Page 1370 – RTO Insider

June 14, 2018

ERCOT Board of Directors Briefs: June 12, 2018

ERCOT CEO Bill Magness assured his Board of Directors on Tuesday that the grid operator is prepared for the summer heat, despite the retirement of 4 GW of coal-fired capacity since last summer.

Magness highlighted a plethora of meetings staff have held in recent weeks with regulators, media, information officers from state utilities, pipeline and gas companies, transmission owners and other stakeholders. He also noted new demand records set in May and June, which the ISO managed without emergency alerts or conservation appeals.

ERCOT Senior Meteorologist Chris Coleman checks his mike with CEO Bill Magness looking on at the June ERCOT Board of Directors meeting. | *AdminMonitor*

ERCOT recorded new monthly demand records of 67.3 GW on May 29 and 67.9 GW on June 1. Magness told the directors May was the hottest ever recorded in the United States, and the second-hottest in Texas.

“We saw it on the system,” he said. “We’re just getting into summer. Here we go!”

Staff has projected a new summer peak of 72.8 GW in August. It says it has 78.2 GW of capacity available and continues to expect to have enough resources to serve load. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

Senior Meteorologist Chris Coleman pointed out that heat records in May don’t necessarily equate to a “blazing” summer. He said Texas’ hottest May in 1996 was followed by the 76th hottest summer on record. Of the 20 hottest Mays dating back to 1895, only five were followed by one of the 20 hottest summers.

“We’ll be hotter than last summer, which won’t take a lot,” Coleman said, referring to the 50th hottest summer on record.

Coleman said the expected rains from Gulf of Mexico and Pacific storms over the next week will help tamp down temperatures in the weeks that follow.

“We’ll always take more rain, but substantial rain leads to soil moisture and water in the reservoirs,” he explained. “That will tone down the extreme heat this summer. That’s the type of thing that prevents 2011 from happening again.”

That year remains the state’s hottest on record. The Dallas-Fort Worth Metroplex recorded 40 straight days of 100-degree temperatures — and 71 overall — in 2011.

Coleman is looking at 2013 and 2006 — Texas’ 21st and 42nd hottest summers — as indications of what to expect this summer, and he said there is a two-in-three chance that temperatures will end up between those two years.

He also predicted less hurricane activity than last year, when Hurricane Harvey dumped 52 inches of rain on the Houston area. Coleman said without the La Nina of 2017 or an El Nino, overall activity will probably be at the lower end of the National Oceanic and Atmospheric Administration’s predicted range of 10 to 16 named storms and five to nine hurricanes.

The good news with May’s summer heat?

ERCOT’s year-to-date net revenues have a favorable variance of $8.3 million, and a favorable year-end forecast of $12.3 million.

IMM’s Garza Calls for Evaluation of Local Signals

Beth Garza, director of ERCOT’s Independent Market Monitor, said the ISO should evaluate the market’s ability to send local signals.

IMM Director Beth Garza | *AdminMonitor*

As she reviewed the Monitor’s annual State of the Market report, Garza reminded the board that price signals that incent new generation are a fundamental aspect of a “sustainable, ongoing market.” She said that net revenues (revenues in excess of assumed production costs) over the past six years are far less than the costs of building a new peaking unit, a result of the market’s capacity surplus.

“We have a market that continues to grow and with requirements continuing to increase, which requires sufficient resources to meet those,” Garza said. “But since the start of the nodal market in 2011, the net revenues have not been sufficient to pay the fixed costs of new generation.”

Net revenues in the market were around $110/kW in 2011, but only broke $40/kW last year — and only in the Houston region. The Monitor has estimated the cost of new entry between $80 and $95/kW, based on the value of simple cycle gas turbines.

ERCOT summer peak bill magness — Net Revenues by Year and ERCOT Zone | *Potomac Economics*

“I don’t have a lot of precision, hence the range,” Garza told the board. “We’ve been so far under for so long, it’s hard to get focused on whether [the point of entry] should be $82/kW or $95/kW. I don’t know what that ratio is, but we have certainly seen a half-dozen years or so of very low contributions toward net revenues.”

Garza said congestion costs increased 95% to $967 million over 2016 because of wind generation exports from the Texas Panhandle, construction of the Houston Import projects and Harvey’s aftermath. She expects the Panhandle congestion costs to continue to increase as more wind is built in West Texas without a commensurate addition of transmission infrastructure.

“The Panhandle … contributes to those high costs because of the large differential in generation costs on either side of that constraint,” Garza said. “Wind generation in the Panhandle is at zero or below. The average cost on the ERCOT side is at 20, 30, 40 dollars. That spread is much higher than other constraints.”

The Monitor again included real-time co-optimization on its annual list of market improvement recommendations. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)

Garza said that real-time co-optimization would make better use of the system’s resources, lower costs, allow for efficient shortage pricing when the market can’t satisfy any of its energy or reserve needs, and allow all supply to participate in the ancillary services markets.

$327M in Tx Projects will Meet Permian Basin’s Load Growth

The board unanimously approved $327.5 million in West Texas transmission projects to address congestion from increasing oilfield load growth in the Permian Basin.

The Far West Texas Regional Planning Group Projects include new construction and upgrades of three 345-kV lines — Riverton-Sand Lake, Sand Lake-Solstice and Solstice-Bakersfield — that staff recommended be designated as critical to system reliability. The board agreed with the recommendation.

Jeff Billo, ERCOT’s senior manager of transmission planning, told directors the projects will allow the region to handle up to 1.7 GW of load. Staff’s independent review of the two Oncor projects indicated local load projections of 880 MW and 1,013 MW for 2019 and 2022, respectively. A year ago, load projections for 2021 came in at 553 MW.

Billo said the region has added 80 rigs in the last year. “It’s the hot spot of hot spots,” he said.

IHS Markit, a global data firm, has predicted the Permian Basin in Texas and New Mexico will become the world’s third-largest producer of oil, behind only Saudi Arabia and Russia. The firm projects production will double to almost 5.4 million barrels a day between 2017 and 2023.

Construction on the Far West Texas projects is expected to begin next year, with completion in 2023.

Board Approves 8 Change Requests

The board remanded back to the Technical Advisory Committee a nodal protocol revision request (NPRR) incorporating an intraday or same-day weighted average fuel price into the mitigated offer cap.

The City of Dallas’ Nick Fehrenbach, representing the commercial consumer segment, had the change pulled off the consent agenda, saying its language was unclear. “I think at best the language is vague and confusing. At worst, it’s an unenforceable clause,” he said.

Fehrenbach said he was unable to come up with a solution with ERCOT staff. Market participants won’t be harmed, he said, because the ISO already uses a manual workaround for exceptional fuel prices.

NPRR847, which cleared the TAC unanimously, is meant to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.

The board also tabled an accompanying verifiable cost manual revision request (VCMRR021), which aligns the manual with NPRR847 by removing language providing for make-whole payments for exceptional fuel costs.

