AUSTIN, Texas — The Public Utility Commission of Texas agreed Friday that Southwestern Public Service does not have the exclusive right to build transmission facilities in its service territory, signaling a final order will be considered at its next meeting.
The PUC’s decision was not the answer SPS was looking for when it filed a request asking the commission to determine whether Texas law includes a right of first refusal that overrides FERC Order 1000. (See Texas PUC Agrees to Take up SPP, SPS Request on ROFR.)
Wes Reeves, spokesman for SPS parent Xcel Energy, said the company “is disappointed with this ruling and will seek rehearing and appeal.” The PUC’s next meeting is scheduled Aug. 17 (Docket No. 46901).
SPS contends that the state’s Public Utility Regulatory Act (PURA) allows it, as the incumbent utility operating outside ERCOT, the ROFR to build in the service area prescribed by the PUC. That would prevent a potential competitive project under Order 1000.
The commission disagreed, sticking to its staff position that “an incumbent utility’s expertise in providing service within its certificated service area does not confer an exclusive legal right to construct transmission facilities within the utility’s certificated service area.”
Commissioner Ken Anderson offered little of his own reasoning but noted ERCOT’s Competitive Renewable Energy Zone (CREZ) project backed his position.
“The fact is, whether it’s CREZ lines or non-CREZ lines, we have transmission lines owned by different service providers inside and outside ERCOT that crisscross each other’s distribution service territory,” he said.
SPS filed a lawsuit in state district court in January, seeking approval to build the project and an injunction prohibiting SPP from issuing a notification-to-construct. The two parties agreed to suspend the proceeding to give the PUC an opportunity to decide how to interpret PURA.
Parties to See LP&L Contested Case After Aug. Meeting
All parties involved in Lubbock Power & Light’s planned migration of its load from SPP to ERCOT agreed they are ready to move on to a contested case, but not until after the PUC’s Aug. 17 meeting (Project No. 45633).
Commissioner Brandy Marty Marquez said the delay would give her and PUC staff more time to study data compiled by ERCOT and SPP in a joint study on the potential move’s financial and reliability impacts.
“Everybody’s ready to go but me,” said Marquez, requesting a hearing schedule be set at the commission’s next open meeting.
Anderson agreed, saying he hasn’t yet “completely digested” the studies.
“There’s a lot of good data in the SPP and ERCOT report,” he said. “It’s not brought together in [a] bottom line, but you can derive it with little work.”
The study indicated SPP would see small production cost decreases in all of its transmission zones except for SPS, which serves LP&L’s 430 MW of load in a contract that has been extended into 2021. ERCOT would see production cost increases but hopes to balance that out by unlocking wind energy in the Texas Panhandle. (See Lubbock Load Could Boost ERCOT Production Costs by $66M.)
LP&L has said it intends to complete a study similar in scope and scale to the grid operators’. It wants to begin the contested case in May 2018, allowing it to successfully integrate with ERCOT before its “bridge agreement” with SPS expires.
AUSTIN, Texas — ERCOT stakeholders last week tabled a proposal to eliminate the reduction of congestion revenue rights (CRR) payments — “deration,” in the ERCOT vernacular — after the measure failed to pass the Technical Advisory Committee.
The nodal protocol revision request (NPRR821) would reverse the deration-settlement mechanism, which was introduced to deter market manipulation but has resulted in large financial losses to generators.
Lower Colorado River Authority’s Randa Stephenson recalled when her company lost $2 million over three months because of a forced outage at one of its power plants. She said generators face downside risk because CRRs are settled in the day-ahead market, which sometimes doesn’t align with real-time outcomes.
“All the generators are trying to do here is the right thing,” said Stephenson, a former TAC chair. “We’re trying to hedge our congestion risk in the real-time, and we don’t feel like we can do that right now.”
The deration price for a CRR path is determined at the constraint level and applied to the CRR payout. CRR 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.
Stakeholders willing to eliminate CRR deration have expressed concern that NPRR821 unfairly changes allocations so that load will bear 100% of the risk associated with deration. Other participants countered that the shortfall is borne by CRR holders when a balancing account is exhausted and said the shortfall risk is not exclusive to load.
“We think the deration process that’s in place now is appropriate,” said Amanda Frazier of Luminant, the only generator to vote against eliminating CRR deration. “It’s a risk that can be managed. It allows for appropriate values of CRR on paths where we have unexpected outages that cause those paths to be oversold.”
TAC’s consumer and independent retail electric provider (REP) segments voted unanimously with Luminant against the measure, providing 10 of the 12 “no” votes. The 15 favorable votes were not enough to meet the required two-thirds threshold to approve the measure.
“The real issue is the risk itself is not changing … and you’re transferring the risk to load, instead of the market participants that are participating in the CRR auction,” said one REP representative, Read Comstock of Source Power & Gas. “I have sympathy for LCRA’s issue, but I’m assuming the price they offered considered that risk that existed. This same risk is going to be transferred to load with this NPRR change.”
“This NPRR is just like insurance. You overpay for insurance, and I think we’re going to wind up overpaying for the CRRs,” said Morgan Stanley’s Clayton Greer, who voted to eliminate deration. “Right now, we have hedges that don’t work when you need them. It’s like buying flood insurance that has an exemption for when it rains. Whenever the outages are taken, that’s when the congestion hits — and that’s when we actually need the coverage.”
Asked by stakeholders to weigh in, Beth Garza, the Independent Market Monitor, said she would leave the “very hard discussion” on money and value assessments to the TAC to decide.
“One of the aspects brought up in discussion that hasn’t been brought up today in the deration process is a way to manage potential manipulation,” Garza said. “I would argue it’s a very heavy-handed way to do that, and an unnecessary way to monitor for manipulative intervention in the CRR market. We don’t see a need for the current deration process.”
“This is very unique when it happens. It’s just the generators that get the derates and take the hit,” Stephenson said. “We’re trying to have a tool here that makes sense for us when we have these unique situations. It’s very hard to predict behavior if we’re going to have price blowouts on the upside, or CRRs get more expensive and give the load more money.”
Comstock urged stakeholders to remain engaged in the auction process. If not, he said, “we’re going to see CRR market participants push for more capacity to be sold at longer terms, because they’re not concerned about risk that exists if they are oversold.”
