American Transmission Co. has agreed to pay a federal fine and undergo a year of monitoring after failing to properly report more than 60 agreements and transactions to FERC over the past 16 years.
Under an agreement reached with FERC’s Office of Enforcement, Milwaukee-based ATC will pay a civil penalty of $205,000 to the U.S. Treasury and submit semi-annual compliance monitoring reports for one year detailing any further violations (IN17-5).
ATC headquarters in Milwaukee | Mortenson Construction
The office found that ATC repeatedly failed to seek approval to merge or acquire FERC-jurisdictional facilities and to file “timely” contracts and agreements relating to rates and charges for jurisdictional service.
“Enforcement determined that, although ATC’s violations did not result in quantifiable market harm, they created a lack of transparency in the market by failing to have all of ATC’s jurisdictional agreements on file with the commission, and by consummating purchases of commission-jurisdictional assets without commission authorization,” the commission said.
In an internal review of its filing processes during 2014 and 2015, ATC discovered 63 instances in which it failed to either properly report or file information starting in 2001.
Those include several agreements that it failed to file pursuant to Federal Power Act obligations, relating to operations, transmission design on shared 345-kV projects, pole replacements, repairs on jointly owned substations, transmission line relocation and ownership, and cost-sharing for jurisdictional facilities. ATC in some cases also neglected to file notices to terminate existing agreements. The company has already paid $1.4 million to several affected parties in time-value refunds.
The company also identified 21 jurisdictional facilities it acquired without gaining FERC approval. The facilities range in value from $1,513 to $1.2 million. FERC retroactively approved each transaction after ATC sought permission between 2014 and 2015.
Section 203 of the FPA requires public utilities to file for FERC authorization to merge or acquire jurisdictional facilities, and Section 205 requires public utilities to file “all contracts which in any manner affect or relate to such [jurisdictional] rates, charges, classifications and services.”
FERC said that, since discovering the violations, ATC has taken steps to “strengthen its compliance policies and procedures and to prevent noncompliance in the future regarding jurisdictional agreements,” holding employee training seminars, updating training documents and developing an internal review process to make sure the company has proper authorization.
CARMEL, Ind. — Now that it has completed a seven-month evaluation of its existing system, MISO says it will provide a detailed decision on how it would rebuild its computer-based market platform in 2019.
The RTO’s near-term focus: to protect and extend the life of the existing market system while exploring and discussing upgrade options with vendors, according to MISO General Counsel Andre Porter.
MISO will present a business case for the making the upgrade at a Sept. 6 workshop on the status of the market platform. MISO’s Board of Directors in June urged RTO officials to provide stakeholders with upgrade details — and a plan — in order to solicit comments. (See MISO: $130M Needed for New Market Platform.)
“Stakeholder participation is critical for the market system enhancement program,” Porter said, urging stakeholders to bring questions to the workshop.
At an Aug. 24 meeting of the board’s Technology Committee, Director Baljit Dail praised the RTO’s stakeholder outreach, but stressed that it should make the upgrade information easier to understand.
MISO expects to select an upgrade option and confirm a vendor in 2019, with roll-out of the new platform targeted for no later than 2024. Officials plan to finalize a budget in October for the estimated $65 million needed to preserve the existing system for another five to seven years, while another $65 million would be allocated to build a new modular platform. The budget will also include a total contingency amount equating to up to 25% of the project cost.
Director Thomas Rainwater commended MISO for being able to finish the evaluation stage of the project on time. “We think that’s a bellwether of what’s to come,” he said.
“The progress you all have made is phenomenal, and you guys should be very proud of this. As a committee, we want this project to be successful. It has the potential for a huge payout,” Dail said, urging officials to provide frequent updates on the project.
As MISO completes the platform rebuild, officials will also explore the intellectual property rights of the software. A deeper discussion on possible copyrights was saved for a closed session of the Technology Committee.
The existing market system, designed by General Electric, was built from scratch in 2005 for $245 million. To incorporate the ancillary services market in 2009, MISO spent $75 million. It spent an additional $30 million to expand the platform upon integration of MISO South in 2013. In any given year, MISO invests about $6 million to $9 million in maintenance and improvement costs, Vice President of System Operations Todd Ramey said.
“The system we use today, and have used since the start of our markets in 2005, is really based on infrastructure used in the late 1990s. This system has started to show signs of its age,” Ramey said.
Several Market Roadmap design changes have been put on hold because of the aging infrastructure, Ramey said. MISO has growing concerns about security and, in some cases, market participants must use older versions of web browsers to view web pages.
ISO-NE and PJM also use GE-designed platforms. Both RTOs will undergo “common” upgrades using a staged approach in the next few years, said Jeff Bladen, MISO executive director of market design.
“In some respects, we’re catching up [with other RTOs], but we have a plan to go beyond what’s done today,” Bladen said during an Aug. 23 Advisory Committee meeting.
Ramey noted that MISO would eventually be forced to change to its platform because GE plans to phase out IT support for the aging software.