The board approved four other NPRRs, a pair of other binding document revisions (OBDRRs) and two changes to the Planning Guide (PGRRs):

NPRR837: Updates the Regional Planning Groups’ tier classification rules, among other related improvements and clarifications, to ensure the RPG and ERCOT are reviewing the most appropriate subset of transmission projects.
NPRR851: Establishes a clearly defined disconnection process within the market rules applicable to a transmission voltage connection to the grid that uses one electrical connection for both generation and load services.
NPRR867: Caps the amount of each counterparty’s available credit limit locked for congestion revenue rights auctions at the pre-auction screening credit exposure amount.
NPRR870: Deletes the gray-boxed requirement for ERCOT to post a forward adjustment factors summary report on the Market Information System’s certified area. The information in this report is already provided on each counterparty’s estimated aggregate liability summary report.
OBDRR004: Revises the risk-weighting factors available for assignment to each emergency response service (ERS) time period; describes the process for updating the ERS time period expenditure limits for any subsequent standard contract terms (if money is needed to fund) and the ERS renewal contract period; and updates a table to reflect the risk-weighting factors’ proposed changes.
OBDRR005: Revises the generic transmission constraint (GTC) shadow price cap that is used in security-constrained economic dispatch for base case constraints from $5,000/MWh to $9,251/MWh. The revision also updates the associated examples in SCED and makes an administrative edit to a protocol reference.
PGRR059: Includes RPG-related changes intended to improve and clarify existing processes.
PGRR060: Updates the reliability performance criteria by defining a DC tie’s unavailability as a new contingency and clarifies the voltage level of transformers referred to in the reliability performance criteria.

— Tom Kleckner

June 14, 2018

Conn. Awards 200-MW OSW, 50-MW Fuel Cell Deals

By Rich Heidorn Jr.

New England’s offshore wind industry got another boost Wednesday as Connecticut officials announced they will purchase 200 MW of output from Deepwater Wind’s Revolution Wind project, adding to Rhode Island’s 400-MW procurement.

Rhode Island announced its selection of Revolution last month at the same time Massachusetts agreed to procure 800 MW from Vineyard Wind. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

“With demand for 1,400 MW of U.S. offshore wind announced in less than a month, there’s a golden opportunity for heavy manufacturing companies and shipbuilders to invest in American jobs, factories and infrastructure,” said Nancy Sopko, director of offshore wind for the American Wind Energy Association.

The Connecticut Department of Energy and Environmental Protection also announced awards for 52 MW of fuel cells and a 1.6-MW anaerobic digestion project Wednesday.

Maxed out on Offshore Wind

The 200 MW in offshore wind is equal to 3% of Connecticut’s load, the maximum officials were permitted to procure under state law. Combined, the renewable energy procurements are equal to 4.7% of Connecticut’s load.

The selected projects will seek to reach agreements on 20-year contracts with the state’s electric distribution utilities, Eversource Energy and United Illuminating. The contracts will be subject to approval by the Public Utilities Regulatory Authority.

The Revolution project will be in federal waters about halfway between Montauk, N.Y., and Martha’s Vineyard, Mass. Deepwater, majority owned by The D.E. Shaw Group, also is the owner of the 30-MW Block Island Wind Farm, the first U.S. offshore wind project. The company also is pursuing a project off New Jersey in a partnership with Public Service Enterprise Group.

As part of the Connecticut procurement, Deepwater agreed to economic development commitments in New London, including the investment of at least $15 million in the New London State Pier to allow “substantial” portions of the project to be constructed and assembled in the city. It also agreed to contract with a Connecticut-based boat builder to construct one of the project’s crew transfer vessels in the state. This project is expected to spur more than 1,400 direct, indirect and induced jobs, officials said.

Vineyard Wind, which had also bid into the Connecticut procurement, said it will continue work on its Massachusetts project, with construction projected for 2019 and full operations in 2021. “We also will continue to develop the remainder of our commercial lease site with the goal of providing New England states with additional wind energy solutions in the near future,” the company said in a statement.

Fuel Cells

Wednesday’s announcement will double the installed capacity of fuel cells in Connecticut to about 100 MW. State officials said the addition will put the state in the forefront of fuel cell adoption, along with California (210 MW installed capacity) and New York (20 MW).

Deepwater Wind fuel cell Revolution Wind project — Doosan fuel cell | *Doosan Fuel Cell America*

The largest fuel cell (19.98 MW) selected was Doosan Fuel Cell America’s for the Energy and Innovation Park in New Britain. The project, the first phase of an economic development project, will use combined heat and power for heating and cooling businesses, including a Stanley Black & Decker manufacturing plant.

Others selected were Bloom Energy (a 10-MW project in Colchester) and FuelCell Energy (a 7.4-MW project in Hartford and a 14.8-MW project in Derby).

DEEP noted the average price in the fuel cell procurements was 11.6 cents/kWh, down from 15.6 cents/kWh in its 2011/12 procurement.

The Turning Earth Anaerobic Digestion Project in Southington will convert 54,000 tons of food waste and 15,000 tons of yard and woody waste into 90,000 cubic yards of compost and mulch annually.

June 14, 2018May 31, 2024

DC Circuit Upholds FERC Order on PJM FTRs

By Rory D. Sweeney

FERC sufficiently justified its decision to revise how PJM allocates revenues from transmission congestion and its subsequent move to reject requests to rehear the issue, the D.C. Circuit Court of Appeals ruled Tuesday (17-1101).

Several PJM stakeholders had petitioned the court to overturn FERC’s January 2017 order that upheld a September 2016 ruling that modeling assumptions the RTO adopted to address financial transmission rights revenue inadequacy had resulted in unwarranted cost shifts between auction revenue rights holders and FTR holders.

The D.C. Circuit Court meets in the E. Barrett Prettyman Federal Courthouse | HSU Builders

FERC had also accepted PJM’s compliance filing in response to a requirement that it develop a method for allocating ARRs that doesn’t consider extinct generators (EL16-6). (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)

The petitioners included Old Dominion Electric Cooperative, American Municipal Power, PJM’s Independent Market Monitor, the New Jersey Board of Public Utilities and the Delaware Public Service Commission. PJM and several stakeholders involved in its FTR markets intervened, including Exelon, Elliott Bay Energy Trading, several Public Service Enterprise Group companies, Appian Way Energy Partners, NRG Power Marketing, DC Energy, Boston Energy Trading and Marketing, Vitol and J. Aron & Co.

The court noted in its decision that between 2010 and 2014, PJM could only fund between 69 and 85% of the prevailing-flow FTRs, so FTR payments were reduced pro rata. That, in turn, reduced the value of ARRs because FTRs were worth less at auction.

PJM’s stakeholders were unable to find consensus on how to address the issue, so the RTO asked FERC to settle it by declaring the current market design unjust and unreasonable. FERC held a technical conference in 2016 and granted PJM’s request, ordering several design modifications. After FERC rejected a request for rehearing, the petitioners appealed the decision to the D.C. Circuit.

The court sided with FERC on all three of the petitioner’s challenges. It ruled that excluding balancing congestion from the funding formula for FTRs was reasonable because including it “reduces the efficacy of FTRs as a hedge.” FERC was also reasonable in requiring the entire market, rather than FTR holders, to bear the costs of the congestion because “FTR holders do not cause and cannot predict the level of balancing congestion” and “are not the sole beneficiaries of balancing congestion,” the court said.

Additionally, the court decided petitioners provided no support for their view that FERC’s actions might endanger FTRs’ exemption at the Commodity Futures Trading Commission.

FERC’s rationale for continuing to net prevailing-flow and counterflow FTRs was also sufficient, the court said. The commission had doubted that “the elimination of netting would improve FTR funding” because that would simply “reallocate FTR revenue inadequacy among various market participants without actually addressing the fundamental issues associated with FTR revenue inadequacy.” The commission also reasoned that netting is “the functional equivalent of applying the same payout ratio to both prevailing-flow and counterflow FTRs,” so all FTRs are treated equally.

