GDF SUEZ Energy Marketing will pay almost $82 million to settle market manipulation charges for offering generation below cost to capture make-whole payments in PJM.
FERC on Wednesday approved a consent agreement between the company and the commission’s Office of Enforcement that requires GDF to disgorge $40.8 million to PJM and pay a civil penalty of $41 million to the U.S. Treasury. GDF did not admit or deny the allegations (IN17-2).
The Troy Energy gas-fired plant in Luckey, Ohio, is one of the units GDF Suez used to own in PJM.
Enforcement charged GDF with violating the commission’s Anti-Manipulation Rule for an improper bidding strategy designed to increase its receipt of lost opportunity cost credits (LOCs).
According to the settlement, the Houston-based power marketer offered below-cost bids on some of its 12 natural gas-fired units to clear PJM’s day-ahead market and profit off the LOCs when the units weren’t dispatched in real time. GDF used a probabilistic, risk/reward approach to compare when units were unlikely to be dispatched against the risk of running the units at a loss, the settlement said.
GDF’s strategy was implemented between May 2011 and September 2013, when Enforcement questioned the practice. The scheme involved 12 simple cycle combustion turbines totaling 1,800 MW at four plants. Based on dispatch history, the company initially expected low energy margins from the units, which did not run often, and that their primary revenue source would be capacity payments.
GDF’s practice took advantage of PJM’s LOC rules, in which CTs that clear day-ahead auctions but aren’t dispatched are paid the difference of the real-time LMP and the higher of the unit’s price-based or cost-based energy offers. Because the formula didn’t subtract start-up and no-load costs, a generator with a day-ahead award could earn a greater margin when it received LOCs and was not dispatched by PJM in the real-time market than it would earn if it was dispatched.
GDF furthered its strategy by discounting its cost-based offers to the level of its price-based offers to ensure the units cleared the day-ahead auctions. The strategy also ensured that the LOCs it received would continue to be based on the discounted offer and would be higher than if based on the units’ estimated costs.
When the company expected that a unit would be dispatched in the real-time market, it typically offered the unit at or above cost and did not discount its day-ahead energy offer. It also typically offered uncommitted units that were not eligible for LOCs in the real-time market without discounting.
“As [GDF] gained experience in implementing the strategy, it became more aggressive in discounting offers for the CT units to get [day-ahead] awards in order to obtain LOCs, at times offering them with discounts as deep as -$25/MWh,” the settlement said.
The company has instituted additional compliance policies to prevent manipulative behavior in the future and will continue to conduct compliance training, the settlement said.
The company also submitted to monitoring and filing an annual compliance report. Enforcement can require a second annual report at its discretion. The compliance report must identify any known violations of commission regulations that happened during the reporting period and detail all compliance actions taken.
PJM’s payment is to be used at the RTO’s discretion — with Enforcement’s approval — to benefit its members.
The Western Energy Imbalance Market (EIM) saw total financial benefits grow 8% during the fourth quarter of 2016 with the addition of Arizona Public Service and Puget Sound Energy as participants, according to a report released by market operator CAISO.
The EIM generated gross benefits of $28.3 million during the quarter, up $2.1 million from the third quarter. The increase came despite typically lower electricity demand in the EIM area during the fall months, the ISO said.
The market has yielded $142.6 million in benefits for its members since being launched in November 2014, the ISO estimates.
EIM operations also helped to displace more than 10,000 metric tons of greenhouse gas emissions during the fourth quarter by enabling the dispatch of 23,390 MWh of surplus renewable energy output from California that would have otherwise been curtailed.
“That avoided curtailment is effectively being used to meet energy needs across the Energy Imbalance Market, and it basically is displacing emitting resources potentially elsewhere in the footprint,” Mark Rothleder, CAISO vice president of market quality and renewable integration, said during a Feb. 1 meeting of the EIM’s governing body.
Rothleder also said that the ISO predicts avoided curtailments to rise sharply with increased renewable energy production during late winter and spring this year. That seasonal pattern will be compounded by increased hydroelectric output stemming from an unusually high water year. The uptick in generation will coincide with low seasonal loads for California and the rest of West.
10-Year Peak for Hydro
Casey Cadle, a real-time operations shift manager for the ISO, said that California faces the heaviest hydro conditions in 10 years. “We’re also going to be having more solar than we’ve ever had in our system, so it’ll be an interesting time of year for us,” Cadle said.