Stephenson, who was sitting in for John Dumas, the LCRA’s normal TAC representative, said she would bring back additional comments and math samples of the “unique situations” to provide a “deeper discussion” on the proposed change.
The motion to table passed by a 23-6 margin. Further discussions will take place at the Wholesale Market Subcommittee (WMS), and possibly the Qualified Scheduling Entity Managers Working Group, before returning to TAC.
“821 is getting rid of the entire deration process in order to fix a relatively small problem,” Frazier said. “There are very directed ways to address the LCRA issue. That’s an issue we are interested in trying to resolve as well.”
EEA Price Adder Change Tabled
The TAC also tabled for another meeting the only revision request that required significant discussion.
The Texas Industrial Energy Consumers has opposed NPRR768 throughout the stakeholder process. The NPRR would revise the categories of ERCOT-initiated actions, such as energy emergency alerts (EEAs), that trigger a real-time deployment adder so that prices reflect current system conditions.
“What ERCOT is really doing [when it calls DC tie imports] is replicating what a good market outcome would be,” said the TIEC’s legal counsel, Katie Coleman. “I know EEAs don’t happen often, but when they do, this could keep prices at the cap for significantly longer than they would be otherwise, and this is real money for my members.”
Referencing ERCOT’s systemwide offer cap of $9,000/MWh, Coleman said, “When you have an EEA in ERCOT and prices are at $9,000, everybody has every incentive to sell power into the ERCOT market.”
In her opening statement, Coleman also said the TIEC is concerned NPRR768 would apply to the Southern Cross Project, a proposed HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeast markets.
“When you’re talking about making a price adjustment for up to 2,000 MW of import, that starts to be real money,” she said.
In delaying action on the proposal in the past, stakeholders have noted the Southern Cross proposal was part of a recent docket before the Public Utility Commission of Texas (45624). In a resulting compliance docket (46304), the commission directed ERCOT to determine the project’s “appropriate” market participation classification, necessary transmission upgrades and cost allocations, and whether any price adjustments are necessary. (See “Southern Cross HVDC Project,” ERCOT Technical Advisory Committee Briefs.)
Coleman said that the commission did not direct ERCOT to take specific action on NPRR768 or similar proposals, and that the ISO’s decision to file the NPRR, rather than leave the issue to stakeholders, was concerning.
“It’s not necessarily an appropriate role for ERCOT to be filing things that increase prices for customers,” she said.
Frazier said Luminant, a participant in the Southern Cross litigation before the PUC, asserted a price correction would be needed if ERCOT curtailed DC ties for reliability reasons. As the Southern Cross DC tie would be a merchant tie, she said, there was little reason to be concerned about replicating market actions.
“[Southern Cross] will have those incentives to operate, so this is more of a backup position,” Frazer said. “Where if ERCOT is taking command and control over someone’s assets that would otherwise be doing something else — and they’re doing that to preserve the reliability of the ERCOT system — then there should be a price correction for that action, which is how we treat other reliability actions.”
“The problem is, the Southern Cross facility [is] not being built to facilitate market transactions in and out of ERCOT,” Coleman countered. “It’s being built to facilitate moving wind from SPP and Texas to regulated utilities in the Eastern Interconnection so they can fulfill renewable requirements.
“We’re concerned the incentives won’t be appropriate for people to sell into ERCOT, even when prices are $9,000.”
The WMS will be given the opportunity to weigh in before the discussion is scheduled to resume during August’s meeting.
TAC Approves 5 Revision Requests
The TAC approved two additional NPRRs, revisions to the load profiling guide (LPGRR) and the retail market guide, and a system change request (SCR):
NPRR822: Establishes the procedure for identifying resource nodes as an “other binding document” instead of a “business practice manual,” and adjusts the process for handling a retired resource’s nodes by allowing ERCOT to convert CRRs at that node to a different, nearby settlement point.
NPRR833: Adjusts NPRR827’s language to account for the steady state when ERCOT implements the long-term, automated change affecting point-to-point (PTP) obligation bid clearing. The NPRR updates the day-ahead market optimization engine to address situations where a contingency disconnects a resource node. The engine will pick up the PTP megawatts and distribute them to other nodes, instead of ignoring them in a contingency analysis if that PTP sources or sinks at the disconnected point.
LPGRR063: Clarifies the wording referring to the competitive retailer (CR) of record for certain profile type requests, and specifies only the CR of record may request certain profile assignments.
RMGRR149: Clarifies certain communications processes for electric service identifiers (ESI IDs) without a REP.
SCR792: Allows ERCOT to send the consecutive clock-minute average exceedances of Balancing Authority ACE Limit (BAAL) to the appropriate entities, and creates a situational awareness display in the information system’s public area that displays consecutive clock-minute average exceedances of BAAL.
DENVER — The SPP Board of Directors and Members Committee approved the Markets and Operations Policy Committee’s decision to allow the Z2, Export Pricing and Gas-Electric Coordination task forces to expire. (See related story, SPP Moves Ahead with ‘Tweaked’ Panhandle Congestion Study.)
Stakeholders also approved two recommendations from the Z2 Task Force. The first eliminated credits for non-capacity upgrades, such as substation facilities, while the second disposed of credits for short-term transmission service of less than a year.
The motion passed the Members Committee with two “no” votes (NextEra Energy Resources and Oklahoma Municipal Power Authority) and an abstention (ITC Holdings).
However, in nearly a year of work, the task force was unable to reach consensus on simplifying the vexing process spelled out in Attachment Z2 of SPP’s Tariff, in which financial credits and obligations are assigned for sponsored transmission upgrades. The group expressed “significant concern” over SPP’s existing congestion rights processes and the “perceived lack of hedging” but was unable to reach consensus on using incremental long-term congestion rights (ILTCRs) to replace Z2 credits.
“With respect to transparency, neither of these two changes does anything to move the ball forward,” said NextEra’s Aundrea Williams. “The vast majority of the task force agreed there was a better market solution out there but couldn’t support it. Perhaps when the TCR market is improved, that’s the time to look at the Z2 process.”
