MISO’s average load during July was 87.9 GW, 4.8 GW more than June and about the same as last year, said Shawn McFarlane, executive director of strategy and enterprise risk management, during an Aug. 23 Informational Forum.
McFarlane said July temperatures were close to normal. Load peaked at 120.7 GW on July 21 during a maximum generation warning. (See “June Energy Prices Up Across Footprint; New Emergency Pricing Encounters Snag in July,” MISO Informational Forum Briefs.)
Systemwide, MISO experienced average July prices of about $30/MWh, about $1/MWh more than last July.
Price convergence in July was the lowest it has been in a year, with a 22.5% difference between real-time and day-ahead prices. At this time last year, there was an average 14.8% divergence. Collections for day-ahead market congestion, at $80.26 million for July, were also at their highest level in a year.
Wind generation contributed 4.3% of total MISO electricity production (2,457 GWh), 661 GWh less than June’s 6% share but more than in July 2015, when wind contributed 3.3% (1,975 GWh).
Queue Reform
Stephen Kozey, senior vice president for compliance services, said MISO will make a revised generator interconnection queue reform filing by the end of October. FERC rejected MISO’s proposed queue changes in March, saying they assumed the current backlog could be blamed on “speculative” projects and failed to consider other potential factors (ER16-675). (See MISO Queue Changes on Hold Pending Technical Conference.)
Kozey also reminded stakeholders that MISO has pushed back implementation of a separate, three-year forward capacity auction for retail-choice areas to the 2018/19 planning year. He said MISO now plans to file in early November. (See MISO Delays Forward Auction Filing; Issues Draft Tariff and Business Rules.)
FBI Agent Informs Stakeholders on Cybersecurity Threats
Special Agent Michael Alford, of the FBI’s Cyber Division, said cyberterrorists, foreign governments and hacktivists most often attack critical energy infrastructure, in what he called a general cybersecurity “declassified briefing” at the Informational Forum.
Alford said hacktivists will sometimes target energy companies over proposed pipelines and development, while foreign governments conduct intrusions for espionage. He said according to the FBI, the energy grid is increasingly becoming a prime target for cyberattacks.
Alford said cyber threats can begin with a single attacker contacting an employee that they’ve performed “Internet reconnaissance” on. He told attendees to be mindful of the information shared on their social network profiles, as hackers will use the pages to gain employee information.
“If you have a LinkedIn account, that’s fine, but be aware that could be used against you,” Alford said.
He said the “end goal” of IT administrators should be to have a good log-in and password system and maintain it.
“You can throw tons of money at a system and make it secure, but that’s not always needed,” Alford said, noting that different departments at the same business need different levels of security.
Alford said utility employees shouldn’t hesitate to report cyberattack suspicions to either local law enforcement or the FBI.
“If you see something, report it, because you’re probably not the only one they’re attacking,” Alford said, adding that state-sponsored attacks often target several businesses or organizations simultaneously.
Responding to policy initiatives from Washington and Albany, NYISO last week released a “road map” for integrating distributed energy resources that seeks to build on the grid operator’s existing markets and demand response programs.
The ISO said the draft report was a response to the New York Public Service Commission’s Reforming the Energy Vision initiative, and FERC Orders 719 and 745, which require the ISO to give DR greater access to real-time markets. NYISO says it provides a framework for market rules that will be developed over the next three to five years to implement the state and federal policies.
Demand Elasticity
NYISO said it agrees with the PSC that DER “can make load more dynamic and responsive to wholesale market price signals.”
The PSC says DER can improve system efficiency if their value is properly reflected in retail and wholesale markets and if utilities are incented to consider them as alternatives to traditional capital investments. The commission envisions the creation of distribution system platform (DSP) providers that plan, operate and administer markets for distribution-level services.
NYISO said REV is largely consistent with how the ISO “administers wholesale markets, plans for bulk system needs and operates the grid.”
Competitive wholesale markets, the ISO notes, were designed in part to facilitate demand-side elasticity. “For a variety of reasons, ranging from the economics and limitations of enabling technologies, this demand elasticity has failed to materialize to a significant degree.”
But with improved technology and economic models, NYISO said, integrating DER into the wholesale markets could “build upon the efficiencies already realized under competitive wholesale market structures.”
‘A Desire to Participate’
The ISO said its new rules will accommodate “controllable resources with various capabilities and a desire to participate in the wholesale markets.”
The report says DER will be incented through economic dispatch and real-time locational prices “that [align] compensation with system requirements.”
“The NYISO intends for the DER program to align incentives and compensation based on the flexibility and measured performance of the DER (or aggregation), and market clearing prices based on the needs of the system. The intent is to treat DER comparably with other supply resources participating in the NYISO’s energy, capacity and ancillary services markets.”
DER participating in the capacity market will be required to offer into the energy and ancillary services markets “for all or a portion of the day, depending on the business model and capabilities of the DER.”
Changes Needed
The ISO said integrating DER will require changes to market design, system planning and grid operations.
