CAISO is seeking comment from market participants on three proposed modifications to the Western Energy Imbalance Market (EIM).
The grid operator on Tuesday kicked off the stakeholder process for the proposals, which include allowing third-party transmission providers to receive congestion revenue when they make unused capacity available between EIM balancing authority areas (BAAs).
| CAISO
In response to questions during a call on the initiative, CAISO said transmission owners will not have to turn over control of their transmission facilities to participate and would receive payment only if there is congestion on the system.
CAISO says the measure would increase transfer capacity among members, which the ISO’s internal Market Monitor has pointed out reduces congestion and limits the ability of any single participant to wield market power within its BAA. (See Increased Transfer Capacity Reducing EIM Congestion.) EIM entities can currently collect congestion revenue through an offset, but that functionality is not extended to third parties.
The ISO plans to use its existing functionality for transmission contributions, known as “energy transfer system resources” that are used to track, tag and settle EIM transfers. It will need to establish a pro forma agreement that enables scheduling coordinators to submit transmission contributions on behalf of a third party, and create a new make-whole mechanism that would guarantee a payment from congestion revenue. The ISO is seeking stakeholder input on what level of interval granularity those payments should be calculated and how their associated costs should be allocated.
CAISO also wants to correct an inequity that occurs when an EIM BAA wheels power between other BAAs. Wheel-through BAAs receive some revenue when congestion occurs but are not compensated if there is no congestion. In that circumstance, only the source and sink BAAs accrue benefits when a wheel-through transfer occurs.
“How should we quantify the benefits of providing EIM transfers through an EIM BAA?” CAISO asked in its meeting materials.
The ISO has also proposed a new policy for situations in which market participants change their bilateral schedules after submitting their hourly base schedules. Under current practice, changes made after submission are exposed to real-time imbalance settlement payments.
Settlement can result in either charges or payments, but there is no way for market participants to know the cost beforehand. Proposed changes would allow them to manage their exposure to imbalance settlement charges, CAISO said.
After the comment period ends June 30, CAISO will post a straw proposal on the initiative by July 27 and hold stakeholder meetings in August and September. The EIM Governing Body is set to review the proposals in October, ahead of a decision by the CAISO Board of Governors in November.
BRANSON, Mo. — MISO wants to spend $130 million over the next five years to construct a new market platform before its existing one becomes outdated, but its Board of Directors is insisting on a thorough stakeholder review of the project’s cost.
Jeff Bladen, MISO executive director of market design, said the upgrade would involve a “piece-by-piece replacement of components” resulting in a “far more modular platform” compared with the rigidity of the current system, which hinders market changes.
Swapping out market software incrementally instead of introducing a new platform all at once is the safer option, Bladen said.
“The risk of a misstep is far less using an incremental process,” he said during a rare June 20 joint meeting of the board’s Markets and Technology committees.
MISO’s current platform is “inflexible,” and even simple market changes require testing and retesting because of possible effects on other software, according to MISO Technology Executive Kevin Caringer. He likened the new design to Microsoft PowerPoint, which can recognize and accept fonts and graphics from other sources.
Looming Obsolescence
The RTO evaluated its market system last year and concluded it had five to seven years before evolving cybersecurity standards and increasing market complexity render the system — designed in the late 1990s — obsolete and no longer able to clear the day-ahead market. (See MISO Reaffirms 2023 End Date for Market Platform.)
“The time is now to begin long-term investment,” Bladen said. “Findings and conclusions drawn from the evaluation resulted in a clear call to immediately initiate a system upgrade.”
Caringer said MISO will spend about $3 million on cybersecurity to extend the life of the current platform for the five years needed for the switch to a new platform.
MISO is asking for an additional 25% contingency budget for unforeseen expenses in addition to the expected $130 million plan. Staff said it will present final cost estimates to the board in September. The board’s Audit and Finance Committee will decide whether to approve the spending in October, and a full board decision on the budget is set for December.
MISO staff predicts the project will yield a 4-to-1 return on investment, with $201 million in benefits, $254 million in cost avoidance and $111 million in risk mitigation.
Director Baljit Dail asked how MISO will prove the benefits and savings to its stakeholders.
Bladen said the RTO can share a recent benefits report once it removes nonpublic information from the document.
“I don’t want this to be jammed into December. At some point, I’m going to ask, has this report been scrubbed and has it been shared with stakeholders? I don’t want that to happen in December,” Dail warned.
Director Paul Bonavia wondered if MISO will give stakeholder groups a chance to collaborate to develop a process for responding to the benefits report.
Bladen responded that MISO expects to follow its normal annual budget process with stakeholder review occurring in the Finance Subcommittee.
“I appreciate that, but the budget process usually doesn’t have $130 million to $160 million in additional spending. One director’s strong counsel to you all is make sure the usual process can handle [this],” Dail said.
Other directors pointed out that the project’s benefits may play second fiddle to the market failure that looms if MISO does not implement a new market platform.
“I’m not too captivated by the benefits. We need to move,” Director Michael Curran said. “I’d love to see the benefits, but we have to spend the money. … It’s a burning platform; it’s a slow burn, but it’s coming.”
“My comment is, however you want to justify the benefit, it needs to be put before the stakeholders,” Dail replied. He suggested that MISO convene a special stakeholder committee to discuss the investment and consequences of not reconstructing the market platform.
“I’d like to see [the stakeholders’] fingerprints all over this,” Curran agreed.
Bladen said MISO could initiate stakeholder workshops to discuss building the platform.
In response to a question from Curran, Caringer said MISO could reach out to developers of its original market platform to help improve the transition. Some longtime MISO employees also have knowledge of the system, he said.
Curran said he wanted to require any potential project vendors to have contact with developers of the original system. CEO John Bear said the board would address that topic in a closed session that immediately followed the meeting.
The D.C. Circuit Court of Appeals on Tuesday denied eight challenges to PJM’s controversial Capacity Performance market rules, potentially cementing fundamental changes to the RTO’s capacity market that critics believe were hastily enacted and unjustifiably increase costs (16-1234).
CP was implemented following a blackout scare in January 2014 when the polar vortex dipped unusually low across the northern U.S. and created record-low temperatures. As much as 22% of PJM’s fleet failed to operate when dispatched, despite being contracted through the capacity market.
The new rules introduced year-round performance requirements for capacity resources along with incentives to perform and steep penalties for failing to do so.
Critics of the new rules argued they would increase the cost to secure capacity by billions of dollars. After FERC approved the changes in June 2015, challengers petitioned the commission for a rehearing, which the commission denied.
