CAISO hauled in the largest share of the $39.52 million in benefits produced by the Western Energy Imbalance Market (EIM) during the second quarter, the grid operator said in a report released Monday.
The ISO was also the market’s dominant exporter of energy over the period as California coped with combined surpluses of solar and hydroelectric output on its system after a wet winter.
CAISO took in $15.49 million in benefits, compared to $8.81 million for PacifiCorp, $8.13 million for Arizona Public Service and $2.47 million for Puget Sound Energy. NV Energy’s estimated $4.62 million in benefits did not include data for June, which is still pending verification.
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The EIM’s total benefits increased by $8.52 million — or 27% — over the first quarter. (See CAISO EIM Exports Rise With Spring, Report Shows.) That spread will increase with the addition of NVE’s June figures.
The gross benefits represent either cost savings for serving load or increased profits from merchant operations within the EIM’s participating balancing authority areas (BAAs). The market’s ability to reduce curtailments also enables participants to collect renewable energy credits that would not otherwise be issued.
The benefits calculation nets out inter-BAA transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
CAISO exported more than 1.11 million MWh of electricity in the EIM’s five-minute market during the quarter, the report shows. Most of that energy was transmitted into NVE’s territory to be wheeled into the PacifiCorp-East area, but APS also absorbed a significant portion. The inclusion of APS and PSE last October greatly increased the transfer capability within the EIM, improving California’s ability to move its solar surpluses into other areas of the West.
Last year’s addition of Arizona Public Service and Puget Sound Energy to the EIM has significantly increased the market’s transfer capacity, facilitating exports from CAISO | CAISO
That export capability enabled CAISO to avoid curtailing 67,055 MWh of renewable output from April to June, displacing 28,700 metric tons of CO2 emissions , the report said. The ISO estimates that, since 2015, avoided curtailments from EIM operations have reduced carbon emissions by 204,941 metric tons, the equivalent of removing more than 43,000 passenger cars off the road for a year.
CAISO’s exports are likely to decline sharply this summer as California absorbs more of its own renewable output in the face of increased summer loads, a pattern seen last year. (See PacifiCorp Increases Share of EIM Benefit in Q3.)
The report also noted the EIM’s impact on the procurement of flexible ramping capacity, which represents resources capable of responding to the variable output of renewable generators.
Because variability can decrease in one BAA at the same time that it’s increasing in another, the EIM enables participants to share flexible resources — allowing each BAA to procure fewer resources than would have been necessary on a standalone basis. These “flexible ramping procurement savings” during the second quarter represented about 39% of what would have been the total requirement of the participating BAAs absent the EIM, the report showed.
The EIM has yielded $213.24 million in gross benefits since commencing operation in November 2014 with PacifiCorp as its first member.
Negative day-ahead prices surged in CAISO during the first quarter as combined surpluses of solar and hydroelectric output frequently left the market upside-down.
Prices went negative during 51 hours in the day-ahead market over the three-month period, compared with just three hours in all of last year, the ISO’s Department of Market Monitoring said.
“This is something we first just started seeing in this quarter,” Senior Analyst Gabe Murtaugh said during a July 31 call to discuss the department’s first-quarter report.
Negative prices indicate that the cost to procure wholesale power was at or below $0/MWh, which happens when there is an oversupply of solar power and other renewables while demand is relatively low.
Negative prices occurred in the day-ahead market during about 10% of the hours in the 11 a.m. to 3 p.m. time frame during the first quarter. They also happened more frequently during weekends when electricity loads were lower.
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Real-time prices also dipped frequently into negative territory during the quarter, occurring at about 10% of intervals in the 15-minute market and 13% of intervals in the five-minute market.
The negative pricing has become central to the debate around renewables in California, with some arguing that it is the result of a rush to integrate renewables without completely accounting for or understanding their impact on reliability and markets.
CAISO average energy prices decreased sharply in the first quarter, from about $35/MWh in December 2016 to about $23/MWh in March. This coincided with increased renewable output and low loads, the Monitor said. Prices in the 15-minute market are consistently lower than day-ahead prices and moved in about the same direction and magnitude each month.
“On average, five-minute market prices in March were notably low at about $17/MWh. This was the lowest average monthly five-minute market price during the past several years,” the Monitor said in the report.
CAISO also curtailed more renewable generation in the quarter, rising to a high in March of nearly 6%, compared with peak curtailment less than 3% a year earlier. Renewable curtailment rose above 80,000 MWh in both February and March, compared with less than 60,000 MWh in March 2016, according to ISO data.
During nearly all first-quarter intervals when prices were negative, the market economically dispatched generation down and CAISO did not have to curtail self-scheduled generation.