“Realizing this goal will require an examination of DER performance obligations, operating characteristics, metering and telemetry requirements, measurement and verification of baselines and performance, market modeling, and an understanding of how to balance the simultaneous participation of DER in retail/distribution-level programs as well as the NYISO’s competitive wholesale market.”
A particular concern will be ensuring accurate load forecasts and metering.
DER will be required to provide data quality equivalent to the “Point Identifier1” metering used by large generators, with “real-time supervisory control and data acquisition (SCADA)-quality or better telemetry data for operations and monitoring functions, and after-the-fact revenue-quality meter data from individual resources for measurement and verification and settlements.”
These measurement and verification services may be performed by distribution service platform providers.
DR = DER
Going forward, NYISO said it will consider all DR as DER.
Source: NYISO
The current Special Case Resources program “has proven to be a valuable tool for planners to project load forecasts and for operators to manage system reliability” and will be retained, albeit “with potential modifications,” the report says.
The Emergency Demand Response Program and Price Capped Load Bidding also will continue. But the current Day-Ahead Demand Response and Demand Side Ancillary Services programs would be replaced.
The ISO says the report is only a beginning. “Implementing the DER initiative will entail considerable time, effort and stakeholder engagement. This road map represents a starting point for initiating discussions that will lead to further refinement on key market design elements, functional requirements and tariff language necessary to implement the vision.”
AUSTIN, Texas — Acting on a request from Texas Gov. Greg Abbott’s office, ERCOT has drafted a revision to its planning guide requiring energy developers to notify the Department of Defense of any projects near military installations.
The planning guide revision request (PGRR 047) was unanimously approved by ERCOT’s Technical Advisory Committee last week and will be considered by the Board of Directors during its Oct. 11 meeting.
The revision requires developers seeking an interconnection agreement to include among their materials a signed affidavit that they have notified the department of its proposed project and requested its review. The declaration only requires the initiation of an informal review, not its completion.
The proposed change is in response to requests by the governor’s office and the Defense Department to require that any proposed construction covered under existing federal regulations “confirm that they have provided notice and obtained review from the [Federal Aviation Administration] and DOD to the extent required under federal law.”
Current federal regulations require any structure constructed above certain height limits (approximately 200 feet) or in proximity to military and civilian airports provide notice to the FAA and DOD siting clearinghouse.
Several projects have recently brought the issue of federal notification to the forefront.
Sheppard Air Force Base near Wichita Falls has said proposed wind developments nearby would interfere with its radar and flight training operations. A proposed wind farm near Corpus Christi in South Texas has drawn concerns that it could impact training missions at two nearby U.S. Navy airbases, despite FAA’s conclusion to the contrary. (See “FAA Stands by its Greenlight for Proposed Wind Farm,” Federal Briefs.)
Speaking before the Texas House of Representatives’ Defense and Veterans Affairs Committee on Aug. 24 in Wichita Falls, ERCOT Director of System Planning Warren Lasher said he wants to see “increased coordination and communication” between the military and wind energy developers to resolve conflicts. “This will ensure that all energy developers check with DOD well before” the developments are put into motion, he said, according to an account in the Times Record News.
The TAC ensured the proposed rule would only affect developments that are not already connected to the power grid. The committee set Nov. 1, 2016, as the effective date for the change, after staff tracked down Lasher at a Public Utility Commission of Texas meeting for his approval.
Related legislation is expected to be proposed when the Texas Legislature begins its 2017 session in January. A Wichita Falls representative is considering filing a proposal that would affect tax abatements for some wind projects near military bases, while a New Braunfels legislator has said she would intervene if an energy project endangered military missions, the Times Record News reported.
Changes in TAC Leadership
Last week’s meeting marked the end of Randa Stephenson’s tenure as TAC chair. Stephenson, of the Lower Colorado River Authority, was recently named the utility’s vice president of wholesale markets and support.
Stephenson said her new job came with additional responsibilities that would preclude her continued role as TAC chair. She said she was disappointed but would continue to participate through the end of the year.
“Are you really disappointed?” asked ENGIE’s Bob Helton, to peals of laughter.
Stephenson “has been a workhorse for the TAC process for many, many years,” said CPS Energy’s Adrianne Brandt, who was unanimously approved as Stephenson’s replacement. “She’s given us almost five years of TAC leadership. It’s a lot of work and a thankless job.”
Helton was unanimously approved as the TAC’s vice chair, replacing Brandt.
TAC Sends 16 More Change Requests to Board
The committee sent 16 other revision requests to the board, endorsing eight Nodal Protocol revision requests (NPRRs) and eight revisions to the nodal operating guide (NOGRRs), the planning guide and the retail market guide (RMGRRs). All but one of the requests passed unanimously.
In addition, the TAC tasked the Wholesale Market Subcommittee to develop a long-term solution for reliability-must-run mitigated offers after a related rule change failed on appeal last month at the committee and this month before the board (NPRR 784). (See “Board Rejects RMR Mitigated-Offer Appeal, Lets Stakeholder Process Move Forward,” ERCOT Board of Directors Briefs.)