Nine organizations challenged FERC’s denial in court. The ensemble is a somewhat unusual partnership of environmental groups (the Natural Resources Defense Council, Sierra Club and Union of Concerned Scientists), representatives of utilities (the American Public Power Association, the National Rural Electric Cooperative Association and the Public Power Association of New Jersey), the Advanced Energy Management Alliance, which represents demand response resources, American Municipal Power, which represents both utilities and resources, and the New Jersey Board of Public Utilities.
FERC’s Reasoning Upheld
The ruling by Judges A. Raymond Randolph, Janice Rogers Brown and David B. Sentelle was unanimous. The court ordered the clerk to withhold issuance of the mandate resulting from the ruling to give the plaintiffs time to file petitions for rehearing before the three-judge panel or the full court.
Left to right: Judges A. Raymond Randolph, Janice Rogers Brown, David B. Sentelle | U.S. Courts
The court’s decision points out that FERC acknowledged the increased capacity costs but cited a study that estimated the new rules would create an annual net savings of potentially billions of dollars starting in 2016. The fact that the study used a penalty that was higher than FERC approved was immaterial, the court found.
“The savings come from the penalty successfully increasing reliability,” the court said in its decision. “Even with a lower penalty, the net savings may be substantial.”
FERC “does not have to find net savings” to approve proposed changes, the court found, and higher costs can be warranted if they increase reliability. FERC said the revisions would do that and also help avoid energy price spikes.
Year-Round Resource Requirement
PJM’s requirement that all CP resources be year-round attracted opposition from numerous groups.
NRDC, Sierra Club and UCS said that the requirement discriminated against seasonal generation such as wind and solar — despite the RTO’s offer that winter-only resources could aggregate with summer resources — because aggregation imposed “transactional costs.”
Utility Scale Solar in Maryland | Constellation
AMP, meanwhile, said aggregation should also be open to traditional resources.
The judges said none of the challenges persuaded them to question the commission’s judgment. “The commission’s policy decision to assess reliability through a year-round capacity commitment is the type of policy judgment to which we afford deference, and that deference is justified by the record,” they said. “The law provides no basis to claim the commission cannot approve uniform performance requirements simply because those requirements will be easier to satisfy for some generators than for others.”
Demand Response
AEMA had problems with CP’s impact on DR, challenging PJM’s proposal to use separate formulas for calculating expected consumption during summer months and non-summer months.
The group said it supported the “peak load contribution” method for the summer, which is based on a DR customer’s contribution to the five hours of the previous year when systemwide demand peaked. It opposed the “customer baseline load” method for non-summer months, which is based on the customer’s contribution to the system’s load for the four days of peak systemwide load during the most recent 45 days.
“Because it was reasonable for the commission to accept PJM’s proposal to use the recent-peak method for non-summer months and any alleged departure from past practice was adequately explained, we defer to the commission’s determination on this issue,” the court said.
AEMA Executive Director Katherine Hamilton said the court rebuff means consumers will face reduced choices and higher prices because residential DR and renewable resources “could be forced out of the market altogether.”
“In the recent auction, the amount of demand resources — both offered and cleared — fell by thousands of megawatts compared with previous years. PJM has now effectively ceded jurisdiction for monetizing these competitive products in the capacity markets, and it will be up to state commissions located in PJM to determine how these products will be operated going forward,” she said in a statement. “As AEMA considers legal options moving forward, we will continue working within the PJM stakeholder process on wholesale competitive market issues and with state commissions on demand response solutions for consumers.”
Procedural Challenge
The court also rejected challenges by APPA, NRECA and PPANJ to PJM’s filing of proposed changes to the capacity market under Federal Power Act Section 205 and its simultaneous Section 206 complaint proposing replacements for energy market rules it said were no longer just and reasonable.
PJM could not file changes to the Operating Agreement under Section 205 because it did not seek stakeholder approval of the changes.
The public power groups argued that the commission could not accept PJM’s Section 205 filing as just and reasonable while simultaneously finding that the filing rendered the Operating Agreement unjust and unreasonable under Section 206. “In effect, FERC found that PJM had created the factual premise and legal basis for FERC to order a change in rates that PJM could not have unilaterally made,” the groups said. “This bootstrapping of results is impermissible.”
The court said the petitioners failed to “explain why PJM’s Section 205 filings regarding the capacity market necessarily must complement existing energy market agreements to be just and reasonable” and cited “no precedent for their theory that the commission was required to act ‘under Section 206 alone.’”
“We therefore see no reason why the commission was not entitled to approve changes under Section 206 in anticipation of the impacts of the Section 205 filing rather than wait for those impacts to be realized,” the court ruled.
Penalties Too Low
PPANJ and the New Jersey BPU contended the CP penalties for resources that fail to meet their capacity commitments during an emergency hour were too low to ensure performance.
The commission approved a penalty rate equal to one-thirtieth of the net cost of new entry per megawatt-hour of shortage. The petitioners said the 30-hour denominator — based on the number of emergency hours in 2013-2014 — was too high, resulting in a penalty that was too low.
“The commission had good reason to conclude that the formula results in a high enough penalty to encourage resources to meet their capacity commitments,” the judges said. “The commission decided the penalty was also low enough to avoid introducing ‘excessive risk’ into the capacity market. Too high a penalty could discourage even reliable resources from entering the market. We defer to the commission’s balancing of these competing concerns.”
Default Offer Cap
Also rejected was a complaint by the BPU and four organizations representing utilities that PJM’s default offer cap, meant to reflect the CP penalties and bonuses, is too high. PJM would only include an offer above the cap in the capacity auction if it determines it is cost-based.
The court rejected complaints the cap could increase capacity costs, saying “increased capacity prices are necessary” to encourage entry of new, reliable resources. “Resource owners need to be able to offer capacity at a higher price in order to recover the costs of improvements,” it said.
Unit-Specific Constraints
AMP challenged the imposition of penalties on CP resources that fail to perform because of unit-specific constraints, saying it was inconsistent with energy market rules, which require PJM to cover resources’ costs if it schedules the them to run outside of their parameter limits.
“Given the different purposes of the capacity market and the energy market, there is no inconsistency in treating the operating-parameter limitations differently in the two markets,” the court said.
PJM on Monday secured U.S. Department of Energy approval to dispatch Dominion Energy’s recently shuttered Yorktown coal-fired plant to address potential reliability issues on Virginia’s Middle Peninsula.
Dominion, which closed the plant in April to comply with an EPA mandate, said it anticipated the department’s order and is prepared to restart both units at the plant as necessary.
