Consolidated Edison on Thursday reported first-quarter revenues up broadly across its operations, with results reflecting regulatory charges, changes in rate plans and weather’s impact on steam revenues.
The company’s $3.23 billion in revenue for the period represented a 2.3% increase over the $3.16 billion recorded in the first quarter of 2016.
ConEd
According to its earnings presentation, Con Ed’s electric distribution business earned $1.93 billion in the quarter, up 1.2% from $1.9 billion in the same period a year ago. The natural gas segment’s earnings jumped 27.5% to $862 million, and steam revenues — the unit mostly serving Manhattan skyscrapers — climbed 15.5% to $298 million.
Related Developments
The New York Public Service Commission in March issued an order that changes the way distributed energy resources are compensated, which affects the holding company’s two regulated utility subsidiaries, Consolidated Edison Company of New York (CECONY) and Orange & Rockland Utilities. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
According to the company’s most recent filing with the U.S. Securities and Exchange Commission, to provide a gradual transition from net energy metering, the PSC allowed “all existing resources to keep their current rate treatment and will delay making significant changes to policies affecting new residential and small commercial rooftop solar until 2020. Larger installations, including new commercial and industrial projects and new community solar projects, will be paid for the value of their exports to the electricity distribution system.”
Upgrading generating stations | ConEd
The New Jersey Board of Public Utilities in February approved a stipulation of settlement for a Rockland Electric rate plan commencing in March 2017, which provides for “an electric rate increase of $1.7 million, reflecting a return on common equity of 9.6% and a common equity ratio of 49.7%.”
Con Ed reported its Clean Energy Businesses subsidiary had 1,133 MW of renewable energy projects in service and 398 MW under construction at the end of the quarter. Regarding Con Ed Transmission, FERC in March issued a revised schedule for the Mountain Valley Pipeline, setting June 23, 2017, for completion of the environmental impact statement and Sept. 21 as the 90-day federal authorization decision deadline.
WASHINGTON — Senate witnesses agreed Thursday that the threat posed by electromagnetic pulse attacks is a major concern but differed on the adequacy of public and private efforts to protect the electric grid.
The Senate Energy and Natural Resources Committee heard testimony from six witnesses on EMPs, policy options for protecting energy infrastructure and improving capabilities for restoring the system after an attack.
Chair Lisa Murkowski (R-Alaska) said there is heightened concern over the threat of EMPs — blasts of electromagnetic energy from a nuclear weapon that can disrupt or destroy microprocessors and other electronic devices — because of the potential spread of nuclear weapons to nations such as North Korea and the ubiquity of electronics.
“This has magnified the impact, as compared to the potential impact in the 1960s, that an EMP burst could now have on the electric grid, the technologies that rely on electronics and our daily lives,” she said.
The broad discussion also veered into risks associated with cyberattacks as well as naturally occurring geomagnetic disturbances (GMDs).
The bleakest pictures were painted by former House Speaker Newt Gingrich and Ambassador Henry F. Cooper, a Ph.D. engineer and former director of the Defense Department’s Strategic Defense Initiative.
Cooper said that most federal and state efforts to safeguard the electric system against low-probability, high-risk attacks have been “grossly inadequate.” He said the U.S. government has not devoted enough attention to EMP attacks that are “known to be included in the doctrine and planning of Russia, China, North Korea and Iran.”
Because no defense is perfect, Cooper said more effort should be made to “harden” critical infrastructure against “the full complement of threats.”
Gingrich said that while North America has done an excellent job of developing an efficient electric grid, this efficiency makes it inherently “fragile.”
A widespread grid failure that lasts a long time could be more damaging than the terror attacks of Sept. 11, 2001, Gingrich said. The former congressman, who wrote about the threat in a 2011 book, “To Save America,” alluded to the possibility of hospitals having patients die for lack of clean water and other services.
“Here we are gambling with our civilization,” Gingrich said. He also cited NASA research that he said suggests Earth could be overdue for a major solar storm that could disrupt much of the grid.