The computer overhaul will mostly affect MISO’s day-ahead market and Energy Management System programs. The RTO’s settlement software system is being rebuilt in a different project launched in 2014. The RTO is currently completing system testing and expects to launch the new settlements platform sometime in the fourth quarter, in time for the early spring 2018 roll-out of five-minute settlements.
VALLEY FORGE, Pa. — PJM and MISO staff provided updates on their proposed pro forma pseudo-tie agreements, the “freeze date” on transmission rights and targeted transmission upgrades at their Joint and Common Market meeting Aug. 22.
MISO’s Kevin Vannoy told stakeholders that FERC accepted the RTO’s pro forma pseudo-tie agreement Aug. 9 with an effective date of March 15, though it was approved in a delegated order and could be subject to further review and refunds now that the commission has a quorum (ER17-1061). (See FERC Conditionally OKs MISO’s Pseudo-tie Pro Forma.)
PJM’s pro forma agreement, filed on Aug. 11, awaits FERC approval. The grid operators filed revisions to their joint operating agreement to address PJM’s pro forma on Aug. 1.
The grid operators next plan to address the “congestion overlap” that is causing some congestion to be charged twice and has led to complaints at FERC. The issue, which occurs when an associated market-to-market constraint binds in both markets, will require a two-phase solution.
“It’s a complex solution” that can’t be done in a single implementation, PJM’s Tim Horger explained.
The first phase, which the grid operators hope to have implemented by Dec. 1, would include JOA changes to better model the impacts of firm-flow entitlements before the day-ahead dispatch is modeled. This will allow day-ahead LMPs for pseudo-tied resources to more accurately reflect expected real-time congestion. The balancing authority receiving the power will receive credit for the flow from the generation unit to the border, while the source balancing authority will model its impacts as loop flows.
“We think it’s a major step and will remove most of the overlap,” Horger said.
The second phase will allow for mitigating day-ahead charges either through refunds or virtual transactions to align transmission usage charges with available financial transmission rights hedges.
The RTOs plan to file JOA changes implementing market-to-market adjustments in September, with implementation of the phase one solution by the end of December. Dec. 1 is the target date for filing additional JOA and tariff changes. Phase two is scheduled for implementation by June 1, 2018.
The grid operators have been using an April 1, 2004, “freeze date” to determine firm rights on flowgates, but issues with that date have “become prominent” over time, the RTOs said. They have developed a two-phase alternative that would be in place by June 1, 2019, MISO’s Ron Arness explained.
The changes would affect designated network resources that came on after the freeze date, which currently are dispatched on a pro rata basis. The new rules would eliminate the pro rata allocation and have them dispatched in the order of their service date.
They also affect “freeze date” transmission service requests, which currently are treated as net imports or exports based on the local balancing authority. The new rules would provide “gross accounting” for imports and exports — generation-to-load LBA calculations would not include generation sourcing TSRs or load served by TSRs — with adjustments that will make the TSR sensitivity factors align with market flow sensitivity factors.
The RTOs plan to complete a whitepaper on the issue by next spring with implementation of phase one in the summer.
PJM’s Chuck Liebold said there has been no targeted market efficiency project (TMEP) study in 2017 because the RTOs are awaiting FERC approval of regional cost allocations for the new category. MISO filed for regional allocation Aug. 4 (ER17-2246), and PJM filed its allocation on April 11 (ER17-1406).
Commission staff tentatively approved the TMEP category in a delegated order in June but said the decision was subject to review by the commission once it regained the quorum it lost in February (ER17-721). (See FERC Tentatively OKs New MISO-PJM Project Type.)
The TMEP proposals are designed to be quick, inexpensive fixes to address historical congestion. Five projects have been identified so far. At an estimated cost of $17.5 million, they are expected to create $99.6 million in benefits.
The RTOs are waiting on FERC approval before submitting the project recommendations to their boards. The benefit allocation for three of the five projects leans heavily toward PJM, with 88% of the $7 million Burnham-Munster project, 89% of the $1 million Bayshore-Monroe project and 90% of the $4.6 million Michigan City-Bosserman project. MISO shoulders most of the allocation on the other two, with 59% of the $150,000 Reynolds-Magnetation project and 76% of the $4.5 million Roxana-Praxair line.
Two-Year System Plan Study
The RTOs have completed regional benefits analysis for the eight interregional projects that were proposed for the solicitation that ended Feb. 28. Only one project — Northern Indiana Public Service Co.’s proposed new line between its Thayer and Morrison 138-kV substations in northwestern Indiana — is expected to provide more benefits than costs. (See 1 of 8 MISO-PJM Proposals Pass Initial Test.)
Liebold said the cost-benefit was not the only factor in recommending projects, but “for a project to be promising, you would expect to see benefits above costs.”
The RTOs will make recommendations to their respective boards on the proposals around November or December.
CAISO is close to finalizing a long-running effort to reduce exceptional dispatch of generation to resolve transmission constraints and comply with reliability standards, but market participants have raised last-minute questions about the proposal.
During an Aug. 21 call on the Contingency Modeling Enhancements (CME) draft final proposal, some stakeholders said they wanted more detail about where CAISO would apply a proposed “preventative-corrective constraint” tool. But the ISO, which is preparing to present a final plan to the Board of Governors next month, said it has provided enough transparency.