The fourth quarter saw PacifiCorp realize almost $9 million in benefits, compared with $8.7 million for CAISO, $5.9 million for APS, $3.1 million for NV Energy and $1.6 million for PSE.
The benefits represent either cost savings — for example, the reduced need for reserves and greenhouse gas credits — or increased profits from merchant operations. 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-balancing authority area (BAA) transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
Arizona ‘Freeway’
The report also showed that a significant amount of energy flowed from the PacifiCorp-East BAA into APS, and then again from APS into CAISO, suggesting that the Arizona utility’s transmission network is fulfilling its potential of becoming a major transit point between the interior West and California based on its ample transfer capability. (See Smooth EIM Transition for Arizona Public Service, Puget Sound Energy.)
“We can transfer a lot back and forth with PacifiCorp, NV Energy and the California ISO,” Justin Thompson, APS director of resource operations and trading, said last year after the company began operating in the market. “We’re kind of the freeway of the EIM system there.”
Rothleder noted that the prevailing transfers during the fourth quarter came out of PacifiCorp-East, with additional supply being picked up on parallel paths crossing Nevada and Arizona for delivery into California. Some flows continue north into the PacifiCorp-West BAA in Oregon.
The middle of the day often brings a reversal, as CAISO exports its excess supplies to inland areas.
“So there’s times where California is pushing and transferring back out to Arizona, to Nevada and on to [PacifiCorp-East], and that’s exactly how the Energy Imbalance Market is supposed to work,” Rothleder said.
CAISO says that transfers across BAAs are a significant contributor to EIM benefits because they provide participants access to lower-cost supplies, even when factoring in GHG compliance costs for energy imported into the ISO.
“The transfers are reflective of the economics and the system conditions at the time, and you’ll see this change and adapt as you change into different seasons,” Rothleder said.
FERC approved a formula rate requested by Transource Energy for its AP South Congestion Improvement Project, but suspended its implementation pending a hearing on whether the company’s proposed return on equity is reasonable (ER17-419).
PJM last year approved a $340.6 million proposal by Transource and Dominion High Voltage to address the congestion issue along the border of southwestern Pennsylvania and northwestern Maryland, despite criticism from other stakeholders. Transource’s part will include two 230-kV double-circuit lines about 42 miles in total: one between the Ringgold substation and a new Rice substation, and another between the Conastone substation and a new Furnace Run substation. (See FERC OKs Transource Pact on AP South Congestion Project.)
Transource, a joint venture of American Electric Power and Great Plains Energy, had requested a 10.4% base ROE, but protesters — including Old Dominion Electric Cooperative and American Municipal Power — argued that Transource incorrectly calculated the median of comparable rate proposals on which it based its request. The commission questioned the proposal as well and ordered an evidentiary hearing. The rate formula, including the approved ROE, will be effective Feb. 1.
The commission also rejected Transource’s proposed 50-basis-point “risks and challenges” adder, saying Transource “has not demonstrated that the project faces risks and challenges either not already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives.”
The commission granted other requests, including a 50-point adder for RTO participation, 100% recovery if the project is abandoned, inclusion of the project under construction into the rate base and a hypothetical 60% equity/40% debt capital structure until the project is in service or secures permanent financing.
ODEC and AMP had protested the hypothetical structure, but Transource argued it was helpful for securing investors during a critical period for the project. Transource noted that it will likely have to negotiate for access to about 300 properties.
AP South is the first competitively awarded transmission project in Maryland and Pennsylvania, as well as the first competitive market efficiency project in PJM. The RTO expects it to produce approximately $620 million in congestion savings over 15 years. It’s expected to be in service by June 1, 2020.
FERC on Monday granted partial rehearing of a 2013 order that rejected a NYISO cost allocation method for some uplift costs under Order 745 (ER11-4338-001).
The commission partially reversed itself and said that a cost allocation method it previously rejected appropriately assigns those costs to transmission customers, including the New York Power Authority, which it had previously determined was exempt.
NYPA’s Robert Moses Niagara Generating Station
Order 745 amended regulations for compensation of demand response resources participating in wholesale markets. To pass the required net benefits test, FERC ordered RTOs to develop a mechanism to approximate the price level at which dispatching demand response resources will be cost-effective.
