Page 1512 – RTO Insider

June 21, 2017

DC Circuit Rejects Challenge to PJM CP Rules

By Rory D. Sweeney and Rich Heidorn Jr.

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.

PJM DC circuit capacity performance rules — 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.”

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.

June 21, 2017

DOE Approves Emergency Dispatch of Yorktown Units

By Rory D. Sweeney

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.

dominion doe yorktown units — 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.

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.

June 21, 2017

Comprehensive DER Oversight Best, NYDPS Hears

By Michael Kuser

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.

distributed energy resources NYDPS — 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

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

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.”

June 21, 2017

Honorable: Leaving FERC, but not Sure When

By Tom Kleckner

CHICAGO — Colette Honorable continues to play it coy when discussing her future.

FERC Commissioner Colette Honorable | © *RTO Insider*

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.”

June 20, 2017

ERCOT BoD Briefs: June 13, 2017

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.

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 board spp — ERCOT CEO Bill Magness updates the Board of Directors on summer expectations. | © *RTO Insider*

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.”

Directors Approve 2018-19 Budgets, Keep Admin Fee Flat

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.

– Tom Kleckner

June 20, 2017

SPP SSC Briefs: June 14, 2017

Having agreed on a first potential interregional project with MISO, SPP is moving the 115-kV line in South Dakota through regional review.

SPP Interregional Coordinator Adam Bell told the Seams Steering Committee on June 14 that staff is working with the Economic Studies Working Group to develop a draft scope of the project.

The working group recommends using Futures 1 and 3 from the updated 2025 models in the 2017 Integrated Transmission Planning 10-Year Assessment to calculate the project’s one-year benefit-to-cost ratio. The group is also recommending using adjusted production cost and transmission outage mitigation as metrics in computing the ratio.

The SSC and ESWG will be the primary stakeholder groups directing the regional review, Bell said. They will make a recommendation to the Markets and Operations Policy Committee, with any approval from the Board of Directors coming in October.

The RTOs’ Interregional Planning Stakeholder Advisory Committee endorsed the $5.2 million project in April, and both stakeholder groups have since given their sign-off.

The project loops a Split Rock-Lawrence 115-kV circuit into Sioux Falls to relieve congestion on the Lawrence-Sioux Falls 115-kV line, shared by the Western Area Power Administration in SPP and Xcel Energy in MISO.

The project was the only one of seven joint recommendations to survive a coordinated system study conducted by the RTOs last year. Some of the projects failed to pass muster because of a $5 million threshold for interregional projects, a metric both RTOs are open to changing. (See 1 Project Recommended for MISO-SPP Coordinated Plan.)

SPP Continuing to Study Overlapping Charges

SPP staff continues to gather data on overlapping charges along the RTO’s seam with MISO, part of a coordinated effort by the two grid operators to determine the size of the problem they’re dealing with and whether agreements between transmission owners address transmission service.

Clint Savoy, senior interregional coordinator, said the issue arose with a MISO TO’s emergency tie agreement with an SPP member. The load was reliant on SPP facilities for service.

“We’re still reliant on the transmission owners and customers to tell us when these events occur,” Savoy said. “It would save the transmission customers money, without requiring system changes.”

Savoy said feedback from members has been slow so far, but staff is following up with those who have not yet responded.

The options before SPP and MISO include:

Revising their Tariffs and/or joint operating agreement to allow for after-the-fact reservations of transmission service for “abnormal” system conditions without unreserved-use penalties;
Revise the Tariffs and JOA to allow for after-the-fact accounting between transmission providers for abnormal system conditions without unreserved-use penalties;
Make no changes and still apply penalties when service is not prearranged; or
Revise Tariffs and/or market protocols to require settlement-location registration for any potential situations, or provide for a proxy for pricing congestion and losses.

Savoy said SPP’s Regional Tariff and Market working groups will take up the discussion and draft revision requests that might be necessary.

MISO Sends $2.15M in M2M Payments to SPP

Market-to-market payments from MISO to SPP in April dropped to almost half of those in March, with SPP collecting $2.15 million for congested flowgates between the two RTOs. MISO had sent its neighbor $3.98 million in March.

