriminatory because the cost shift burden is not evenly distributed and the disparate rate treatment is not based on any differences in service or the customers.
The cost shifts are contrary to FERC’s policies on transmission pricing, cost allocation and RTO membership, the utility said.
“This is a fairness issue,” said KCP&L’s Denise Buffington, the utility’s director of energy policy and corporate counsel. “You should not decouple the costs from the decision to build for a specific set of customers.”
The recent creation or expansion of multi-owner zones has highlighted various notice and equity issues that did not exist in historical single-owner zones, Buffington said. She suggested modifying SPP’s license plate rate design to address the increasingly common integration of smaller TOs into existing zones.
Buffington first introduced a Tariff revision request in 2016 to address the gap she said exists between the zonal placement decisions for new TOs and the cost effects of those decisions.
After receiving pushback from SPP and members, she revised her proposal to establish a mechanism holding customers of an existing zone harmless from network integration transmission service (NITS) rate increases of more than 2% or $1 million (whichever is lower). The Markets and Operations Policy Committee and the Board of Directors rejected the proposal in July. (See SPP Board Rejects Changes to Tx Zonal-Placement Rules.)
“You can be sure it will be argued about at FERC,” Buffington warned at the time.
The complaint suggested to FERC that SPP maintain separate NITS rates for the new and existing TOs upon integration. Customers of the new entity would pay its annual transmission revenue requirement (ATRR), and customers of the existing TO would continue paying the same rate previously paid based on the existing ATRR.
Public power entities have consistently opposed the transmission-owning members’ suggestions, saying it would discourage smaller entities from building transmission and getting cost recovery. FERC is already considering several cases involving cost shifts (ER16-204, ER17-2020).
“We’re still reviewing the 87-page filing, but it appears similar to the proposal KCP&L made in the SPP stakeholder process … and addresses a topic already under review by FERC,” said Brett Hooton, vice president of South Central MCN, which is involved in one of the dockets. “The proposal included in the complaint is discriminatory, anti-competitive, and undoubtedly unjust and unreasonable.”
The Missouri Public Service Commission on Monday intervened in the docket (EL18-20).
Z2 Complaints
Also last week, Xcel Energy on Oct. 10 filed a Section 206 and 306 complaint against SPP on behalf of SPS, its Texas-based utility. The complaint said SPP had violated its Tariff by assessing Attachment Z2 credit payment obligations to SPS in a manner that is “inconsistent with the SPP Tariff, violates the filed rate doctrine, is inconsistent with SPS’ network transmission service agreements with SPP and is otherwise unjust.”
Xcel requests that FERC find as unjust and unreasonable SPP’s $12.8 million net assessment to SPS for historical revenue credit payment obligations (CPOs) and ongoing monthly charges of approximately $485,000 for current CPOs and amounts uplifted. The company is seeking to have SPP recalculate the CPOs for SPS’ transmission service reservations, recalculate the historic and ongoing Z2 charges, and provide refunds to SPS with interest.
KCP&L, American Electric Power and Westar Energy have all intervened in the proceeding (EL18-9).
SPP’s process for assigning financial credits and obligations for sponsored upgrades under Attachment Z2 of its Tariff has bedeviled the RTO and members for almost two years. Last year staff identified about $200 million in revenue credits to be collected for transmission upgrades under its Tariff’s Attachment Z2, which details how to reimburse network upgrade sponsors. The bills covered eight years of credits and obligations for 2008-2016, when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See “Z2, Two Other Task Forces Expire,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
CARMEL, Ind. — Ameren Missouri is urging MISO to scrap a newly proposed process for identifying when generators deviate from dispatch instructions, asking the RTO to instead take a more lenient approach.
The new process, which relies on a calculation formulated with help from the RTO’s Independent Market Monitor, would impose a “failure to follow dispatch” warning when a resource fails to move at least half its offered ramp rate over four consecutive dispatch intervals. Generators are currently flagged after they deviate by more than 8% from dispatch signals over four consecutive intervals. (See MISO Invites Feedback on Plan to Curb Dispatch Deviations.)
The utility is asking MISO to instead use an incremental percentage approach consisting of tightening tolerance bands over a period of time — or to delay the project altogether and only focus on generators that deviate from setpoint instructions for an hour straight.
“We understand the concerns with [day-ahead margin assistance payment] and the concerns about not following setpoint instructions,” Ameren Missouri’s Jeff Moore said during a presentation given at an Oct. 12 Market Subcommittee meeting. “However, we believe there should be further discussion on the topic to fully understand the goals of this effort, address concerns of generators that are making good faith efforts to follow setpoint, and possibly explore other alternative proposals.”
Moore suggested that MISO could decrease its 8% threshold to 7%, and then 6%, to test improvement at each stage. He said his proposal maintains the current practice already familiar to generators. He also added that MISO could drop a new calculation altogether and focus on generators that don’t respond to dispatch instructions for at least one hour.
“To us, 60-minute deviations are a bigger problem. They’re not making a good faith effort,” Moore said.
As it stands, MISO’s new calculation could penalize larger units with low ramp rates, he said.
Ramp rates offered by MISO are not always the same over the entire class of generation, Moore said, asking for a “reasonable allowance” for units to respond to setpoint instructions.