“In our discussions with stakeholders, it seems there’s general support for a long-term solution gravitating around placing RMR offers last in the stack,” said NRG Texas’ Bill Barnes, who has championed the revision request.
The 16 revision requests approved are:
NPRR 753: Gives non-modeled generators the option of using the advanced metering system data submittal process and requires the installation of ERCOT-polled settlement meters to ensure the energy flows are reflected in real-time initial statements.
NPRR 760: Ensures that operating days with no activity are captured in the denominator for calculations of credit variables. It received two no votes and three abstentions.
NPRR 778: Changes competitive retailer rules regarding move-in or move-out date changes to prevent an inadvertent error. The change should eliminate two-thirds of manual interventions currently required.
A companion change, RMGRR 139, modifies market processes to align with NPRR 778’s proposed changes.
NPRR 779 and PGRR 048: Clarify references to the Texas Reliability Entity and the Independent Market Monitor. Current protocols refer to the Texas RE in both its capacity as the Regional Entity and the Public Utility Commission of Texas Reliability Monitor. The NPRR also removes the 24-hour deadline for ERCOT to notify the Reliability Monitor of a failure to provide ancillary services. The new language clarifies that the IMM is an included party in several provisions related to the ERCOT stakeholder process.
NPRR 782: Removes inconsistencies in protocol language by changing the equations governing the settlement of ancillary services. The change affects resources unable to deliver on their ancillary services obligations because of transmission constraints.
NPRR 785: Allows ERCOT to automatically prepopulate current operating plans (COPs) for wind and photovoltaic resources with the most recent forecast for the next 168 hours. Qualified scheduling entities representing these resources can either submit the prepopulated forecast as the COP by default or submit a lower number.
NPRR 786: Corrects the allocation of transmission losses, distribution losses and unaccounted-for energy (UFE) so that negative loads do not result in loss of UFE allocations.
NPRR 787: Removes the requirement that the qualified scheduling entity receiving a verbal dispatch instruction confirmation include the name of the individual that received the confirmation within the electronic acknowledgement.
NOGRR 150: Moves voltage-support obligation language to the Operating Guide so that the requirements are recognized as binding. It also allocates voltage-support responsibility to the appropriate entity, and clarifies that the ERCOT transmission operator has the authority to instruct a QSE to modify its resource’s voltage set point.
NOGRR 158: Modifies language in the nodal operating guide relating to limits on hydro resources’ responsive reserve to ensure consistency with NPRR 669.
PGRR 049: Removes the option to submit generation interconnection or change request (GINR) applications through standard mail or fax and updates the mailing address for GINR payments to the ERCOT treasury department.
RMGRR 134: Gives non-modeled generators the option to use the advanced metering system data-submittal process and clarifies processes for unregistered distributed generation versus registered non-modeled generators.
RMGRR 140: Removes the current date restrictions to give ERCOT increased flexibility when executing a competitive retailer’s acquisition of another retailer’s customers to prevent a “mass transition event.” The change will prevent end-use customers from being transitioned to provider-of-last-resort service and reduces associated uplift to the market.
RMGRR 141: Clarifies procedures during an extended unplanned system outage.
A Wisconsin wildlife hospital’s dispute with American Transmission Co. over its “Grandfather Spruce” tree will go to trial after a judge this month denied the utility’s motion to dismiss the case.
Yvonne Wallace Blane and Steven Blane, founders of Fellow Mortals Wildlife Hospital in southeastern Wisconsin, filed the lawsuit in June against ATC after the company proposed to clear-cut a 50-foot easement into the 5-acre wildlife sanctuary for a 138-kV transmission line.
On Aug. 15, ATC’s motion to dismiss the case was denied by Walworth County Circuit Court, which also imposed a temporary restraining order preventing the company from cutting any trees or applying herbicides on the hospital’s property pending a four-day trial scheduled for Oct. 10.
Fellow Mortals’ lawyer Robert Kennedy, of law firm Rizzo & Diersen in Kenosha, said he plans to argue that the 1970 easement — between the property’s previous owners and ATC predecessor Wisconsin Power and Light — is ambiguous and intends that trees should be cut only if ATC’s lines are in danger.
A Wisconsin animal wildlife hospital won a temporary injunction to block American Transmission Co. from clear cutting trees along its 138- kV transmission line. The hospital says the trees provide their animals a “buffer” from the weather and traffic noise from the adjacent road. A 100-year-old Norway spruce towers above younger walnuts and other trees in summer (left), and winter (right).
‘Tough Case’
“We have a very tough case ahead because in one interpretation, we have a 50-year-old easement that does state that ATC can cut down any trees they want,” Kennedy said. “Our argument is the trees do not pose a threat.”
Kennedy said if ATC is allowed to clear-cut, it’s “very likely” that Fellow Mortals would have to shut down the sanctuary.
“ATC does not think Fellow Mortals is unique enough to warrant an exception, yet wildlife rehabilitation itself is an endangered resource,” said Yvonne Blane, who first opened the hospital with her husband, Steven, from their home in the mid-1980s before selecting the current location in 1994.