Rooftop solar and other renewables pushed up negative prices in CAISO in the first quarter
Prices at times surged above $750/MWh at certain times because of generator ramping limitations when solar resources rolled off the system at sunset.
“During these intervals, steep increases in net load exceeded flexible ramping capacity procured through the flexible ramping product and required the power balance constraint to be relaxed because of insufficient available incremental energy,” the Monitor said.
Congestion in the Western Energy Imbalance Market (EIM) continued to isolate PacifiCorp-West (PACW) from CAISO and PacifiCorp-East (PACE), the Monitor said. This drove down prices in PACW and Puget Sound Energy compared with the ISO and the rest of the EIM.
Arizona Public Service and PSE joined the EIM in October 2016, adding new transfer capacity. This reduced congestion between APS, CAISO and PACE, the Monitor said. EIM market prices in the APS area were close to those in NV Energy, PACE and CAISO.
The Monitor earlier this month said that bid limits placed on PacifiCorp, NVE and APS are no longer needed because of increased transfer capacity in the EIM. (See CAISO Monitor Says EIM Bid Limits No Longer Needed.)
The report reiterated the Monitor’s recommendation that the ISO’s congestion revenue rights auction be eliminated and replaced with a market or locational price swaps based on bids for CRRs. (See CAISO Monitor Proposes End to Revenue Rights Auction.) CAISO is in the midst of an initiative to investigate the efficiency of the auction.
Public Service Enterprise Group CEO Ralph Izzo said last week that the company has received “just about universal support for the continued operation” of its nuclear plants.
Speaking during the company’s second-quarter earnings call on Friday, Izzo also revealed that PSEG’s Public Service Electric and Gas plans to ask the New Jersey Board of Public Utilities to decouple its distribution revenue from its sales volume to enable it to support large-scale investments in energy efficiency.
PSEG — which owns the Hope Creek Generating Station and 57% of the adjacent Salem Nuclear Generating Station in New Jersey, and 50% of the Peach Bottom Atomic Power Station in Pennsylvania — wants financial compensation for its emissions-free generation, which it says is at risk from low power prices.
Salem & Hope Creek Nuclear Reactors on Artificial Island
Izzo said it’s good that the Department of Energy recognizes a challenge “with baseload generation and fuel diversity,” which will be the subject of a report the department plans to release soon. He called “the recent PJM proposals on how to deal with inflexible units … potentially quite helpful.” (See New York ZEC Suit Dismissed.)
Izzo | PSEG
Still, Izzo said, “the problem, according to the forward price curve, is at New Jersey’s doorstep, and there’s no denying it.” As a result, he said, PSEG will “continue to educate stakeholders at the state level about the need to preserve the diversity and resiliency of our electric generating mix.”
PSE&G will make the decoupling request in a rate case it plans to file no later than Nov. 1. A growing number of utilities are seeking to decouple their revenue from their sales. The move enables them to get the money they say they need to maintain their infrastructure even if their sales are flat or declining. In California, for example, utilities receive incentives to encourage their customers to use renewables and conserve electricity.
PSEG earned $109 million ($0.22/share) in the quarter, down from $187 million ($0.37/share) in the second quarter of 2016. The company said its most recent figures were affected by accelerated depreciation associated with the June 1 retirement of its last two coal-fired generating stations. PSEG’s revenue in the most recent quarter was $2.13 billion, up from $1.91 billion a year ago.
A Central Texas heat wave is leading to surging demand for electricity, helping ERCOT continue its streak of breaking demand records.
The Texas grid operator’s latest record came Friday when it reported 69,525 MW of demand between 4 and 5 p.m., the fifth time in July it exceeded last year’s mark of 67,469 MW.
Temperatures in Austin, where ERCOT is headquartered, hit 105 F on Sunday, breaking a 60-year-old record for the date and marking the 13th straight day of triple-digit heat. Nearby San Antonio broke heat records Saturday and Sunday with temperature readings of 105 and 104 F, respectively. The previous records were set in 1950 and 1946, respectively.
On Saturday, ERCOT broke the weekend peak demand record by nearly 1,500 MW when it recorded a preliminary total of 68,413 MW between 4 and 5 p.m. — after hitting 67,728 MW in the previous hour.
And the ISO has set new monthly demand records for nine of the past 12 months, including the last four.
“The system has performed well so far this summer,” said ERCOT spokesperson Robbie Searcy. Unable to resist the use of a pun, she said, “We have kept up with monthly record demand in June and July, and blazed past the previous weekend record without any reliability concerns.”
ERCOT’s final resource adequacy seasonal assessment projected demand to peak this summer at 72.9 GW in August, above the all-time high of 71.1 GW set in August 2016.
Area heat indices have been as high as 109 F, but temperatures are expected to drop into the high 90s for much of this week.
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.”