SPP has now collected $21.4 million from its neighbor since the two began the M2M process in March 2015.

Temporary flowgates racked up most of the payments ($1.38 million), binding for 435 hours. Permanent flowgates, which normally account for most the payments, were binding for 347 hours.

— Tom Kleckner

June 20, 2017

Huntoon: Microgrid Defense Misses the Point

By Steve Huntoon

Noblis continues to miss the basic point, which is readily apparent from two figures from its January 2017 report “Power Begins at Home: Assured Energy for U.S. Military Bases” (see graphic). The left figure is the status quo of individual building backup generators. The right figure is a microgrid.

microgrid military cybersecurity — Huntoon

As you can see, the microgrid adds exposure to military base distribution system problems because it is dependent on the distribution system. And distribution system problems cause the vast bulk of outages (87%).

This is not, as Noblis claims, a matter of “correcting” poorly maintained military base distribution systems, which Noblis would do by having the local utility assume responsibility for them.

Problems on local utilities’ own distribution systems cause about the same percentage of their customers’ outages (90%), as documented in footnote 5 of my column. Noblis does not address this.

The point is that most outages have nothing to do with poor maintenance, by military bases or by local utilities. Most outages are caused by severe weather, lightning, human error, unpredictable equipment failure, vehicle collisions, even metallic balloons and squirrels.

If local utilities had magic wands, they would wave them.

Noblis suggests undergrounding distribution systems to mitigate the added risk of microgrids, but it didn’t add the enormous cost of undergrounding to its microgrid costs.^[1] And it doesn’t consider that service restoration of an underground line outage typically takes much longer.

Speaking of cost, Noblis says its hypothetical microgrid cost under its natural gas “Case B” is close to the real-world cost of the microgrid at Marine Corps Air Station Miramar. I can’t reconcile this claim with the capital cost data Noblis presents in its Appendix C.2, which appear to be much lower. By the way, even if the Noblis data were right, its Case B is still uneconomic in the Northeast and Southeast regions that it modeled, and only economic in California.

And a few words about cybersecurity. My column did not suggest that no cyber protection exists for microgrids, simply that microgrids add cyber risk (and electromagnetic pulse risk) that does not exist with individual building backup generators.

The Department of Defense cyber protection that Noblis refers to is based on “limiting communication bandwidth within the network [microgrid].”^[2] The dilemma is that operating a microgrid of substantial size in parallel, in order to get the peak shaving, energy savings and demand response benefits that Noblis is counting on, cannot be done without communications links with the regional grid operator and the local utility. In other words, you can have (1) high cyber protection through isolation, or (2) benefits of parallel operation, but not both. Noblis eats the cake and has it too.

Finally, Noblis criticizes my reporting that the University of California, San Diego (UCSD) microgrid flunked its acid test in the Southwest Blackout of 2011. Noblis says my reference to that microgrid as “flagship” was “strange at best.” I didn’t make that up — just Google “UCSD microgrid flagship” (without quotation marks).

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel LLP.

(See STAKEHOLDER SOAPBOX – Noblis: Huntoon Microgrid Critique ‘Seriously Flawed’.)

The Edison Electric Institute estimates that undergrounding a distribution line costs up to $5 million per mile. http://www.eei.org/issuesandpolicy/electricreliability/undergrounding/documents/undergroundreport.pdf (page 31, Table 6.4). ↑
https://energy.gov/sites/prod/files/2016/03/f30/spiders_final_report.pdf (page 3-15). Microgrid Cyber Security Reference Architecture, which the DOD cyber protection follows (page 3-14), does not consider operational modes in which the microgrid is operating in parallel with the rest of the grid. http://prod.sandia.gov/techlib/access-control.cgi/2013/135472.pdf (page 23). ↑

June 20, 2017

PJM Making Moves to Preserve Market Integrity

By Rory D. Sweeney

For some time, PJM has found itself in a no-win situation, pitting stakeholders valuing market consistency against those seeking flexibility to integrate changing ideas and technologies.