Finally, the court rejected the argument that FERC should not have eliminated outdated transmission paths from the formula used to allocate ARRs. While petitioners instead wanted FERC to artificially increase growth forecasts, the commission “adequately explained why it preferred to rectify the root cause of the problem rather than pursue a remedy that could distort the planning process, such that transmission planning is not based on expected system conditions,” the court said.

The court also said it saw “no cause to displace FERC’s considered policy judgment on this matter.”

June 13, 2018

FERC: No Emergency on Grid

By Rich Heidorn Jr.

WASHINGTON — FERC commissioners told Congress yesterday the grid is not facing a national security emergency, as the Trump administration has claimed in its call for saving at-risk coal and nuclear generation.

national security emergency ferc coal nuclear trump — The Senate Energy and Natural Resources Committee held its first oversight hearing with all five FERC commissioners in a decade | © *RTO Insider*

At an oversight hearing before the Senate Energy and Natural Resources Committee, Sen. Martin Heinrich (D-N.M.) asked the five commissioners whether any of them believed there is a national security emergency in the wholesale power markets.

“I do not, senator,” Commissioner Cheryl LaFleur responded.

“Anyone answer that with a yes?” Heinrich asked. None of the other commissioners spoke.

But coal-state senators also got commissioners to offer soundbites supporting their positions.

When Sen. John Barrasso (R-Wyo.) asked whether the commissioners agreed on the need to keep coal in the generation mix, Chairman Kevin McIntyre responded by reiterating his support for “an all-of-the-above strategy.”

McIntyre also agreed under questioning from Sen. Joe Manchin (D-W.V.) that Energy Secretary Rick Perry has the authority to issue emergency orders under the Federal Power Act and Defense Production Act of 1950. “There’s no question that the secretary does,” McIntyre said.

The two and a half-hour hearing — the first Senate oversight hearing involving all the FERC commissioners in a decade, according to Chair Lisa Murkowski (R-Alaska) — also touched on LNG and pipeline project licensing and the Public Utility Regulatory Policies Act (PURPA).

But President Trump’s June 1 directive that Perry prevent additional coal and nuclear plant retirements dominated the discussions. (See Trump Orders Coal, Nuke Bailout, Citing National Security.)

Most Democrats, led by ranking member Maria Cantwell (D-Wash.), blasted the proposal. LaFleur and Commissioners Richard Glick and Rob Powelson were the most outspoken in their opposition to the subsidies.

Commissioner Neil Chatterjee was somewhat more sympathetic, saying some critics had been too quick to dismiss DOE’s draft memo, which seeks to justify capacity and energy payments to prevent plant retirements.

“There are a number of points in the memo that are thoroughly well cited and researched,” he said. “I think we can have disagreements about what the remedy may be, but I think they raise a real issue … that we need to look at.”

While acknowledging the vast majority of outages are the result of distribution and transmission failures rather than losses of generation, Chatterjee added, “We shouldn’t assume that that good fortune will continue.”

‘Policy Vacuum’

Murkowski acknowledged, “I have my concerns with the steps the Department of Energy is reported to be considering.” But she said DOE was trying to fill a “policy vacuum” created by FERC’s failure to act more quickly on resiliency concerns.

“In my view, FERC should be pointing the way on policy improvements that address grid vulnerabilities, while reaffirming our commitment to competition in wholesale power markets. Frankly, as one who has been concerned about this issue for years now, I find it unfortunate that prior commissions did not lead more effectively,” she said. “We must increase the light and lower the heat in policy debates about price formation, state resource preferences and subsidies.”

LaFleur, the commission’s longest-serving member, defended the commission’s work in navigating the shift to more gas and renewable generation.

“We work to ensure resilience by overseeing market changes to increase compensation to resources that are on line in times of system stress and extreme weather, including baseload resources. In the energy market, we [have] worked on a number of steps since 2014 to improve price formation to make sure the markets send the correct price signals,” she said.

LaFleur said the commission should continue to craft “tailored regional solutions” to address tensions between wholesale markets and state policy favoring certain generators.

“Indeed, I believe the resource turnover we’re experiencing is an expected consequence of markets and technological change, and the lower prices that result from well-functioning markets are a benefit to consumers — not a problem to be solved, unless reliability is compromised,” she said.

“We cannot try to stop the natural evolution of this industry by claims there’s a national security emergency unless there is evidence to suggest an emergency actually exists,” said Glick. “… We need to keep on being vigilant and keep monitoring the situation. But we also need to be wary of people using the situation — or the potential situation — as an excuse to achieve market changes they haven’t been able to achieve otherwise.”

Cantwell said the administration’s “radical” plan could cost consumers billions, telling the commissioners that maintaining “‘just and reasonable’ [rates is] your job … That is why we have a FERC.”

But Sen. Joe Manchin (D-W.V.) dismissed concerns that the subsidies would raise prices. He noted that the draft DOE memo envisioned subsidies for two years while the agency studies grid risks. “You’re acting like it’s going to be forever,” he told the commissioners.

When he pressed the commissioners to identify any generation sources other than coal and nuclear that can provide 24/7 “baseload” power, Glick mentioned “some hydropower,” while Powelson volunteered natural gas.

‘Human Impact’

Sen. Shelley Moore Capito (R-W.V.) complained that renewable subsidies and environmental regulations had “led to a failure that has been punishing” coal generation and the communities that depend on them.

Glick and Chatterjee expressed sympathy for those who have lost their jobs due to coal and nuclear plant closures. But they said providing relief to such workers is the job of Congress and state legislators, not FERC.

Chatterjee said he understood the “human impact” of plant closures because of his visits to West Virginia coal country with Capito and the Colstrip coal plant with Sen. Steve Daines (R-Mont.).

“That is not something that we factor into our record. We will look at plants like Colstrip and make a determination based on … whether there would be threats to reliability in the event the plants shut down,” he told Daines. “But that’s certainly something that’s well within your purview.”

June 13, 2018

ERCOT’s Botkin Named to Texas PUC

Texas Governor Greg Abbott on Monday appointed ERCOT Director of Communications and Government Affairs Shelly Botkin to fill the final vacancy on the state’s Public Utility Commission. Her term expires Sept. 1, 2019.

Shelly Botkin ERCOT PUC of Texas — Botkin

Botkin’s appointment will bring the three-person commission back to full strength. She will fill the position vacated by Brandy Marty Marquez’ departure in March. (See Marquez to Depart Texas PUC.)

Botkin will be sworn in Wednesday and attend her first PUC open meeting Thursday.

The 46-year-old Botkin has been with ERCOT since 2010. She spent the previous 10 years as a senior policy analyst in the Texas Senate and House of Representatives.

ERCOT CEO Bill Magness said in the statement the ISO looks forward to working with Botkin.

“Shelly’s knowledge of electric market policy and the regulatory and legislative process has been a tremendous asset to ERCOT over the last eight years,” he said.

Shelly Botkin ERCOT PUCT — The Texas Governor’s Office is in the state capitol building, constructed from 1882 to 1888.

The PUC has seen a complete turnover of commissioners in little more than a year. Donna Nelson and Ken Anderson, the two longest-serving commissioners, both left the agency last year. They were replaced by Chair DeAnn Walker and Arthur D’Andrea, respectively.

— Tom Kleckner

June 13, 2018

Solar Inverter Problem Leads CAISO to Boost Reserves

By Jason Fordney

CAISO will make permanent a once-temporary practice of boosting its power reserves to account for utility-scale solar tripping offline because of an inverters problem, something NERC has identified as a major reliability issue.

