Speaking Tuesday at the Energy Bar Association’s midyear conference, the former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) tallied off six objectives for revising FERC’s regulatory posture.
They ranged from streamlining project review for natural-gas and hydropower projects, to determining a “just and reasonable” return on equity for transmission projects; from changing FERC’s interpretation of de novo review and revising the Public Utility Regulatory Policies Act, to addressing cyber threats. Chatterjee said he also wants to ensure the industry doesn’t outrun itself with technology advancements.
Reliability
But although it was buried deep in his speech, his timeliest goal appears to be maintaining grid reliability “during a time of rapid change,” which comes in light of the Department of Energy’s recent Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants.
Chatterjee has already said he supports investigating the issue. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.) On Tuesday, he suggested that those baseload resources may be needed to avoid changing the generation fleet too much, too quickly.
“Reliability is and will continue to be our foremost priority,” he said, listing off several of FERC’s responsibilities related to reliability. “In my view, the DOE NOPR fits comfortably within those efforts. … We must ensure we don’t find ourselves coming to regret not having asked hard questions like these amongst all the changes in the energy industry.”
He also said that news of attempts by Russia and North Korea to hack the grid highlight other reliability needs.
“It’s clear that defending our nation from international cyber threats is one of the most serious challenges of our time,” he said.
Streamlining Review
Chatterjee also voiced support for streamlining the review process for natural gas pipeline and hydropower projects.
“The FERC review process continues to get longer and longer, due in large part to increased participation in the process by stakeholders, including numerous legal challenges,” he said. “FERC owes both sides an opportunity … to receive a timely up-or-down decision.”
Chatterjee dismissed suggestions that FERC depart from its “longstanding” reliance on customer agreements to gauge the economic need for a project “in favor of weighing a broad range of economic, social and aesthetic values.” Gas subscriptions on pipelines are “clear, unequivocal statements of economic need by the market itself.” (See FERC Chair: Court Ruling Won’t Change Pipeline Reviews.)
He blamed project delays on incomplete applications, negotiations with federal and state agencies and the “sheer number” of comments, saying “FERC is most definitely not the principle source of those delays.” He urged applicants to use FERC’s prefiling process and said he hopes to “pursue understandings that can be reached on an agency-to-agency basis” to improve response time. There is no way to speed up comments or responding to them thoughtfully, he said.
Additional Issues
With the generation fleet changing and transmission constraints raising prices, consumers stand to benefit from developing additional transmission infrastructure, Chatterjee said. The “most critical near-term piece” is finding the right financial incentives for enticing project investment, which will involve determining “what represents a just and reasonable return on equity for transmission projects.”
Courts have rejected FERC’s interpretation of its de novo review authority five times, he said, so the commission must develop a “proper scope” that is “fair and legally defensible.” FERC has been chastised by Congress in the past for not properly handling enforcement cases. (See FERC Enforcement Process Under Fire in House Hearing.)
Finally, Chatterjee indicated he plans to address FERC’s implementation of PURPA, specifically the “1-mile rule” for qualifying facilities. FERC has ruled that QFs located within 1 mile of each other are considered to be “located at the same site” and that wind farms of 20 MW or larger within ISO/RTO regions are presumed to have access to competitive markets and thus ineligible for PURPA’s must-purchase obligation on incumbent utilities. However, stakeholders have complained that QF developers are circumventing the 20-MW cap by creating separate corporate entities for individual turbines or small groups of turbines, or disaggregating large projects by siting turbines more than 1 mile apart. (See Witnesses Offer Alternate Realities on Need for PURPA Reform.)
RENO, Nev. — Energy storage can provide many benefits to the Western electricity grid, but it will require complex and costly modeling to be integrated properly, a panel of regional energy experts said this week.
The power industry, and its regulators, will require a long-term effort to accurately analyze the benefits and costs of storage, the panel of utility representatives and others said during an Oct. 17 joint meeting of the Committee on Regional Electric Power Cooperation (CREPC) and the Western Interconnection Regional Advisory Body.
Sector participants must study what ancillary services and sub-hourly and locational benefits storage resources can offer along with the range of other uses being explored for the technology.
Fully modeling the impact of energy storage across the existing utility system “is going to be a very difficult nut to crack” and a big computational problem, said Elaine Hart, a Portland General Electric power analyst.