According to Blane, there were 229 licensed wildlife rehabilitators in Wisconsin in 2001; today there are 110. “Honestly, there aren’t a whole lot of wildlife hospitals like us left,” Blane said.
Blane said Fellow Mortals’ acreage used to be part of a farm that was split up following a house fire. “That simple farmer signed that easement so long ago because he had a kind heart. I don’t think he ever dreamed this would have happened,” she said. “I don’t think people think about easements, and this is a cautionary tale. Never ever find out later what contracts are tied to your property.”
Blane said she receives a letter from ATC “every few years” notifying them of trimming. Near the first of the year, Blane said she received another letter and assumed it was for routine trimming. “We worked with them in the past, and they’ve always been great,” she said.
However, Blane said she woke up one morning in February to see the area partitioned off with orange tape and blue X’s spray-painted on several trees.
“It’s a tremendous amount of wildlife habitat that they could be destroying,” said Kennedy, who first came across the hospital years ago when he brought in two orphaned woodchuck cubs.
Vegetation Management Plan
ATC says its vegetation management plan will minimize service interruptions and create access for maintenance, and that pruning trees, as has been done in the past, is less efficient than cutting the tall-growing vegetation on a regular rotation.
Aerial view of Fellow Mortals Wildlife Hospital Source: Google Maps
The company, which spoke to local media earlier in the dispute, is no longer commenting because of the litigation. Spokesperson Alissa Braatz would only say that the company is “removing all incompatible vegetation from the easement area for safety and reliability purposes.”
The Blanes say that mature trees and dense undergrowth on the easement are necessary to provide the animals a buffer against wind, snow and noise from the adjacent road.
They also say they are willing to pay for trimming. An estimated 100-year-old Norway spruce, or “Grandfather Spruce” as Fellow Mortals staff refer to it, has been periodically trimmed for the nearly 50 years the easement has been in place, most recently in 2009.
“The idea is to keep these animals segregated from humans as much as possible,” Kennedy said.
The Blanes posted photos on Facebook to show the spruce in winter, when it “alone buffers the wind and snow and noise and provides screening and privacy” for the wildlife. There is additional cover from young walnut trees and other vegetation “during the busy summer months, when traffic on rural Palmer Road is nearly constant,” they wrote.
Hawks, Woodchucks and Deer
Unlike other animal rescue facilities that transfer wildlife elsewhere for care and rehabilitation, Fellow Mortals keeps its animals from the time they are admitted to when they’re released. Over the years, its patient list has included owls, hawks, rabbits, woodchucks, beavers and deer. The Blanes and their small staff have treated 1,400 animals so far in 2016.
Blane said the hospital treats about five large birds per year, including cranes that are admitted with leg fractures from colliding with transmission lines. She said the hospital has spent about $25,000 in donations so far on the case, and she regrets it can’t be spent on the “hundreds” of animals currently in the hospital’s care.
“We bought [the property] for the trees and the location,” Blane said. “Everything has been built around the property we chose. We were offered other property for free and turned it down. We created a very special place here that we thought would be around for a long time.”
Room for Settlement?
The couple argues that no power interruption incidents have ever occurred on their premises.
According to the Blanes, the spruce was recently examined by a certified master arborist and given a low risk of falling. Kennedy said he is prepared to call on a tree expert who can testify the spruce is “solid as a rock” and any weather event that causes the tree to fall would also cause severe damage to ATC’s lines.
Their attorney says the only suggestion ATC has offered Fellow Mortals in the dispute is not much of a compromise: The company has offered to plant low-lying vegetation after the trees are removed. Kennedy says that is not an option.
“We would accept some trimming, but we have pictures of the clear-cutting they’ve done in other places. It looks like a Brontosaurus rampaged it,” he said.
“There’s no question that it’s more profitable for ATC to clear rather than trim periodically. If you clear-cut, you can wait 20 years before sending crews back out. But it’s a cost-saving measure on the backs of all these landowners with nice forested areas,” Kennedy said.
Town Weighs In
The hospital’s online petition protesting ATC’s plans has gathered more than 86,000 supporters, nearing their 90,000 goal. It also gained an ally in the town of Geneva, which has an ordinance that requires town approval for all tree cutting and sharply restricts clear-cutting.
“As I am sure you are also aware,” Town Attorney Richard W. Torhorst wrote in a June 9 letter to ATC, “the Federal Energy Regulatory Commission takes the position that best practices relating to vegetation management does not require clear-cutting along the right of way.”
ATC attorney Christopher Zibart fired back with a letter the following day saying that the company recognized the state Public Service Commission — and not the town — as having “the authority to regulate this core public utility function.”
Street view of Fellow Mortals Wildlife Hospital Source: Google Maps
Zibart also swatted away Torhorst’s reference to FERC, noting that ATC’s line X-55 is below FERC’s 200-kV voltage threshold.
“In any event, the FERC does not manage specific vegetation practices and has stated that it does not ‘mandate nor prohibit’ removal of trees,” Zibart continued. “Where, as here, the specific trees in the right of way are incompatible with the line (they will continue to grow back into the lines and would not likely survive whatever ‘trimming’ could be done), it is best to remove them.”
