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.
December was marked by all-time high wind output in MISO, along with higher gas prices and erratic weather patterns that challenged the RTO’s forecasters, officials said at a Jan. 24 Informational Forum.
Jeff Bladen, MISO’s executive director of market design, said that while average temperatures in December were “near normal,” the month saw “rapid transitions in temperatures and winds,” leading to inaccurate forecasting and poor unit commitment.
“Ultimately, unit commitment decisions are heavily influenced by weather forecast accuracy,” Bladen said.
There are ongoing efforts to improve load forecasting capabilities, he added. “The challenge is more volatile weather … it’s something we continue to work on to improve our ability to manage and predict,” Bladen said.
Load averaged around 77 GW during December, a 9-GW increase over November. The month’s peak of 100 GW occurred Dec. 19.
MISO’s systemwide energy prices averaged just above $30/MWh, up 22% compared with the previous month. Bladen said the increase could be attributed to an $3.59/MMBtu average natural gas price that was $1.15 higher than in November.
A month-to-month upending of wind output records has become almost standard for MISO, and a new high of 13.7 GW was set Dec.7, surpassing the previous record of 13.3 GW set in late November. Wind production for the month totaled 5,687 GWh, the highest value recorded for the RTO.
MISO Creates Focus Group for IT Refresh
MISO will create a Market System User Experience Focus Group to learn about information technology shortcomings, said Curtis Reister, the RTO’s director of software delivery.
The group will meet Feb. 23 and is open to all users of MISO market systems who would like to comment on their market experiences and make suggestions.
The group, part of MISO’s wider effort to make software improvements in 2017, will gauge customer satisfaction with usability, performance and security and seek to understand customer experiences. (See MISO to Study Aging Software; Market Improvements Planned for 2017.)
The RTO noted that its electronic market systems are more than 10 years old. While some applications have been improved for functionality, there have been “minimal” changes to front-end design.
“There is some dissatisfaction out there, and we want to understand it,” Reister said.
The focus group will also decide which IT investments will have the biggest payback, he added.
MISO CEO John Bear said software investments are needed to manage a larger, more diverse fleet. “We’re dealing with a lot more intermittency and a lot more generators,” he said.
Some of the improvements might require members to make system changes implemented over the long-term in order to give those members adequate time to update, Bear said.
MISO will also switch platforms for its external website, according to Executive Director of External Affairs Kari Bennett.
Stakeholder Input Needed on Cost Allocation
Patrick Brown, manager of transmission planning for MISO South, said the RTO expects stakeholders to submit comments on transmission cost allocation by Feb. 27, in time for a Hot Topic discussion at the March 22 Advisory Committee meeting.
The RTO released a market efficiency project (MEP) cost allocation strawman in December, proposing to lower the current 345-kV voltage threshold and remove a footprint-wide postage stamp allocation of costs in favor of one in which costs are borne solely by participants in benefiting transmission pricing zones. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)
MISO expects cost allocation refinement to continue into the third quarter before Tariff changes are drafted in the fourth quarter and filed sometime in mid-2018.
In a sprawling decision, FERC last week rejected requests for rehearing by multiple energy sellers implicated in market manipulation during the Western Energy Crisis of 2000/01 (EL00-95-289).
The sellers — which include Hafslund Energy Trading, Illinova Energy Partners, MPS Merchant Services, Shell Energy North America and APX — had asked the commission to reconsider previous findings related to the disgorgement of overcharges the companies raked in from May to October 2000, the so-called “Summer Period” of the crisis, which ultimately cost California ratepayers billions of dollars.
In that decision, the commission set out what it deemed the “appropriate remedy” for the anomalous bidding, false export and false load scheduling tariff violations engaged in by the companies in an effort to drive up market clearing prices during the crisis: the disgorgement of any payments received in excess of a marginal cost-based proxy price.
The commission decision dealt with companies implicated in manipulating prices during the initial “Summer Period” of the Western Energy Crisis.
A subsequent opinion required that companies found to have engaged in those practices would be forced to disgorge overcharges for all sales made during trading intervals in which market prices were affected by any of the companies’ tariff violations.