Yorktown Generating Station | Dominion
Energy Secretary Rick Perry granted PJM’s request for a 90-day window to dispatch the units as necessary to “maintain grid reliability,” and the order can be renewed upon request indefinitely if the situation remains unchanged. PJM and Dominion are required to create a dispatch methodology and submit what dates the units are operated, along with estimated emissions and water usage, to the department.
“While this is not a long-term solution to the reliability issues, Dominion Energy supports PJM’s action and the DOE decision, and will work to ensure the units’ availability as required,” Dominion spokesperson Bonita Billingsley Harris said in an emailed statement.
Stalled Project
The order stems from Dominion’s difficulty in gaining approval for the proposed Surry-Skiffes Creek 500-kV transmission line across the James River, which has for years faced opposition from local and environmental activists. Approved by the PJM Board of Managers in 2012, the transmission project remains stalled pending permit approval from the Virginia Marine Resources Commission (VMRC) and a waiver from the state Department of Environmental Quality for water quality certification. The U.S. Army Corps of Engineers issued a conditional permit earlier this month that requires approval from both agencies.
Map of transmission system at Virginia’s middle peninsula | PJM
The project will additionally require a special-use permit from the James City County Board of Supervisors. Members of the public will have the opportunity to weigh in during both the VMRC and county permit hearings, Harris said.
Dominion estimates the line would take at least 18 months to construct after all permits are approved. The company had hoped to complete the project prior to closing the Yorktown units, which are among the few generators able to serve load in the populous but isolated North Hampton region.
While Dominion sought to shutter Yorktown by 2014 to avoid expensive emissions upgrades required by EPA’s Mercury and Air Toxics Standards, PJM required the units to remain operational to maintain reliability on the peninsula in the absence of the proposed line. State and EPA approvals extended the shutdown deadline several years, but applicable extensions finally ran out on April 15 and Dominion closed the doors.
Dominion warned that failure to build the line before shutting down the units could result in blackouts, an assertion opponents dismissed as scare tactics. In February, the company provided PJM a regional remedial action scheme that calls for dropping service to approximately 150,000 customers in the event of an emergency in order to prevent potential voltage collapse from N-1-1 contingencies. (See Opposition to Va. Tx Line May Trigger Unintended Consequences.)
No Surprise
The order didn’t catch Dominion by surprise.
“When it became apparent we would not receive approvals in time to complete the new transmission line before the coal units had to be retired, we pursued an aggressive plan of equipment upgrades, enhanced inspections, maintenance scheduling and contingency preparations to protect energy reliability on the Virginia Peninsula until the permanent solution could be put in place,” Harris said.
While the company was prohibited from running the Yorktown units after April 15, its contingency plans included keeping them in operating condition in case of an emergency, she added.
Despite its potential open-ended approval to run the units, Dominion said it remains committed to shutting them down and building the transmission line.
“This law protects PJM and Dominion from civil or criminal liability or citizen suit, but it is our intention to continue moving forward as quickly as possible to build and energize the transmission project limiting the time these units will operate to ensure the best environmental outcome,” Harris said.
ALBANY, N.Y. — Regulatory oversight of distributed energy resources is better fully mapped out at the beginning of the process rather than built piecemeal, more than a dozen industry stakeholders told staff of the New York State Department of Public Service on Monday at the second of two technical conferences on DER oversight.
New York PSC Technical Conference on DER Oversight
The first conference was held June 12 to explore how the Public Service Commission can best regulate utilities and protect consumers through the application of uniform business practices and marketing standards in the new era of rooftop solar and residents becoming “virtual” DER providers through membership in community distributed generation programs.
“What we have done in other areas is we’ve erred on the side of being more generous in the initial phase, trying to support new markets, but then you go to try to introduce new rules [and] people go crazy,” said Erin Hogan, director of the state’s Utility Intervention Unit. “So in my mind, it almost seems better to start with a more comprehensive structure and take away, as opposed to trying to add when you’ve discovered a problem.”
The PSC in March adopted a new “value stack” pricing mechanism for solar and other DER, along with two other orders to transition utilities into “distributed system platforms” and align their incentives with DER providers. The Value of Distributed Energy Resources order approved March 9 (Case NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
Benefit of the Bargain
Weiner
Scott Weiner, DPS deputy for markets and innovation, chaired the June 19 roundtable discussion and emphasized that “we’re dealing with not the purchase of bread or the repair of a car, which has its own protection, but with the provision of electricity and the opportunity of companies to enter into a marketplace, an expanded marketplace that has been created by the commission. The underlying question is, what responsibility does the commission have to make sure that end-use customers receive the benefit of the bargain that they’re agreeing to?”
“Oversight is important to build consumer confidence,” said Sara Margaret Geissler, manager of customer operations regulatory performance at Consolidated Edison. “We all want to create a market that they can have confidence in … and a core part of that is making sure, or having enough guidelines to ensure, that they understand what they’re signing and they know who to call if they have an issue.”
Geissler represented the joint utilities at the technical conference, which also include Central Hudson Gas & Electric, National Grid (which owns New York State Electric and Gas, and Rochester Gas and Electric), Orange and Rockland Utilities, and Rockland Electric.
Differentiate the Customers
Strauss
Valerie Strauss, policy director at the Association for Energy Affordability, noted the importance of differentiating between residential and commercial customers — and between different levels of commercial customer.
“We need to look at this in terms of the risk to the consumer,” Strauss said. “The current proposal is a blanket [that] kind of covers everybody. … We would suggest that that be revisited and some changes made for the provisions to more reflective of the risk.”
Strauss suggested that commercial customers could be differentiated by the number of units they control: “Certainly a mom-and-pop owner who has five buildings with 10 units each is not a sophisticated [commercial and industrial] customer. A property manager who owns 100 buildings that have 100 units each probably is.”
Community DG is new in New York but not in other markets, according to Hannah Masterjohn, policy vice president at the Clean Energy Collective.
“We have pretty substantial markets in Massachusetts, in Colorado, where we’ve already got thousands of customers participating in projects,” Masterjohn said. “When we look at our experience … we find low complaints overall, and the vast majority are related to utility billing issues. When we’re talking about community solar, the customer’s paying a third-party provider, but what they’re paying for is bill credits on their utility bill, so that benefit that’s getting delivered to them, that’s where they have most challenges.”
David Sandbank, director of the New York Sun program at New York State Energy Research and Development Agency, has overseen 64,000 solar installations since 2012 and said that his program doesn’t have any oversight over community DG.
“Right now, our focus is really on system performance of the main system itself,” Sandbank said. “There’s no specific protections for community solar subscribers in New York. … We have provided a lot of customer education on our website and we’ve launched a very robust digital marketing campaign to educate potential solar customers.”
Zack Dufresne, communications director at the Alliance for Clean Energy New York, asked whether the state could afford to regulate heavily.