CAISO kicked off the CME initiative three years ago to address a Western Electricity Coordinating Council reliability provision requiring grid operators to return a critical transmission path to its system operating limit within 30 minutes of a destabilizing event, such as the loss of a generator or transmission line. The ISO’s present approach to managing those contingencies relies on out-of-market interventions coupled with day-ahead market measures that procure a “bucket” of responsive capacity resources based on a flat megawatt rating of the line.
WECC has since retired that standard, but CAISO still needs to comply with NERC standards requiring a return to normal operations in 30-minute and four-hour time frames.
Under the proposal, resources contributing to restoring normal operations would receive both an energy payment and a payment for reserve “corrective capacity” set aside by the ISO, the cheapest way to provide needed generation if needed because of a contingency, CAISO says.
“The goal here is to reflect the real reliability constraint in the market,” said Perry Servedio, CAISO senior market design policy developer. “We believe the proposal improves transparency related to these constraints by improving the pricing and dispatch.” The latest version has “a hodgepodge of final tweaks to the policy.”
CAISO is Trying to Resolve Temporal Transmission System Reliability Constraints in its Market | CAISO
Southern California Edison had previously raised concerns over the complexity of the proposal, while Calpine and NRG Energy were supportive but said that the mechanism should allow participants to bid for corrective capacity. The ISO said that the proposal “fully captures and compensates” for capacity needed to meet any restraints on the system.
During the call, some stakeholders questioned why CAISO had not specified on which transmission paths the constraint tool would be applied. SCE said there is not enough transparency around how the paths would be selected, making it difficult to analyze the benefits.
For SCE, “the benefits are very limited. We don’t see any incremental benefit because you do have all the tools you have today,” Senior Project Manager Wei Zhou said. He added it will increase complexity in the market.
CAISO Principal George Angelidis responded that “I think we are getting bogged down in implementation details and we are missing the big picture here.” The fundamentals of the proposal have not changed, and it is “still a tool that will provide the ability to reduce constraints that are imposed by operators based on their judgement of system conditions,” he said.
“I don’t know why we are making a big issue on this trivial application change” of where the tool will be used, Angelidis said, adding that it would be used wherever it would provide a benefit.
Servedio said that “the selection criteria is: whatever we need to do to operate within our facility ratings.”
The grid operator is taking comment on the final draft proposal until Aug. 31.
CAISO has a separate and overlapping effort underway to resolve certain generator and transmission contingencies currently handled by out-of-market operations. (See Stakeholders Wary of CAISO Contingency Modeling.)
CARMEL, Ind. — A mid-July heat wave failed to drastically alter MISO’s monthly average load and energy price, stakeholders learned at an Aug. 22 Informational Forum.
July’s temperatures averaged near normal overall, MISO Executive Director of System Operations Renuka Chatterjee said.
Load averaged 87 GW during the month, up from an average 80 GW in June and “consistent with the summer weather conditions,” Chatterjee said. Load peaked for the year at 120.6 GW on July 20, close to last July’s peak. Day-ahead and real-time energy prices averaged $30/MWh and $31/MWh, comparable to a year ago, owing to natural gas prices that held steady below $3/MMBtu.
“Overall, this July was a typical summer month,” she said.
MISO experienced fewer forced outages this year but more planned outages when compared to last year. Forced generation outages decreased by about 3 GW from a year ago to about 11 GW, while planned outages were up 1 GW to about 6 GW. Real-time congestion stemming from forced outages led to “unanticipated higher prices” in MISO South on July 28, Chatterjee said.
| MISO
July boasted 2,277 GWh of total wind generation, a 7% decrease compared with last July. Meanwhile, MISO’s registered wind capacity increased from 15.9 GW to 16.8 GW year-to-year.
WILMINGTON, Del. — PJM and its Independent Market Monitor remain at odds over whether price-based offer updates should be connected to cost-based offers and specified in each unit’s fuel-cost policy.
At last week’s Markets and Reliability Committee meeting, PJM’s Lisa Morelli outlined the RTO’s planned Manual 11 revisions for implementing intraday offers. The presentation was the culmination of a long debate at August’s Market Implementation Committee meeting, where stakeholders pressed PJM and the Monitor to find as much common ground on the issue as possible. (See “Stakeholders Push PJM and IMM for Consensus on Intraday Offers Rules,” PJM Market Implementation Committee Briefs: Aug. 9, 2017.)
Morelli’s presentation outlined where PJM and the Monitor continue to differ on linking a unit’s price-based offer to its fuel-cost policy. The RTO believes there’s no need for them to be linked, but the Monitor says updating price-based offers should be limited to simultaneously updating cost-based offers, which must be specified in the unit’s fuel-cost policy.
“We think it’s the only way to ensure that the timing of price-based offers and cost-based offers don’t permit the exercise of market power,” Monitor Joe Bowring said. “What we’re concerned about is this will result in one-way optionality for the generators to raise prices during the day but not be required to reduce costs when gas costs go down.”
The two sides will continue to seek compromise until the September MRC meeting, but they will have to pursue separate Tariff revision proposals if they haven’t reached agreement by then, Morelli explained. It could come as a new problem statement for stakeholders to consider, she said.