When solar generation is at its peak, CAISO will set the operating reserve target at either 15% of the total solar production forecast or the maximum NERC/Western Electricity Coordination Council requirement, whichever is greater.

caiso utility-scale solar inverters power reserves — CAISO says the inverter problem affects utility-scale solar, not rooftop systems | *Sarah Swenty/USFWS*

The ISO has worked with solar operators to reprogram inverters since last year, CAISO Shift Supervisor John Phipps said Monday at a Market Performance and Planning Forum. Some of the inverters began working properly after reprogramming, but others are hard-wired and still subject to tripping. Phipps said 2,700-2,800 MW of generation across the whole ISO system cannot be reprogrammed.

“They are not in any one regional area; they are spread out across all the plants in California,” Phipps said during a presentation, adding that the issue is not affecting behind-the-meter or storage resources.

The inverters, which convert photovoltaic DC output to utility frequency AC, sometimes trip offline to protect the systems during voltage fluctuations. CAISO began procuring additional reserves a year ago, after the problem occurred in August 2016 because the Blue Cut fire in Cajon Pass caused transmission line faults and disconnected 1,200 MW of solar. (See CAISO Boosts Reserves After August Event Report.)

CAISO CEO Steve Berberich last month cautioned the ISO’s Board of Governors about the seriousness of the problem, which caused the loss of 860 MW of solar resources on April 20. (See CAISO Board Approves Forecast Error Measures.)

The inverter problems have so far triggered two NERC alerts, one on June 20, 2017, and the other on May 1 of this year. NERC said the problem could also affect non-bulk power systems and recommended all operators follow recommendations spelled out in the more recent alert.

“While this NERC alert focuses on solar PV, we encourage similar activities for other inverter-based resources such as, but not limited to, battery energy storage and wind resources,” the agency said in the May 1 alert.

Ancillary Service Scarcity Increases

CAISO has seen an increase in ancillary service scarcity events in the real-time market, Director of Market Analysis and Forecasting Guillermo Bautista Alderete told the forum. He said while the number of incidents has increased, the magnitudes are small, with about 75% of the scarcities at fewer than 10 MW. The increased incidents stem from a confluence of factors and changes in the market, he said, including the solar operating reserve requirement.

Most recently, CAISO issued three notices of ancillary service scarcity events for May 3-6, May 15 and May 23-28, nearly all of which were associated with regulation up service and mostly in the SP26_EXP region in Southern California. In 2018, 46% of the scarcities happened in SP26_EXP, 35% in NP26_EXP and 19% in CAISO_EXP.

CAISO pays an ancillary services scarcity price when it is unable to procure the target quantity of one or more ancillary services in the integrated forward market or real-time market runs. About 52% of the scarcities are due to limits in generator telemetry, which is the process whereby a generator supplies the ISO with real-time data. Mismatches between telemetry and real-time needs require the ISO to procure additional capacity in the real-time market. About 33% are due to generator outages and re-rates, and 15% are categorized as “other.”

CAISO’s Market Monitor in its 2017 State of the Market report noted that scarcity events in the real-time market “increased significantly” from 26 in 2016 to 54 in 2017.

June 12, 2018March 25, 2025

Five Questions on Trump’s Coal, Nuke Bailout

By Rich Heidorn Jr.

More than a week after President Trump directed Energy Secretary Rick Perry to prevent additional coal and nuclear plant retirements, the administration has provided no additional details on how it plans to implement the bailouts or how much they will cost.

With no answers coming from D.C., analysts and others have been left to speculate on the bailout’s potential impact. Here’s five important questions and possible answers.

Can the Trump/Perry Plan Survive Legal Challenges?

Trump’s directive came after the leak of a 40-page draft Department of Energy memorandum that said coal and nuclear plant retirements are a threat to national security, in part because natural gas pipelines could be subject to terrorist attacks. It called for keeping at-risk plants alive through capacity and energy payments for at least two years while the department studies the risks and then creates a “Strategic Electric Generation Reserve.”

The memo cited the Defense Production Act of 1950 (DPA) — enacted to aid the nation’s civil defenses and war mobilization at the beginning of the Korean War — and Section 202c of the Federal Power Act, which allows the energy secretary to issue emergency orders during energy shortages.

The DOE memo said the retirements threaten the electric supplies for the nation’s military bases, citing a 2008 Defense Science Board report that noted virtually all of the electricity supplying the nation’s more than 500 military installations is generated outside the facilities. “Backup power at military installations is based on assumptions of a more resilient grid than exists and much shorter outages than may occur and is not sized to accommodate new homeland defense missions,” the report said.

At the time, the bases’ backup power was almost entirely diesel generators. Since then, the Defense Department has begun investing in microgrids and solar generation to allow their critical operations to continue operating during grid outages.

Preview?

Attorneys general from nine states and D.C. offered a preview of legal arguments against the DOE plan in challenging FirstEnergy Solutions’ March 29 request to invoke 202c to prevent retirements of its coal and nuclear generation in PJM.

In a May 9 letter to Perry, attorneys general for Massachusetts, Connecticut, Illinois, Maryland, North Carolina, Oregon, Rhode Island, Virginia, Washington state and D.C. said 202c was never intended to rescue “inefficient generators.”

Perry testifying before the House Energy Subcommittee | © RTO Insider

“Section 202c explicitly authorizes the secretary to issue temporary orders only in wartime or other ‘emergency’ situations resulting from ‘sudden’ electricity demand spikes or supply shortages,” they wrote. “Though the Federal Power Act does not define the terms ‘emergency’ or ‘sudden,’ the plain meaning of these terms indicates that Congress intended Section 202c authority to be invoked rarely, in response to acute events that demand immediate response.”

DOE says it has deployed Section 202c on eight occasions, all in response to regional energy challenges. It has not previously been applied nationwide.

The department’s memo contends that “Congress contemplated the use of the provision not merely to react to actual disasters, but to act in a preventive manner. A variety of man-made and natural threat conditions require … a federal agency ready to do all that can be done in order to prevent a breakdown in electric supply.”

The AGs cited statements by FERC and PJM that potential plant closures do not pose an emergency. They also rejected a National Energy Technology Laboratory study cited by FirstEnergy that concluded PJM’s demand during the December 2017-January 2018 cold snap “could not have been met without coal.”

The study “mistakenly concludes that coal-fired generation was critical to reliability because coal-fired generation disproportionately increased during the cold snap,” the AGs said. The extreme cold caused a spike in natural gas prices, briefly making coal generators more competitive.

“That certain resources were dispatched is not evidence the system lacked (or will lack during future events) other resources that could have been called upon instead to meet market demand and maintain reliability,” the AGs said. “PJM has more than enough capacity to meet demand, even in extreme weather.”

FAST Act

In addition to the DPA and FPA, the memo cites a third law as apparent authority, the 2015 Fixing America’s Surface Transportation Act (FAST) Act, which amends the FPA to authorize DOE to order emergency measures to protect “defense critical electric infrastructure” following a presidential declaration of an imminent grid security emergency.

Peskoe | © RTO Insider

“Citing these three laws implicitly concedes that there is no single law that provides DOE with the authority to do what it wants to do,” Ari Peskoe, director of the Electricity Initiative at Harvard Law School’s Environmental & Energy Law Program, said in a podcast last week. “DOE’s argument is that the whole is greater than the sum of its parts.”