“These regulations will take significant resources on the part of the PSC,” he said, “and I’m wondering if starting off with this maximalist position, [will] the DPS staff have the resources in place for that?”
“Let’s not have the tail wag the dog,” Weiner said. “If we feel there are certain activities that commission staff should be engaged in, we’ll make sure we have the resources.”
The FERC commissioner has said she would not seek a second term when her current one expires June 30. What she has not said is whether she will leave on that date or stay on until a replacement is nominated. (See No 2nd Term for FERC’s Colette Honorable.)
Honorable alluded to the uncertainty during a Monday luncheon address to fellow regulators, friends and attendees at the Mid-America Regulatory Conference. It was her only appearance during the conference, but it kept her long MARC attendance streak alive.
“I should have had a T-shirt made up: ‘I haven’t announced when I’m leaving, and I haven’t announced what I’m doing,’” she said.
One thing’s for sure: Honorable will spend at least the next two years in D.C. Call it returning the favor to her 16-year-old daughter, Sydney, who is still in high school.
“She loves it [in D.C.],” Honorable said. “I owe it to her. She was very good when I moved there.”
Honorable was nominated by President Barack Obama in August 2014 to fill the remainder of former Commissioner John Norris’ term. She was unanimously confirmed to the post by the Senate later in the year.
Honorable — who announced her departure in April — and acting Chairman Cheryl LaFleur have held down the fort at the quorum-less commission since February, when Chairman Norman Bay resigned.
Pennsylvania Public Utility Commissioner Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), were only recently nominated to fill two of the three vacancies. Both easily cleared the Senate’s Energy and Natural Resources Committee, but have yet to be confirmed by the full body. (See FERC Nominees Easily Advance to Full Senate.)
Powelson is president of the National Association of Regulatory Utility Commissioners, a post Honorable once held.
“I’m looking forward to when Rob joins us at FERC, or joins Cheryl,” Honorable said, a sly comment some in the audience missed.
An Arkansas native, Honorable was named to the state’s Public Service Commission in 2007. She chaired the PSC from January 2011 until January 2015, succeeding Paul Suskie, now SPP’s executive vice president of regulatory policy and general counsel, and one of her “work husbands.” (Her real husband died shortly before her FERC nomination.)
Acknowledging “uncertain times for regulators,” Honorable had some words of advice for those in her profession.
“We absolutely must protect our ability to work independently, no matter who is in office,” she said. “I want to urge you to stay true to that. I would have been shocked if the White House called and asked me to vote on something in a certain way. Keeping the lights on, reliably and safely, does not have a political or ideological bent.”
Honorable’s fellow regulators responded with a standing ovation, perhaps her last as a FERC commissioner.
She has no regrets about her decision.
“At the end of the day, I’m proud I kept the consumers first in my work,” she said. “It doesn’t mean I’ve been anti-business. In fact, I was shocked to read an article that described me as pro-business. It just shows I can work pragmatically by bringing together people from both sides of the aisle.”
MARLBOROUGH, Mass. — Environmental activists and state and RTO officials agreed Thursday that President Trump’s rollback of Obama administration energy and climate policies are causing uncertainty for New England officials even as some states attempt to fill the void.
Two panels at the Northeast Energy and Commerce Association Environmental Conference on June 15 discussed the implications of the Trump administration’s policies, including proposed EPA budget cuts and two executive orders to reduce regulations and prevent implementation of the Clean Power Plan.
Ad Hoc Decision Making
Former EPA Deputy General Counsel Ethan Shenkman said Trump’s May 28 order — which called for a sweeping re-examination of all U.S. energy and environmental policies to eliminate burdens on domestic energy resources — may result in ad hoc decision making (Executive Order 13783). (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)
In addition to seeking to eliminate the Clean Power Plan, the order also directs the Council on Environmental Quality to rescind its guidance on how federal agencies should consider greenhouse gas emissions and the effects of climate change in National Environmental Policy Act (NEPA) reviews. CEQ coordinates federal environmental efforts and works with agencies and White House offices in the development of environmental policy. NEPA reviews are required for any “major” federal action.
Trump also ordered the elimination of the Interagency Working Group on Social Cost of Greenhouse Gases, created by the Council of Economic Advisers and the Office of Management and Budget in 2009, and dismissed the group’s work products as “no longer representative of governmental policy.” Instead, Trump ordered that “when monetizing the value of changes in greenhouse gas emissions resulting from regulations,” agencies rely on a 2003 Bush-era finding by OMB.
Withdrawing the guidance document means “you’re back to a situation of uncertainty and some ad hoc decision making as each agency in region by region decides how they’re going to address these issues going forward,” said Shenkman, a partner with law firm Arnold & Porter Kaye Scholer.
State Funding Worries
ISO-NE environmental and regulatory analyst Patricio Silva gave a presentation that highlighted Trump’s proposed 31% reduction in EPA’s budget for fiscal year 2018, to $5.7 billion from $8.2 billion this year. Silva said the cuts could impact New England states’ capacity to enforce environmental regulations. In 2016, Connecticut, Vermont, Massachusetts and Maine relied on EPA for 21 to 24% of their environmental agency budgets, while New Hampshire and Rhode Island saw the federal grants fund 35%.
Roger Reynolds, of Connecticut Fund for the Environment/Save the Sound, said the proposed 31% reduction would eliminate funding for estuaries and the Great Lakes. “And since we’re closely associated with Long Island Sound, that concerned us greatly,” he said. “Long Island Sound generates $18 billion annually for the regional economy, and that’s on the low end of the estimates.”
Noting that his group received $8 million in federal funding in 2017, twice its 2016 outlay, Reynolds said that “it’s not entirely clear — in fact, quite the opposite — that Congress is necessarily in lock-step [with Trump], especially on environmental funding.”
Silva also pointed out that presidents’ proposed cuts don’t always survive Congress. For example, President Ronald Reagan proposed 25% to be cut from the EPA budget over two years, and the budget for fiscal 1982 ended up being decreased by 7%, Silva said.
‘Rollback Rebound’
“There is a significant amount of uncertainty now facing all segments of the industry when it comes to determining what’s going to happen and what are the consequences of the regulatory agenda that the incoming administration has been outlining,” Silva said.