During the MOPC meeting last month, members learned staff would have to resettle nine years of historical Z2 credits and obligations because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
Unfazed by a nearly 50% cost increase, stakeholders reaffirmed their endorsement of the proposed $13.75 million seams project with Missouri-based Associated Electric Cooperative Inc. (AECI).
Golden Spread Electric Cooperative and Southwestern Public Service opposed the project, while NextEra and American Electric Power abstained.
The project involves installing a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield, Mo.
Nickell attributed the project’s increase to an increase in the amount of work needed to upgrade the 161-kV line. Staff’s cost-benefit re-evaluation of the project since last month’s MOPC meeting has shown SPP will still receive most of the benefits. (See “Staff to Review AECI Joint Project After Cost Increase,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
Based on the amount of unforeseen work, AECI has agreed to increase its share of the project’s cost to 10.9%, or $1.5 million. SPP will bear the remaining $12.25 million.
The project would be regionally funded, as it solves congestion issues on SPP’s side of the seam. It is contingent on reaching an agreement for compensating AECI, which will own the project and be responsible for its construction, operations and maintenance.
Previewing testimony he would deliver to a Congressional energy subcommittee the day after the board meeting, SPP CEO Nick Brown said he had a good story to tell. (See related story, RTOs to Congress: Don’t Lose Faith in Markets.)
“SPP is obviously one of the nation’s RTOs that has been successful in reliably implementing a significant amount of wind,” he said. “We have been very successful at reliable operations because of three specific actions we have taken over the last decade.”
Those actions, Brown said, included SPP’s $10 billion infrastructure build, deploying a day-ahead market for unit commitment and consolidating 18 balancing authorities into a single entity.
“Take any of the three away, and we would not be where we are today,” he said. “Make no mistake, we have been very successful because of the bold moves our members have taken over the last decade.”
Vote on FERC Nominees Possible in August
FERC’s Patrick Clarey said the U.S. Senate’s shrinking August recess may give the body time to act on nominees waiting to join the five-person commission, which currently consists of acting Chair Cheryl LaFleur.
Republicans Robert Powelson, a Pennsylvania commissioner, and Neil Chatterjee, energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), advanced out of the Senate Energy and Natural Resources Committee in June on the strength of 20-3 votes. A confirmation vote by the full Senate has not been scheduled, but it is on the executive calendar, Clarey said.
“There could be a vote any time,” he said.
The White House has said President Trump intends to nominate Republican attorney Kevin McIntyre as chair and Richard Glick, the Democrats’ general counsel for the committee, to fill the remaining two spots on the commission. (See Trump Names Energy Lawyer McIntyre as FERC Chair.)
However, McIntyre and Glick’s official paperwork has yet to be submitted, Clarey said.
FERC has been without a quorum since Chairman Norman Bay stepped down in February. Colette Honorable left the commission when her term expired June 30.
Oversight Panel Members to Serve as Liaisons with SPP Officers, Businesses
Oversight Committee Chair Joshua W. Martin III said the committee’s members will “establish ongoing contact” with SPP officers and staff and oversee defined areas of responsibility.
The liaisons are: Harry Skilton (internal audit), Phyllis Bernard (compliance), Graham Edwards (Market Monitoring Unit) and Bruce Scherr (security).
In another personnel-related action, Brown notified members that NextEra’s Williams, Duane Highley (Arkansas Electric Cooperative Corp.), Dave Osburn (Oklahoma Municipal Power Authority), David Hudson (SPS), Philip Crissup (Oklahoma Gas & Electric) and Jon Hansen (Omaha Public Power District) have all reached the end of their terms on the Members Committee. With the exception of Crissup and Hansen, all have chosen to run for re-election.
Consent Agenda Includes 8 Revision Requests
Members and the board unanimously approved a consent agenda that included eight revision requests and several other items:
MWG-RR185: Clarifies which SPP criteria document (Planning Criteria or Operating Criteria) is referenced when used in the market protocols and the Tariff’s Attachment AE, and directs users to the correct document.
MWG-RR82: Ensures combined cycle units avoiding outage deviation penalties and do not lose eligibility for start-up cost make-whole payments (MWPs) because of physical or environmental limitations. Adds a previously discussed increase in the MWPs’ grace period for commitments from one hour to two hours. The revision’s implementation date was scheduled for this August to allow SPP to complete development of software that allows market participants to register and submit separate offers for each of the combined cycle units’ multiple configurations.
MWG-RR222: Includes a multi-configuration combined cycle resource’s (MCR) committed and actual configuration for each interval in a bill determinant report, allowing MCRs to shadow the configuration SPP is using to settle these resources.
MWG-RR225: Cleans up confusing and misleading Tariff language on ILTCRs that could have construed ILTCRs as load-serving entities or non-LSEs.
MWG-RR226: Changes settlement location pairs that have potential for unconstrained flow to electrically equivalent settlement locations during the auction revenue rights process to comply with a FERC order (ER17-310). SPP will post the settlement locations before the annual ARR allocation process, along with the system topology and other data.
MWG-RR229: Satisfies FERC Order 831’s requirements on energy offer caps by using actual costs for MWPs on offers above $1,000/MWh. According to the order, costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used to calculate LMPs.
ORWG-RR228: Clarifies existing planning criteria language for system operating limits to reduce the potential of misinterpretation by entities complying with NERC reliability standards.
RTWG-RR233: Ensures that eligible network customers will not be billed twice for the same deliveries by not assessing charges against a specific use of an owner’s facilities that do not receive the benefit the charges provide to other transmission owners.
A request that FERC waive SPP rules to allow restating of settlement prices for TCRs at Omaha Public Power District’s Fort Calhoun nuclear plant site. The plant was retired Dec. 1, 2016, but incorrect modeling of shift factors from Dec. 1 to Dec. 14 resulted in the marginal congestion component being overstated and the TCR settlements sourcing at the location being understated.
DENVER — SPP’s on-again, off-again high-priority congestion study of the Texas and Oklahoma panhandles region is on once again following approval by the Board of Directors.