On energy-offer verification, PJM and the Monitor also remain divided over whether self-certification by the curtailment service provider is sufficient validation for demand response. The Monitor says it is not.
“The main arbiter in this is really FERC,” PJM’s Rami Dirani said. “So FERC has to really decide whether this approach is actually the proper approach going forward.”
There is also some difference of opinion on the exception process for verifying offers that are not consistent with a unit’s fuel-cost policy, verifying offers over 1,000/MWh and verifying operating reserve credits for verified offers over $1,000/MWh, but PJM believes the two sides are moving toward a compromise.
Summer-only DR to be Studied
Stakeholders approved by acclamation a problem statement and issue charge regarding summer-only DR, but not before state and consumer representatives pushed for additional revisions.
The proposal came out of the Seasonal Capacity Resources Senior Task Force, which culminated in a seasonal resource aggregation filing and approval at FERC late last year, PJM’s Scott Baker explained. However, RTO staff pared the problem statement’s scope down to eliminate other seasonal resources, such as wind, hydro or energy efficiency.
John Farber with the Delaware Public Service Commission asked for a friendly amendment that specifically noted analyzing the load forecast would be in the scope of the group.
“One of the values of DR is to manage the peak. A managed peak costs less than one that’s not managed,” he said.
Greg Carmean, executive director of the Organization of PJM States Inc., noted the Energy Policy Act of 2005 stipulated that unnecessary barriers to DR participation in the markets be removed. “I haven’t seen where PJM has gone back and evaluated whether or not their annual product actually is a barrier to demand response,” he said.
Stu Bresler, PJM’s senior vice president of operations and markets, said that the RTO’s strategy paper on DR indicates how it intends to move forward on the issue. The problem statement identifies several items that are already considered out of scope, including loss-of-load expectation analysis; seasonal capacity procurement or developing a seasonal market; re-establishing non-Capacity Performance products such as base capacity; or limited DR.
The initiative is following through on the strategy paper’s list of goals. PJM’s Pete Langbein said the Demand Response Subcommittee will be working on those in sequential order.
“I think this problem statement is a continuation on working on valuing DR,” Baker said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said recent PJM rule changes have “hit hardest” on residential DR viability, “so this is great to see PJM taking these efforts.”
“The current construct is a barrier for residents to participate,” he said. He asked that PJM reconsider DR’s potential as a capacity product, but Baker declined to include the amendment.
PJM’s Ken Seiler provided some initial observations on PJM’s response to the Aug. 21 solar eclipse, saying the analysis will be used to better prepare for the 2024 eclipse, whose path of totality is expected to cross over PJM’s western edge.
Operationally, he said the RTO performed without incident. “We had enough regulation; we had enough reserves.”
About 2,200 MW of solar generation was lost, he said, but that remains largely an estimate as about three-quarters of it is behind-the-meter generation. Only about 500 MW was grid-connected and directly observable.
“The real surprise” came when operators saw CAISO and MISO curtailing units in expectation of lower demand, he said.
“We thought the load would be pretty much flat,” but PJM also saw a load drop similar to other grid operators, Seiler said. PJM had a load of about 133,600 MW about 1:45 p.m., which dropped to 129,500 MW an hour later.
| PJM
Weather likely accounted for some of the decline. Certain regions saw temperatures drop by up to 10 degrees Fahrenheit, which “does seem to correspond fairly significantly with the load drop,” he said. The weather forecast predicted temperatures in the 90s, but the average was around 85, he said. Additionally, unpredictable “pop-up” storms materialized in the footprint, which have a dampening effect on temperature.
“Certainly, wind and weather and cloud cover provided some level of impact,” he said.
However, human activity seemed to also play a major role. PJM found through discussions with the Nest home thermostat supplier that the company had advised customers that they could cut back on air conditioning during the eclipse to compensate for the reduction in solar output, resulting in a 750-MW drop in load.
Additionally, people departing from their normal business day to view the eclipse caused a reduction. PJM received reports that some manufacturing facilities delayed lunch and instead shut down during the eclipse.
Stakeholders Approve Misc. Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 11: Energy & Ancillary Services. Revisions, along with others associated with the Regional Transmission and Energy Scheduling Practices document, were developed as part of the implementation of Coordinated Transaction Scheduling, a new real-time energy scheduling product across the PJM-MISO interface.
Tariff and Operating Agreement revisions that clarify the two-year limit on requests for billing adjustments.
Joint operating agreement and Tariff revisions to develop a pro forma agreement for dynamic scheduling. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
VALLEY FORGE, Pa. — As PJM begins to define its overarching principles for assessing cost-containment guarantees in competitive bids for developing transmission projects, one is destined to remain contentious.
“A cost-cap commitment is only one factor considered by PJM in its overall review and evaluation of project proposals for selection in the [Regional Transmission Expansion Plan],” the RTO has said.
Some merchant transmission developers, such as LS Power, are pushing to have those commitments become a defining factor, while PJM transmission owners, such as ITC Holdings and Public Service Electric and Gas, have argued that other aspects should be given just as much weight. State and consumer representatives have also expressed support for giving increased weight to cost caps. (See Containment Policy: PJM Takes Up Cost Caps.)