“In the May 16, 2013, order, the commission rejected NYISO’s original August 19, 2011, proposal to allocate demand response costs as Schedule 1 uplift costs that are then allocated to transmission customers on the basis of load ratio shares, because NYISO had failed to demonstrate how its proposal appropriately allocates costs to those that benefit from demand reductions,” FERC wrote. “We grant rehearing of the cost allocation issue and find that NYISO has demonstrated that its original proposal to allocate the costs of demand response as Schedule 1 uplift costs that are then allocated to transmission customers on the basis of load ratio shares appropriately allocates costs to those that benefit from demand reductions.”
NYISO had argued that FERC applied an unnecessarily narrow interpretation of the order’s cost allocation requirements by exempting bilateral contracts from the DR day-ahead program. It also argued FERC was imposing different requirements in New York than it did in other RTOs.
FERC’s ruling means the cost allocation will apply to the NYPA, which sells power to retail customers in bilateral contracts, including businesses that participate in the state’s economic development programs. That load is mostly served by the authority’s hydropower system, but it also participates in the NYISO wholesale market.
The commission granted the ISO’s request for a flexible effective date and ordered a compliance filing within 60 days.
In other issues addressed by the order, FERC:
Dismissed a rehearing request by DR supporters claiming discrimination against behind-the-meter resources. The commissions said it was beyond the scope of the proceeding and moot as NYISO has resolved the issue.
Found the ISO had justified its exclusion of off-peak hours from the calculation of the net benefits threshold by “demonstrating the different thresholds for applying the net benefits test using all hours and using only peak hours (HB13 through HB19) for the reference months” in its original compliance filing.
Said the ISO has supported selection of the highest point on its representative supply curve at which supply becomes inelastic as the threshold point for the net benefits test. “We find persuasive NYISO’s description that the lower of the possible points of unitary elasticity is an artifact of the mathematical smoothing function rather than a point on the supply curve with economic significance.”
Ruled NYISO’s existing cap for the in-day adjustment and its proposed measurement and verification methodology comply with the requirements of Order 745.
Agreed with the ISO that the hourly calculation of load ratio shares for cost allocation should be performed instead of the current daily calculation.
The New Hampshire Supreme Court ruled on Tuesday that state transportation officials — not landowners — can determine if the Northern Pass transmission line can be buried in a highway right of way.
The Society for the Preservation of New Hampshire Forests sued in late 2015, maintaining that Eversource Energy needed its permission to bury the line through its property, even though previous owners granted a right of way to the state Department of Transportation for a roadway that is now the four-lane Route 3.
The court ruled that jurisdiction rests with the department. It also said there is no material difference in the permission granted in 1931 between a surface highway and a developer’s attempt to build an underground transmission line today.
“We conclude that use of the Route 3 right of way for the installation of an underground high voltage direct current electrical transmission line, with associated facilities, falls squarely within the scope of the public highway easement as a matter of law, and that such use is within the exclusive jurisdiction of the DOT to regulate,” the court wrote.
Jack Savage, a spokesman for the Forest Society, was surprised by the ruling when contacted by RTO Insider on Tuesday, as he was awaiting a schedule for oral arguments. Atop the ruling was a notation from the court that “oral argument is unnecessary.”
The organization owns a parcel of land along Route 3 in northern New Hampshire known as the Washburn Family Forest, and it granted easements to the DOT.
“As we’ve previously noted, the Forest Society has frequently demanded Northern Pass be buried, yet in this case, had filed this lawsuit to prevent its burial,” Northern Pass said in a blog post.
The Forest Society said the ruling merely delays resolution of eminent domain questions that will eventually return to the Supreme Court.
“The Supreme Court’s decision regarding the Forest Society’s lawsuit against Northern Pass is unfortunate in that it puts off until later a private property rights issue of extraordinary importance to New Hampshire landowners. In short, the court punted,” it said in a statement.
Northern Pass is a proposed 192-mile transmission line that would import 1,090 MW of Canadian hydropower from Quebec to be fed into the New England power grid. Sixty miles of the route is proposed to be underground.
Eversource says additional burial would make the project uneconomic. Opponents want the entire route underground.
The project is before the state’s Site Evaluation Committee, with its ruling due in September.
Republicans on Thursday suspended committee rules to approve Oklahoma Attorney General Scott Pruitt as EPA administrator, sending him on to the full Senate.