“Baseload coal-fired units are not precision instruments,” he said. “The system models are what they are, but I sometimes feel we’re trying to fit a ramp rate with an imperfect machine.”
Moore said large baseload issues can be inundated with “normal” delays: fuel quality issues, feed rates, or problems with valves that can consume ramp rate time and result in a failure to follow dispatch flags.
“These happen when you’re stopping and starting large pieces of equipment,” Moore said. “Some days it may sit there and hum perfectly, and it may only be 2 to 3 MW short.”
Monitor staffer Michael Chiasson pointed out that MISO offers numerous ramp rates for generators to select. “You have 30 different ramp rates to choose from to avoid a homogenous ramp rate,” he noted.
“We aren’t interested in penalizing generators that make a good faith effort. Perhaps if we have examples of what a good faith effort looks like for this class of generator,” Chiasson said, asking large baseload generators to provide scenarios in which normal characteristics of the generator would slow down an otherwise faithful dispatch response. He added that the Monitor isn’t “fast and concrete” on its proposal and the calculation could be tweaked a bit, but argued against gentler treatment of large baseload generators.
“When someone offers a ramp rate, they’re saying they can move those number of megawatts, and MISO should expect it of them. I don’t think we should try and levelize this because, ‘It’s a coal/steam unit; don’t expect much out of it.’… That’s not a comparable standard,” Chiasson said.
He said it would be unfair to owners of fast-moving gas units to allow coal units a watered-down dispatch grace period.
“We’ve been recommending this for a half a decade,” fellow Monitor staffer Michael Wander reminded stakeholders.
MISO Market Quality Manager Jason Howard said the RTO will issue a more detailed uninstructed deviation proposal in November. He also said the RTO will review Ameren’s proposal and stakeholder comments.
CARMEL, Ind. — After criticizing Ameren Illinois for miscalculating its summer peak load forecast, Dynegy last week called on MISO to develop a new process for verifying load forecasts produced by load-serving entities.
Dynegy’s Mark Volpe said that while Zone 4 in Southern Illinois represents just 8% of total MISO capacity, it showed the largest under-procurement in the RTO’s Planning Resource Auction, when reserves came up 467.8 MW short of requirements when the summer peak occurred July 20.
The reason, according to Dynegy: Ameren’s portion of the Zone 4 load forecast for the July 2017 peak dropped 484 MW, or 6.4%, from the previous year to 7,069 MW. That led to an overall zone peak forecast of 8,925 MW, down 481 MW, compared with last year’s actual peak of 9,500 MW.
Dynegy said that none of the other zones in MISO showed a similar drop in load forecast.
“This raised our eyebrows at Dynegy,” Volpe said during an Oct. 11 Resource Adequacy Subcommittee meeting.
“We questioned MISO repeatedly on the reasonableness of the forecast, and MISO continually defended the Ameren Illinois load forecast as plausible and reasonable, given gains related to investment in energy efficiency programs, a decrease in commercial and industrial load, and an overall downturn in the economy,” Volpe said.
As required by its Tariff, MISO asks resources to provide forecasts of annual coincident, monthly non-coincident and local resource zone peak demand for use in producing annual load forecasts.
“MISO should have worked closer with Ameren to resolve what we see as an understatement of load forecast in Zone 4. Given the benefit of hindsight of the July 20 peak load … it seems to us that our concerns were pretty valid,” Volpe said.
Consumers Energy’s Jeff Beattie pointed out the Zone 4 planning reserve sharing group easily compensated for the 468-MW shortage.
“To me, that’s one of the benefits of being in an RTO,” Beattie said.
“You’re right — from a macro perspective, things are fine,” Volpe said, adding that he was more interested in the year-over-year changes to load forecasts.
Volpe said MISO does not currently have provisions to perform an after-the-fact examination of forecasts provided by LSEs. He suggested that an independent third party could provide a “look back” of the load forecasts to check for accuracy.
“None of us like penalties, of course, but I think we need to put on our thinking caps and find a way to review whether a load-serving entity came close to its planning reserve margin,” Volpe said. “We’re concerned with overall system reliability, and we have to realize that this impacts all connected to the transmission system.”
Minnesota Public Utilities Commission staff member Hwikwon Ham asked Volpe who would pay for the third-party review. Volpe said costs would have to be worked out if MISO pursues the proposal.
MISO Executive Director of Strategy Shawn McFarlane said the RTO will address the presentation at the November meeting. Kevin Sherd, MISO director of forward operations planning, said the RTO continues to support its existing load forecasting process.
“Quite frankly, we think the forecasts are good on a reasonable, one-year-out basis,” Sherd said.
Improving the Independent Load Forecast?
Volpe suggested that Purdue University — the same third party that produces independent load forecasts used to evaluate the MISO’s own predictions — could verify LSE load forecasts.
But MISO said last month that after three years of using forecasts prepared by Purdue, the process could use improvement, although it did not propose possible changes.
The university’s State Utility Forecasting Group generates forecasts for all 15 MISO states using public data from the Energy Information Administration. The forecast includes summer and winter values for annual energy use in MISO’s 10 local resource zones and aggregate, coincident and non-coincident peak demand predictions for each zone. MISO is nearing the end of a three-year contract with Purdue to provide the forecasts.