The study, ordered by the board in April to address historical congestion and frequently constrained areas (FCAs) in western Oklahoma and Texas caused by large amounts of wind energy, met pushback from the Markets and Operations Policy Committee three weeks ago. It was then revived with new direction by the Strategic Planning Committee later in that week. (See “Committee Gives Congestion Study New Life,” SPP Strategic Planning Committee Briefs: July 13, 2017.)
When SPP Vice President of Engineering Lanny Nickell presented a revised study scope to the board and members based on stakeholder feedback last week, he said he couldn’t recommend proceeding with the study.
“It’s to the point where the scope is so watered down now, I don’t think you’re going to get any value out of it,” Nickell said. “If you want to do a study, let’s do it right.”
Kelly Harrison, Westar Energy’s vice president of engineering, agreed, pushing for a more in-depth analysis that would provide that value to the market.
“If we could get some type of study to determine what it would take to move wind out of SPP — maybe to somebody who wants to buy that wind — it might send a price signal of what it would cost to move that wind with firm transmission,” he said. “Right now, [developers] don’t know what to pay. A longer study would give us a goal post and send a signal to the marketplace. We’re putting states in a bind with what I think is a pretty valuable resource.”
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Nickell suggested a compromise by “tweaking” the scope of the 2018 integrated transmission plan near-term (ITPNT) assessment currently underway to include a summer scenario that models large amounts of wind. Stakeholders have taken the model out of previous studies because of concerns of “too much wind in the model for a summer-peak condition,” he said.
“It may make sense to reassert that model and use it in the 2018 ITP near-term, if evaluated against other needs,” Nickell said.
“That satisfies me!” board Chair Jim Eckelberger said.
Stakeholders agreed using the 2018 ITPNT would produce more timely results and reduce the drain on staff resources already engaged in regular studies. Staff’s workload is sure to be exacerbated should the Mountain West Transmission Group integration proceed. The ITPNT study is to be completed no later than April 2018. (See SPP, Mountain West Members Get Acquainted.)
“I don’t want anyone to forget why this began,” said West Texas-based Golden Spread Electric Cooperative’s Mike Wise. “The genesis of this discussion is based on … endemic congestion north and south of [Southwestern Public Service] and the continuation of a FCA south of there.
“Find me a solution. That’s what I’ve been asking for … for 10 years. I’m waiting for when the congestion goes away,” he said. “One of your members here is crying out. Please, please, let’s get this FCA taken care of, and don’t forget us.”
The Members Committee endorsed the revised high-priority study 10-8, with two abstentions. The board also voted in favor of the new study approach.
Work to improve SPP’s transmission congestion rights market will continue in the Market Working Group.
Separately, the board and Members Committee approved the expiration of the Export Pricing Task Force, which was charged with evaluating “mechanisms to establish equitable and not unduly discriminatory prices” to ship electricity in and out of SPP’s footprint. The task force was unable to provide a recommendation to handle the RTO’s growing wind energy (23 GW in the interconnection queue and not in service).
“We determined there are no really good solutions. There’s no silver bullet, so to speak,” said Wise, the group’s chair. “We asked for views on potential solutions that doesn’t, in the end, have SPP consumers footing the bill. The consumers that benefit from this wind are going to need to pay for the transmission.”
That was before AEP’s announcement it would build a 2,000-MW wind farm in western Oklahoma and send the energy eastward. (See related story, AEP to Spend $4.5B on Largest Wind Farm in US.)
WILMINGTON, Del. — The Pennsylvania State Senate approved a tax on virtual transactions, moving the measure to the state’s House of Representatives, PJM CFO Suzanne Daugherty told the Markets and Reliability Committee on Thursday.
Senators passed the tax on a 26-24 vote as part of a larger budget-funding package that includes several other consumer and corporate taxes. The Senate bill is the latest in a series of funding proposals after Pennsylvania legislators approved a budget by their constitutional deadline on June 30 but failed to agree on how to fund it. However, the Senate Appropriations Committee officially booked $0 for the PJM tax.
The state’s interest in developing the tax came to light in mid-June, after PJM attempted to explain to Department of Revenue representatives the issues with levying a tax on RTO transactions. Daugherty alerted several PJM financial stakeholders, who launched their own advocacy efforts at the State Capitol, but ultimately blamed the RTO for not making them aware early enough to develop a comprehensive response. (See Traders: PJM Delay Could Mean Pa. Tax; RTO Denies Supporting Levy.) PJM remains opposed to any new taxes on its membership.
FirstEnergy’s Jim Benchek asked Daugherty about PJM’s plan to address the situation. She responded that the RTO will continue to watch the tax’s progress and that it’s “too early to see” how it might respond if the tax is implemented.
Stakeholders Question Focus on DR in Seasonal Capacity PS
While aggregation rules allowed a substantial amount of seasonal resources to clear the 2020/21 Base Residual Auction as annual products, thousands of megawatts of such resources that have cleared past auctions didn’t this time around. To address those situations, PJM is proposing a problem statement and issue charge, which received a first read last week.
However, stakeholders questioned the limitations PJM put on the scope of the analysis. The issue charge focuses on “the impact of peak-shaving resources on the load forecast” and exploring “non-capacity wholesale market mechanisms to value demand response resource flexibility.”
“I struggle with why you’re limiting this to nonmarket issues,” said John Farber of the Delaware Public Service Commission.
Farber argued that adding market opportunities would spur innovation “so all stakeholders could get the benefit of managing that peak.”
Several stakeholders, including American Municipal Power’s Ed Tatum and Carl Johnson representing the PJM Public Power Coalition, asked why the documents focused on DR.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said his members are concerned about opportunities for residential customers, which he said have been “significantly limited” in recent years.
Organization of PJM States Inc. Executive Director Greg Carmean asked that PJM’s education on the topic explain how the RTO came to develop the products it currently has and the impact of important legal decisions, such as FERC v. EPSA.
Tom Rutigliano, who consults with several energy management companies, requested that the analysis not be precluded from providing preliminary recommendations available for the next BRA in May 2018, despite a stated timeline that would provide results late next year.
PJM’s Pete Langbein, who is overseeing the proposal, said he is open to any suggested changes.
“We’re trying to be realistic about what it’s going to take and not be overly aggressive,” he said about the timeline.