The Senate Environment and Public Works Committee voted 11-0 for Pruitt after suspending rules requiring the presence of at least two Democrats to hold votes. The Finance Committee took a similar step Wednesday to overcome a boycott that had blocked the confirmations of President Trump’s Treasury secretary and Health and Human Services secretary nominees.
Republicans on the environment committee acted after Democrats boycotted a meeting Wednesday, in response to Chairman Sen. John Barrasso’s (R-Wyo.) rejection of their request for a delay so Pruitt could answer more questions.
“Committee Democrats and I sent many questions and document requests to Mr. Pruitt over a month ago. We believe these inquiries, and our questions for the record, elicit information from the nominee that he possesses and that he should be able to provide to the committee,” the ranking Democrat, Sen. Thomas Carper (D-Del.), wrote in a letter to Barrasso. “Failure on his part to do so is not only an affront; it also denies Democratic committee members, and all members of the Senate, information necessary to judge his fitness to assume the important role of leading the EPA.”
In the Democrats’ absence Wednesday, the Republicans spent nearly an hour rebuking their colleagues.
1,200 Questions
“Let’s be clear. Attorney General Pruitt has answered … 1,200 questions. He answered over 1,000 more questions than the EPA administrator nominees for the incoming Obama, Bush and Clinton administrations,” Barrasso said. “The minority may not like all of Attorney General Pruitt’s answers, but he has given them answers.”
“If a student doesn’t show up, they flunk the class. If an employee doesn’t show up, they get fired,” said Sen. Shelley Moore Capito (R-W.Va.). “Failing to show up does not serve our constituents.”
Sen. Joni Ernst (R-Iowa) said the move by Democrats has gone past vetting. “There comes a point where vetting has been turned into obstruction,” she said. “I would ask my colleagues on the other side: What is the true purpose of their witch hunt?”
Sen. Jerry Moran (R-Kan.) was more blunt, calling the boycott “governing by tantrum.”
During Pruitt’s six-hour confirmation hearing before the committee Jan. 18, Democrats cited Pruitt’s campaign contributions from the oil and gas industry and his 14 lawsuits against EPA as attorney general. They included challenges to the Cross State Air Pollution rule (CSAPR), the Mercury and Air Toxics Standards, regional haze rule and emission regulations on new power plants. Pruitt did say he did not agree with President Trump’s claim that climate change is a hoax, but he has led the legal fight by states against EPA’s Clean Power Plan. (See Dems Unmoved by EPA Pick’s Charm Offensive.)
‘Deeply Concerned’
Carper’s letter to Barrasso on Monday said he and his Democratic colleagues were “deeply concerned” about the answers Pruitt gave in response to the senators’ written questions.
Carper cited Pruitt’s refusal to provide communications he had with representatives of agricultural companies regarding water quality litigation between Arkansas and Oklahoma. Pruitt said the records could be obtained under the Oklahoma Open Records Act.
“Mr. Pruitt provided this answer 19 times in response to questions several Democrats posed on a variety of matters. We are deeply concerned that senators are being directed by a nominee to obtain information on his record outside of the confirmation process — especially given that the Oklahoma Office of the Attorney General has a two-year backlog on such record requests,” Carper wrote.
Carper said Pruitt also was unable to name a single EPA regulation that he supports, responding “I have not conducted a comprehensive review of existing EPA regulations.”
“Based on the lack of substance with respect to many of his answers,” Carper said, “it is unclear whether Mr. Pruitt supports any clean air or clean water federal regulations.”
Democrats were particularly upset that Pruitt refused during the confirmation hearing to commit to recusing himself from agency matters dealing with pending litigation he initiated, or in which he participated, as Oklahoma attorney general. Pruitt said he would consult with EPA’s ethics counsel on a case-by-case basis.
Sen. Jeff Merkley (D-Ore.), one of the senators who boycotted the meeting, issued a statement explaining why. “Until Scott Pruitt answers these important questions, until he clarifies his positions and tells us how he is going to resolve the many conflicts of interest his nomination poses, it would be irresponsible for the committee to vote on his nomination,” Merkley said.
Because only Supreme Court nominees are subject to a filibuster on the Senate floor, Democrats won’t be able to block Pruitt’s nomination without Republican defections.