Oregon-based PGE has been using software tools to model storage, Hart said, utilizing a production cost model for its integrated resource plan (IRP) that simulates the electricity system and dispatch over 20 years and 30 different potential future scenarios based on gas prices, resource output, energy prices and other factors. The effort requires significant computing power and lengthy running of software programs to model possible outcomes.
“We are really lucky that we had this tool when we started evaluating energy storage,” Hart said. To reduce computational time, timelines for modeling could be expanded to every few years instead of every year, for example, and other adjustments could be made, she noted.
Getting it Right
The Washington Utilities and Transportation Commission is working to help that state’s investor-owned utilities integrate energy storage into their IRPs, commission energy adviser Jeremy Twitchell said. The regulator has directed utilities to improve their analysis of energy storage options, an initiative launched after it observed activities at FERC and in California, New York and around the country.
“The key takeaway as we looked around was there were niche storage applications at the time: There were cost-effective applications in a limited scope,” he said. The commission knew utilities needed to be more flexible and that technology costs were dropping, but its modeling capabilities were inadequate.
The commission felt that if it got the modeling right, utilities would integrate the technology in a cost-effective way, Twitchell said. It held workshops to identify challenges, bringing in national laboratories to provide modeling advice and finding that storage can perform well as frequency support and fast response. He also said storage should also be studied for its impact on the transmission and distribution grid, and not just as an IRP resource.
The UTC earlier this month issued a policy statement saying that the absence of an organized market in the West is creating many of the challenges of integrating energy storage, but Twitchell said that perspective is changing because regulated utilities can still capture the benefits of storage without relying on wholesale market outcomes.
FERC in January issued its own storage policy statement “to provide guidance regarding electric storage resources seeking to receive cost-based rate recovery for certain services while also receiving market-based revenues for providing market-based rate services.” According to FERC, the main issues around integrating storage relate to protecting cost-based ratepayers from the potential for double-recovery of costs, preventing adverse market impacts, and maintaining RTO and ISO independence from market participants.
Commissioner Cheryl LaFleur dissented against the policy statement, which was approved by former Chairman Norman Bay and former Commissioner Colette Honorable, saying she disagreed that the issue should be split off from a Notice of Proposed Rulemaking that FERC issued in November 2016.
Travis Kavulla, CREPC co-chair and Montana Public Utilities Commissioner, asked the panel how more “price discovery” could be incorporated into the modeling process. He said that storage has generally been implemented in two ways: as a “mandate backed up with technocratic guess-work shoved into the rate base,” or with ISOs designing products that let batteries compete in markets.
Tucson Electric Power’s Lee Alter said that IRPs covering all resources could discover pricing and compare different technologies, and that studying storage “jibes really well with the IRP process.” He said his utility is beginning to model energy storage, including sub-hour modeling that serves to study not just integration of batteries, but other impacts from the Western Energy Imbalance Market, pumped storage and other resources.
The discussion made clear that modeling the impacts of energy storage, identifying the benefits and turning energy storage services into a consistent revenue stream will be an ongoing challenge for utilities, regulators and other stakeholders.
While stakeholders are still deciding what topics MISO’s Energy Storage Task Force must take on to prepare the RTO for integrating a revolutionary technology, they must also recognize which are off-limits in order to avoid intruding on state jurisdiction.
The new task force has been charged with creating a list of detailed storage issues to be assigned to other MISO stakeholder groups. The RTO in August already floated its suggestions on how to dole out the work. (See Progress Builds for MISO Energy Storage Effort.)
Invenergy’s 31.5 MW Grand Ridge Energy Storage project | BYD
Invenergy’s John Fernandes, the task force’s chair, doesn’t want his group to simply provide MISO’s Steering Committee “a laundry list of issues and wish them luck.” That committee is responsible for assigning specific storage-related issues to other stakeholder committees.
“I don’t want to leave things open-ended,” Fernandes said during the group’s first conference call Oct. 16.
He said the task force should identify in what ways existing market rules might impede participation by storage resources, while also providing the committee with a recommended course of action. That would include helping to determine how to assign issues across committees and identifying which parts of the Tariff require revision.
Clarity from Complexity
The task force’s draft charter stipulates that the group consult storage experts to sort out issues that arise from market integration “that may introduce complexity to the footprint.”
MISO liaison Joe Gardner said the RTO’s goal for the task force is to identify possible near- and long-term changes and additions to market rules.