Beyond being one of many factors considered in a project proposal, cost-cap provisions would be voluntary and limited to project construction costs. PJM’s Craig Glazer outlined the RTO’s other proposed principles last week at a special session of the Planning Committee on the topic. They include:
Clearly articulating the cost-cap commitment in the proposal submission, along with what is covered and any exclusions;
Providing proposed contractual language on covered and excluded items;
Ensuring that all cost-cap terms and conditions will be made public, while any information and part of the proposal inappropriately labeled as confidential will not be considered;
Supporting the rationale for any exclusions, with PJM evaluating the risk and potential cost impact of excluded events;
Providing quarterly progress updates, with cost-cap enforcement through FERC’s ratemaking process; and
Reserving for PJM’s Board of Managers the right to reconsider projects that aren’t making required progress and reassign completion to another developer.
“If the cost cap gets exceeded, I don’t want [PJM] to be the only entity that sues to enforce the DEA [designated entity agreement],” Glazer said. “The cost cap portion of the DEA … is really an agreement with FERC, an agreement with the ratepayers: Here’s what the project is going to cost.”
He explained that the legal process would likely require action from the developer to address the overages.
“The shoe would be on the developer’s foot to try to recover those costs,” he said. “PJM would provide an opinion on that subject, but we’re not central to that case. You’re not suing PJM for having violated the DEA.”
LS Power’s Sharon Segner said PJM was missing as an overarching principle that meaningful cost caps are preferable to cost estimates. When RTO staff hesitated to agree to that, she argued that additional clarity is needed in how proposals are being evaluated.
“If you go back to the original language in Order 1000 … there was specific instruction to the regions to disclose how proposals will be evaluated,” Segner said. “I think it’s reasonable to the development community for PJM to give general guidance on how it uses cost estimates versus cost caps in the evaluation process, and I think that is consistent with the mandate of Order 1000.”
“To simply make a bland statement that we value cost caps — and we do — it has no value,” PJM’s Steve Herling said. “The problem is the cost cap has 100 different parts, and depending upon how you structure those parts, you have a cost cap that’s valuable or a cost cap that’s completely meaningless. So for us to make a general statement that we value cost caps, it’s motherhood and apple pie, but it doesn’t actually tell you anything.”
“All I’ve heard so far was ‘meaningful cost caps’ or ‘valuable.’ … Propose [legal] language because we’re kind of at a loss as to what would be good here,” Glazer said.
“We’re comfortable with the fact that you’re considering cost caps,” ITC’s Brenda Prokop said. “We’re not comfortable with it being always the most important factor. We don’t think that’s appropriate.”
PSE&G’s Alex Stern agreed with that.
John Farber of the Delaware Public Service Commission urged patience in making any definitive decisions on the issue.
“Cost caps are a recent phenomenon, and it’s way too early in my opinion for PJM to be forced to make definitive statement as to the role cost-cap proposals would have in its evaluation,” Farber said. “I tend to agree with Sharon that legally binding cost caps could be superior to just cost estimates or desktop worksheets — but that doesn’t mean that they would be. I think PJM needs to gain experience with cost-cap proposals to understand how different terms have different effects.”
Glazer explained that part of PJM’s hesitation is how a proposal with a cost cap should be considered if it is substantially higher than a credible proposal with just a cost estimate. He described the cost cap in that situation as a “fig leaf” designed to attract positive consideration.
But Greg Poulos, the executive director of the Consumer Advocates of the PJM States, argued that giving caps deference doesn’t mean they have to be determinative in every situation. “I think there’s a big difference between the two,” he said.
The group has its next meeting scheduled for Sept. 8.
VALLEY FORGE, Pa. — With nine proposals to compare and four months left in the year, stakeholders appear to be eyeing the finish line of PJM’s yearlong effort to consider reforming its capacity construct.
Last August, a coalition of public power organizations, concerned that conversations about potential modifications to the RTO’s Reliability Pricing Model regarding the impact of state policies were taking place out of the PJM stakeholder process, began a campaign to win stakeholder approval to re-examine the RPM.
The Capacity Construct/Public Policy Senior Task Force (CCPPSTF) started meeting in March with a goal of filing with FERC by the end of the year any changes to the capacity market stakeholders agree to make.
That ambitious timeline has led the CCPPSTF to meet about twice a month and schedule six meetings in August alone. At the group’s fifth meeting for the month, stakeholders began to show signs of restlessness.
The Skinny Model
PJM’s Murty Bhavaraju explained additions to a model developed by RTO staff to compare nine capacity revision proposals using fictional and simplified numbers. PJM’s Dave Anders called it a “skinny model” because it’s designed to be shaved down to just the essential pieces to understand the mechanics of the proposals.
Adrien Ford of Old Dominion Electric Cooperative pressed RTO staff to make the model more representative of real-world conditions so that stakeholders can determine whether any of the nine proposals would work better than the existing process.