Peskoe said there are three paths opponents could take to attempt to block the bailouts, including a federal court suit to overturn the eventual DOE order and FERC complaints challenging individual wholesale contracts compensating the at-risk plants as not just and reasonable. “And separately you could also have more action at FERC arguing that these contracts are disrupting the larger market,” he added.

Prior 202c Invocations

DOE’s most recent invocations of 202c were limited to single generating plants and local reliability problems.

In December 2005, DOE granted the D.C. Public Service Commission’s request to order Mirant Corp. to continue running its Potomac River Generating Station despite its inability to meet EPA’s National Ambient Air Quality Standards, finding that the region otherwise faced a “reasonable possibility” of extended blackouts.

DOE noted that much of the district, including the FBI, State Department and other federal government agencies, were supplied only by the Mirant plant and two 230-kV lines connected to other generation. The loss of those sources also would threaten the city’s water treatment center, which would be forced to release untreated sewage into the Potomac River if it lost power for more than a day, the department said.

The order required Mirant to keep the plant operating at a low level that allowed a quick start-up if either of the lines were lost. “Mirant and its customers should agree to mutually satisfactory terms for any costs incurred by Mirant under this order,” the department said. “lf no agreement can be reached, just and reasonable terms shall be established by a supplemental order.”

Originally set to expire in 10 months, the order was twice extended for two months and once for five months. It was terminated on July 1, 2007, after the completion of new transmission.

Most recently, DOE in June 2016 granted PJM’s request to order Dominion Energy Virginia to continue running its coal-fired Yorktown Power Station for 90 days despite its violation of EPA’s Mercury and Air Toxics Standards. The department found that reliability in the Hampton Roads area of Virginia could otherwise be at risk during summer peaks.

PJM said it needed to keep the plant available because of delays in construction of the 500-kV Skiffes Creek transmission project, the subject of court fights because of the proximity of its James River crossing near historic sites.

DOE extended the 90-day order four times thereafter, most recently on June 8, 2018. That order expires on Sept. 9. PJM’s most recent extension request estimated the transmission project will be complete in August 2019 and that Yorktown will not be dispatched after May 2019.

What’s FERC’s Role?

The five FERC commissioners are due to testify Tuesday before the Senate Energy and Natural Resources Committee in a previously scheduled oversight hearing. But it is unclear how much they will say about the proposed bailouts.

FERC was given no advance notice of the Trump directive and had received no additional information on it as of last Tuesday, when Chairman Kevin McIntyre met with reporters after speaking at the Energy Information Administration’s Energy Conference. (See related story, FERC Blindsided by Half-Baked Trump Order.)

The draft memo had been prepared in advance of a June 1 meeting of the National Security Council, and DOE’s plan will be reviewed by the NSC’s Policy Coordinating Committees. FERC is not a principal in the process.

Tezak | ClearView Energy Partners

Although FERC has been excluded from policy deliberations thus far, the resilience docket the commission opened in January could play a role in any litigation, Christine Tezak of ClearView Energy Partners said in an analysis for clients Friday (AD18-7). FERC opened the docket after rejecting DOE’s Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants with on-site fuel. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

Evidence that FERC, RTOs and states are moving aggressively on resilience could undercut DOE’s legal standing, Tezak said. “We would expect the opponents of action … to reference the contents of this proceeding before FERC as evidence that the DOE’s conclusions regarding resiliency are misplaced or in error.”

If DOE’s order survives legal challenges, the FERC proceeding could provide a path forward after the two-year study, Tezak said. “We think there is the potential for the FERC’s resilience docket to provide information that could lead to DOE winding down if not ending altogether its potential market intervention.”

In addition, FERC will hear testimony at its annual technical conference on reliability July 31 to consider whether new NERC standards are needed to ensure “essential reliability services” (AD18-11). NERC has identified those services as including frequency and voltage support, ramping capability, operating reserves and reactive power. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)

Chatterjee, Glick Call for Mandatory PL Standards

In a perhaps unlikely pairing, Commissioners Neil Chatterjee, a coal-state Republican, and Richard Glick, a carbon-conscious Democrat, joined Monday in an apparent effort to reassert FERC’s role in the debate. In a joint op-ed, they called for mandatory reliability standards for natural gas pipelines like those FERC and NERC enforce on the grid.

They noted that the Transportation Security Administration, which has responsibility for securing natural gas, oil and hazardous liquid pipelines, relies on voluntary cybersecurity standards. “In May 2017, TSA confirmed that it had just six full-time employees” overseeing pipeline security, they wrote.

“Given the high stakes, Congress should vest responsibility for pipeline security with an agency that fully comprehends the energy sector and has sufficient resources to address this growing threat,” they continued. “The Department of Energy could be an appropriate choice: It is the sector-specific agency for energy security and recently created its own cybersecurity office.”

How Will it Affect Emissions?

Because the bailout would cover both coal and nuclear plants, there is disagreement on how it would affect carbon emissions.

As of March, according to EIA, 21.2 GW of coal generation and 6.2 GW of nuclear capacity were scheduled to retire through 2027. EIA’s list does not include FirstEnergy’s announcement in late March that it will close its Davis-Besse, Perry and Beaver Valley nuclear plants, which total about 3.9 GW, by 2021.

About 21.2 GW of coal generation and 10.1 GW of nuclear capacity are at risk of retirement through 2027 | FirstEnergy Solutions, Energy Information Administration Electric Power Monthly, March 2018

Bloomberg New Energy Finance said in a report last week that emissions might be lower than the status quo if at-risk nuclear plants are kept running. It said that although capacity payments would keep coal plants available for backup, they may not actually run more under the Trump plan. Thus, the nuclear plants “could displace millions of tons of carbon dioxide a year” from coal plants, analyst Will Nelson said.

coal and nuclear plant retirements trump rick perry

Sivaram | © RTO Insider

While nuclear plants have capacity factors of more than 90%, many at-risk coal plants operate less than 50% of the time.

But Varun Sivaram, fellow for science and technology at the Council on Foreign Relations, told Axios last week that freezing coal and nuclear generation at their 2017 levels — preventing them from the drops forecast by EIA — would mean coal-fired production would be 24% more than the additional nuclear generation in 2025. That would translate to between 0 and 5% higher emissions in 2025 relative to 2017, depending on the relative displacement of gas and renewables, he said.

How Will it Impact RTO Markets?

RTO officials told RTO Insider last week that, like FERC, they had received no information from DOE on the plan or when it might be finalized. (See More Questions than Answers for FERC, RTOs on Bailout.)

“We don’t know if it will be a week, two weeks or months” before DOE acts, said one RTO official.

Craig Glazer, PJM’s vice president of federal government policy, told the EIA conference last week that Trump’s directive will “probably complicate” his RTO’s struggle to deal with state nuclear subsidies. He said he fears a “half slave/half free” industry in which generators dependent on market revenues increasingly compete with those receiving cost-of-service payments or subsidies.

While RTO officials may not lead the legal challenges, their insistence that there is no emergency won’t help DOE’s defense. They point out that they have been successful in keeping plants running temporarily beyond their retirement dates when needed to prevent reliability problems. ISO-NE, for example, has asked FERC to waive its Tariff to keep Exelon’s Mystic generating station running to address fuel security concerns. (See Mystic Waiver Request Spurs Strong Opposition.)

Prest | Resources for the Future

Palmer | Resources for the Future

Brian C. Prest and Karen L. Palmer, fellows with nonpartisan think tank Resources for the Future, wrote last week about the questions raised by DOE’s proposed Strategic Electric Generation Reserve. Among them: the size of the reserve, how generators would be procured and whether those selected be permitted to participate in or return to the energy markets.