FERC dismissed as moot rehearing requests by MPS, Illinova, Hafslund and Shell that called into question the commission’s previous findings of tariff violations by the companies. The commission pointed out that the 9th U.S. Circuit Court of Appeals had already determined that FERC’s orders on those matters were final and that the commission “reasonably concluded that the sellers engaged during the Summer Period in the practices deemed tariff violations.”
The commission also denied a request for rehearing by MPS and Illinova in which the two companies contended that FERC’s requirement that an individual seller disgorge profits not directly connected to any violation they committed represents an award of retroactive refunds to buyers rather than disgorgement. The two companies had complained that FERC’s disgorgement remedy is limited to the return of profits obtained illegally. The commission countered that the 9th Circuit has recognized that the Federal Power Act “gives FERC authority to order refunds if it finds violations of the filed tariff and imposes no temporal limitations.”
FERC rejected an argument by all five companies challenging the validity of the marginal cost-based proxy price methodology being used in the proceeding. “The commission has affirmed the presiding judge’s finding that the marginal cost-based proxy methodology … provides for a credible proxy of prices in a normal competitive environment,” the commission wrote.
The commission also rebuffed the companies’ argument that they should not be responsible for disgorgement of profits from all sales affected by the tariff violations by any of the market’s participants. Commissioners said they found persuasive the arguments of a California expert witness that the tariff violations had “intertemporal” effects on the state’s market during the crisis.
The commission also rejected a contention by MPS and Illinova that the prices established by the CAISO and now-defunct California Power Exchange markets were contract rates subject to the public interest standard of review embedded in FERC’s landmark Mobile-Sierra decision.
“The prices set by the CAISO and CalPX auction markets do not constitute contract rates because they result from a generally applicable auction mechanism set forth via tariff,” rather than from an arms-length transaction between two parties, the commission said.
The CAISO and CalPX tariffs did not contain the terms of a public interest standard of review, the commission noted.
The commission also denied a request by Exelon, the successor-in-interest to AES NewEnergy, for a rehearing on the issue of the fuel costs the company submitted to offset its refund amounts.
“The commission considered the full array of evidence, noting certain CAISO records submitted by Exelon related to the transaction, but ultimately finding that Exelon had not ‘clearly linked any evidence of its actual incurred costs to the resource and sale at hand,’” the commission said, citing language in a previous ruling. The commission reiterated a requirement that fuel cost information be “clearly linked” with a resource and an energy sale and “easily verifiable by supporting evidence.”
Settlement Agreements
In two other orders stemming from the energy crisis, FERC rejected two of California’s motions to preserve remedies or refunds against other non-settling parties as a condition for concluding settlement agreements with Illinova and MPS (EL00-95-299, EL00-95-300).
California had asked for the commission to affirm that a settlement with either company would not release non-settling parties from facing the possibility of having to disgorge profits from energy sales inflated by tariff violations committed by Illinova and MPS. The state argued that FERC’s failure to grant the motion would make future settlements impossible by reducing the liability of the remaining sellers and incent them to wait for others to settle first, thereby deterring California from settling with any of them.
In denying California’s motion, the commission stated that it “has dismissed from the proceeding parties that settled … before and during the instant proceeding, excluded the conduct of non-parties from the scope of the proceeding and emphasized that the trading hours impacted by the settled parties’ tariff violations will not be included in disgorgement amounts due from the remaining respondents.” The state failed to provide a compelling reason for the commission to reverse that long-standing practice, the commission added.
The commission noted that it was not ruling on either settlement agreement and directed California to notify FERC within 30 days whether it wished to revise or withdraw from the agreements.
CARMEL, Ind. — MISO’s Steering Committee last week advanced three topics for discussion: the RTO’s settlement with SPP, a potential cost recovery defect and potential cost-sharing for customer-funded upgrades.
The committee decided that the Market Subcommittee will discuss a possible cost recovery gap, an issue raised by Entergy. The gap arises when MISO decommits or manually redispatches a resource to offline status, the utility contends.
“If the resource is later brought back online to fulfill the remainder of an existing commitment period or to meet a subsequent commitment period, the resource is not guaranteed start-up cost recovery,” Entergy said.
The company wants the RTO’s Tariff revised “to provide incentive for resources to follow MISO instructions and to ensure that a resource owner is not forced to choose between following MISO instructions and incurring an uncompensated cost, and disregarding MISO instructions.”