After Trump announced his decision to withdraw from the Paris Agreement on climate change June 1, several states, including most of New England, vowed to uphold U.S. commitments to reduce greenhouse gas emissions. Silva said this is evidence of the risk of a “rollback rebound” — a term he credited to D.C.-based consultants ClearView Energy Partners. If states rush to fill the vacuum left by the Trump administration, Silva said, they could create a patchwork of regulatory policies that further complicate business for energy developers. (See Trump Pulling U.S. Out of Paris Climate Accord.)
| ISO-NE
“We have no idea what’s going to happen with the high-priority infrastructure initiative that the administration’s put out,” said Silva. “Again, with the absence of any staff at CEQ to implement these programs and also … the withdrawal of policy guidance on how greenhouse gas is accounted for… we now run the risk that if a new transmission project is developed here in the region, it could be facing different greenhouse gas standard assessments by FERC, Fish and Wildlife [Service] and Army Corps of Engineers. And then CEQ would be stuck trying to reconcile all those different approaches.”
Lack of staff could jeopardize permitting and oversight not only for new transmission, but also for generators, pipelines, fuel storage and port projects, he said.
Silva repeated a comment by lobbyist and former Trump transition official Michael McKenna, president of MWR Strategies, who said “personnel is policy.”
“At 120 days in, we have any number of federal departments and other entities that affect energy policy across the country that have significant vacancies,” Silva said. “[At] EPA, only two out of 13 senior staff positions [have been] either nominated or confirmed.”
FERC’s loss of its quorum in February is “a source of particular anxiety, since they regulate us,” Silva said. “There are many ISO/RTOs that have more pressing matters that have been delayed by the lack of the quorum.” A Senate panel on June 6 cleared nominees Neil Chatterjee and Robert Powelson for a vote by the full Senate. (See LaFleur Ready to Welcome New Members as FERC Backlog Grows.)
FERC will be controlled 3-2 by Republicans once all the vacancies are filled, raising the chance of a change in ideology. For now, a lack of clear policy from the commission on the treatment of nuclear resources and integrating markets and public policy “could complicate a variety of both state initiatives, but more importantly from our perspective, it complicates and makes planning much more difficult,” Silva said.
Freeze on Rulemaking
Executive Order 13771, issued Jan. 30, calls for federal agencies to rescind two regulations for every one promulgated, making it perhaps the most significant of Trump’s orders, said Seth Jaffe of law firm Foley Hoag. “It’s not about regulatory budgeting or anything; it’s about a freeze on significant regulations,” said Jaffe, who moderated a panel on regulatory changes at the end of the day and also participated with his own presentation.
The March order also could be significant because it is not only about getting rid of the CPP, but also rescinding all the Obama administration executive orders and guidance on climate issues, Jaffe said. “Top to bottom, wipe the slate clean on everything Obama did on climate and federal [policy].”
Jaffe said Trump picked a good point of attack on the CPP, which some experts say may have exceeded EPA’s authority by seeking to impose regulations beyond generators’ “fence line.”
“The Trump administration [could] say ‘We’re not going to get rid of the endangerment finding. We’re still going to regulate greenhouse gases from power plants where we have jurisdiction, but what we’re going to do is just regulate greenhouse gases from those power plants, rather than somehow pretend that what we’re regulating is emissions from power plants when what we’re really doing is incentivizing renewable energy.’”
While that is a sound legal argument, Jaffe said, the Trump administration may risk losing the deference usually shown by the courts to the executive branch if it ignores climate science and fails to provide a rational basis for its reversal of Obama policies.
MARLBOROUGH, Mass. — It’s not just “look before you leap.” For those considering crawling through the maze of regulations and property laws that determine whether a pipeline or electric transmission project can win all the permits needed to start construction, it requires looking dozens of steps ahead.
“An iterative process is crucial,” Thomas Burack, former commissioner of the New Hampshire Department of Environmental Services, told participants of the Northeast Energy and Commerce Association Environmental Conference on June 15.
“Underlying the environmental regulations, the state and federal permit processes, are property laws … that have interplay with the environmental laws,” said Burack, now with law firm Sheehan Phinney Bass & Green. “They regulate what we can do on the land, in the surface water and the groundwater… they’re all interconnected from a technical and regulatory standpoint. You really need to have an integrated and coordinated approach if you’re working in this arena.”
Planners should consider property law rights from the very beginning of the design process, which may come into play in even getting access to an area to assess its potential for a project, said Trey Martin of Downs Rachlin Martin, who gave a presentation on stormwater aspects in linear transmission project planning, construction, operation and maintenance.
Each New England state has a program that either implements federal law — in Massachusetts and New Hampshire it’s EPA issuing stormwater permits — or its own stormwater requirements, according to Martin.
“While you have to figure out what steps you can make and when you can start each one to reach your milestones, it’s also important to think about context,” he said. “In Vermont, a context for stormwater to keep in mind is that most of the state is subject to TMDLs [total maximum discharge loads] for impairment to major watersheds.”
As an example, he showed a photo of an algae bloom on Lake Champlain, the result of phosphorous from fertilizer and other pollutants running off farmland and roads.
“The cost to do the cleanup that the state and EPA have set in motion is at least in the tens of millions per year over 20 to 25 years,” Martin said.
The New England Clean Power Link, a transmission line planned by Transmission Developers Inc.-New England (TDI-NE) under Lake Champlain, had special challenges because the lake is a public trust resource under Vermont law. Water and land held subject to the public trust may only be used for purposes approved by the legislature as public uses.
The line was designed to run across the bottom of the lake, make land and carry power out of Vermont to southern New England. “So no off-takers in Vermont,” Martin said. “What’s the public good for Vermonters? In order to really expedite the permitting, this company made ‘public good’ payments into a clean water fund for Lake Champlain restoration. Obviously it was not the only factor in a really good project that got permitted completely, but it was a major factor. It really bought a lot of goodwill both with regulators and with the municipalities struggling with these questions.” (See Energy Department OKs Canadian Hydro Line in New England.)
Jeff Nelson, director of energy and environmental services for VHB, gave a presentation on how to handle wetlands concerns and overcome protests during the permitting process. VHB worked on a 41-mile natural gas pipeline extension for Vermont Gas that was proposed in 2012, fully permitted in 2014 and went into operation in April 2017.
Vermont Gas is licensed to serve the whole state but now serves mainly the northwestern part of Vermont with gas piped from Canada. “The project involved negotiations with some 220 landowners, is regulated by the Vermont Public Service Board as well as the state Agency of Natural Resources, and impacts waters and wetlands regulated by the Army Corps of Engineers,” Nelson said.
A key part of the final design was avoiding resource impacts, most significantly by choosing to use horizontal drilling, he said. The longest section of such drilling was just 3,000 feet under Monkton Swamp. “No surface impact, no change to the vegetation or the hydrology was something that the regulators frankly insisted on,” Nelson said.