MISO said that after three iterations of the third-party forecasts, it has refined its methodology based on stakeholder wishes, leading to use of Applied Energy Group and electric generation expansion analysis system data to create predictions of generation and renewable growth, instead of simply relying state mandates and goals.
“We’ve used the forecast to date for comparison,” MISO Director of Planning Jeff Webb explained earlier this month, noting that the RTO first consults resource adequacy requirements under Module E of its Tariff, then compares the independent forecast against aggregated forecasts submitted by LSEs and transmission owners to determine reserve requirements.
Tim Aliff, MISO director of interconnection and planning, said that if the RTO misjudges its temperature forecast by even 1 degree, it either underestimates or overshoots its load forecasts by about 1 GW. On Sept. 22, it expected the footprint to top out at 89 F, instead of the actual high of 92 F, he said.
“That can be a big impact from a load perspective. Those 3 degrees might not feel like much outside, but it caused us to be off by about 4 GW,” Aliff said during an Oct. 12 Market Subcommittee meeting.
“Ninety degrees in September isn’t all that odd, but 90 degrees in late September is odd,” he added.
MISO emergency conditions Sept. 21-25 were the result of a combination of record temperatures, high load, and seasonal and forced generation outages. (See MISO Capacity Easily Exceeds Predicted Winter Peak.)
On the day of the maximum generation event, MISO had 4.6 GW of stranded capacity due to forced and planned outages and derates. Additionally, 1.1 GW of generation tripped offline suddenly. Aliff pointed out that during the emergency conditions, MISO South was still recovering from the impacts of Hurricane Harvey.
“It’s kind of unusual on a Saturday to get into a max generation situation,” Aliff said of Sept. 23, which also fell under the maximum generation warning. “Shoulder months can be challenging, so we continue to review what we need to do to reduce these challenges, if you will.”
Michigan Public Service Commission staffer Bonnie Janssen pointed out that by late September, school is in session, which contributes to load.
Xcel Energy’s Kari Clark asked whether MISO could make transmission constraints more visible to market participants during emergency conditions so generators can better understand if their megawatts are unlikely to be able to aid an emergency.
“If we know that we could help you, that would be helpful in our processes,” Clark said.
Aliff said Clark’s suggestion was useful and that he would take it back to his team.
Minnesota Public Utilities Commission staff member Hwikwon Ham asked if MISO has identified a possible transmission solution that would have moderated the situation. Aliff responded that it had not investigated but could look into it.
The September emergency marks MISO’s second maximum generation event of the year. On April 4, MISO called up load-modifying resources for the first time in 10 years in the face of a similar blend of unseasonably high loads coupled with a large number of generation and transmission outages. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs.) MISO did not have to shed load during the September emergency.
CARMEL, Ind. — WEC Energy Group uncovered a Tariff inconsistency while it was developing a proposal to improve MISO’s behind-the-meter generation participation rules, a company representative said last week.
WEC’s Chris Plante said MISO’s definition of what constitutes a network resource, defined in Module B of the Tariff, doesn’t recognize all capacity acquired under Module E, which covers the procurement of resource adequacy (RA).
Module B does not allow a network customer to generically claim the MISO energy market or capacity market as its network resource, thus technically excluding the customer from counting unregistered BTM generation — which does not have existing transmission service — toward RA requirements, Plante said during an Oct. 11 Resource Adequacy Subcommittee meeting. However, Module E currently allows those resources to be counted as capacity.
To reconcile the discrepancy, Plante suggested that MISO’s definition of “uppercase,” or registered, BTM generation be limited to the following categories:
Network resources behind the market delivery point;
Resources behind the market delivery point participating in the market; and
Resources behind the market delivery point that causes flow on the transmission system.
Plante proposed that any resource be required to register as a network resource with MISO before it can fulfill capacity obligations. The proposal aligns with a plan the RTO is already formulating through planned implementation of a one-time deliverability test for BTM generators that could trigger a requirement to acquire network service in an upcoming capacity auction. (See MISO Proposes Deliverability Rules for Behind-the-Meter Capacity.) Unregistered BTM generators currently enjoy identical treatment to those generators registered as a network resource without having to register with MISO, something the RTO aims to change.
Plante said MISO’s “lowercase” BTM generation — resources not required to register — should be limited to those resources located behind the retail meter and used by a retail customer only to manage load “at the same electrical location,” Plante said. Such resources would not have to respond to emergency conditions.
“We just want comparable treatment among all network resources,” Plante said. “We don’t believe just listing the MISO market as your network resource is appropriate,” according to Module B of the Tariff, Plante said.
Customized Energy Solutions’ Ted Kuhn asked if network customers would now have to enter the capacity auction with a resource already specified. “There would be no way to just go to the auction and say, ‘I’ll take what’s available,’” Kuhn said.
Kevin Murray, attorney for the Coalition of Midwest Transmission Customers, agreed that network customers aren’t currently following MISO’s Tariff as written but added that if they did, and had to identify resources before participating, the capacity auction would clear at near-zero prices “until the end of time.” Plante agreed.
Other stakeholders suggested it was time to re-examine Module B and update its network resource definitions to align with today’s emerging technology.
Plante said WEC wasn’t “wedded” to its proposal and asked stakeholders for more written feedback on the two types of BTM generation.