Jim Jablonski announced he has retired as the executive director of the Public Power Authority of New Jersey. Jablonski, a former chair of the Members Committee, said it was a “pleasure and an honor” and a “humbling experience” to be involved in the PJM stakeholder process over the past decade.
He said some of the hardest issues he dealt with included the development of the minimum offer price rule and the Capacity Performance construct.
“It was a reaction to an anomalous event that may never, ever happen again, and we made these broad, sweeping changes to the capacity market that only increased costs to customers.”
He said that while he agrees with the need for reliability, the people paying the bills need to be considered.
“I still am concerned about cost to customers,” he said. “It seemed like every time we turned around here, we were raising costs to customers.”
He has no immediate plans following retirement, but given his broadcasting background, he may consider media opportunities involved with PJM. He said he joked with PJM’s Stu Bresler about starting a 24-hour PJM TV channel.
Brian Vayda, a former PJM employee, is succeeding Jablonski as executive director.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 1: Control Center and Data Exchange Requirements. Revisions developed to comply with NERC reporting requirements. Transmission operators will be required to maintain certain data during outages, including bus voltages for all 345-kV substations or higher and megawatt flows for all tie lines and all lines 345 kV or higher.
Manual 11: Energy and Ancillary Services and Manual 18: PJM Capacity Market. Clarifies language on what is needed to qualify for exempt or bonus megawatts during performance assessment hours in Capacity Performance. PJM says it needs certain data to determine how close generators follow its schedule. The data include values for economic minimum and maximum and emergency maximum.
Pseudo-tie pro formaagreement and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See “OC Discusses Pro Forma Agreements for Pseudo-Ties, Dynamic Schedules,” PJM OC Briefs: July 11, 2017.)
Manual 14B: PJM Regional Transmission Process and Operating Agreement revisions. Redesigns to the Transmission Expansion Advisory Committee reflecting the change from the annual, 12-month Regional Transmission Expansion Plan cycle to an overlapping 18-month cycle beginning each September. The window for short-term projects will expand from 30 to 60 days. (See “RTEP Cycle Revisions Approved,” PJM PC/TEAC Briefs: July 13, 2017.)
An endorsement vote on Tariff and Operating Agreement revisions to clarify the two-year limit on requests for billing adjustments was postponed to a later meeting.
Members Committee
Stakeholders Endorse Consent Agenda
Stakeholders endorsed by acclamation the committee’s consent agenda along with several other Operating Agreement and Tariff changes:
Pseudo-tie agreements and Tariff and Operating Agreement revisions. The documents were developed to standardize pseudo-ties and minimize operating confusion. (See MRC item 3 above.) Eighteen members opposed and six abstained.
Stakeholders Endorse Regulation Changes Despite Continued Opposition
Stakeholders endorsed Tariff and Operating Agreement revisions to regulation market rules on performance scores, clearing and settlements that were previously endorsed by the Regulation Market Issues Senior Task Force and the MRC. The revisions change the rate for substituting traditional RegA and fast-response RegD. (See PJM Regulation Compensation Changes Cleared over Opposition.)
John Horstmann of Dayton Power and Light reiterated his past objection to the changes, which he said don’t provide a sufficient transition period for the energy storage units developed for the original 15-minute neutrality requirement. However, the measured passed handily with 4.24 in favor out of 5 in a sector-weighted vote. Such votes require an approval of 3.33 (66.7%).
DENVER — The SPP Regional State Committee unanimously agreed last week with its Cost Allocation Working Group to leave the aggregate study’s safe harbor cost limit unchanged at $180,000/MW.
The study assesses which projects are necessary to satisfy transmission service requests (TSRs) to move energy around the SPP system, as well as who pays for those projects. Transmission upgrades under the safe harbor limit are base-plan funded through the RTO’s highway/byway approach.
The safe harbor is applied when the aggregate study’s waiver criteria are met:
The utility does not have more than 20% of its designated resources (used to meet a load-serving entity’s capacity margin requirement) come from wind energy when the TSR is granted.
It has a five-year minimum commitment term for the TSR.
The utility does not have designated resources greater than 125% of its forecasted load when the TSR is granted.
SPP has not recommended a change to the safe harbor amount since it was first established in 2005. Staff does file an annual letter at FERC (ER05-652), testifying as to whether the amount is correct.
Adam McKinnie, chief regulatory economist with the Missouri Public Service Commission and the CAWG’s chair, said an annual limited review of the safe harbor could include a discussion of the FERC letter and the methodology behind SPP’s recommendation on whether to change the amount.
CAWG members, staff and stakeholders have been discussing the correct methodology for calculating the limit. No consensus has been reached, but the discussions continue, McKinnie said.
The RSC also agreed with the CAWG to review the base-plan funding eligibility criteria and the safe harbor limit on an annual basis, with in-depth review at least once every five years. Both votes were unanimous.
The group just spent two years conducting the first review of the safe harbor waiver criteria. McKinnie estimated it would take nine to 12 months to conduct intensive reviews of safe harbor issues in the future, while a limited review could be done during a quarter and focus on issues of interest to the RSC or stakeholders.
“Frankly, we don’t want this to be our full-time job,” John Krajweski, a consultant with the Nebraska Power Review Board, told the RSC.
The Kansas Corporation Commission’s Shari Feist Albrecht agreed, saying, “The motion provides sufficient flexibility and doesn’t impede the RSC’s ability to request a study.”
SPP Wind Capacity Nears 17 GW
Bruce Rew, SPP’s vice president of operations, said the RTO is continuing to successfully integrate large amounts of wind energy.
The RTO currently has 16,280 MW of installed and operational wind capacity, with another 100 MW of wind registered but not yet operational. It expects another 5 GW to become operational before production tax credits expire in 2020, and it has another 18 GW in its interconnection queue.
SPP set a record for North American RTOs in April when it recorded a 54.47% wind penetration level. Rew noted SPP had not seen wind penetration levels of 40% until last Christmas. It exceeded 40% for seven days in the first quarter, and another seven days in April.
SPP’s Integrated Marketplace currently has 191 market participants, up from 172 a year ago, with 125 classified as financial-only and 66 as asset-owning. Rew said the RTO lost a financial-only entity during the second quarter.