Although the DOE memo provided no details, the fellows looked to the strategic reserve Germany is considering as it continues its phase out of nuclear power. The country has retired more than half of its nuclear generation since 2008 while more than tripling its non-hydro renewable capacity. It now gets half its capacity from non-hydro renewables versus 27% coal and nuclear and 14% gas.

Germany’s reserve will be initially capped at 2 GW, about 2% of peak load, rising to as much as 5 GW (5%) after 2020. The reserve capacity will be procured through technology-neutral competitive auctions and open to demand response. The capacity would be used only as a last resort.

“It is not clear from the scant description in the memo how the SEGR would be procured, but the heavy-handed approach for the electricity purchase mandates suggests that competitive auctions are probably not under consideration,” they wrote. “It seems more likely that plants would be chosen in the same way that they would be chosen for the electricity purchase mandates — based on a federally determined list of ‘fuel-secure’ generators (best interpreted as coal and nuclear plants).”

They note that Germany plans to address concerns the reserve will discourage new capacity investment by prohibiting reserve generators from re-entering the market. “Unfortunately, DOE’s proposed order is specifically designed to send the message that government policy will find a way for unprofitable plants to return to the market, even calling its own order a ‘stop-gap measure.’”

How Much Will it Cost?

Because so many details about the administration’s plan are unknown, no one has produced an analysis of how much it will cost — including DOE itself. (See related story, Dems Hit Coal, Nuke Bailout at House Hearing.)

But some analysts produced estimates on the DOE NOPR rejected by FERC. It would have given cost-of-service payments to coal and nuclear plants in RTOs with capacity markets if they have 90 days of fuel on site.

ICF estimated the NOPR would cost ratepayers $1 billion to $4 billion per year between 2018 and 2030. The estimate was based on contracts for differences bringing money-losing generators to break even.

ICF caveated that the analysis might have underestimated the cost because it did not include recovery of and on capital. But it said the analysis also didn’t account for the likelihood that wholesale electricity and natural gas prices will be lower than they would have been had the plants retired.

Orvis | Energy Innovation Policy & Technology

Energy Innovation Policy & Technology, which supports policies reducing greenhouse gas emissions, said the NOPR would have cost from $311 million to $900 million annually in PJM, ISO-NE, NYISO and MISO alone. The low estimate represents the out-of-market payments needed to bring units with negative net cash flows up to zero. The upper limit adds capital recovery and a rate of return on undepreciated capital and future capital expenditures.

“There are, of course, important differences between the resilience NOPR and the 202c actions being discussed by the Trump administration, but our study is a good rough estimate of the cost to keep the same group of uneconomic plants online,” said Robbie Orvis, director of energy policy design for the group.

June 12, 2018

Competition, Cooperation and Costs the Talk at OSW Conference

By Michael Kuser

BOSTON — Competition among states to set the highest offshore wind energy targets and to secure supply chain jobs is gradually giving way to a regional cooperation, the head of the Bureau of Ocean Energy Management said last week.

OSW Conference Offshore Wind Energy BOEM — Cruickshank | © *RTO Insider*

“In our view, all of the federal leases, they don’t belong to any particular state, and we need to be thinking about how to manage those assets on a regional community basis,” acting BOEM Director Walter Cruickshank said at New Energy Update’s U.S. Offshore Wind Conference, held June 7-8.

“And we’re certainly seeing that already,” Cruickshank added. “We’ve seen projects that were leased off of one state getting agreements with neighboring states.”

He cited the collaborative development efforts of Massachusetts and Rhode Island, of “Virginia and the Carolinas, and obviously in the New York Bight, where there are a lot of states that have stakeholder interest.”

New Energy Update held their annual U.S. Offshore Wind conference last week in Boston. | © *RTO Insider*

In May, Vineyard Wind, a partnership between Avangrid Renewables and Copenhagen Infrastructure Partners, won a contract to supply Massachusetts with 800 MW of offshore wind energy. In the same solicitation, Rhode Island picked Deepwater Wind to build a 400-MW version of its Revolution Wind proposal. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

Picking up the Pace

Panelists at the conference also discussed ways to reduce costs and speed up permitting.

The Department of Energy’s 2015 Wind Vision report set a goal of deploying 86 GW of offshore wind by 2050. The U.S. would need to use about 4.2% of the total technical resource area to reach the goal, according to the National Renewable Energy Laboratory’s September 2016 Offshore Wind Energy Resource Assessment. The technical resource area includes areas of the Great Lakes and the Atlantic and Pacific coasts with wind speeds of at least 7 meters/second and water depths of less than 60 meters (Great Lakes) or 1,000 meters (the oceans).

The 11 BOEM leases issued so far could produce 20 GW by 2030 “based on the physical capacity of these leases,” said Tom Harries of Bloomberg New Energy Finance. The typical timeline from lease to operation is five to seven years.

Stephen Bull, senior vice president at Norway-based Equinor (formerly Statoil), said he’d like “to see BOEM interact more at the state level, to really try to fast-track or work quicker to get wind energy areas out there.” Conference chair Stephen Pike, CEO of the Massachusetts Clean Energy Center, a state agency in charge of offshore wind development, asked about having BOEM pre-permit the leases to speed up development, as is done in Europe.

“That’s not the way the federal government works,” said Cruickshank, explaining that the bureau has no funding for capital-intensive marine surveys.

Floating Turbines

Although BOEM’s leases to date have been off the Atlantic Coast, BOEM is also looking to the Pacific, which will require floating wind technology because of the much greater water depths, Cruickshank said.

“We’re cautiously optimistic we’ll be able to move ahead with some of those leases later this year.”

Daniel Simmons, principal deputy assistant secretary for DOE’s Office of Energy Efficiency and Renewable Energy, said improving floating platforms “is an important area for us just because so much of our wind resources offshore is in deep water.”

Walter Musial, manager of offshore wind at the National Renewable Energy Laboratory, who explored the levelized cost of energy for floating turbines, said about 58% of potential offshore wind areas are deeper than 60 meters.

“Floating obviously starts out a bit more expensive, but it’s a maturity thing, so fixed and floating turbine costs converge over time,” Musial said. “Actual costs are confidential — they don’t report them in the newspaper.”

Manufacturers need to see the market demand in order to develop optimized turbine systems for floating platforms, he said. “Up till now, every single deployment has been with a turbine that was actually designed for a fixed bottom system, so we’re sub-optimum,” he said.

But the industry is now moving beyond the floating prototype phase. “I’ve counted about 11 projects totaling 229 MW,” Musial said. “These are going in with some subsidies, but also with regular financing, and they’re going in all over the world.”

NREL wind analyst Garrett Barter agreed, saying the current design paradigm of offshore turbines “won’t give you a cost-competitive floating system.”

Engineering and design are just a fraction of the total cost for a floating wind turbine. Most of the costs are the operational expenses, logistics, assembly and installation, and financing, he said.

“So you really need a systems approach that can tackle all these complexities at the same time, and not just focus on the turbine itself,” Barter said. He recommended multidisciplinary analysis and optimization, which is “a tool and also a state of mind where you connect the whole power production process, the whole load path, the controls that sit in between those two, and the whole balance sheet over the lifecycle of the plant.”

He said the offshore industry may have to evolve into a structure like that of the aerospace industry, where a global supply chain serves a system owned by the prime contractor.