From technological advancements that have reduced demand, to the shale gas boom that has upended the supply stack, to governmental actions that have artificially buoyed preferred technologies, what’s an RTO to do?

“Increasingly, public policies seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes,” PJM said in an explanatory document released last week. “The most recent iteration of state policies has involved explicit, legislatively driven subsidies for specific generating units. These types of subsidies can suppress wholesale electricity market prices and threaten these markets’ basic design mission.”

But through that document and three supporting papers, PJM believes it has found a way forward. The RTO published the document along with the last two of three working papers that each focus on addressing different aspects of the issue.

The first, published the same day as a May FERC technical conference analyzing the viability of energy markets, offered guidelines for how states could work with PJM to develop carbon pricing rules that integrate with existing market structures. (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)

The second, published last week as an update of a proposal PJM floated last year, outlines a two-phase capacity auction that would allow subsidized resources to be counted as available reserves without influencing the clearing price. (See PJM’s Grid 20/20 Ponders Mixing Public Policy, Competitive Markets.)

Also published last week was a third paper containing ideas initially advanced in PJM’s response to its Independent Market Monitor’s 2016 State of the Market report. In it, the RTO proposes tweaks to its energy market design to address complaints that market factors — both naturally developing and artificially introduced — have improperly depressed clearing prices so that true real-time costs aren’t being accurately reflected. The grid operator argues that its price-setting logic should be revised to allow inflexible units to set LMPs. (See PJM Differs with Monitor in State of the Market Response.)

“Since the inception of competitive wholesale electricity markets, the industry has evolved significantly and in ways that could not have been fully anticipated,” the document said. “Technological disruptions … have altered the economics of electricity supply, creating new opportunities and challenges. … These shifts in economic trends and market dynamics could lead to an unintended bias in the energy markets favoring lower capital cost resources … [putting] financial stress on all units, but particularly large units with high capital costs.”

The proposals face an uphill battle for acceptance. Stakeholders have criticized PJM for filing some of the ideas with FERC as additional testimony during the technical conference. The Monitor opposes the proposed changes to the LMP-setting logic.

Market participants have also expressed concerns with the RTO’s two-phase capacity-auction proposal. And carbon pricing was a tough sell long before President Trump set out to eliminate his predecessor’s signature Clean Power Plan. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)

PJM acknowledges the work ahead. The capacity proposal, it said, “likely will be evaluated with other potential solutions” by the Capacity Constructs/Public Policy Senior Task Force, which has been meeting regularly since January and remains mired in foundational discussions on the basic goals of a capacity construct. (See PJM Capacity Task Force Debates the Value of Price Transparency.)

The other proposals haven’t found a home for discussion yet, but the RTO is confident something must be done.

“I certainly think a do-nothing approach going forward puts the goals of the markets in general at risk,” Stu Bresler, PJM’s senior vice president of operations and markets, said at PJM’s Grid 20/20 conference on the issue last August. “The risk of a do-nothing approach is a detrimental effect on the long-term price signal.”

June 20, 2017

SOAPBOX – Huntoon Microgrid Critique ‘Seriously Flawed’

By Jeffrey Marqusee

Steve Huntoon’s March 13 column “Microgrid Kool-Aid and National Security” reviews the Noblis report “Power Begins at Home: Assured Energy for U.S. Military Bases” and raised a number of issues that he claims invalidate the study’s conclusions. Huntoon’s claims and conclusions are seriously flawed.

Huntoon cites a recent Government Accountability Office report that found outages can be attributed to on-base problems as opposed to the utility. He states that outages attributed to on-base issues cannot be solved: “if they were easily avoided, they would be.” From this statement he concludes, incorrectly, microgrids cannot be the solution.

Our report specifically acknowledges that problems with on-base distribution systems must be corrected prior to using a microgrid and in most cases this can easily be accomplished. Currently, some outages on military bases are completely due to the utilities that serve the base (Fort Irwin), while others are due to on-base infrastructure issues (Camp Lejeune). Fixing these on-base problems is well understood and routinely done. Simple activities such as tree trimming, routine maintenance and, when needed, undergrounding of distribution systems can and do reduce the issue to near zero. Fort Belvoir has demonstrated this through these actions over the last several years.