“This uppercase and lowercase BTMG personally drives me nuts,” said Planning Advisory Committee Chair Cynthia Crane during a Sept. 27 meeting of her committee. She suggested MISO instead use an “R” before the BTMG acronym to differentiate registered and unregistered BTM generation, instead of using the “uppercase” and “lowercase” designations.
MISO will continue to discuss market definitions for BTM generation at the November RASC meeting. Earlier this year, Manager of Resource Adequacy John Harmon said he thinks the energy industry will be focusing on BTM and distributed energy resource issues for years to come.
State regulators warned PJM last week that it should avoid any capacity market changes that would increase costs or restrict state policies setting generation preferences.
In a letter Oct. 9, the Organization of PJM States Inc. said it has “increasing concerns” with the discussions in the RTO’s Capacity Construct/Public Policy Senior Task Force (CCPPSTF).
OPSI President John Rosales, a member of the Illinois Commerce Commission, said some proposals being discussed by the task force could raise prices significantly and “result in unjustified restrictions of lawful state public policies regarding preferences for characteristics and attributes of electricity supply resources.”
PJM stakeholders approved the task force in January following months of debate. The group’s issue charge called for a “proactive” review of the Reliability Pricing Model to ensure stakeholders are involved in the RTO’s response to “unforeseen events” such as proposed power purchase agreements for coal plants in Ohio and the adoption of zero-emission credits for nuclear plants in Illinois that are at risk of closing because of low market prices. “The failure to successfully anticipate these occurrences resulted in important policy debates circumventing the PJM stakeholder process and going directly to litigation at FERC,” it said. (See PJM to Review Impact of State Public Policies on RPM.)
Rosales’ letter contrasted the task force’s charge to identify “areas where state actions and the current RPM capacity construct may not be aligned” with the Capacity Performance rules enacted after the 2014 polar vortex resulted in the loss of 22% of the RTO’s generation. “Unlike PJM’s initiative to implement the Capacity Performance proposal, there has been no demonstration of facts, data or information other than hypothetical fears supporting the concerns” of the task force, he said.
“Some of the proposals would revise the procedures for resource eligibility to participate in the Base Residual Auction (BRA) and the implementation of the RPM to administratively adjust resource offers and raise the price for capacity. Based on estimations provided in the CCPPSTF, it appears customers are at significant risk of increased cost for capacity. … Regardless of intention, neither artificially and unnecessarily higher capacity costs nor improper restrictions on state public policies would be acceptable to OPSI.”
The group criticized the task force’s charter, saying that barring discussions of impacts outside of the capacity market “will almost certainly raise the potential for distortions in total supply costs paid by customers.”
The regulators also criticized the task force’s “accelerated timeline,” saying it increases the risk of implementing rules before they are fully vetted and ignores the backlog FERC is attempting to eliminate following its six months without a quorum.
Failing to consider “the intended, and unintended, consequences” of the task force proposals “will likely produce overly narrow, inefficient and excessively costly results,” OPSI said.
“OPSI does not believe PJM has demonstrated any convincing reason to interfere with the lawful pursuit of state public policy in the OPSI jurisdictions. Nevertheless, if PJM persists in proceeding, OPSI would urge PJM to revise its CCPPSTF timeline and process to allow for more robust, comprehensive and appropriate” discussions.
VALLEY FORGE, Pa. — The preliminary day-ahead scheduling reserve (DASR) requirement for 2018 is 5.29%, PJM’s Tom Hauske told the Operating Committee last week. The requirement is calculated for each season by combining the average of the seasonal load-forecast errors and the forced-outage rate, both of which dropped about 0.1% for the 2018 calculation.
The final value won’t be known until the data from this month are included, Hauske said. PJM staff will return next month to seek endorsement of the requirement, which is down from this year, when it was 5.48%.
PJM’s Chris Pilong announced proposed Manual 13 changes that would update the DASR requirement and ease the requirements for calling hot weather alerts in the spring and fall.
The changes would allow such alerts at temperatures below the current 90-degree trigger during the spring and fall months when generation and transmission outages lower available capacity.
American Electric Power’s Brock Ondayko expressed concern with the change.
“I understand what you’re trying to do, but I have a concern about some of the ramifications by kind of making more liberal the circumstances that you would go into a hot weather alert,” he said.
“One of the challenges we wrestled with is we have a 90-degree trigger, and is there some other trigger — some other temperature — that makes sense? Unfortunately, there really isn’t,” Pilong said in response.
He noted days in September or October where the temperature nears 90 degrees and said there’s not a lot of historic data for “those unusual temperatures for that time of year.”
Ondayko disagreed with PJM’s perspective. “I think there are other ways that you could suggest that people have some reserve ready,” he said.
The manual changes also would delete redundant information and clarify the emergency procedures that trigger a performance assessment hour under the Capacity Performance rules.
PJM’s Dave Souder, Brian Fitzpatrick and Marilyn Jayachandran explained how staff plan to incorporate the RTO’s focus on resilience into operations. Many of them deal with increased gas-electric coordination.
“We’re going to see more and more gas” generation, Souder said.
Fitzpatrick said PJM is analyzing the pipeline systems serving gas-fired units to identify critical infrastructure, understand where redundancies and limitations exist and “make sure there is enough gas scheduled to meet the requirements.”