On Tuesday, the Senate Energy and Natural Resources Committee approved Rep. Ryan Zinke (R-Mont.) as secretary of the Interior Department and former Texas Gov. Rick Perry as energy secretary. Zinke’s nomination was approved 16-6 with four Democrats joining all Republicans in support. Perry was approved 17-6. The two nominations move to the full Senate, where they are expected to be approved.
DALLAS – SPP members elected 40-year industry veteran Mark Crisson to the RTO’s Board of Directors on Tuesday, expanding the board to 10 members.
After nearly 30 years with Tacoma Public Utilities in Washington state, Crisson served as CEO of the American Public Power Association (APPA) from 2007 to 2014 in D.C. He was interim general manager of Kentucky’s Paducah Power System and deputy general manager with the Navajo Tribal Utility Authority before retiring in 2016.
Crisson told RTO Insider he was attracted to SPP’s stakeholder-driven culture, which he said is similar to APPA’s emphasis on its members.
“At APPA, we would hold up SPP’s core principle of stakeholder focus as an example of how other organizations should run things,” Crisson said. “The belief is having customers and members driving the decisions and developing solutions. It takes time, but it’s better doing it that way than dealing with problems later.”
He said he was excited by the opportunity to stay involved in the electric industry, while also enjoying his retirement.
“I bring a lot of management experience and customer experience,” he said. “I’ll try to be cognizant as a board member to offer support and guidance, but not set specific direction. I hope I can provide meaningful, high-quality technical advice.”
A graduate of the U.S. Naval Academy, Crisson served in the Pacific nuclear submarine fleet from 1970 to 1975. He joined Tacoma Public Utilities after completing his service and earned a master’s in business administration from Pacific Lutheran University in 1981.
Golden Spread Electric Cooperative’s Mike Wise, himself a graduate of the U.S. Air Force Academy, said teasingly, “It’s nice to have another academy grad in leadership, though it’s not necessarily the right one.”
SPP CEO Nick Brown said Crisson “brings a distinct and rare set of skills and experiences to our group of directors, and we look forward to benefiting from his insights as we ramp up our engagement in national energy policy discussion.”
Crisson helped lead Tacoma through the 2000/01 Western Energy Crisis before becoming chair of APPA’s board in 2003 after 10 years as a director. He centered his work on climate change legislation, federal environmental regulations, analysis of ISO/RTO wholesale power markets, grid reliability and cybersecurity. He was recognized with APPA’s first annual Mark Crisson Leadership and Managerial Excellence Award when he left the organization in 2015.
Board Expansion
FERC in August 2015 approved SPP’s request to expand its board to up to 10 people, with a minimum of seven. The RTO said the expansion was to increase the “flexibility” of director succession planning, “with due consideration given to director tenure, knowledge sharing and risk management.”
The Russell Reynolds Associates search firm also identified Crisson as a candidate during the initial search. He was interviewed again in November by the Corporate Governance Committee, which represents each of the membership sectors.
As he did last January, Westar Energy’s Kelly Harrison urged the membership and SPP to continue to improve the board’s diversity. Long-time director Phyllis Bernard is the only woman on the SPP board, while she and Joshua W. Martin III are the only two members of a minority.
“I know it’s a challenge, because those folks might be in high demand,” Harrison said.
Arizona Public Service can continue to charge market-based rates in Tucson Electric Power’s balancing authority area (BAA), FERC has ruled.
The commission said Jan. 30 that APS had overcome its concerns about the company’s ability to exercise market power in the neighboring BAA, closing the book on a Section 206 proceeding investigating the issue (ER10-2437-003).
APS said that closure of Unit 2 at its Cholla coal-fired plant contributed to the reduction of its market power in Tucson Electric Power’s service territory. | APS
The commission granted APS market-based rate authority (MBRA) despite finding “unpersuasive” the utility’s argument that it lacks the sufficient generation and transmission rights within the Tucson Electric area to exercise market power.
Commissioners also declined to rely on APS’s delivered price test (DPT) submission because the analysis did not cover all 10 required season and load periods.
“Because the indicative screens are only intended to screen out sellers that raise no horizontal market power concerns, we find that sellers opting to submit a DPT to rebut the presumption of market power must comprehensively analyze 10 season/load periods even if the indicative screen failure(s) only occurred in a single season,” the commission said.