The town attorney acknowledged that the town’s ordinance does give public utilities an exemption from obtaining a permit for tree trimming, but he said ATC is “not exempt from the prohibition against clear-cutting,” which allows exceptions only for residential properties.
‘Positive Balance’
ATC’s Braatz told local website MyWalworthCounty.com in June that the company hopes to reach a settlement that would include “compatible vegetation and fencing to help create the privacy and noise buffering that they desire.” The company has a Web page illustrating the low-lying plants it recommends for rights of way.
“We believe this would accomplish a positive balance between ATC’s responsibility for ensuring safe and reliable electric service and the Fellow Mortals’ compassion and commitment for healing wildlife,” she said.
“I think what ATC is doing is unethical and not community-minded, and I think there are employees in the company who are uncomfortable with how far this has gone,” Blane said. “I don’t know why it’s so important for ATC to be right except they might be afraid that this is going to set a precedent.
“The voltage has remained the same. The poles have remained the same. The only thing that’s changed is ATC’s policy.”
Northern Indiana Public Service Co. said last week it may shut down one coal-fired plant and partially close another.
Though nothing has been finalized, NIPSCO officials said they are considering closing the two-unit Bailly Generating Station on Lake Michigan as soon as mid-2018 and idling two of the four units at the R.M. Schahfer Generating Station in Wheatfield, Ind., by 2023. NIPSCO’s plan was unveiled last week at a public meeting on its biennial integrated resource plan, which is due to the Indiana Utility Regulatory Commission on Nov. 1.
Bailly Generating Station Source: NIPSCO
“Companies with aging coal-fired units are facing intense economic and environmental regulatory pressures that are driving important decisions today about how to meet the customer needs of tomorrow. Given these factors, we believe it may be in our customers’ best interests to retire some of NIPSCO’s coal-fired generation units,” Violet Sistovaris, NIPSCO executive vice president, said in a statement.
Sistovaris said NIPSCO would work closely with stakeholders to come up with a retirement strategy for inclusion in its IRP, which looks ahead 20 years.
The retirement dates coincide with the effective dates of EPA’s coal ash rule in 2018 and Effluent Limitations Guidelines in 2023.
Graycor Industrial Constructors completed a Wet Flue Gas Desulfurization system at NIPSCO’s R.M. Schahfer Generating Station located in Wheatfield, Ind., in 2014 Photo Source: Graycor
NIPSCO, which has invested more than $800 million in emission-reducing technologies for its coal-fired units, said compliance with the new rules would cost an additional $1 billion over seven years if it keeps its entire coal fleet operating.
Six years ago, 90% of NIPSCO’s generation capacity was coal-fired. Today, that figure is down to 72%. NIPSCO’s portfolio includes three coal-fired plants, one natural gas–fired station, two hydroelectric plants and purchased wind power.
The closures at Bailly and Schahfer would remove about 31% of NIPSCO’s total generating capacity. Bailly’s two units opened in 1962 and 1968; Schahfer’s four units were opened over 10 years beginning in 1976.
This month, the company said it would demolish its long-dormant Gary, Ind.-based Mitchell Generating Station over the next two years for $18 million. The plant was permanently closed in 2011.
California lawmakers last week passed a bill to reduce the state’s greenhouse gas emissions to 40% below 1990 levels by 2030.
The State Assembly approved the measure on a 48-31 vote, largely along party lines. Two Democrats opposed the bill, with one abstaining, while just one Republican voted in favor. The bill breezed through the State Senate on a vote of 25-13 and is expected to be signed into law by Gov. Jerry Brown.
The bill builds on the California Global Warming Solutions Act of 2006, the landmark legislation that required the state to reduce its emission to 1990 levels by 2020. It also codifies an executive order issued last year by Brown, making it more difficult for a future governor to roll back efforts to reduce the state’s emissions.
“Today, the Assembly speaker, most Democrats and one brave Republican passed SB 32, rejecting the brazen deception of the oil lobby and their Trump-inspired allies who deny science and fight every reasonable effort to curb global warming,” Brown said in a statement in response to the Assembly’s vote.
Senator Pavley
“Today’s action sends an unmistakable signal to investors of California’s commitment to clean energy and clean air,” said Sen. Fran Pavley (D), author of the bill. “This will trigger more investment and more jobs in our thriving clean-energy sector and solidify California’s leadership in demonstrating to the world that we can combat climate change while also spurring economic growth.”
The bill affects the electric, manufacturing and transportation sectors. The state Air Resources Board (ARB) will determine specific reductions by industry.
Utilities — which could benefit from the electrification of the transportation fleet — have not opposed the bill and have been preparing for the change since last year’s executive order. The state’s renewable portfolio standard — 50% by 2030 — is expected to generate most of the needed reductions for the power sector. (See California Policy Goals to Require Significant Transmission Upgrades.)