Jayachandran explained PJM’s seasonal, monthly and ad hoc assessments of the system. PJM has developed procedures to factor pipeline issues into its operations.
“We would coordinate with generation owners and pipelines to come up with a plan to determine if the [unit] is able to swap to their dual-fuel” source or another pipeline.
Going forward, PJM will be continuing its gas-electric coordination and working with the Argonne National Laboratory on modeling the pipeline system.
LITTLE ROCK, Ark. — SPP began the public portion of integrating the Mountain West Transmission Group with a pair of lively stakeholder meetings Friday and Monday.
Representatives from the two entities shared details of SPP’s integration process, proposed modifications to the RTO’s governing documents and the integration’s timeline. The two meetings attracted about 325 current and potential SPP members, state regulators, and environmental and customer advocates in person or on the phone.
“This will start the debate process as we work together in a way that benefits both SPP and Mountain West,” SPP COO Carl Monroe said in kicking off the meeting at Mountain West member Tri-State Generation and Transmission’s offices in Westminster, Colo.
During a Monday meeting in Little Rock, SPP members peppered representatives with numerous questions about several of Mountain West’s proposals to modify the RTO’s stakeholder process.
The “Westsiders” have suggested:
Creating a Westside Transmission Owners Committee with decision-making authority over issues reserved to the transmission owners;
Prohibiting the SPP Board of Directors from changing decisions by the new committee, and replacing the board’s secret ballots with open ballots;
Expanding the Regional State Committee’s authority to include resource adequacy and congestion rights allocation oversight for SPP’s Western Interconnection region, and giving Western members of the committee the right to direct the RTO to make FERC filings; and
Adding seats on the board committees for Western representatives.
Kenna Hagan, senior manager of planning, policy and strategy for Black Hills Corp., said Mountain West’s proposals result from years of discussion among the coalition’s 10 utilities.
“This is a compromise position that’s taken us three years to derive,” Hagan said. “There’s strong interplay between each of those items we’re proposing. It’s not all or nothing … but it’s important to us to move forward as a group.”
Duke-American Transmission Co.’s Bob Burner called Mountain West’s suggestions “protectionist proposals,” saying, “It certainly discourages independent transmission developers from looking at anything on the west side.”
Other stakeholders questioned the differences between east and west in transmission cost allocations and rate design, but those involved in the negotiations worked hard to allay concerns.
“These are not meant to be two separate processes,” said Tri-State’s Mary Ann Zehr. “They’re supposed to work in concert with each other.”
“You’re bringing up things we will have to address [in the stakeholder process] and work through,” said SPP Associated General Counsel Mike Riley.
SPP and Mountain West are in the third stage of the RTO’s process for integrating new members, when staff will convene special all-member and stakeholder meetings to discuss proposed document changes. Mountain West triggered the stage when it said in September it had completed initial discussions with the RTO’s management team and would begin public negotiations. (See Mountain West to Step up Talks with SPP on Joining RTO.) Mountain West, which primarily services Colorado, Wyoming and Nebraska, announced its intentions in January to join SPP. The two entities are working on an Oct. 1, 2019, target date for membership.
SPP’s existing members will see a phased-in, reduced administrative fee. The fee, currently 48 cents/MWh, will drop to 43 cents for 2020, resulting in annual savings to existing members of $16 million to $25 million for the first three years and a total net present value benefit of approximately $209 million for the first 10 years of Mountain West membership, SPP said.
A Brattle Group study conducted for Mountain West found the entity could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with one. A separate Glarus Group study of DC tie flows in a combined Mountain West-SPP market showed “significant” benefits, with annual net production cost savings ranging from $11.7 million to $28.8 million.
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Any changes to SPP’s governing documents will be reviewed by stakeholders on the Corporate Governance Committee (governing documents), Strategic Planning Committee (negotiating strategies, new member deliberations), Markets and Operations Policy Committee (Tariff revisions) and the RSC (state regulatory agency input).
SPP’s board will have the final call on any changes.
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SPP will conduct a reliability assessment of each incoming member’s transmission system to ensure they meet the minimum reliability planning criteria. Staff performed similar assessments when it added Nebraska’s utilities and the Integrated System.
“We’ve been through this before,” said Lanny Nickell, SPP vice president of engineering.
VALLEY FORGE, Pa. — PJM’s plan for addressing uplift remains on schedule, and the final two phases of its three-phase solution will be filed by the end of this week, staff announced at Wednesday’s Market Implementation Committee meeting.
The two remaining phases will be filed separately. In May, after four years of debate, stakeholders endorsed the final phase of the plan despite opposition from financial marketers. The filings address allocation of uplift and limit the locations where financial traders can place bids. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
Bruce Bleiweis of DC Energy asked if PJM had any indication whether newly installed FERC Commissioner Robert Powelson would recuse himself from the decision. Powelson previously chaired Pennsylvania’s Public Utility Commission. PJM staff said they had no information on that.
Debate Continues on Intraday Offers
The results were mixed for the Independent Market Monitor’s proposed revisions to the intraday-offer procedures, which go into effect on Nov. 1.