The RTO’s balancing authority has successfully maintained NERC control performance standards while maintaining high system availability, he said. The day-ahead market’s posting has not been delayed during the last year, Rew said, and the real-time balancing market has successfully solved 99.95% of all intervals.
Interested Observers: Colorado’s PUC
Colorado Public Utilities Commission Chairman Jeff Ackermann and Commissioners Frances Koncilja and Wendy Moser were guests of honor and given front-row seats for the July 24 RSC discussion.
SPP CEO Nick Brown welcomed the commissioners, along with the new members of the RSC.
“It’s always been a strategy for SPP, and one we identify every strategic cycle, to maintain and establish a good relationship between staff and the RSC,” Brown said. “We’ve recognized for more than a decade how important it is to get you engaged in the process.”
The Colorado PUC will be among the bodies passing regulatory judgment on the Mountain West Transmission Group’s potential membership in SPP. The commission has held two public information sessions on the merger and has scheduled a third for Aug. 24. (See SPP, Peak Reliability Pitch RC Services for Mountain West.)
“The [Mountain West] expansion is an important decision, not only for the 10 members of the Mountain West, but for SPP as a whole,” Brown said. “We encourage you to stay engaged.”
DENVER — SPP stakeholders made another effort to revise the RTO’s transmission-zone placement process last week, but once again came up short when the Board of Directors sustained its earlier rejection.
The revision request’s (RR172) defeat likely means future disputes over cost shifts caused by SPP’s zonal-placement decisions will be resolved through litigation.
“I’m not sure about next steps, but you can be sure it will be argued about at FERC in both current dockets and future dockets,” Kansas City Power & Light’s Denise Buffington told RTO Insider.
Several cases involving cost shifts are currently before FERC (ER12-959, ER16-204 and ER17-2020). Another (ER15-1499) has been settled between KCP&L and the City of Independence, Mo., and the terms are being phased in. After KCP&L objected to Independence being placed in its zone, the parties agree to phase in the city’s annual transmission revenue requirement in three tranches ($3 million for June 2015-December 2016, $3.5 million for 2017 and $5 million for January 2018-May 2019).
Buffington has been the driving force behind RR172 for more than a year. She says there is a gap in SPP’s process for placing applicant transmission owners (ATOs) in existing zones. Staff currently determine which of 18 transmission pricing zones to place new TOs, which can result in cost shifts for those in the incumbent zone.
“When SPP provides analysis to an impacted zone, SPP specifically states which zone the new TO comes into,” Buffington said. “One of the issues in litigation is whether or not SPP should even make that decision. SPP has argued in litigation that that’s within their scope and is their responsibility.”
Buffington said she revised RR172 to incorporate that concept, saying it mitigates the costs of zonal-placement decisions and protects both existing and new customers from cost shifts by capping cost shifts for legacy facilities at 2% of the annual transmission revenue requirement or $1 million, and creating an 18-month period without cost shifts for the facilities following integration. It also would have provided an exclusion for legacy facilities that were jointly planned for the benefit of all customers in the zone.
“We’re trying to isolate the cost of legacy facilities built outside the SPP planning process,” Buffington said. “We want the board to give us some guidance on the policy. We feel we need some bookends around the cost structure, to help both existing and new members.”
The revision had been through nine in-depth discussions in three stakeholder groups. Three weeks ago, it was rejected following a contentious discussion at the Markets and Operations Policy Committee, setting the stage for last week’s appeal. (See Divide Evident Between SPP Tx Owners, Users.)
Public power entities led the opposition to RR172. Dave Osburn, general manager of the Oklahoma Municipal Power Authority, was among those signing a letter that was submitted four days before the board meeting. The letter, co-signed by Golden Spread Electric Cooperative and Northeast Texas Electric Cooperative, charged “KCP&L has been transparent that the RR172 process, and the expected failure, is simply a prerequisite” to a Section 206 complaint at FERC.
“One of the concerns we have on this is as a transmission-dependent utility we should be careful to not approve something that keeps the smaller entities from building transmission and getting cost recovery,” Osburn said during the discussion. “We’ve been paying a load-ratio share of transmission customers for quite a while. Some assets in existing transmission zones may not benefit all customers either, but we pay our load-ratio share regardless. The money we pay is just as important as the TOs’.”
“This is an additional burden for a new ATO. They are going to have to present a lot of data people haven’t in the past,” said NTEC Vice President Jason Atwood. “It concerns me we’re always talking about expanding the footprint. The concern about something like this is it could impact the expansion.”
Nebraska Public Power District’s Paul Malone, whose company is involved in one of the FERC dockets, wondered aloud whether there was an ulterior motive to the current zonal-placement process.
“Costs shifts are not a one-time issue. They come back year after year,” Malone said. “Are the new members joining because they expect someone else to pay for their system? Is that the windfall to entice them to join? I hope not.”
“We’re all trying to do the right thing for our customers. They’re the ones impacted by these cost shifts,” Buffington said. “Nothing in this proposal is intended to prevent entities from collecting the revenue requirement. It’s all about which customers pay.”
The Members Committee approved RR172 by an 11-9 vote. However, the board voted against the motion.
Midwest Energy’s Bill Dowling was among those supporting RR172, though he was reluctant to change the Tariff language.
“That gives us the flexibility to continue to adjust the process, especially when some of the issues around cost mitigation and cost shifts are still in flux,” he said. “It’s been an issue, and it continues to be an issue.”
“It’s not the end of the story,” SPP Board Chair Jim Eckelberger said. “There was a suggestion to let some time pass and see what we learn from it. That may be one answer to it, but sooner or later, if nothing is forthcoming and the problem still exists — and I think it’s a problem — we’ll have to assign the problem to someone.”
“We’ll continue to work with the stakeholders to find a path forward,” Buffington said. “I don’t know if that will be in a FERC proceeding or through the stakeholder process, but we’ll do some work on that.”
The board did approve a four-step communications process for SPP staff to follow in making zonal placement decisions. The Transmission Owner Zonal Placement Process document addresses the growth of transmission zones in SPP’s footprint and concerns expressed over the process in FERC proceedings. (See “SPC Approves Zonal Placement Process Document,” SPP Strategic Planning Committee Briefs: July 13, 2017.)