Considered a more rigorous analysis than FERC’s “indicative” screens for determining market power, the DPT considers native load commitments to capture a detailed picture of an electricity supplier’s “available economic capacity” — energy available for offer in the open market — over multiple seasons and load conditions.
But other factors worked in the utility’s favor.
A key piece: Evidence included a supplemental indicative screen analysis showing that APS passed the pivotal supplier and wholesale market share tests for 2015 and 2016 — an improvement over the 2014 analysis that prompted FERC to institute the Section 206 proceeding.
The updated report showed APS’s summer period wholesale market share in the Tucson Electric BAA dropping from 22.4% in 2014 to 15.8% in 2015 — followed by another decline to 13.3% last year. The utility’s market share was well below 20% during other seasons and periods, the commission found.
APS cited as reasons for the reduction in market share Tucson Electric’s purchase of a portion of the Gila River natural gas-fired plant, the retirement of Unit 2 at APS’s Cholla coal-fired plant and the expiration of certain APS option contracts.
“Based on APS’s other alternative evidence, we find, on balance, after weighing all other relevant factors, that APS has rebutted the presumption of market power in the Tucson Electric balancing authority area,” the commission said.
The favorable ruling comes nearly six months after FERC rejected APS’s effort to gain MBRA in the Western Energy Imbalance Market (ER10-2437). In that order, the commission rejected the argument that CAISO’s mitigation measures would suffice to keep APS’s market power in check and noted that the utility did not even attempt to file indicative screens or a DPT to rebut the presumption that it exercised power within its own portion of the EIM.
The Jan. 30 decision also follows a November 2016 order in which the commission said that it would commence a Section 206 proceeding to determine whether Tucson Electric should retain MBRA within its own service territory (See Tucson Electric Could See Loss of Market Rate Authority in its BAA.)
That review was triggered after the utility filed a “change in status” notice demonstrating that it passed market share screens for neighboring BAAs but failed the same test for its own area (ER10-2564, et al.).
AUSTIN, Texas — ERCOT reliability unit commitment (RUC) activity increased more than three-fold in 2016, staff said at the Technical Advisory Committee meeting last week.
The number of instructed resource hours jumped from 411 in 2015 to 1,514 last year. Most of the activity occurred during the high-demand summer months, with almost 98% of the hours (1,481) noted as addressing congestion, primarily in the North and Houston zones, and the remaining 33 hours for capacity shortages.
No resource hours were committed for ancillary service shortages, voltage or reactive support, system inertia or in anticipation of extreme cold weather or startup failures.
“Although we saw a large increase in the total number of RUC commitments, we thought it was interesting to find the average dispatch limit and base points [metrics] stayed fairly similar,” said ERCOT’s Dave Maggio, manager of market analysis and validation.
According to Maggio’s report, 170 resource hours were dispatched above the low dispatch limit (a resource’s minimum production level in order to be dispatched). For 127.1 of those hours, the RUC-instructed resource was mitigated and the LMP was less than the RUC offer floor. He said the RUC-instructed resource was not mitigated for 39 hours and the LMP was less than the RUC offer floor, indicating a problem with its energy offer curve.
“If you remove the opt-out hours and just look at when the RUC occurred, it’s telling us that for 84% of the resource hours, the unit was never even dispatched off its [low sustained limit],” Barnes said, referring to a resource’s minimum sustained production capability. He painted Reliant Energy as not being in the “all-RUC-is-bad camp,” but in the “RUC-is-too-conservative” camp.
“In terms of what we’re getting for our money, [based on the results,] it’s arguable RUC didn’t always need it,” Barnes said. “If the unit was never needed to move 1 MW off its LSL [this often], we probably should be looking at the design of the RUC process. Is it too conservative or not?”
Potomac Economics’ Beth Garza, director of ERCOT’s Independent Market Monitoring group, pointed out to the TAC that 478 of the hours were bought back through the use of the resources’ opt-out status. Those resources are then excluded from RUC settlements as if the commitment never happened.
“There continues to be, from my perspective, great uncertainty in the market about how to opt out, and the specific process by which that can occur,” she said, reiterating what she called one of her “common themes.”
“It seems to me there’s a widespread lack of understanding of the specific actions that have to be done right now, versus after [NPRR] 744 is implemented. … The process will change.”