Stakeholders endorsed a joint proposal from PJM and the Monitor on changes to Manual 11 that would allow reapplication of the three-pivotal-supplier test after offers are updated. However, they declined the Monitor’s recommendations on other Manual 11 changes to verification of energy offers and endorsed PJM’s plan. (See “PJM, IMM Agreement on Intra-Day Offers Seen as ‘Massive Change,’” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
The Monitor’s Catherine Tyler argued that PJM’s proposed energy-offer screen, which is being implemented to comply with FERC Order 831, fails to incorporate information from fuel-cost policies and other cost inputs. The offer-verification changes for demand response also don’t follow the rules already in place for generators, she said.
“I think there’s a real concern that if there aren’t more details in the manual, if there’s no [offer] cap, then an astronomically high offer could go through, and PJM has no process to stop payment without going to FERC.”
The Monitor, she said, is concerned that the process is not standardized. However, stakeholders hesitated to apply a standard before seeing how the process works in the real world.
“I think we have a learning curve, and while I don’t disagree with the value of a standard, I would suggest that having a standard without any history isn’t productive,” CPower’s Bruce Campbell said.
PJM’s proposal on verifying offers passed with one vote in opposition and 21 abstentions.
Give Them Some Credit
PJM is proposing to use modeling to improve its financial transmission right credit requirements. By incorporating the RTO’s PROMOD planning simulations, credit requirements can take into consideration the impacts of future transmission upgrades, PJM’s Hal Loomis said. Because system upgrades reduce congestion, they also decrease the value of nearby prevailing-flow FTRs.
The plan would analyze the impact of upgrades on FTR bid and cleared credit requirements. PJM’s threshold for analysis would be upgrades with at least a 10% impact on constraints with at least $5 million in congestion. Just three of the 22 system upgrades placed in service for 2017/18 fit those criteria.
PJM is proposing two implementation alternatives. The first, which staff prefer, would incorporate the PROMOD simulation results into the publicly available FTR credit calculator prior to the FTR bid window. While the RTO would only publish the difference between the simulation and historical values for each node, Loomis noted that some stakeholders have complained it would provide market intelligence.
“We know transparency is important to our members. It’s also important to FERC,” Loomis said.
The second option, which resembles the current undiversified adder process, would have PJM issue incremental collateral calls between the close of each FTR bid window and publication of the cleared auction results. While this doesn’t give away information, it could require posting additional collateral within a day. Those who miss the deadline would have their bids removed.
PJM hopes to implement one of the processes in time for the 2018/19 annual FTR auction next spring and apply it to all existing positions. Members with a credit shortfall will be restricted in their FTR transactions during a 12-month “transitional cure period” in which they won’t be at risk of default but can only make transactions that reduce their credit exposure. No collateral returns will be allowed until the shortfall is cured.
“If there’s a shortfall, we want members to cover the shortfall,” Loomis said.
A poll in PJM’s Credit Subcommittee found strong support for all facets of the proposal, including the RTO’s preference for posting the nodal differences, Loomis said.
DC Energy’s Bleiweis suggested better alternatives are available, adding that “PJM should keep its views of the future confidential.”
Instead, he said, the PROMOD data should be supplemented with third-party forecasts.
“One of the issues we had with the poll is we weren’t able to answer the questions we wanted to answer,” he said. “There are experts out there who do congestion forecasting. PJM should work with them.”
He made the argument during a presentation on his company’s concern that the rule changes would still allow participants to hold substantial FTR portfolios while posting little or no collateral. DC recommends a minimum collateral threshold, along with scaling capitalization requirements for increasingly risky positions. Bleiweis also recommended a mark-to-market test in which PJM would collect additional collateral based on the current market value of the purchaser’s FTR portfolio.
He acknowledged that these recommendations would “absolutely” increase DC Energy’s credit requirements.
“We think it’s critical to protect the market,” he said. “The worst thing that can happen to the FTR market is another default. We had one in 2008.”
PJM Chief Financial Officer Suzanne Daugherty asked stakeholders to address the issue sequentially rather than with an omnibus solution. “We’d like to get this one known exposure addressed,” she said.
Bleiweis acknowledged PJM’s progress on the issue and agreed to take his proposal to the subcommittee in exchange for Daugherty’s commitment that it would be addressed soon.
“Over the last 13 years, we’ve made a lot of progress on credit issues. We’re not going to stand in the way,” Bleiweis said.
Earlier in the meeting, stakeholders also endorsed proposed changes to credit requirements for regulation resources to allow credits to offset charges daily. The existing process settles credits monthly but charges weekly, which can create a collateral requirement within the month despite the existence of a much-larger outstanding credit. Travis Stewart of Gabel Associates, which identified the issue and advocated for the change, thanked PJM for the effort.
Stakeholders were uncharacteristically divided on whether to allow discussion of concerns raised by the Monitor on the long-term FTR market but eventually assented to it. Monitor Joe Bowring presented a problem statement and issue charge on FTRs with terms of one or three years, which he said have a very concentrated ownership and don’t accurately reflect the prices in corresponding annual FTR auctions. He suggested there was a lack of interest in the product.
“It has become increasingly clear that the three-year FTR product sold in the long-term FTR auction should be eliminated,” the Monitor said in its State of the Market report for the first half of 2017.