“I’m just hopeful that this skinny model is Step 1 in the analysis,” she said. “This doesn’t get me to the point where I understand whether we have an issue. … People are going to look at the numbers and the numbers aren’t realistic.”
PJM has resisted using historical numbers in the models because they will require incorporating a lot of assumptions that could drastically skew results, which stakeholders might incorrectly view as price forecasts. (See PJM Stakeholders Begin Defining Capacity Design Needs.)
Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked staff to develop some way to whittle down the options to compare.
“There’s still so many on the table, it makes it hard to think about where we’d go,” he said.
Panoply of Proposals
Another round of proposals received updates from their initial presentations based on feedback.
American Municipal Power filled in some blanks in its proposal, which would emphasize long-term bilateral contracts and reduce the significance of the forward-looking annual capacity auction to fill in whatever capacity obligations remain outstanding beyond the contracts.
AMP’s Steve Lieberman said the auction would be held between 12 and 18 months prior to the start of the delivery year, with a single Incremental Auction held 30 to 60 days ahead of the delivery year. Under the current construct, PJM holds Base Residual Auctions three years ahead of the delivery year, with IAs occurring annually after that until the delivery year.
AMP is also developing the idea of a secondary capacity exchange.
John Hyatt with Monitoring Analytics expanded on the Independent Market Monitor’s proposal to extend the existing minimum offer price rule (MOPR). Monitor Joe Bowring has long argued that competitive, pure markets are unable to accommodate subsidized bids; therefore such bids must not be allowed to influence auction results.
Jennifer Chen with the Natural Resource Defense Council provided additional context to the Sustainable FERC Project’s proposal, which would reduce the capacity requirement to the needs of the off-peak season and allow seasonal resources to account for the additional demand during the peak season.
Chen said her plan would use the BRA construct to procure always-ready Capacity Performance resources up to the needs of the off-peak season (i.e., winter needs for summer-peaking zones and vice versa), then allow the peak season to be addressed using what she termed a “seasonal CP product.” The plan would shift the variable resource requirement demand curve left, reducing the annual procurement to account for the reduced amount of CP resources procured.
The plan has no repricing mechanism to eliminate the influence of subsidized offers. Subsidies that only compensate for a desired attribute, such as carbon-free generation, would leave the generation unit free to offer into the BRA to be compensated for its contribution to resource adequacy. Units that receive a subsidy sufficient for full compensation would be treated like a contracted resource, and the load-serving entities contracting that source could opt out of a corresponding amount of its capacity obligation.
The proposal left stakeholders perplexed.
“I don’t get how it addresses [subsidized units’] impacts on the market,” said Carl Johnson, who represents the PJM Public Power Coalition. “I’m really confused about how mechanically this would do that.”
Chen said her reading of the task force’s charter was that the goal is to accommodate state actions to promote certain fuel types and that her proposal does that.
Johnson asked for Chen’s proposal to outline what it definitively commits to, but Lieberman defended the ability of the proposals to be flexible.
“To me that’s actually a positive that some of these proposals don’t seem so stuck to where they’re at” and are open to feedback and revisions, he said.
The task force is turning its focus to identifying appropriate polling questions and potential repricing triggers, but both efforts received stakeholder criticism.
ODEC’s Ford asked why staff wanted to develop polling questions rather than just determine the popularity of the nine proposals. PJM’s Anders, who is facilitating the group, said he believes the group’s final vote should be on the package’s relative popularity.
“I hear your point that it may not be ready to poll on the packages,” Ford said. A poll on various capacity construct components is “better than nothing,” she said, “but it would be better to poll the packages.”
Exelon’s Jason Barker asked why the task force was waiting to address the repricing triggers, as most proposals reference a trigger but fail to identify a specific mechanism. Anders said that since almost all of them are to be determined, the actual trigger can be determined later once the group has agreed on a plan.
Great Plains Energy has pulled back from its attempted acquisition of Westar Energy, recasting the move as a “merger of equals” after the two companies last week asked Kansas regulators for permission to merge under a tax-free share exchange.
The Kansas Corporation Commission blocked an earlier version of the deal in April, criticizing the $60/share purchase price as too high. (See Westar Shares Fall as Kansas Regulators Block Great Plains Deal.) Shareholders are poised to gain less in the new, stock-for-stock proposal.
| Great Plains and Westar
Under the new proposal, Great Plains would no longer become Westar’s parent company. Instead, the two companies would combine under a $14 billion holding company operating in Kansas and Missouri. Westar shareholders would own about 52.5% of the company with Great Plains shareholders holding the rest, according to the amended merger application (18-KCPE-095-MER).
The new deal would entail no cash exchange or transaction debt, and retail customers would receive $50 million in upfront bill credits across all rate jurisdictions. The combined company would serve about 1 million customers in Kansas and almost 600,000 customers in Missouri.
The two companies are expected to retain their original names after the merger, and Westar will continue to maintain an operating headquarters in Topeka, Kan., staffed by 500 employees. The companies have pledged not to lay off any employees. Corporate headquarters for the merged company would be located in Great Plains’ Kansas City, Mo., location.