NPRR 744 was passed by the TAC and the Board of Director’s last spring and is scheduled to be implemented June 27-29. It is intended to improve the process used to notify ERCOT of a decision to opt out of a RUC order.
With the change, qualified scheduling entities (QSEs) that submit bids and offers on behalf of resource entities or load-serving entities will be required to opt out of RUC settlement by telemetering a resource’s status during the first interval it is online and available.
“This allows the entity that got RUCed to opt-out without using telemetry status,” Maggio said. The NPRR helps the ERCOT system, he said, “because the decision for employing the price adder [occurs] simultaneously.”
Noting about 600 of ERCOT’s RUC-committed resource hours took place in June and July, Garza said she believes much of that was a deferral by market participants in making their own commitment decisions.
“In deferring that decision, RUC is going to step in at some point and make a decision on your behalf,” she said. “To the extent we can get people to opt-out appropriately, there may not be a market impact. I think there’s a question there: Is [RUC] bad? Is it helping us get to better commitment decisions across the market? Opting out helps with that part as well.”
Several stakeholders pointed to the 33 resource hours instructed for capacity and questioned whether they should be in ERCOT’s market design.
“It’s created uncertainty around outcomes during those time periods that impact pricing during a capacity shortage,” said Citigroup Energy’s Eric Goff. “Hopefully, we have a significant price signal to get generators to commit themselves. If we don’t, that’s an even bigger problem.”
Morgan Stanley’s Clayton Greer suggested expanding ancillary services as another tool that could be used to “provide the same service.”
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week endorsed a protocol change that incorporates futures prices to estimate forward risk, a change that the ISO says could reduce market-wide collateral requirements by $30 million to $70 million, depending on several parameters.
Under Nodal Protocol Revision Request 800, collateral requirements would be calculated using a ratio of the futures average price to the historic average price. It would be based on the Intercontinental Exchange’s 21-day North Hub price curves.
ERCOT said exchange-based electricity futures market prices are “assumed” to be a better indicator of forward risk than historic ERCOT market prices.
Reliant Energy Retail Services’ Bill Barnes, representing the independent retail electric providers, called the change a “novel approach,” saying ERCOT may be the first electricity market to use this methodology.
“There is no better way to assess forward-price risk than to use the forwards, and that’s what this does,” he said. “It pulls those in and uses them to adjust your historical credit exposure.”
Barnes said the revision request represents two years of work by the Credit Working Group to improve how forward collateral evaluations are working in the protocols. ERCOT’s current methodology uses historical prices in its evaluations.
“In vetting [the current] approach, the working group found there were some pretty severe flaws in how they worked,” he said. “The most accurate way to collateralize future credit risk … [is] what do we think your participant represents as far as a credit risk to the ERCOT market.”
“It’s consistent with how we mark our exposure to the markets,” said Shell Energy North America’s Greg Thurnher. “It seems to make common sense. It seems to be more effective than our previous practices, which essentially look in arrears to anticipate a forward exposure when the seasonality of our market paints a very different picture.”
Luminant cast the lone dissenting vote, saying its opposition to the NPRR was based solely on the implementation costs to ERCOT and individual market participants.
“We estimate costs of up to $300,000 to make changes in our systems, and we don’t see the requisite benefit,” said Luminant’s Amanda Frazier.
Barnes noted the revision request was granted urgency status so that it could be incorporated into an existing release bundle for ERCOT’s credit monitoring and management system.
“That will potentially help streamline the implementation and perhaps lower the cost,” he said.
The change is estimated to cost ERCOT as much as $250,000 to implement. It has the support of the ISO’s Finance and Audit Committee.
Small Municipalities’ Revision Request Tabled for 7th Time
Tom Anson, an attorney representing the Small Public Power Group of Texas (SPPG), was granted a request to table until August his appeal of a rejected revision to the Nodal Operating Guide regarding the definition of transmission owners. This marks the seventh time NOGRR 149’s appeal has been tabled since it was first brought to the TAC last March, shortly after it failed to pass the Reliability and Operations Subcommittee.
The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak is less than 25 MW. The NOGRR was developed in 2015 to settle the noncompliant status of seven municipally owned utilities, ranging in size from 9 to 21 MW.
Anson said the SPPG has been told it is “trying to make a market where there isn’t one,” and he said one transmission provider told the group it didn’t have “much of an appetite to provide service.” However, he also said the SPPG has four “conceptual” proposals in hand.