A discussion on generator-funded upgrades that benefit other interconnection customers was assigned to MISO’s Regional Expansion Criteria and Benefits Working Group (RECBWG), despite a request by EDF Renewables that the topic be directed to the Interconnection Process Task Force (IPTF). The company wants such projects to receive some reimbursement through MISO, EDF said.
Jeff Webb, MISO director of planning, said the IPTF would be appropriate if project costs were only to be shared among interconnection customers, but he doubted that cost-sharing would be that limited. He suggested that the RECBWG first discuss the potential scope for cost allocation.
A stakeholder discussion on metrics used for the SPP-MISO transmission cost allocation settlement will initially be assigned to the Resource Adequacy Subcommittee for an examination of possible capacity benefits.
Jesse Moser, MISO director of seams relations and strategy, said internal decisions on the metrics belong in the RECBWG, which is already considering broader cost allocation changes. Still, some stakeholders contended that the issue should first move into the RASC for exploration of potential capacity benefits from the settlement.
The settlement requires MISO to “conduct a stakeholder discussion regarding the use of capacity benefits as an alternative way to allocate costs” of the joint operating agreement (ER14-1736). (See “Cost Allocation Set in MISO-SPP Settlement,” MISO Market Subcommittee Briefs.)
Madison Gas and Electric’s Megan Wisersky said she was surprised to learn MISO would delve into a cost allocation discussion before assessing the resource adequacy impacts of the settlement.
Indiana Utility Regulatory Commission staffer Dave Johnston said the topic should be discussed in the RASC.
“To me, RECBWG is for transmission projects,” Johnston said. “This is not what this is. This is a settlement between parties with a bucket of money.”
WILMINGTON, Del. — PJM must determine how to handle different rules for new and existing pseudo-ties after stakeholders vetoed a package of reforms for external resources at Thursday’s Markets and Reliability Committee meeting but then agreed on applying the updated rules only to new pseudo-tie requests.
The package appeared headed back to the drawing board after failing to reach the 3.33 out of 5 necessary in a sector-weighted vote. But Exelon’s Jason Barker immediately motioned for a vote on an “alternative” package that excluded existing pseudo-ties from the new requirements, saying it would “move toward something that we think is an improvement over the status quo.”
The original proposal, developed through the Underperformance Risk Management Senior Task Force, called for making deliverability requirements uniform for resources within and outside of PJM’s footprint and requiring confirmatory feasibility studies for all pseudo-ties. Existing pseudo-ties would have had until delivery year 2022/23 to conform to the deliverability standards for internal resources. (See No End in Sight for PJM Capacity Market Changes.)
By Oct. 1, 2018, PJM would notify external resource owners whether their pseudo-tie is operationally feasible. Owners of resources that fail would be required to perform the required upgrades or would be declared ineligible to offer capacity.
Stakeholders balked at the implication that their units might become nonviable if the transmission owner — over which neither they nor PJM has authority — declined to meet the new standards.
“It’s their system; they can do things their way,” said Mike Borgatti of Gabel Associates.
PJM’s Adam Keech acknowledged, “We’re not in a place where we can require someone to upgrade to our standards.” He estimated there is roughly 3,500 MW of external generation pseudo-tied to PJM.
Joe Bowring, PJM’s Independent Market Monitor, called the original proposal “a significant step forward” but still inadequate because imported capacity remains an inferior substitute for internal capacity resources and suppresses market prices.
“If units don’t meet the rules and requirements, they don’t meet the rules and requirements. That should be the end of the story,” he said.
When the measure failed and Barker proposed applying the updated standards to new pseudo-ties, Bowring questioned whether Barker intended for existing pseudo-tied units to then be grandfathered in perpetuity. Stakeholders agreed that the alternative proposal would be silent on existing pseudo-ties and that portion would be sent back to the task force for further consideration. The measure was endorsed, receiving 3.97 in favor on a sector-weighted vote. The same proposal was later approved during the Members Committee meeting with 3.88 in favor.
PJM Senior Vice President of Operations and Markets Stu Bresler said there will need to be a discussion with the Board of Managers on having separate rules for similar groups. “We certainly can’t live that way for very long,” he said.
Work on Uplift Moves Forward Despite NOPR
In three decisive votes, stakeholders swiftly moved forward on efforts to address uplift.