Oil industry lobbying efforts unexpectedly stalled SB 32 in California’s assembly last year, but supporters wrangled a comfortable margin to pass the bill during the current session. Photo of Valero Benicia Refinery
The oil industry lobbied hard against the legislation, which faced uncertainty since stalling in the Assembly last summer. Prospects soured after a group of Democrats representing low-income communities opposed the bill based on concerns that efforts to reduce the carbon content in gasoline would translate into higher fuel prices, which disproportionately affect people with lower incomes. Some lawmakers also complained that the bill provided the ARB with too much latitude to develop and implement emission-reduction programs without sufficient public oversight.
To address both concerns, the legislature last week passed a companion bill (AB 197) that will put two legislators on the ARB as nonvoting members and require the board to report annually to a newly created joint legislative committee on climate change policies. It also directs the ARB to prioritize emissions rules and regulations that limit economic impact on the state’s disadvantaged communities and regions reliant on agriculture.
Implementation of SB 32 was contingent on the passage of AB 197.
The current version of SB 32 does not extend the state’s cap-and-trade system, which is set to expire after 2020. The California Chamber of Commerce is challenging the program in court, contending that the emissions trading scheme constitutes a tax requiring approval by a two-thirds majority of the legislature.
That legal uncertainty has undermined investor confidence in the market for California carbon credits. The ARB-run auction Aug. 16 saw buyers pick up less than 35% of available allowances, following a dismal 10.5% showing in May. Previous auctions have typically been fully subscribed, providing significant revenues for the state.
Still, in light of last week’s Assembly vote, Brown expressed optimism about the program.
“With these bills, California’s charting a clear path on climate beyond 2020 and we’ll continue to work to shore up the cap-and-trade program, reduce super pollutants and direct more investment to disadvantaged communities,” Brown said.
Eversource Energy and National Grid have withdrawn their requests to bill electric ratepayers for natural gas capacity from the proposed Access Northeast pipeline project, bowing to a ruling by the Massachusetts Supreme Judicial Court.
The filings made Monday for their four electric distribution companies followed the court’s Aug. 17 decision vacating an order by the state Department of Public Utilities approving pipeline capacity contracts. (See Mass. Supreme Court Vacates EDC-Pipeline Contract Order.)
Last week, state Attorney General Maura Healey filed a motion asking the DPU to dismiss the contracts.
Eversource spokesman Michael Durand said the companies’ filings with the DPU were a formality in light of the court’s decision. “This does not affect our commitment to the project. We remain committed to working with the New England states to provide the infrastructure so urgently needed to ensure reliable and lower-cost electricity for customers,” he said.
“The companies reserve the right to seek department approval of the same or similar agreements in the future to the extent that, in the future, there is a change in relation to the department’s legal authority to approve such agreements,” Eversource wrote. National Grid made an identical filing on behalf of its EDCs.
Eversource and National Grid are co-sponsors of Access Northeast, which developer Spectra Energy says will deliver 925,000 dekatherms/day of natural gas to the New England power market.
Spectra spokesman Creighton Welch said the company is not giving up on the pipeline. “There is a sizeable need for natural gas throughout New England that is unabated by the court’s decision,” Welch said. “Therefore, our path forward is clear and our mission to re-establish the Massachusetts contribution is full-speed ahead. We are confident that, ultimately, the interests of New England’s consumers will prevail with desperately needed gas supply made available by Access Northeast.”
The Conservation Law Foundation, the successful plaintiff in the case, said the EDCs had no choice. “The Massachusetts Supreme Judicial Court made it clear last week that electric companies can’t gamble on pipelines with the hard-earned money of businesses and families across our state. That is exactly what these contracts would have done, and so Eversource and National Grid had no choice but to face reality and withdraw their proposals,” spokesman Josh Block said.
FERC last week approved rule changes to improve the ability of energy storage resources to participate in CAISO’s markets (ER16-1735).
The changes will allow “non-generator resources” to submit their state-of-charge as a bid parameter in the day-ahead market and manage their own state-of-charge and energy limits for the purposes of bidding into the market.
Non-generator resources are those that can be dispatched to generate, consume or curtail consumption of energy to any operational level within their specified capacity range.
The non-generator resource model is the primary means by which energy storage devices currently participate in CAISO’s market, enabling batteries to continuously operate across a range that includes both charging and discharging. For bidding purposes, the ISO assumes that the available energy from a storage resource is a function of the resource’s state-of-charge — information the ISO obtains through telemetry.
While that approach is sufficient for real-time operations, CAISO contends that it does not provide a storage resource’s scheduling coordinator a “usable” bid parameter for the day-ahead market.
Under current day-ahead bidding practices, CAISO assumes that a resource’s initial state-of-charge is the ending value from the previous day’s day-ahead award. If there was no such award, the ISO assumes the charge to be 50% of the resource’s megawatt-hour limit.
The Tariff change will allow a scheduling coordinator to replace the ISO’s assumed state-of-charge values with its own bids “to better reflect actual conditions” for a storage resource, CAISO said in its proposal.