Driving Down Costs

Experts say it will take several years for the U.S. market to mature before it matches the separate cost curves for the established European market

“We think the transition happens around 3 to 4 GW of installed capacity, which should be in 2028 in the U.S., and the industry will move onto the established cost curve and really see price reductions,” Harries said. “The regulatory route gets simplified, and then gradually you build your experience and you move down this cost curve. Supply chains gain experience, and routes to market become very clear.”

Jonathan Cole, managing director of offshore for Avangrid parent Iberdrola’s renewable business, wants to see nearly that much capacity entering the pipeline each year.

“As soon as possible, get to a place where this market is being fed with 2 to 3 GW of new projects every year, which means you’ve got enough volume to support a local supply chain,” Cole said. “That’s when you’ll truly see cost reductions and the industrialization happening.”

Cole said that so far, they’ve been able to lower development costs through tax credits, which are now being phased out.

“We’re hoping that the downside of removing the tax credits is going to be more than compensated by the positive … making a more efficient and optimized installation,” he said.

Northeast Advantage

Vineyard Wind CEO Lars Thaaning Pedersen said tax credits are an important part of the price structure in Massachusetts, but “the benefits … these projects will bring to the southeast coast” of New England may be more important, such as avoiding the high cost of building transmission lines to bring hydropower from Canada.

The state “has taken a bold step already … and I’m confident that Massachusetts will be at the center of the industry,” Pedersen said.

Francis Slingsby, head of strategic partnerships at Orsted, congratulated Pedersen. Despite not winning the first round of the Massachusetts-Rhode Island solicitation, Slingsby said Orsted is committed to developing its Massachusetts lease areas, “which in our estimation are superb.”

“Wind speeds increase as you move farther north along the coast, which gives New England an innate advantage,” he added.

Massachusetts Energy Secretary Matthew Beaton referred to the previous day’s tour of the New Bedford Marine Commerce Terminal, which was built for the deployment of offshore wind, as evidence of the state’s chance to lead the industry.

“To see international companies come in with Massachusetts companies made me realize … this thing’s for real, this thing’s happening, and we have all the pieces that we need,” Beaton said. “Eight hundred megawatts is just the starting point.”

Bill White, MassCEC director of offshore wind development, said, “Growth in Massachusetts is really about … what it will cost to ratepayers.”

John B. Lavelle, head of offshore wind for GE Renewable Energy, said volume will be the biggest driver of cost reductions. Lavelle said GE will “compete in the U.S. with our 12-MW platform that we just announced.”

Operating costs will come down partially through “a lot of automation,” Lavelle said. “You don’t want to send people 15 miles off the coast if you don’t have to.”

NY, NJ, Md. Moving Forward

Elisabeth Treseder, senior regulatory adviser for Orsted, said New Jersey’s commitment in May to build 3,500 MW of offshore wind by 2030 — surpassing New York’s target of 2,400 MW — “provides a lot of certainty and reassurance” to the market. (See Gov. Signs NJ Nuke Subsidy, Renewables Bills.)

“We’re still waiting for the New Jersey Board of Public Utilities to finish its plan, which for us means focusing on the local supply chain and workforce development,” Treseder said. “New Jersey was very wise in passing a $100 million tax break for offshore wind manufacturing, which left them an additional pool [of incentives] for suppliers.”

Kenneth J. Sheehan, director of economic development and emerging technologies at the BPU, said the state is working to develop its master plan and its first solicitation.

Left to right: Kenneth J. Sheehan, NJBPU; Elisabeth Treseder, Ørsted; and Jim Lanard, Magellan Wind | © *RTO Insider*

“We are looking for suppliers, transmission, for all the factors that go into it, and the OREC [offshore wind renewable energy credit], the single price, up-front method of funding, takes all this into consideration,” Sheehan said.

Jim Lanard, CEO of Magellan Wind, asked Sheehan what his state’s position is regarding wind energy areas that could serve both New York and New Jersey.

“Half the New York Bight is in New Jersey, so we’re not practically upset about additional project development off our shore,” Sheehan said, referring to the Atlantic Coast region between Cape May, N.J., and Montauk Point on Long Island. “At the start, it’s every state for itself. … Everything could be supplied from New Jersey. And New York thinks the same of itself.”

Kevin Knobloch, president of transmission developer Anbaric’s New York Ocean Grid, said that particularly with New Jersey’s goal of 3,500 MW, there’s a sense of great urgency to get the first turbines in the water.

“We believe the wise approach is from the very first solicitations to separate generation from transmission, and open it up to competition,” Knobloch said. “In so doing, the state decision-makers still reserve the right to go with an offer that’s bidding on both attributes.”

OSW Conference Offshore Wind Energy — Harries | © *RTO Insider*

Doreen Harris, director of large-scale renewables at the New York State Energy Research and Development Authority, said the agency is also identifying new wind energy areas off New York City. There is a proceeding before state regulators now “to make the first utility-scale procurement later this year,” she said.

Christer Geijerstam, director of the Empire Wind project for Equinor, which bought the first New York lease in 2016, said that aside from preparing for a state bid, the company is “focused on project technical issues to reduce asset risks” prior to the hoped-for start of construction.

John Hartnett, business opportunity manager of U.S. offshore wind for Shell Wind Energy, said his company “had really jumped into the U.S. markets driven by the evidence of the northeast. Right now, we are investigating the upcoming lease opportunities, both in Massachusetts and New York, and are very hopeful to have site control in time to participate in the upcoming auctions.”

The Maryland Public Service Commission approved two offshore wind projects totaling 368 MW in May 2017, allowing the developers to receive ORECs. The projects are estimated to create 9,700 full time equivalent jobs and result in more than $2 billion of economic activity in Maryland, including $120 million of investments in port infrastructure and steel fabrication facilities.

Samuel Beirne, wind energy program manager for the Maryland Energy Administration, said that “most offshore wind developers have to contract through the state Public Service Commission [to obtain ORECs] … and most use a third-party consultant to help them.”

Aileen Kenney, senior vice president of development for Deepwater Wind, said the company’s 120-MW Skipjack project off Maryland will start construction in 2021 and go online the following year.

“Right now we’re mapping all the seafloor, doing bathymetry analysis,” Kenney said.

Production Tax Credit

According to DOE, the federal renewable electricity production tax credit is an inflation-adjusted 1.9 cent/kWh tax credit for wind for the 2017 calendar year. The credit lasts 10 years after the date the facility is placed in service.

The tax credit is phased down for wind facilities as a percentage reduction: for wind facilities beginning construction in 2017, the PTC amount is reduced by 20%; for 2018, 40%; and for 2019, 60%.

June 12, 2018

FERC OKs Change to SPP ‘Net Benefits’ Test for DR

FERC last week approved SPP’s May 2016 proposal to change how it measures the net benefits of demand response under Order 745 (ER12-1179).

FERC Order 745 Net Benefits Demand Response — Inside SPP’s control room | *SPP*

The 2011 order requires grid operators to pay DR resources full LMPs when they are able to reduce demand and their dispatch is more cost-effective than generation, as determined by a net benefits test.

SPP’s May 2016 compliance filing came in response to an April 2014 FERC order requiring the RTO to re-evaluate its net benefits test methodology using Integrated Marketplace data. The commission also asked SPP to propose any necessary changes to make its methodology compliant with Order 745 and to re-evaluate the appropriateness of its systemwide DR cost allocation mechanism.