The main reason it has not been done at all bases is well recognized at the Defense Department and is the driver for utility privatization. Maintenance of on-base utility systems has been underfunded for decades. Fort Belvoir is a perfect example. Upon privatizing the on-base utilities, the frequency of outages attributed to on-base issues began to rapidly decline to near zero.

Huntoon argues that microgrids place military installations at risk to cyber threats. He implies that this risk should not be taken.

As the report explicitly states, cyber risks are real and must be addressed, but this was not the focus of our study. If you believe that cyber risks should be always avoided, then you cannot have advanced meters, smart buildings or network anything (including weapon systems). You network things because it buys performance advantages, as in the case of microgrids, and if you own the network you can manage that risk. Huntoon seems unaware that cyber protection for microgrids exists. Cybersecurity solutions for microgrids have been demonstrated on bases by the government’s Environmental Security Technology Certification Program and its Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS) program.

Huntoon says, “please note one other glaring oversight in the study. This one involves the estimated cost of microgrids.” He claims the study’s estimated costs are grossly wrong by comparing numbers he incorrectly quotes from the report with recent costs for a project at Marine Corps Air Station Miramar.

His comparison of our estimates and a real-world example at Miramar are grossly in error. He quotes our number for the capital costs of an all diesel generator system rather than the costs for one that is half natural gas and half diesel like Miramar. The numbers he should have quoted from the report, which are relevant to Miramar, are twice the numbers he does quote. In addition, he ignored the costs of two microgrid control stations as well as other upgrades. In fact, our cost estimates, constructed prior to the award of the Miramar contract, when compared apples to apples is within 10% of the actual costs.

In the conclusion, Huntoon states, “And speaking of fact, the nation’s ‘flagship’ microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.” He implies that microgrids don’t work.

microgrids military bases noblis — UC San Diego Microgrid | *UC San Diego*

No one in the microgrid technical community believes that the U.C. San Diego microgrid is the “flagship” example. Using a decade-old, university-based microgrid as an example is strange at best. Dozens of microgrids have been demonstrated in recent years. They all operate as designed during outages and provide assured power. For example, the White Oak microgrid, which is described in the report, has maintained power during dozens of outages, never experienced a failure and is saving money each year.

Jeffrey Marqusee, Ph.D., is chief scientist for Noblis, a nonprofit science, technology and strategy organization whose clients include many federal government agencies.

(See Huntoon: Microgrid Defense Misses the Point.)

June 20, 2017

UPDATE: California Heat Wave Prompts CAISO Flex Alert

CAISO on Monday called on consumers to voluntarily conserve energy this week as scorching heat drove up electricity usage and caused outages in Pacific Gas and Electric’s service territory.

The ISO issued a “flex alert” effective 2 to 9 p.m. on Tuesday and Wednesday, with peak load expected to break 47,000 MW both days in the face of triple-digit temperatures. The alerts are issued when the grid is “under stress” from generation or transmission outages, or persistently high temperatures, the ISO said.

This week’s expected peaks would be more than 90% of CAISO’s all-time peak demand of 50,270 MW, set on July 24, 2006.

By late Monday, the ISO forecast that the day’s peak demand would hit about 44,600 MW, well short of an earlier forecast of 46,500 MW.

Temperatures soared up to 110 degrees in California’s interior, the most intense heat wave to hit the state since the summer of 2013. Multiple days of extreme heat are stressing equipment and causing some outages. PG&E still had 4,200 customers without power as of Monday morning, with about 189,000 customers initially affected.

“This is a heat wave, and we have got all our generation that we can make available made available to us,” CAISO spokesman Steven Greenlee said during a media call held jointly with PG&E.

An extended period of very hot weather is expected across the interior portions of southwest California through the middle of the week, and temperatures could reach 112 degrees in parts of the state, the National Weather Service said as it issued a heat advisory.

– Jason Fordney