The plan requires approval from both the KCC and the Missouri Public Service Commission. The companies will also file applications before FERC and the Nuclear Regulatory Commission as early as this week and will seek respective shareholder approval during the fourth quarter. If approved, the deal is expected to close in the first half of 2018.
The CEOs of both companies say the revised agreement represents savings for customers and an opportunity for long-term growth for shareholders, while better positioning the companies to invest in infrastructure.
“We carefully listened to the KCC’s concerns with our original transaction and crafted a new merger agreement using the KCC’s earlier order for guidance to bring better value to customers and shareholders of both utilities compared with remaining standalone,” said Great Plains CEO Terry Bassham.
Westar CEO Mark Ruelle called the merger “a long and unpredictable path” during a second-quarter earnings call in early August: “We spent a lot of time in May and June confirming that there wasn’t just a stop sign in the order, but also road map to approval. … It wasn’t the course on which we first set out, but I’m pleased where it’s taken us and encouraged by the value it creates for our customers and our shareholders. The KCC order was clear that a big premium deal was going to be problematic.”
Fewer Future Rate Cases
In testimony to support the filing, Ruelle said that without a merger, Westar’s “flat sales and rising costs” will translate into higher prices. Bassham testified along similar lines, saying that “costs to serve … customers will continue to rise unchecked” and absent a merger, Great Plains “would need to seek higher prices and more frequent price increases as the remedy for any unmitigated higher costs.”
Both CEOs claim the merger will lessen the need for future rate cases.
“With the merger savings, we’ll no longer be as dependent on rate cases to produce earnings,” Ruelle said during the earnings call.
In early August, Great Plains posted a second-quarter loss of $22.1 million ($0.10/share), while Westar announced earnings of $72 million ($0.50/share), in line with last year’s second-quarter results.
AUSTIN, Texas — With Hurricane Harvey rapidly gaining strength in the Gulf of Mexico and threatening the Lone Star State, ERCOT’s Technical Advisory Committee on Thursday focused on three tabled revision requests and appeals before quickly scattering to their homes and work.
“Be safe,” urged TAC Co-Chair Bob Helton, of Dynegy, as he adjourned the meeting.
Committee members did approve one of the three tabled issues, passing a nodal protocol revision request (NPRR768) after staff filed comments most could agree to. The NPRR was the subject of vigorous debate during the July TAC meeting but was passed this time with only Shell Energy and Sharyland Utilities abstaining. (See “EEA Price Adder Change Tabled,” ERCOT Technical Advisory Committee Briefs: July 27, 2017.)
The revision request adds real-time DC tie imports and exports through registered block load transfers to the list of ERCOT-initiated actions that trigger a price adder to ensure that prices reflect scarcity conditions.
Staff revised the language to cap the total adjustment for DC tie imports at 1,250 MW, the current capacity of all DC ties.
That was enough to placate the Texas Industrial Energy Consumers group, which has opposed the measure throughout the stakeholder process.
“We have a philosophical disagreement about whether this is appropriate,” said Katie Coleman, legal counsel for TIEC. “Rather than continue fighting about that, we got comfortable about moving this forward with a megawatt limit on it.”
Shell’s Greg Thurnher called the revised language a “nice compromise” and a “step in the right direction” to support scarcity pricing signals, but said he wasn’t sure “every adder is a good adder.”
“This one has a lot of fine print,” Thurnher said. “We’ve had some growth in traditional [DC ] ties that could be excluded for the circumstances it’s trying to prevent. We’ve arrived at the solution, but I’m not sure it’s a good one.”
NPRR768 does not address the Southern Cross Project, a proposed HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeastern markets. Several stakeholders agreed that is a discussion for a later date.
“When we wrote this, we tried to recognize what exists today,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “We don’t believe it’s biased toward anything. Our process allows the accommodation of whatever the future is going to be. This was our effort to put something forward to get to a compromise and recognize some of the concerns.”
Shell filed comments to ERCOT’s revisions, suggesting modifying the NPRR to restrict price correction to imports ordered on DC ties classified as transmission facilities. Cratylus Advisors’ Mark Bruce, speaking for Southern Cross, disagreed with the change.
“It seems pretty clear to us that once the Southern Cross project is interconnected to the ERCOT network, it will be a transmission element by definition, which means the definition of a transmission facility has to be amended to include it,” Bruce said. “Shell’s comments don’t really change anything. It actually opens it up and includes Southern Cross when it goes live.
“The ERCOT approach, on its face, is sort of less discriminatory. It doesn’t really start distinguishing between transmission facilities based on regulatory classification or ownership structure of the facility, which in our view isn’t a permissible way to go about this. In our view, this is either a good policy, [and] you put the megawatts in the calculation, or it’s not good policy, and you don’t.”
“Our intent was to impose a limit,” Thurnher responded. “The protocols get tricky when they define things. I think of Southern Cross as a load sometimes and a generator sometimes, neither of which are transmission assets. If Southern Cross gets built, then this needs to be revisited.”
Said Coleman, “We are intentionally leaving that for future discussion.”
CRR Deration Remanded Back to Subcommittee
The TAC unanimously remanded back to the Protocol Revision Subcommittee NPRR821, which failed to pass the committee in July after substantial discussion, to reconcile “three very different” modifications proposed by stakeholders.