Bowring and Vitol’s Joe Wadsworth sparred over the Monitor’s goals and perception of the problem. Wadsworth asked if Bowring’s interests were in improving the efficiency and liquidity of long-term market transactions or simply abolishing FTRs. Bowring responded that the question is whether long-term FTRs are helping or hurting the efficiency of markets overall.
“That’s not a very clear answer to me. Take that as constructive [criticism]. Take it as nothing more than that,” Wadsworth said.
Rather than a lack of interest, there are impediments, like regulatory uncertainty, that make many participants nervous about transacting years in the future on energy products in general, he said. He later added that Vitol supports open dialogue and wouldn’t vote against having a discussion.
Marji Philips of Direct Energy said it was interesting that Bowring’s proposal was “being picked apart … which tells me that everyone picking it apart is afraid of losing money.”
“We don’t see any harm” in the discussion, she said.
The measure received 64% approval with a vote of 108-60 and 53 abstentions.
OPSI, PJM at Odds over PRD
State regulators are at odds with PJM over requirements for demand-side resources, including price-responsive demand (PRD) bids.
PJM says PRD bids should be available year-round, the same as generation resources under Capacity Performance rules. But the Organization of PJM States Inc. (OPSI), which speaks for the state regulators, argues they should be allowed to make seasonal contributions.
The dispute came to a head during PJM’s presentation of its proposed PRD rule changes to match CP requirements. PJM’s Pete Langbein outlined three proposals. The RTO’s proposal would extend annual requirements developed for DR to PRD. A second proposal would limit the triggers for assessing CP penalties to just penalty assessment intervals. The third, from DR-participant Whisker Labs, would extend the existing PRD rules to the winter, create a summer-only product and allow it to be aggregated with a winter resource for an annual CP resource.
OPSI Executive Director Greg Carmean made a statement developed from a resolution OPSI sent to PJM’s Board of Managers on Oct. 9 urging the grid operator to create market mechanisms that enable participation of summer-available demand resources.
Bowring said that if PRD bids are meant to be price responsive, they should be energy resources rather than capacity.
The issue has existed since PJM implemented its CP construct in response to the 2014 polar vortex. CP requires that all resources have year-round availability and includes penalties for those that fail to respond during emergencies.
OBF Changes
PJM’s Tim Horger announced that PJM has alertedNYISO that it plans to end the controversial 400-MW operational base flow (OBF) through northern New Jersey on Oct. 31, 2019.
The OBF was created in May in response to Consolidated Edison ending its decades-old agreement with Public Service Electric and Gas to “wheel” 1,000 MW from upstate New York through PSE&G’s northern New Jersey territory and into New York City. Amid stakeholder complaints about its necessity, PJM decided to retain 400 MW of that flow as the OBF.
PJM now says it won’t need the cushion to manage energy flows in the area once the Bergen-Linden Corridor project is complete. Per the grid operators’ joint operating agreement, PJM provided NYISO two years’ notice of the change, which NYISO acknowledged.
OVEC Joining
The Ohio Valley Electric Corp. (OVEC) is planning to join PJM. OVEC’s Scott Cunningham said the company plans to join PJM as its own transmission zone, despite having no load to service.
OVEC, which is headquartered in Piketon, Ohio, owns 2,200 MW of generation capacity but will have no load after a U.S. Department of Energy contract ends sometime before 2023. The company was created in 1952 to service roughly 2,000 MW of load from a uranium enrichment plant near Piketon operated by the Atomic Energy Commission.
DOE, which took over operation of the plant after the commission was abolished in 1974, ceased operations there in 2001. The department ended the 2,000-MW contract in 2003 but maintains a load that can be 45 MW at its maximum but is generally less than 30 MW. In months with mild weather, it is less than 20 MW, Cunningham said.
OVEC’s two coal-fired generating plants are already pseudo-tied into PJM, and its eight “sponsors” are allowed to sell their portions of the output into PJM’s markets. OVEC has no distribution and does not belong to an RTO, although its reliability coordinator function is performed under an agreement with MISO.
The generation would become internal to PJM following membership, eliminating the pseudo-ties, American Electric Power’s David Canter said. AEP is one of OVEC’s sponsors.
PJM’s Asanga Perera said there might be some auction revenue rights associated with the membership.
VALLEY FORGE, Pa. — Stakeholders approved PJM’s 2017 installed reserve margin (IRM) calculations at last week’s Planning Committee meeting.
The updated calculations reduced the IRM from 16.6% to 15.8% for delivery year 2021/22, thanks to an anticipated fleet-wide equivalent forced outage rate (EFORd) reduction from 6.59% to 5.89%. PJM calculated EFORd — which measures the probability a generator will fail completely or in part when needed — for the existing generation fleet and the fleet expected in future study years. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)
PJM also reduced the winter weekly reserve target for each month this winter. December dropped from 24% last year to 23% this year. January’s target fell from 30% to 27% and February from 28% to 25%.
PJM is planning to revise its evaluation process for new and upgrade transmission service requests to provide early analysis of recommended upgrades and cost estimates. The initial study, which does not address the upgrades or cost estimates, would be replaced with a feasibility study, PJM’s Ed Franks said. The subsequent system impact and facilities studies would remain the same. (See “Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues,” PJM Planning and Tx Expansion Advisory Committees Briefs.)