Sodium sulfur battery storage facility at Pacific Gas and Electric’s Vaca-Dixon substation. Source: California Energy Commission
“CAISO contends that non-generator resources choosing to self-manage their energy limits and state-of-charge will be able to maintain their states-of-charge at an optimal level through their bidding strategies, enabling resources to better account for dynamic needs in real time and avoid uninstructed imbalance energy settlements,” the commission’s order explained.
The commission’s ruling will also enable CAISO to implement a mechanism to allow energy storage devices to more effectively participate in the ISO’s demand response programs. Those programs measure demand reductions by comparing actual consumption relative to a baseline of expected consumption.
But when demand is offset by a behind-the-meter generation device — such as a storage resource — and “there is no sub-meter to separate consumption and energy produced on site, this approach fails to distinguish the cause of the demand response,” the ISO wrote. “The CAISO cannot tell whether the [DR provider] is curtailing consumption or serving its load from a behind-the-meter resource.”
To remedy the problem, the ISO consulted with stakeholders to develop special metering methodologies.
“These performance methodologies will accommodate sub-metering and allow the CAISO to ascertain demand response performance based upon the gross load [of a DR provider] independent of behind-the-meter generation, the behind-the-meter generator output itself or both,” the ISO said.
Acknowledging stakeholders’ criticism, PJM removed capacity-deficiency and administrative penalties it had proposed for its fuel-cost policy rules and instead offered a single formula-based one. The proposal was made in the compliance filing PJM submitted to FERC on Aug. 16 (ER16-372-002).
The filing was supposed to focus on improving flexibility for hourly generation offers, but PJM also proposed changes to its policy-approval rules and penalties that it said were “integral to the effective clearing of cost-based hourly offers.” The RTO announced it was simultaneously initiating a petition under Section 206 of the Federal Power Act to get the additional changes implemented in case FERC decided their inclusion was outside the scope of the compliance order.
The debate over the rules governing fuel-cost policies stems from a 2015 FERC order to allow day-ahead offers that vary by the hour and the ability to update offers in real time. (See Generators Balk at PJM Proposal on Fuel-Cost Policies.)
FERC wanted the changes made by November 2015, but PJM said at the time that the required revamp to its market system would make that timeline impossible.
Natural gas plants in PJM’s energy market, such as UGI’s Hunlock Creek Energy Center in Luzerne County, Pa., would be subject to the RTO’s rules on fuel-cost policies. Photo Source: Stantec
In this week’s filing, PJM requested an effective date of Dec. 1 for the penalty and policy-approval rules contingent on FERC issuing its approval by Oct. 17. Implementation on Dec. 1 would maximize the benefit of the rules, PJM said in the filing, because “winter is the season in which price volatility in the natural gas markets are most likely to occur.”
The Independent Market Monitor has requested a 10-day extension to the Sept. 6 deadline for submitting comments on PJM’s filing. The Delaware Public Service Commission filed comments in support of the Monitor’s request.
For the hourly offer market rules, PJM said it couldn’t accurately estimate an implementation date because it “will be one of the most in-depth and complicated undertakings in PJM’s recent history, as PJM’s systems have been designed and implemented on the basis of daily offers.” The RTO suggested it will take at least a year, but it requested approval of a timeline that gives it 30 days after FERC’s ruling to propose an estimated effective date and up to 30 days before that proposed date to determine a final effective date.
PJM kept much of its original submission for real-time offer regulations, but it proposed several definitions and revisions. Among them are:
Prohibiting generators from oscillating between market-based and cost-based offers;
Increasing the cutoff for real-time offers from 60 minutes to 65 minutes prior to the applicable clock hour to account for PJM’s ancillary services optimization engine; and
Prohibiting increases to a generator’s incremental energy offer, but allowing it to increase its market-based offers in real time to reflect increases in costs. (PJM proposes defining incremental offers as those pairing price and megawatt quantities, in dollars per megawatt-hour, which combine to include all of the energy segments above a resource’s economic minimum. It excludes no-load costs.)
The fuel-cost policy rules are designed to provide clarity for how policies will be reviewed, delineate submission requirements, define consequences and outline the role of the Monitor.
Sellers without a PJM-approved fuel-cost policy could only be price takers, making offers of $0/MWh. They would also be subject to the penalty, which is up to 75% of the product of the LMP paid to the seller and the unit’s capacity during the hour. The percentage starts at 5% on the day the seller is notified about not having an approved policy and increases 5% each day until a policy is approved. It caps out at 15 days, after which the seller continues to be penalized at that rate.
PJM proposes using the same penalty for a seller who submits an offer that doesn’t comply with its existing policy. The penalty structure is based on a formula used by ISO-NE.
Sellers who have policies rejected by PJM or the Monitor would revert to a previously approved policy until the rejected policy is satisfactorily amended. The RTO also proposed a procedure to revoke a seller’s policy altogether — meaning it would no longer have any approved policy — but said it would only be used in cases of fraud or when a policy doesn’t “remotely reflect” applicable fuel costs.
PJM also proposed an annual review process, in which sellers would have to submit by June 15 of each year any updated policies or confirm that the existing policy remains compliant. PJM would then have until Nov. 1 to provide the seller with a compliance determination.