The action was a far cry from last month, when PJM’s Dave Anders explained that the Energy Market Uplift Senior Task Force had only been successful in half of its goals. The task force endorsed two proposals to reduce uplift and volatility. However, it considered more than a dozen proposals to address cost allocation issues and couldn’t find majority agreement on any of them. The MRC instructed the task force to revote on the top five.
Earlier this month, the task force endorsed a package for the MRC to consider on Thursday. The proposal would maintain much of the status quo but include up-to-congestion transactions in the allocation of day-ahead and balancing operating reserves in the same way incremental offers and decremental bids are included. It would also remove the ability for internal bilateral transactions to offset deviation charges.
However, with FERC having issued a Notice of Proposed Rulemaking on uplift and UTCs on Jan. 19, PJM staff assumed stakeholders might want to postpone action on the issue until receiving clear direction from the commission. (See FERC Proposes More Transparency, Cost Causation on Uplift.)
Not so. “I think that PJM has shown in a lot of studies that UTCs do impact commitment and decommitment … and that’s a cause of uplift,” FirstEnergy’s Jim Benchek said. “If down the road that NOPR results in rulemaking actually happening … then we’ll deal with that rulemaking at that time. My final comment is let’s vote today.”
So they did: The Phase 1 proposal was approved with a sector-weighted vote of 4.1 out of 5. It largely maintains the status quo, except that it includes in the determination of balancing operating reserve credits only the day-ahead revenues from the hours the resource operated in real-time, not all day-ahead revenues.
The proposal to postpone voting on Phase 2 for one year was opposed by 3.8 out of 5 in a sector-weighted vote, and a vote on the package succeeded with 4.01 out of 5. The proposals will go for a vote before the Members Committee at its Feb. 23 meeting to approve the Operating Agreement revisions and endorse revisions to the addendum to Attachment K of the Tariff. The Tariff revisions will then need to be approved by the Board.
Separately, stakeholders also approved a problem statement and issue charge to reconsider historical practices and provisions in the Operating Agreement and Manual 33 restricting the sharing of data that is considered confidential or market sensitive. Changes could result in more transparency on transmission constraints, the reliability assessment commitment process and conservative operations in day-ahead and real-time operations.
Stakeholders OK Manual Changes
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Revisions to Manuals 11 and 12 to account for the updated regulation requirement developed by the Regulation Market Senior Issues Task Force. (See “Regulation Requirement Changing from ‘Peak’ to ‘Ramp,’” PJM Operating Committee Briefs.)
Revisions to Manual 27 developed as part of an annual review.
Revisions to Manual 38 developed as part of a periodic review to provide more clarity on outage coordination.
Revisions to Manual 40 that, among other things, reduce the grace period for completing operator training. (See “Manual 40 Revisions Approved with Exelon’s Addendum,” PJM Operating Committee Briefs.)
Revisions proposed by the Governing Document Enhancement & Clarification Subcommittee to clean up definitions in the Tariff, Operating Agreement and Reliability Assurance Agreement.
Members Committee
Members Approve Charter for Security Committee
Despite stakeholder inquiries about its non-decisional status, the Members Committee endorsed by acclamation the charter for a new Security & Resiliency Committee.
American Municipal Power’s Ed Tatum asked what purpose the group would serve if it didn’t make any decisions. PJM staff said it would operate in an advisory capacity like the Transmission Expansion Advisory Committee. Exelon’s Gloria Godson clarified that the group was not formed at the behest of transmission owners.
“This was not a [Transmission Owners Agreement-Administrative Committee] idea,” she said. “In fact, a lot of TOA-AC folks have an issue with this idea.” (See “Preview of Security Committee Receives Tepid Response,” PJM Markets and Reliability and Members Committees Briefs.)
According to PJM, the new committee will serve as a forum to discuss threats and hazards and offer case studies, solutions or other best practices. To avoid compromising company security, the committee won’t include any Critical Energy Infrastructure Information in meetings and the news media will be barred. It will password-protect its minutes and only allow external partners by invitation. Corporate nondisclosure agreements will be used as needed.
Consent Agenda Endorsed
The committee also endorsed:
Operating Agreement revisions associated with residual auction revenue rights enhancements.