“The analysis as it’s currently done is just constantly refined as projects drop out of the queue. That’s just the nature of the process,” Franks said. “We feel that at least giving them something up front high-level is more appropriate than having them wait until the impact study to get something.”
Franks said PJM could evaluate and consider combining the feasibility and impact studies if customers preferred that approach. The changes don’t apply to requests that enter the queue through available transfer capability calculations.
PJM is planning to request FERC approve an April 1, 2018, implementation, which will require the Markets and Reliability Committee endorse the Tariff changes in December and the changes to Manual 14A in February. Necessary changes for Manual 2 will be developed through the manual’s usual endorsement process.
PJM is hoping to continue developing its transmission design standards with new underground line construction guidelines, but transmission customers question their usefulness. (See “Competitive Planning Components Endorsed; Pieces Remain,” PJM Planning & Tx Expansion Advisory Committees Briefs.)
Transmission developers acknowledge the standards when they sign PJM’s designated entity agreement (DEA) to receive approval to construct a project, but the RTO does not enforce them. DEAs are required for companies assigned projects through PJM’s competitive-bidding process. Customers were concerned that the standards don’t bind the developers to any specific actions.
“It raises the question for me … is whether all underground construction should be held to the same … standard,” said Ed Tatum of American Municipal Power.
“PJM is not going to go through a checklist with the proposing entities ensuring that they considered all of … the minimum standards. It’s more for an awareness,” the RTO’s Michael Herman explained. Some of the highly detailed standards are “really beyond the scope of tracking,” he said.
“These are minimum standards,” PJM’s Sue Glatz added. “These are not the only standards that apply to transmission projects.” Transmission owners have their own, she said.
As PJM works on factoring resilience into planning, stakeholders are hoping the new criteria will address specific issues. PJM’s Mark Sims provided an update on the RTO’s progress, which elicited questions from state advocates.
Ruth Ann Price with the Delaware Division of the Public Advocate asked about a comment PJM CEO Andy Ott made at the Grid 20/20 conference in September. Ott had said that one of PJM’s resilience goals would be to make “critical facilities less critical.” (See PJM Defends Resilience Focus as Pre-emptive, not Excessive.)
Price asked how that concept would be applied in PJM’s planning, but the RTO’s Steve Herling cautioned against jumping to conclusions.
“That’s just an example that Andy was using as to how we might visualize the problem and how we might go about solving them,” he said.
Greg Poulos, executive director the Consumer Advocates of the PJM States, was disappointed PJM isn’t specifically focused on that goal.
“I was really surprised to hear that’s not a main emphasis. I didn’t realize it was just an example and not a major project,” he said.
PJM staff asked for patience in developing a plan.
“Traditional power flows are well understood. They haven’t changed much over time, those metrics. But for resilience, we’re creating brand new metrics,” Sims explained. “I think the approach is to set a longer timeline … but we’re still very much working on the technical side of things.”
Interconnection Webpage Gets a Facelift
PJM has redesigned its webpage for the interconnection queue to incorporate more information. PJM’s Tawnya Luna unveiled the new look, explaining that it includes new county-level and megawatt filters. Users will be able to save a list of projects and receive weekly or monthly updates on them via email.
The site will change over in late October. PJM is seeking feedback for future revisions, Luna said.
How Immediate is Immediate?
Transmission customers and merchant transmission developers joined together at last week’s meeting of the Transmission Expansion Advisory Committee to raise concerns about PJM’s categorization of “immediate need” projects.
The debate began when Sims described modifications that will raise the costs of a project in Dominion Energy’s territory. The b2361 project northeast of Fairfax City, Va., originally ran about 4.5 miles from the Idylwood substation to a new Scott’s Run substation and was expected to cost about $32 million. But that plan ran into siting issues at Scott’s Run. The project’s scope has been expanded to instead rebuild the Tysons substation and run the line there for a total cost of at least $111.7 million. The project’s in-service date has also been moved back five years to 2022.
Mark Ringhausen with Old Dominion Electric Cooperative said the changes should warrant including the project in PJM’s competitive bidding processes for transmission projects that were developed through FERC Order 1000, but Dominion’s Ronnie Bailey disagreed.
“I don’t think an Order 1000 process would get us to a better answer,” he said.
Sims said the project has already been approved for construction by PJM’s Board of Managers.
“We’re changing to scope for it,” he said.
“This seems a little different than a routine scope change because it’s a five-year scope change,” said LS Power’s Sharon Segner. “Delaying the in-service date by five years would clearly put this project not in ‘immediate need.’ … We would encourage this immediate-need designation process to not be a rubber stamp process.”
PJM’s Tariff requires that “immediate need” projects must be in service within three years. But Sims clarified that the designation refers to when the project is needed, not when it will be in service.
John Farber with the Delaware Public Service Commission brought up the issue again later in the meeting during a discussion of projects in Public Service Electric and Gas’ territory.
“Really, it’s a ‘wanted by’ date, and the ‘required date’ is when it actually goes into service?” he asked.
Sims said the “required in-service date” is when the project is needed, but that date can’t always be met. He added that it’s “a little circular” to suggest competitive bidding for such projects would be faster at defining an in-service date because that wouldn’t be known until the end of the bidding process.