Solar, storage and run-of-river hydro would be required to have a cost of $0, while wind would need to account for energy and tax credits. Waste-to-electricity resources, such as landfill gas and biomass facilities, would have to include fuel costs even if the facility is paid to accept the waste — meaning their fuel costs would be negative.
The policies would also need to include maintenance adders, heating requirements, unit-specific performance factors and start-up cost calculations.
The filing also detailed PJM’s understanding of the Monitor’s role, noting stakeholder confusion over its involvement in initial policy approval and ongoing oversight. In previous discussions on the topic, the Monitor has questioned PJM’s proposed regulations, saying they cross into its authority.
FERC “has made clear that the act of approval or disapproval of fuel-cost policies is one to be undertaken by PJM and not the IMM,” PJM said in its filing. Penalties would only be assessed if both PJM and the Monitor agree on it. In the event that they disagree, PJM proposed that the matter be referred to FERC’s Office of Enforcement.
During a conference call last week to review the filing, PJM staff clarified that specific implementation processes would be outlined later in changes to Manual 15. The changes will be reviewed by the Market Implementation Committee.
If FERC approval allows for an effective date prior to the beginning of the annual review process, PJM plans to concentrate initially on generation units without any policies or ones that received tacit PJM approval based on negotiations with the Monitor. It would then rely on the annual review process to ensure all units had approved policies. Under PJM’s existing protocols, some units have not been under any requirement to get a policy approved and others have undergone lengthy negotiation processes with the Monitor.
Both PJM and the Monitor described “significant philosophical differences” in their perspectives on the correct oversight scheme.
The “fundamental difference,” according to Monitor Joe Bowring, is his group’s role in the process. PJM made some “significant mistakes” in the filing and isn’t “correctly observing that division of labor set forth in the Tariff,” he said.
Ed Tatum of American Municipal Power asked about the differences in opinion on how short-run marginal costs should be handled.
Bowring responded that PJM’s proposed protocols should be adjusted. PJM’s Jeff Schmitt said that would be addressed in changes to Manual 15.
Jason Cox of Dynegy suggested that the penalty have tiered levels corresponding to whether a noncompliant offer affected the market price, but PJM said that was not part of the filing.
Entergy and Exelon filed a petition with New York regulators Monday seeking approval of Exelon’s $110 million purchase of the James A. FitzPatrick nuclear plant (16-E-0472).
Fitzpatrick Nuclear Plant Source: Entergy
The companies asked the Public Service Commission to approve the acquisition by Nov. 18. The PSC has a regularly scheduled meeting on Nov. 17.
“Prompt approval is warranted here because … the transfer does not raise any issues regarding retail energy sales to captive ratepayers, it does not raise any market power concerns in the competitive wholesale markets in New York or the adjoining regions and it is consistent with commission precedent,” the companies said.
The petition says an “investment decision” on refueling the plant must be made soon, as FitzPatrick’s current fuel cycle is expected to end about Jan. 31, 2017.
Entergy said last year it would close the money-losing plant in early 2017. Exelon agreed to purchase the generator after the PSC adopted a subsidy for the no-carbon emission attributes of nuclear power. (See Entergy Sells FitzPatrick to Exelon.)
FitzPatrick, which produces an average 7 million MWh annually, is licensed to operate through 2034.
If approved, Exelon would own all of the upstate nuclear fleet in New York: FitzPatrick, R.E. Ginna and Nine Mile Point 1 and 2. They total 2,267 MW, or 5.9% of the generating capacity in NYISO, according to the companies.
Entergy would still own the only other nuclear plant in the state, Indian Point in the Lower Hudson Valley.
Concern over Subsidy Payments
In a separate filing Monday, Exelon asked the PSC to guarantee subsidy payments for Ginna and Nine Mile Point in the event that its purchase of FitzPatrick plant falls through (15-E-0302).
The company said language in the Clean Energy Standard adopted Aug. 1 by the commission could be interpreted to end the subsidy in March 2019 if not clarified. The order directed the purchase of zero-emission credits (ZEC) in six two-year tranches from 2017 to 2029. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
The CES anticipated the FitzPatrick sale after negotiations between Exelon and Entergy were announced in mid-July.
“The FitzPatrick purchase condition [of the CES order] is unclear as to whether the 12-year duration of the R.E. Ginna facility’s, the Nine Mile Point facility’s and the FitzPatrick facility’s respective ZEC contracts are conditioned on the sale of the FitzPatrick facility by Sept. 1, 2018, or whether the 12-year duration language applies only to the FitzPatrick facility’s ZEC contract,” the petition states.
The petition says there is ambiguity in the order and its Appendix E, which states: “If the sale and closing does not occur, there will be no commitment for the program to continue beyond Tranche 1 and the commission will have six months before the otherwise planned commencement of Tranche 2 to determine a future course of action, if any.”
Exelon is asking for specific language to limit the two years of ZEC payments only to FitzPatrick if the sale is not completed.
It asks for a clarification or limited rehearing order by Nov. 18, the same date it has requested for approval of the sale.