The RTO proposed adjusting its net benefits test to use all available offer data and include non-peak hour data in the construction of supply curves. It said it would first average supply curves and then smooth the resulting average curve when performing the net benefits test.

“We agree with SPP that these two design changes to SPP’s net benefits test methodology are appropriate given the greater availability of offer data in the Integrated Marketplace,” the commission said. It ordered SPP to file Tariff revisions by July 5 implementing the two changes.

FERC also accepted SPP’s explanation that it did not need to adjust its DR cost allocation provisions, given there had not been any load-reduction activity in its footprint.

— Tom Kleckner

June 12, 2018

Troubled Waters for Powerex in EIM

By Robert Mullin

PORTLAND, Ore. — Two months after making a smooth integration into the Western Energy Imbalance Market, Canada-based Powerex now finds itself navigating a turbulent relationship with market rules the company says undercut the value of its hydroelectric resources, company officials said last week.

At issue for Powerex is the frequency with which transmission constraints at the U.S.-Canada border trigger CAISO’s local market power mitigation (LMPM) process in the EIM, which mandates use of default energy bids (DEBs) to settle transactions. Inflexibility in the formulas underpinning the DEBs often leave Powerex market operations out of the money, the company says.

CAISO EIM Powerex hydro — Spires | © *RTO Insider*

“The LMPM processes and the DEB options are not workable for Powerex or for external hydro more generally,” Powerex Director of Power Jeff Spires said during a presentation at a June 6 meeting of the EIM Regional Issues Forum meeting at Bonneville Power Administration offices.

Powerex, which markets surplus power for the government-owned BC Hydro utility, began transacting in the EIM on April 4. As part of its membership, Powerex has volunteered about 300 MW of its transfer capacity into the market, half of which links British Columbia with the Puget Sound Energy balancing authority area (BAA) near Seattle. The other half allows transfers into CAISO via the Malin delivery point on the California-Oregon Intertie.

“We participate with large-scale hydro that’s very fast-ramping,” Mike Goodenough, Powerex trading manager, told the forum. “Often times we’re in a ‘buy’ mode, and particularly when the market is in oversupply, we’re buying, and the transmission can become constrained because we ramp so fast during the market power mitigation market run [that] the ties fill. And at that point, there’s a constraint and market power [mitigation] kicks in. The default bids then kick in and override all of our bids and offers.”

DEB Options ‘Formulaic’

The problem in those instances, Goodenough said, is that the EIM’s DEB options are “more or less formulaic” and “often very wrong” with respect to Powerex’s opportunity costs during a trading interval.

The result is “very frequent mitigation” that forces Powerex to sell below its opportunity costs when it intends to be purchasing in the market to take advantage of arbitrage, Goodenough said.

During these periods, Powerex’s traders seek to raise their sell offers upward to avoid sales but are prevented from doing so when mitigation kicks in, defaulting the market to rely on DEBs.

“And because the default bids are wrong, where we would be a buyer, we are now in the dispatch run as a seller,” he said. “And so, there’s obviously two problems there. One is, we’re now selling into a market in which there might already be in oversupply. But more importantly for us, we’re now depleting energy-limited resources at the wrong time.”

In an April 30 presentation to a CAISO workshop on broader DEB issues, Powerex described the shortcomings of each default bid option available to EIM market participants heavily reliant on hydro assets:

The “variable cost” option, based on heat rates, fuel price and greenhouse gas costs, is “not relevant” for hydro resources that are more driven by opportunity costs than variable production costs.
The “backward-looking” LMP option — based on the on the lowest 25th percentile of LMPs at which a resource has been dispatched during the previous 90 days — is “not workable” for hydro resources whose opportunity costs “are driven by current and expected future conditions.”
The “negotiated rate” option, in which a formula is negotiated between a resource’s scheduling coordinator and CAISO and its Department of Market Monitoring, is “theoretically workable” for all resources but “not workable in practice” for hydro resources outside the CAISO BAA. This option requires the ability to determine a methodology to estimate expected marginal costs, “which are complex, dynamic, and involve both objective and subjective factors,” Powerex said.

“You can’t precisely estimate costs for hydro,” Spires told the forum. “External [to the CAISO BAA] hydro in particular has multiple bilateral opportunities. We have a myriad of constraints within the BC network,” including seasonal monthly, weekly and daily storage requirements, as well as recreational constraints.

“There’s so many different things and they can change at the drop of a hat and you need to be able to respond to that, and so we really support flexibility in determining what your marginal opportunity costs are,” Spires said. He said the flexibility is required to avoid “forced sales.”

Spires said that the EIM’s LMPM process functions as if the supplier conduct threshold for triggering mitigation is zero, meaning that “as soon as your bid or offer price is even a penny above the reference price, then you’re subject to potential mitigation if the transmission is constrained.”

“It goes beyond the commercial impact — it’s an operation impact as well,” Spires said. “And it’s a loss of control of being able to decide what to do with your resources in light of the information that you have at the time.”

Unlike other EIM members, Powerex functions only as a marketing operation and not as a balancing authority or load-serving entity, which means it has no ratepayers exposed to EIM prices.

Thus, the company says its import transfer path into British Columbia is used primarily for “economic displacement” (importing low-priced power to displace use of internal generation) and doesn’t serve any retail customers. In its April 30 presentation, the company questioned whether it was appropriate to apply LMPM to transfer paths where “there is no potential for market power.”

Spires said the situation is discouraging Powerex’s participation in the EIM.

“It’s frankly less attractive than the existing real-time market — the intertie bidding framework where we don’t face these issues, [and] particularly for us, because we have transmission access to the CAISO and so we’ve got the opportunity to deliver a clean supply into that market,” he said. “And so the EIM is a step backwards from that perspective.”

Spires concluded his presentation by expressing appreciation for CAISO’s support in transitioning Powerex into the EIM, but he also urged the ISO to address the company’s dilemma soon.

“We think that it is important to others, and we’re looking forward to working on these issues, but we need a resolution quickly.”

Interim Solution?

In April, CAISO asked FERC to approve a Tariff waiver to alleviate the impact of LMPM on Powerex’s operations by reducing the number of intervals for which mitigation applies after being triggered (ER13-1889).

“The interim solution consists of an automated process by which Powerex’s EIM transfers will be restricted only during intervals in which this condition [producing forced sales] occurs, as well as limiting mitigation of Powerex’s aggregated participating resource to the market interval in which the mitigation of that resource is triggered,” CAISO said in its filing.

The ISO said the interim solution “will apply solely to Powerex’s aggregated participating resource operating under the unique Canadian EIM entity arrangements.”

But while the potential Tariff waiver would partially alleviate the LMPM issue for Powerex, the company has noted it would not address the company’s underlying concerns about the DEB calculation options or the fact that its sales prices would be mitigated to uneconomic levels when LMPM is triggered.

During the April 30 workshop, CAISO Vice President for Market Quality and Renewable Integration Mark Rothleder acknowledged “there is a gap” between what some stakeholders “feel their ultimate opportunity costs are and what they believe a calculated DEB under the existing mechanisms can achieve.”

“This may be the fundamental issue in terms of continuing the EIM and the success of the EIM, so we have to get this right,” Rothleder said, adding that the ISO must receive comments from stakeholders before kicking off an initiative to address the DEB issue.

While time might be of the essence for Powerex, CAISO told RTO Insider on Monday that “no time frame has been set for this miscellaneous stakeholder process as of this time, although we do plan to have a second workshop in July to further discuss the concerns and some ideas for addressing them.”