After avoiding as much resource impact as they could, the planners minimized impact by co-locating 20 miles of the pipeline along a Vermont Electric Power Co. high-voltage transmission line. “That took advantage of an existing cleared corridor [and] minimized the amount of new forest clearing … minimizing the amount of overt disturbance,” Nelson said. The planners co-located an additional 10 miles of the pipeline along a highway, so three-quarters of the project was sited along existing corridors.
After the routing, the construction phase involved mapping every element and sensitivity, using timber mats to protect the ground, creating sediment traps to keep dirty water from running off, and even separating topsoil from the subsoil and replacing them in the right order for full habitat restoration.
Addison Natural Gas Project Construction | VHB
Despite the care taken to avoid impact, many “loud voices” opposed the pipeline, Nelson said. “It was a challenging project from that standpoint because lots of people had varying opinions on how things should happen. I think the newspaper [lead] pretty much sums up the whole thing: ‘41-mile Vermont Gas pipeline extension into Addison County is finished … after three years, $165 million and countless protests.’”
Brian Butler, president of Oxbow Associates, who called himself the “bugs and bunny guy,” presented on the “smorgasbord of species that are regulated in the Northeast region under one or another statute. With rare and endangered or threatened species, we have a couple tiers of regulation that are applicable to linear projects.”
The federal Endangered Species Act of 1973 serves as the umbrella. But once away from the whales and the migratory seabirds along the shore, federal law specifically protects only a small number of inland species in New England, according to Butler.
“Those are mostly freshwater mussels,” Butler said. “Those are the things most likely to be encountered in a pipeline or a linear kind of project where you’re crossing high quality streams.” Bats and bog turtles also pop up at moderate frequencies, he said in an email following the conference. “The adoption of the Final 4(d) rule with regard to long-eared bats by USFWS [Fish and Wildlife Service] reduced the survey and avoidance burdens inherent in the precedent, interim ruling,” he said.
In New England states, a pipeline is more likely to encounter the more numerous state-listed species, and the state codes are administered by bodies that deal with fisheries and wildlife. “As the federal money might be withdrawn from some of these agencies [because of President Trump’s proposed budget cuts], both federal and state agencies, you might anticipate a diminution of staff and a demoralization of the remaining staff, and it may confound these processes … the approvals that we’re discussing right now,” Butler said.
In planning for permitting, it’s useful to anticipate the seasonality of certain rare plants, some of which may only be visible or growing for three weeks or a month. “So if you’re sitting on your hands and then decide ‘we need to make a survey for that plant,’ you may conceivably have to wait for 10 months to clearly identify it. You always want to be trying to think ahead. The only invariant that comes in these projects is the variability that comes in the first several months or year of locating the project as well as anticipating the timing.”
BOSTON — When Connecticut Consumer Counsel Elin Swanson Katz decided to support a controversial bill to provide state financial support for Dominion Energy’s Millstone nuclear plant, it strained relationships.
“In fact, some of our closest allies barely spoke to me during the [legislative] session,” she said.
Katz’s anecdote, related to an audience at the 154th New England Electricity Restructuring Roundtable on Friday, was one example of the schisms that have arisen in recent years as many former nuclear power opponents have traded their fear of meltdowns and nuclear waste for appreciation of the plants’ ability to produce large amounts of power with no carbon emissions.
Similarly, Katz and other consumer advocates have had to consider whether losing a plant such as Millstone would be more expensive to ratepayers than any subsidies that would ensure its continued operation.
Opening a panel discussion featuring partisans on all sides of the nuclear debate, moderator Jonathan Raab observed: “The environmental community, like the consumer advocacy community, is not of one mind on the role of nukes in our society.”
Low natural gas prices, flat demand growth and growing renewable generation have squeezed the finances of many nuclear plants, leading policymakers in New York and Illinois to approve subsidies in the form of zero-emission credits (ZECs). Officials in New Jersey, Ohio and other states are considering similar measures despite challenges to the Illinois and New York ZECs in court and before FERC. (See Exelon Encouraged by Perry’s Memo, Thinks ZECs Will Hold Up.)
Matthew Crozat of the Nuclear Energy Institute told the audience that states are stepping in to save nuclear plants because wholesale electric markets have failed to price carbon emissions.
Crozat identified several plants that have closed or are slated for decommissioning by 2025. While some closed because of mechanical issues, “market forces claimed well operating plants,” Crozat said. “They just could not see a way to recover their costs in the future, and that includes Vermont Yankee here in New England.”
A combination of market forces and public policy pressures could result in the retirement of eight nuclear plants in the coming decade, for a total of about 12 GW of capacity, or some 60 million tons of CO2 avoided annually, Crozat said.
“When Vermont Yankee closed [in 2014], all of its generation was replaced by natural gas,” Crozat said. “This was not a surprise; it was the next available unit in the system. I think it was the first time in 15 years that carbon emissions from New England’s power sector had gone up, and we saw the same pattern in California as well” following the loss of San Onofre in 2013.
Controversy in Connecticut
Earlier this month, the Connecticut General Assembly failed to pass a bill, S.B. 106, that would have allowed the 2,111-MW Millstone plant to bid into the state procurement process.
Opponents of the bill said it represented a burden on state ratepayers and an unnecessary handout to a power plant that had not been proven to be unprofitable. John Shelk, CEO of the Electric Power Supply Association, who also spoke at the Roundtable, said Millstone is likely the most profitable nuclear plant on the East Coast. (See Millstone No Dead Weight for Dominion, Says Opponents’ Study.)
Katz, however, said she was concerned about what the loss of the plant — which produces half of the electricity consumed in the state — would mean to the ratepayers she represents. “It would have provided a potential opportunity, in my view, to save electric ratepayers money, and the procurement process would have allowed me to oppose a potential contract if it did not do so,” Katz told RTO Insider after the conference. “We did not think Millstone was at serious risk of closing, so we did not look at the proposed legislation through that lens.”
If Millstone retired, the region would undoubtedly have to secure new generating capacity, which would result in higher capacity costs, she said. “Connecticut and the region would presumably increase its reliance on natural gas and we would need more pipeline infrastructure to avoid infrastructure constraints. Connecticut, as you know, is at the end of the pipeline, and in cold winters that creates real problems for us.”
In addition, Millstone’s retirement “would likely see New England’s electric sector emissions increase by as much as 8 million tons, or approximately 27%,” Katz said. “Closure would make compliance with our state’s Global Warming Solutions Act challenging, as it requires that we must achieve greenhouse gas emissions 10% below 1990 levels by 2020 on an economy-wide basis.”
Not So Fast
In considering the future of nuclear power in New England, you couldn’t get more concise than a recent paper by the Rocky Mountain Institute titled “What the grid needs is a symphony, not a shouting match,” Shelk said.