However, Buffington found little solace in the document’s passage.
“The process document does not solve any of the underlying issues,” she said, referring to her concerns about a lack of notice and transparency. “SPP has used informal criteria to determine which zone to place a new entity in. They’ve never included cost impacts in their solution. The process lacks transparency and harms existing customers.”
Arkansas Electric Cooperative Corp. CEO Duane Highley reminded the board and members that his company’s long-time stakeholder representative, the recently retired Ricky Bittle, always believed SPP should consist of one zone.
“Maybe the time for Ricky’s dream has come,” SPP Director Phyllis Bernard said. “It seems the difficulty of this whole issue, trying to talk through it and work it out, has seemed to be intractable. It seems to take up so much resources, good will, time and results that no one is satisfied with it. A [single postage-stamp] rate is a worthy goal to work towards.”
MISO’s Steering Committee last week declined to reconsider a stakeholder proposal that would allow funders of transmission upgrades for lines under 345 kV to recover some of their costs through the RTO’s allocation process.
Wind developer EDF Renewable Energy and nonprofit Wind on the Wires approached the committee during a July 26 conference call to insist again that costs for customer-funded upgrades be categorized as “non-[MISO Transmission Expansion Plan] upgrades,” a project type they said would address “chronic congestion on existing transmission elements that do not meet the criteria for market efficiency projects or multi-value projects.”
EDF’s Great Western Wind Project in Oklahoma | EDF
Under MISO’s current rules, only upgrades on lines 345 kV or above qualify as market efficiency projects.
The call marked the second time the issue had come before the Steering Committee, which had previously assigned the issue to MISO’s Regional Expansion Criteria and Benefits Working Group (RECBWG) in the spring. EDF representatives argued that the issue wasn’t given a fair hearing and was dismissed too quickly, and asked the committee to direct the RECBWG to re-examine the issue.
Xcel Energy’s Carolyn Wetterlin, chair of the RECBWG, said the working group generally agreed that “if a market participant chose to fund [an upgrade], they should have done it without an expectation of future reimbursement.” Stakeholders participating in the working group voted against taking up the proposal, which some attributed to buyer’s remorse after EDF voluntarily decided to upgrade the MISO grid but did not receive the expected benefits.
According to Wetterlin, RECBWG members pointed out that customer-funded upgrades are performed outside the MTEP. As such, they aren’t subject to the RTO’s transparent standards for determining whether a project is the most efficient solution for solving the transmission issue.
The RECBWG concluded that the issue is still not worth pursuing, Wetterlin said.
The ‘but for’ Principle
“We think there’s need for a deeper discussion at the RECBWG,” Wind on the Wire’s Natalie McIntire countered.
EDF argued that its simple cost reimbursement would only apply to new customers that could not have been granted new service by MISO “but for” the customer-funded upgrade.
“We’re trying to get some compensation when new users come on the grid,” said Bruce Grabow, an attorney representing EDF. “This wouldn’t be a full-blown cost recovery … it’s just a reimbursement of a portion of installed costs if the next customer coming down the pike couldn’t get network service but for the network upgrade.”
New interconnection customers can currently enter the grid and reduce some of the benefit that the original funders of the project had expected, as MISO grants non-firm usage rights to the customers that paid for the upgrades, he said.
Grabow said the poor financial benefits of market participant-funded projects are evident: No such projects were brought forward in MISO’s transmission plans from 2014 to 2016.
“This occurred notwithstanding known congestion on voltages below 345 kV. Participants see the need but are not utilizing this avenue because of the lack of reimbursement and/or retained benefit,” EDF and Wind on the Wires said in a joint presentation.
‘Devastating’ Rate Shocks
Indianapolis Power and Light’s Lin Franks said that “having after-the-fact cost allocation would seriously complicate” MISO’s planning processes.
“It could cause rate shocks that could be quite devastating,” Franks said, adding that customer-funded upgrades are “just the way the world works,” with customers accepting the risks of funding their own upgrades. She noted that transmission rates cover the cost of using existing upgrades on the system.
NRG Energy’s Tia Elliott said that the stakeholder process was not necessarily flawed even if EDF and Wind on the Wires did not receive the stakeholder response that they wanted from their proposal. ITC Holdings’ Cynthia Crane, who attended the RECBWG meetings, said she thought the issue was “properly vetted” at the RECBWG.
Elliott pointed out that the Steering Committee’s decision does not preclude the two companies from approaching the Advisory Committee with its proposal. And the two companies could always file a complaint at the FERC level, according to We Energies’ Tony Jankowski.
Participant-funded transmission projects have always been excluded from MISO’s cost allocation procedures, while projects not eligible for allocation can be recovered through a zonal transmission rate. The RTO is considering changes to its cost allocation rules — which have not been altered since the integration of MISO South in 2013 — especially given that Entergy’s integration transition period, which limits cost sharing in MISO South, expires next year. The RTO has said that it may lower the 345-kV threshold on market efficiency projects. (See MISO Stakeholders Debate Postage Stamp Cost Allocation.)
FOLSOM, Calif. — The CAISO Board of Governors last week greenlit new rules that allow the grid operator to constrain the operations of gas plants across the state and the Western Energy Imbalance Market (EIM), part of a package of initiatives drawn up in response to the loss of the Aliso Canyon storage facility.
The board unanimously approved the new market rules in a 5-0 vote, as the broader public discussion over Aliso Canyon intensified.
CAISO Director of Market and Infrastructure Policy Greg Cook explained to the board that there are still operational risks around the loss of Aliso Canyon. The gas constraint tool is limited to use for physical constraints on the grid, not to manage economic conditions.
“There is potential for similar types of physical gas constraints elsewhere outside of Southern California, and our operators have found that this is a valuable tool” to maintain electric and gas system reliability, Cook said.
CAISO asked the board to approve extending some temporary provisions and make others permanent as it develops a new long-term suite of market rules in its Commitment Cost and Default Energy Bid Enhancements (CCDEBE) proceeding, expected to be implemented in fall 2018.