“These things take time,” Anson said. “We can’t promise we can turn any of these into a reality, but if the SPPG is willing to invest time and money into the effort with those who are helping them, we’ll see if we can’t turn one of these into not just a potential market solution, but a real market solution.”
Anson said the SPPG would withdraw its appeal should it reach a deal with one of the transmission service providers. He agreed to return to the TAC in May with an update.
ERCOT to Keep Admin Fee Flat Through 2019
Staff told stakeholders the ISO intends to maintain its system administration fee of 55.5 cents/MWh through 2019.
Market participants requested more advance notice of future fee increases during the 2016-17 budgeting process. The fee was raised from 46.5 cents/MWh during those discussions.
Committee Chairs, Vice Chairs Approved
The TAC confirmed its subcommittee leadership for 2017. The chairs and vice chairs are:
Commercial Operations Subcommittee: Chair Michelle Trenary, Tenaska Power Services; Vice Chair Heddie Lookadoo, Reliant Energy Retail Services.
Protocol Revision Subcommittee: Chair Martha Henson, Oncor Electric Delivery; Vice Chair Diana Coleman, Texas Office of Public Utility Counsel.
Reliability and Operations Subcommittee: Chair Alan Bern, Oncor; Vice Chair Boone Staples, Tenaska.
Wholesale Market Subcommittee: Chair Jeremy Carpenter, Tenaska; Vice Chair David Kee, CPS Energy.
Stakeholders Vote for More Inclusive Steady State Models
Stakeholders unanimously endorsed a revision to the Planning Guide that modifies the conditions proposed generating resources must meet to be included in steady state working group (SSWG) base cases (PGRR 053).
The change would require only the data provided for full interconnection studies (the standard generation interconnection agreement, applicable permits, notice to proceed and financial security) for including a proposed generation resource in the base case. ERCOT says the current rules, which also require completion of a resource asset registration form, has “created a need to unnecessarily use extraordinary dispatch conditions in the SSWG base cases.” The change will result in more representative generation dispatch scenarios in base cases, the ISO said.
“This lessens that data that’s required,” said ERCOT’s Jay Teixeira prior to including proposed All-Inclusive Generation Resources in the planning models. “Our intention was to pick up every resource that submits a resource form and are in the non-network model.”
The vote came after members struck references to “all-inclusive” generation resources, which had been added by the Reliability and Operations Subcommittee. Stakeholders said the term created confusion.
Katie Coleman, an attorney representing industrial customers, said she is working with ERCOT staff to update NPRR 190, which could help clear up the confusion. The NPRR was withdrawn in 2010 and was designed to add language acknowledging the existence of generation resources that qualify as distributed generation or are self-generators.
Revision Requests, Shadow-Price Cap Change Endorsed
The committee unanimously approved staff revisions to how ERCOT sets shadow-price caps and power-balance penalties under security constrained economic dispatch. The revisions update the shadow-price offer caps from $5,000/MWh to $9,000/MWh, reflecting the ISO’s current value for shadow-price caps.
The TAC also unanimously approved three additional NPRRs, another NOGRR and revisions to the Planning Guide. They will be brought to the Board of Directors on Feb. 14.
NPRR 794: Moves reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols. The NPRR was approved in conjunction with COPMGRR 044.
NPRR 805: Clarifies the criteria under which congestion revenue rights (CRRs) account holders can submit multi-month offers for long-term auctions. The months must be consecutive, within the period covered by the auction and during months when the account holder has ownership of the CRR.
NPRR 806: Clarifies that municipalities and cooperatives not participating in ERCOT’s competitive market (non-opt-in entities, or NOIEs) have the option of accepting a refund or capacity for their preassigned CRR-eligible resources. The NOIEs cannot select one option for some months of the year and the other option for the remaining months.
NOGRR 165: Aligns the operating guides with NERC reliability standards to ensure ERCOT and its transmission operators develop plans to mitigate operating emergencies. The plans should address NERC standard EOP-011 (Emergency Operations Planning) requirements and does not include black start or geomagnetic disturbance plans.
PGRR 052: Ensures appropriate operating limits are established when stability studies are performed after a full interconnection study (FIS) has been completed and model data or transmission system changes not available during the FIS become available before the new unit is brought online.