“We are the lead plaintiff contesting the Illinois ZECs,” he said. “We’re also part of the litigation in New York, and we were working at the state level. … Why do we care? It’s very simple. These proposals single out nuclear, and only nuclear, for substantial state subsidies. It doesn’t extinguish the risk that nuclear plants face; it merely shifts it to the rest of us and our customers.”
EPSA has been joined in the Illinois litigation by PJM’s Independent Market Monitor, who has called ZECs a “contagion” that undermines the markets.
Shelk said that at current PJM prices of about $30/MWh, the Illinois ZECs are worth about $11.50/MWh.
“Those of us that are competing against each other, one set of competitors gets $30, and somebody else gets almost a 50% premium to the market,” he said. “And it’s unrelated to carbon. If we take steps to switch … from coal to gas or within gas to more efficient gas turbines — which are coming on the market very rapidly — we get zero for that attribute. And as you all know, a ton [of emissions] avoided is a ton avoided. So nuclear and only nuclear power, and only certain plants in PJM and New York, would get that additional price.”
Armond Cohen, executive director of the Clean Air Task Force, began his career as a lawyer fighting nuclear power, but he has now come to see the environmental value of nuclear power in improving air quality in New England.
“As you can see in the march towards a zero-carbon grid, nuclear contributes something … quite significant when compared to some of the other options,” Cohen said.
All the renewable energy being developed “adds up, but the point is, in scale, it’s still a little bit less than the existing nuclear,” he said. “And I’m not arguing this as an either/or; quite the contrary. I’m arguing that we should maintain the nuclear base and build on top of it. Over the longer term, the management of a very high weather-dependent system becomes complicated.”
Cohen said he has hopes for next-generation nuclear power technology, which promises to reduce costs by using coolants that remain stable at higher temperatures. He estimated costs can be achieved at about $40 to $60/MWh for the new designs.
“Those [new coolants] are things like molten salts to sodium helium and can operate at atmospheric pressure,” he said. “That reduces the need for pressurized containment, and that’s about two-thirds of the plant’s steel and concrete at Seabrook and Millstone. If you don’t have to keep water under very high pressure and containment, you vastly reduce the size and complexity of construction. That allows you to go to a factory production model with faster and more predictable completion times.”
Several developers in the U.S. have designs of next-generation nuclear power plants “at the paper stage” and foresee operational plants by 2030, Cohen said. He lamented that the U.S. has fallen behind China, which hopes to bring its first such plant online next year.
Ari Peskoe, senior fellow in electricity law at Harvard Law School, outlined the issues that contributed to the nuclear industry’s problems and the legal hurdles ZECs may have to clear.
“Restructuring removed generation from the rate base and severed the state’s planning authority, its environmental regulatory authority, from how the plant was actually going to earn its money,” Peskoe said. “That’s critical, because if at the end of the day the plant can’t earn its money, it’s not going to get built.”
Peskoe summarized three legal claims about ZECs at issue in federal court: That the states are regulating wholesale rates and thus intruding on FERC’s exclusive jurisdiction (field pre-emption); that they “stand as an obstacle” to FERC’s regulation of just and reasonable rates (conflict pre-emption); and that they favor in-state businesses in violation of the Constitution’s dormant Commerce Clause.
Rulings on the ZECs, Peskoe said, could have broader implications. “If ZECs are pre-empted, are [renewable portfolio standards] or the Regional Greenhouse Gas Initiative next?” And if a nuclear PPA is rejected, he asked, will Massachusetts’ procurements for hydro and offshore wind be at risk?
AUSTIN, Texas — Jeff Billo, ERCOT’s senior manager of transmission planning, told the Board of Directors last week that further analysis indicates Lubbock Power & Light’s potential transition from SPP could result in as much as $77 million in increased production costs — an $11 million jump from the preliminary results presented in May to the Technical Advisory Committee. (See Lubbock Load Could Boost ERCOT Production Costs by $66M.)
The increase did not go unnoticed by Director Carolyn Shellman, of San Antonio’s CPS Energy.
“So, you caught me on that,” Billo joked, when questioned about the difference. He explained the increase was caused by the addition of a third synchronous condenser to a previously approved project, designed to reduce wind energy congestion in the Texas Panhandle.
“Once we added a third [condenser], we didn’t see quite as much [economic] benefit from a wind-congestion relief perspective,” Billo said.
Staff’s evaluation indicates an increase of $77 million in fuel costs to serve the additional load in 2020 and $74 million in 2025. The preliminary numbers were $66 million and $60 million, respectively.
Should LP&L’s load be integrated into ERCOT, it will be placed in either the ISO’s West zone or its own zone. Analysis indicates non-LP&L consumers would see an increase of 3 to 5 cents/MWh in the years 2020 and 2025 to pay for serving Lubbock’s load.
| ERCOT
Billo reminded the board that the increased production costs will be offset by additional wind energy flowing into the ERCOT market through the LP&L interconnection.
“The Lubbock Power & Light facilities create a new transfer path for wind energy out of Panhandle,” he said. “[The facilities] connect to wind resources where we’re seeing a lot of congestion.”
LP&L announced in 2015 it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. The Public Utility Commission of Texas last summer asked the grid operators to conduct coordinated studies on the move, focused on a cost-benefit analysis for ratepayers. (See PUCT Asks ERCOT, SPP to Coordinate on Lubbock P&L Move.)
ERCOT plans to file its study with the PUC by the end of June (Docket 45633). SPP has said it intends to file its study results with the commission in late June.
‘Healthy Margins’ Headed into Summer Months
ERCOT CEO Bill Magness said “healthy” reserve margins “well above our targets” have the grid in good shape to meet increased demand this summer. The ISO’s latest Capacity, Demand and Reserves report indicated reserve margins of 16.8 to 18.9% in the next five years. (See ERCOT Sees Enough Generation Through 2022, 73-GW Peak for Summer.)
ERCOT set demand records in both April and May, recording 59.2 GW on May 26 for its latest monthly high. The ISO has set new demand highs for seven of the 12 calendar months during 2016-17.
“Continuing growth on the system is pretty much evidenced by that fact,” Magness said.
Dan Woodfin, ERCOT’s senior director of system operations, said the ISO has sufficient resources (81.9 GW) available and doesn’t expect the Houston and Rio Grande Valley areas to be the “significant issues” they have been in recent years. He said transmission limitations may create congestion for exports from the Panhandle and imports into Houston.
Chris Coleman, the ISO’s meteorologist, said he doesn’t expect above-average temperatures in Texas this summer, despite the warmest winter on record. He shared data with the board that showed little correlation between warm winters and warm summers, and said it’s “highly unlikely” temperatures will reach the record-breaking levels of 2011.