The EIM Governing Body previously approved elements of the Aliso Canyon Gas-Electric Coordination Phase 3 proposal. (See EIM Leaders Endorse CAISO Gas Constraint Measure.) CAISO will submit the rules to FERC for approval.
The board’s approval extended a temporary rule that the day-ahead market gas price index use information published every morning to better reflect gas costs, and requires a scalar to be included for the next-day gas index to account for tight gas conditions in Southern California and higher gas costs.
Cook said he hasn’t seen much need for gas constraints in Southern California in the past year, but the ability to use the scalar would be there if unforeseen events happen.
Also approved was a right for gas generators to file for after-the-fact cost recovery of energy costs if units are mitigated down to their default energy bid.
Stakeholders generally support the gas constraint tool but do not want it to replace or affect the package of bidding rule changes being developed in the CCDEBE proceeding. Representatives from NRG Energy and Pacific Gas and Electric said there are concerns about the package but were generally supportive. But many stakeholders have commented that there are broader problems that must be adequately addressed in the CCDEBE proceeding. The Western Power Trading Forum did not support use of the gas constraint tool unless the scalar is retained.
CAISO’s Department of Market Monitoring had expressed concerns about the Phase 3 proposal, but its concerns have been addressed, including an eventual automation of the process whereby constrained transmission paths are deemed uncompetitive and constraints are implemented.
NRG Director of Regulatory Affairs Brian Theaker told the board that his company originally opposed the Aliso Canyon mitigation procedures because it distracts attention from CCDEBE and “long-standing problems with regards to the ISO bidding structure.” Suppliers cannot reflect gas procurement costs in bids and could not recover those costs, he said.
The company’s opposition has been “tempered a little bit” because of process on CCDEBE, he said. “CCDEBE is a long way off,” and the company supports extending the Aliso Canyon measures.
FOLSOM, Calif. — The CAISO Board of Governors last week approved a set of market rules designed to aid the integration of distributed energy resources and transmission-connected energy storage into the ISO’s markets.
ISO staff closely consulted with market participants over the past year to develop the Energy Storage and Distributed Energy Resources (ESDER) Phase 2 proposal in response to the growing volume of distributed resources in California. The board’s approval of the measure sends the rules to FERC for a new round of comments and review.
DER developers such as energy storage companies are aggressively moving into an area that is seen as increasingly important and profitable — balancing renewables and addressing California’s “duck curve,” which graphically describes the impact of the variable output of solar generation on the ISO grid at different times of the day. (See Report: Calif. ‘Duck Curve’ Growing Faster than Expected.)
CAISO CEO Steve Berberich told the board that ESDER Phase 2 is part of a broader strategy to accommodate emerging technologies, including demand response, storage and other new types of systems that might be coming to the grid.
“We think that leveraging them is going to be critical to how we manage the grid, and help decarbonize the grid as well,” Berberich said. He added that “we are committed to continue to work with all those that provide these services,” and with the California Public Utilities Commission.
Storage makes up 20% of the resources in CAISO’s interconnection queue, which contains 325 projects totaling 58,000 MW, according to the grid operator. Renewables represent 68% of the generation waiting to interconnect, while conventional resources account for 9%.
Beyond 10-in-10
As part of ESDER, the board approved a set of alternative energy usage baselines to assess the performance of proxy demand resources, which are DER aggregations of retail customers. It also approved new rules that distinguish between charging energy and station power for storage resources, and a net benefits test for DR resources that participate in the Energy Imbalance Market (EIM).
The ISO currently relies on a “10-in-10” baseline methodology that works well for many large commercial and industrial customers but not for all customer types, CAISO said in briefing documents. Using the 10-in-10 methodology, the ISO calculates a baseline by examining the 45 days prior to a trade date and finding 10 “like” days in which no DR was required. It then uses hourly average meter data to create a baseline representing a typical load profile, and the resource is paid for reducing usage below the baseline.
Under the new proposal, baselines for residential resources would be based on a four-day weather match that estimates what electricity use would have been in the absence of DR dispatch under similar weather and on similar days, using a control group of similar users.
Commercial baselines would be based on the 10-in-10 method with a 20% adjustment cap, an average of the previous five days and a control group. Baselines are adjusted using actual load data in the hours preceding a DR event to better reflect variables that might not appear in the historical data.
The package approved by the board also includes a new definition for station power, to distinguish between power used to charge a storage device and energy for station power. It simplifies the definition of station power to align with local regulatory authorities.
The newly approved initiative also incorporates additional gas pricing indices into the “net benefits test” that determines a price threshold to indicate when DR provides a net benefit to all purchasers by reducing the wholesale price. The price threshold is used to determine if an adjustment is required to the settlement of the load-serving entity that procured the load curtailed by the DR resource.
Greg Cook, CAISO director of infrastructure and policy, told the board that the measure allows the ISO to “take into account that the real-time market now has a much broader footprint than just the ISO balancing area, and we should take that into account in the calculation of the net benefits test.”
‘All Hands on Deck’
Tesla’s Powerpack is an example of utility-scale storage | Tesla
CAISO stakeholders are supportive of the new baselines and the station power proposals. Tesla and other storage companies urged CAISO to move quickly to develop a new DER product that would pay for storage to take excess generation, but the ISO said that measure needs more development, and it was not included in ESDER Phase 2. (See Storage Advocates Urge CAISO on DR Product.)
Ted Ko, director of policy for energy storage company Stem, told the board that the ESDER package and DER will be an important tool in reducing the duck curve and curtailments of excess renewables.
“It seems like a time for all hands on deck,” Ko said. “We should be looking for all solutions to reduce that curtailment and bring all solutions to bear.” This also includes developing the EIM and regionalization of CAISO, he said.
Stem has been participating in CAISO as a proxy demand resource and has contracts to deploy more than 400 MWh of DER over the next several years in California. The company needs the ISO to provide a market signal to know when charging is most helpful to the grid, Ko said, and technical and policy guidance from the ISO and other companies. He said that Stem and other companies want the ISO to “take this leadership position with urgency” on developing a load consumption proposal.
Berberich said that CAISO will brief the board at its next meeting on the integration of the load-consumption DER product. There are jurisdictional issues to be worked out with the PUC, he said, and he asked storage companies to contribute their ideas.