The revision request would eliminate the reduction of congestion revenue rights (CRR) payments, or deration, by reversing the day-ahead market’s deration-settlement mechanism. The mechanism, which was introduced to deter market manipulation, has resulted in large financial losses to generators.
The deration price for a CRR path is determined at the constraint level and applied to the CRR payout. Payments can be derated if transmission elements are oversold, the target payment is a positive value, or the CRR source or sink is a resource node.
The Lower Colorado River Authority filed two proposed adjustments to NPRR821 following a $1.9 million loss in 2016 that it called “unusual and unique.” LCRA said it worked with ERCOT and others in attempting to find a balance between low impact and low implementation cost.
The company’s preferred solution was linking the CRR’s holder and the point-to-point (PTP) obligation of the qualified scheduling entity on the same path. It suggested linking the PTP price to the corresponding CRR value if a PTP obligation bid is awarded to a QSE with a CRR. If the CRR is derated, the PTP bid’s settlement price is matched to the CRR’s derated value.
The second option would cap the PTP’s value at the derated CRR’s value on the same path.
“It’s clear a lot of folks still have a learning curve with how this process works and the way the money flows,” said LCRA’s Randa Stephenson. “If it’s TAC’s will to send this back, please be ready to vote on this. This is going to be an issue that comes back to us.”
ERCOT staff agreed and volunteered to put together a presentation detailing all the proposed modifications.
“I just want to make sure everything’s clear,” Ögelman said, noting that LCRA’s proposal considers PTPs, not CRRs. “People need to look at all of these things to understand all of the mechanisms.”
DC Energy’s suggestion to add a “circuit-breaker” lowering the capacity offered in the CRR monthly auctions when the balancing account reaches zero at the end of any month drew positive feedback from several stakeholders.
“It’s a little bit more protection for our customers,” said Austin Energy’s Barksdale English.
Under DC Energy’s proposal, the CRR balancing account would be allowed to rebuild its value before reverting to the 90% capacity offering status quo.
Morgan Stanley offered the third proposal, which it said would “level the playing field” for all CRR participants by making short pays equivalent, regardless of the source or sink of the owned CRRs. Eliminating the current process — which covers hub and load zone CRRs and provides hedge value for those instruments involving resource nodes (well over half of these shortfalls) — would eliminate the expense created for load, the company said.
“There was a request to try and narrow the NPRR, and this narrows the application as far as you can get it,” said Morgan Stanley’s Clayton Greer, whose first preference was either the original NPRR or DC Energy’s proposal. “It actually eliminates all short-pay recoveries and hedge payments entirely. The retail segment argued that derate support was being done on the backs of load. If that’s the case, then all derate coverage would be on the backs of load.”
The Protocol Revision Subcommittee (PRS) plans to return with new language for NPRR821 in September.
Small Municipalities’ Appeal Tabled Again
The committee once again tabled the Small Public Power Group of Texas’ (SPPG) appeal of a rejected revision to the Nodal Operating Guide (NOGRR149) regarding the definition of transmission owners. In granting a six-month extension until February, the TAC agreed to take up the “substance of the appeal” at that time.
The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak load is less than 25 MW. The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads from 9 to 21 MW.
The SPPG has been filing monthly updates since the appeal was last tabled in January. In its most recent, the group said, “significant progress has been made” in reaching permanent market solutions for its members’ designated TO service, but they have not yet been achieved.
“All of these have been proceeding as hard and as fast as they can,” said Tom Anson, legal counsel for SPPG. “These things take more time than you think. We want another six months to keep working hard at it.”
The appeal has now been tabled eight times since it was first brought to the TAC in March 2016, shortly after it failed to pass the Reliability and Operations Subcommittee.
PRS Adds Resource Definition Task Force
The PRS brought forward two unopposed NPRRs and announced the formation of the Resource Definition Task Force. The task force, chaired by Vistra Energy’s David Ricketts and ERCOT’s Jay Teixeira, will work to synch up the ISO and Public Utility Commission of Texas’ definitions.
The TAC tabled NPRR829, one of two unopposed revision requests, to allow ERCOT time to refresh its initial impact statement. Staff said it believes the second impact statement, which should be complete for the next PRS meeting, will come in above the current $120,000 to $160,000 estimate to implement.
NPRR829 requires the use of telemetered data from non-modeled generation in the day-ahead market to more accurately calculate QSE collateral requirements. The change will increase day-ahead liquidity through the increased participation of non-modeled generation, and potentially allows ERCOT to gain near real-time transparency into the generation.
The committee unanimously approved NPRR836, which incorporates the following “other binding documents” into the protocols as a new Section 23 (Forms): Congestion Revenue Right Account Holder Application Form, Load Serving Entities Application Form, Managed Capacity Declaration Form, Market Participant Agency Agreement Form, Notice of Change of Information, QSE Agency Agreement Form, QSE Application Form, Qualified Scheduling Entity Acknowledgement, Resource Entity Registration Form, Transmission/Distribution Service Provider Registration Form and WAN Agreement.
Changes to these Section 23 forms will be made using the NPRR process.