“The main reason I won’t forecast a repeat of 2011 is because it’s wetter. Quite a bit wetter,” Coleman said, pointing to drought-breaking rains over the last few years that have raised reservoir capacity from 75.5% full to 87.2% in the last year. “We have 1.2 trillion gallons of water more than we did in the reservoirs in 2011.”
But Coleman told directors that Texas is long overdue for a hurricane’s landfall. The last storm to hit the state was Hurricane Ike, which devastated Southeast Texas in 2008. Another year without a hurricane’s landfall would equal the longest such span since 1900.
“We’re way overdue,” he said. “Statistically, we average one storm every 2.5 years.”
Coleman is forecasting 14 named storms and seven hurricanes, including four major storms. He is projecting three or four named storms in the Gulf of Mexico, where water temperatures never dropped below 73 degrees this winter.
“There’s a very strong correlation between a warmer-than-normal Gulf of Mexico and extreme weather,” Coleman said. He said there is a disturbance in the gulf over the Yucatan Peninsula and Bay of Campeche that could develop into a named storm (Bret) later this week, a forecast backed up by the National Hurricane Center.
Coleman has also been developing medium-range (eight to 14 days) and long-range wind forecasts (one to three months), work that’s still in progress. He said above-normal temperatures lead to windy conditions, and he expects a “windy” summer.
Board Vice Chair Judy Walsh asked Coleman whether he would begin to do wind forecasts that could provide meaningful data.
“That’s my plan,” Coleman said. “I just wrapped up this study, and I’ll try to apply it for the rest of the summer.”
Magness Unfazed by Lagging Admin Fees
Despite a $2.3 million negative variance in budgeted system administration fees, ERCOT still has favorable net revenues of $1.3 million — and little reason to worry, Magness said.
“Thinking about revenues in ERCOT in the springtime is sort of like Joaquin Andujar,” he said, referencing the late Major League Baseball pitcher. “Joaquin Andujar once said, ‘I can sum up the game of baseball in one word: you never know.’”
Magness noted that a year ago, revenues were down $2.2 million, yet the ISO ended up with a favorable variance. ERCOT is on track to finish 2017 with a $2.6 million favorable variance in net revenues.
“It’s all about managing to what we have,” he said. “We think we will come much closer to the forecast.”
The board unanimously approved ERCOT’s 2018-19 biennial budget, which includes $222.3 million and $228.0 million for operating expenses, projects and debt-service obligations for 2018 and 2019, respectively. The ISO is currently operating under a $223.1 million budget.
The 2018-19 budget keeps the system administration fee flat at 55.5 cents/MWh. It was raised from 46.5 cents/MWh with the current budget, approved in 2015.
Walsh, who chairs the Finance and Audit Committee, said projections through 2023 show load growing at almost 2% and labor costs escalating at 4% annually. She said committee members asked ERCOT staff to come back in August with analysis on how to keep from raising the admin fee.
“As we look out further in time … and if these assumptions prove true, we’re going to have to balance the levers we have,” Walsh said, referencing FTR revenues, credit revolvers and the admin fee. “We want to explore how each of those moving parts work, so we’re fully apprised of what our choices will be, should we continue to have higher growth in expenses than load,” she said.
After 4 Years, NPRR Gets Unanimous Approval
Nodal protocol revision request (NPRR) 562, four years in the making, was among 10 changes unanimously approved by the board.
“This was a very challenging issue,” Magness said. “You notice the NPRR started with a five. Everything else [on the agenda] started with an eight.”
NPRR562 creates new requirements for identifying and protecting against subsynchronous resonance (SSR) and clarifies responsibilities for affected entities. The ERCOT system has become more vulnerable to SSR with the introduction of series capacitors for voltage support. Without proper mitigation, SSR can quickly destroy resonating elements and resources, and lead to cascading outages.
“We built a grid that delivers power at 60 Hz,” said Woody Rickerson, ERCOT’s vice president of grid planning and operations. “That’s the synchronous heartbeat of the grid.”
Rickerson said series capacitors increase the risk of energy being exchanged at a frequency of less than 60 Hz.
The board also approved related changes to the Planning Guide, PGRR056, which accounts for potential SSR vulnerability in the transmission planning process, providing references and citations to the appropriate protocol sections related to SSR, and removing its definition from the guides.
Magness brought Fred Huang, manager of dynamic studies, before the board for special recognition, calling him instrumental in guiding NPRR562 through the PUC’s rulemaking process.
“[Huang] always ends up in the middle of something really hard and thorny we have to solve,” Magness said.
NPRR831, the only revision request to receive a separate vote, relates to private-use networks (PUNs) — networks connected to the ERCOT grid that contain load typically netted with internal generation and not directly metered by the ISO. The change updates market systems to calculate a net load value for each PUN that will be included in the load zone price for all markets, when the load is a net consumer from the grid.
Source Power & Gas’ John Werner encouraged ERCOT to find a short-term solution before NPRR831 goes into effect in October, saying revenue neutrality allocation has reached $50 million this year, five times the amount for the same period last year. The increase is a result of largely PUN loads creating point-to-point obligation payments without offsetting energy imbalance charges.
The consent agenda included five other NPRRs and two additional PGRRs:
NPRR796: An administrative revision specifying that character set validations are available within each Texas standard electronic transaction implementation guide.
NPRR820: Aligns the definition of an aggregate generation resource (AGR) with the Protocols, which allow a resource entity to register several generators as an AGR. Intermittent resources are not included.
NPRR824: Aligns Protocol language with NERC reliability standards for energy emergency alerts and real power balancing control performance.
NPRR827: Bars ERCOT from awarding point-to-point obligations in the day-ahead market when the corresponding clearing price is greater than the bid price for the PTP obligation by 25 cents/MWh or more. ERCOT said the change will prevent harm to market participants over “modeling issues that need to be resolved and any resolution will take many months to implement.” The ISO said the language change will not need to be reversed once the modeling issue is addressed because “any resolution of this issue must honor the fact the PTP obligation bid price reflects the maximum willingness to pay by the bidder.”
NPRR830: Revises the basis of ERCOT’s calculation of the four-coincident peak calculation (4-CP) to be consistent with NERC’s net-energy-for-load methodology. The proposed methodology uses metered net DC tie flows.
PGRR057: Aligns the Planning Guides with NERC Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing geomagnetic disturbance vulnerability assessments.
PGRR058: Clarifies specific generation to be included in the Planning Guide and the applicability requirements for proposed generation that must submit generation interconnection or change requests.