“Getting as much clarity and consensus now will behoove us in the long run … for planning, reliability and markets,” Gardner said. MISO has set aside funding to conduct storage-specific planning studies, he added.
However, stakeholders attending the task force meetings are at odds over the specifics of discussions.
Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that the task force should not interfere with state jurisdiction, saying stakeholders can explore whether MISO should create potential market products if states decide to allow aggregators to offer storage, but they should steer clear of deciding rules for interconnection.
“We have to have a discussion about what we can do within the law,” Ham said.
“I have no interest in treading on state jurisdiction,” Fernandes said, adding that the group will also steer clear of retail tariffs and distribution rules. “But the industry is going to force our hand,” he warned, predicting a future influx of storage participation that will require market rules.
Generation or Transmission?
Indianapolis Power and Light’s Lin Franks said the task force should be clear that it will not consider storage as it pertains to transmission planning, instead focusing on how to get it unfettered access to the wholesale market.
Fernandes responded that the group should not limit its consideration of possible storage benefits. “Storage as transmission is a very viable business model,” he said.
“Storage is not wires. It’s a substitute,” Franks countered.
Fernandes said storage-owning stakeholders have “been having the discussion with MISO on storage acting as wires” and the group should consider all storage, whether it functions as a generation or transmission asset.
“Storage as a transmission asset should be on the table … and very much front and center in MISO because it’s envisioned by FERC,” American Transmission Co.’s Bob McKee said. “FERC has already said storage should be recognized as transmission.”
MISO stakeholders also debated whether the group should only tackle grid-scale storage issues, leaving distributed energy resources unaffected. Fernandes said he had concerns with ignoring DER “considering it’s a grid-scale storage developer that signs my checks.”
The task force will meet again in late November to finalize a charter and agree on topics, while most of its substantive work will occur next year. Stakeholders will weigh in on the group’s draft charter through Nov. 3. The task force is slated to meet through the end of 2018, when stakeholders will determine whether the group will be retired or extended.
NRG Energy on Monday asked the California Energy Commission to suspend its review of a proposed 262-MW gas-fired plant in Oxnard, likely closing the book on a project that met with stiff resistance from community and environmental groups.
The company’s request came after Commissioners Janea Scott and Karen Douglas earlier this month issued what they acknowledged was an “unusual” notice recommending denial of the Puente Power Project. They wrote that it would be “inconsistent with several laws, ordinances, regulations or standards and will create significant unmitigable environmental effects.” (See CEC Members Recommend No-Go for Puente Plant.) The commission is responsible for issuing construction and operating permits for new generating plants.
Scott and Douglas, who together constituted the committee preparing the commission’s decision on Puente, said they made their recommendation so early in the process because they saw a need to study alternatives to the plant after CAISO filed comments contending that the economic feasibility of preferred — or non-emitting — resources could only be established through a new request for offers. While Southern California Edison selected Puente through a standard procurement process, CAISO pointed out that costs for preferred resources have since declined enough to warrant a new RFO. The ISO also noted that cost should not be the only factor driving the decision.
“An economically feasible option need not be the least expensive option, especially given the environmental and performance issues that are unique to each portfolio,” the ISO said.
The commission also received hundreds of comments opposing construction of the plant.
In its Oct. 16 filing with the commission, NRG said it is still considering whether to fully withdraw its application for certification (AFC) for Puente.
“Granting this motion [to suspend the proceedings] will ensure effective use of resources of the committee and the parties to these proceedings in the event that the applicant determines to withdraw the AFC,” NRG said.
The Puente plant would have been built on the site of the Mandalay Generating Station in Oxnard (shown), where NRG plans to shut down two existing steam turbine units to comply with California’s once-through cooling restrictions. | NRG
The company proposed to build the plant on the site of its Mandalay Generating Station, where it will shut down two existing gas-fired steam turbine units that don’t comply with California’s upcoming regulations restricting once-through cooling. About 2,000 MW of generation in the area is due to retire by 2020 because of the regulations.
The fast-ramping Puente plant would have been capable of reaching more than 95% of its capacity within 10 minutes, helping to integrate renewable resources and ensure reliability in the state’s Ventura/Moorpark subarea, a load pocket that imports much of its electricity through a single substation, the company has said.
The California Public Utilities Commission has already authorized SCE to enter into a long-term resource adequacy contract with the plant, which was slated to begin operating in 2020.
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.
I KCP&L
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. — 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.
| SPP
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.
| SPP
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.