Government is on the Case
While the domestic electric grid is a “complex ecosystem” where disruptions can cascade, much work has been done to safeguard the power system, said Caitlin Durkovich of strategic consulting and advisory firm Toffler Associates.
“There is no doubt we live in a dangerous world,” said Durkovich, the Department of Homeland Security’s assistant secretary for infrastructure protection under President Barack Obama. “The bottom line is the risk to digital and physical infrastructure has grown and our critical infrastructure is more vulnerable than it was a few decades ago,” Durkovich said.
“I want to be clear: We have not ignored the threat of an EMP,” Durkovich told the committee.
Sen. Jim Risch (R-Idaho) also defended the government’s efforts to protect the grid. “These issues have not been ignored by the United States,” Risch said.
But many of the defense efforts are not something that can be discussed in public sessions, Risch said. At the same time, “there is not enough money in the world to protect us 100%,” he added.
FERC, EPRI Recap Ongoing efforts
Acting FERC Chair Cheryl LaFleur offered a rundown of FERC’s and NERC’s efforts to protect against grid disruptions.
The subject of EMP and GMD events have been the topic of “significant scientific research and debate, as well as broad discussion among regulators, elected officials, industry and other stakeholders,” LaFleur said.
“As noted above, the GMD and physical security standards help provide protection against particular aspects of the EMP threat,” LaFleur said. “However, FERC has not directed NERC to develop a standard specifically targeting EMP. To be clear, I believe this is the result of reasoned consideration of the issue.”
Robin Manning, the Electric Power Research Institute’s vice president for transmission and distribution, briefed the Senate panel on his organization’s research on GMDs, EMPs and “high-altitude EMP” (HEMP) events.
“EPRI has been researching GMD for many years, with significant applications now implemented across the electric industry,” Manning said. “Implications and solutions for EMP and HEMP are less understood. Much of the available information is not specifically applied to electric utilities, making it very difficult for utilities and regulators to understand effective options for protecting energy infrastructure,” Manning said.
Lincoln Electric System CEO Kevin Wailes, co-chair of the Electricity Subsector Coordinating Council, testified on behalf of the American Public Power Association.
Wailes said he is skeptical of suggestions in some quarters that the power sector “fully gold plate” the entire grid so it could “theoretically, at least partially survive a high altitude nuclear event.” There is no consensus on what measures should be taken or how effective or costly they might prove, Wailes said.
Despite President Trump’s moves to dismantle his predecessor’s climate change policies, Pacific Gas and Electric isn’t having second thoughts about its strategy of capitalizing on California’s greenhouse gas reduction goals, the utility’s new chief executive said.
“We believe that, regardless of what happens at the federal level, California will continue to lead the way in transitioning to a clean energy economy and we are absolutely committed to remaining a key partner in the state’s efforts,” PG&E CEO Geisha Williams said during a May 2 call to discuss quarterly earnings.
PG&E earned $576 million ($1.13/share) during the first quarter of this year, compared with $107 million ($0.22/share) during the same period a year ago, when the utility recorded $381 million in expenses related to the September 2015 Butte Fire. The blaze was sparked after a tree came into contact with a company-owned power line.
Operating revenues for the quarter were up 7.4% to $4.27 billion on a 43% increase in natural gas sales, just under a third of which was attributable to booking out-of-period revenues stemming from a 2016 decision by the California Public Utilities Commission related to the previous under-collection of gas transmission fees. PG&E’s electricity sales were down 2% from a year earlier to $3.07 billion.
Williams said that California’s transition to a cleaner economy would require state regulators to enact measures that “ensure a fair allocation” of electric supply costs to investor-owned utility customers that choose to depart for the state’s growing number of community choice aggregators (CCAs) and direct access energy providers.
Last month, the state’s three IOUs — which also include Southern California Edison and San Diego Gas & Electric — recently filed a proposal with the PUC seeking changes in how the utilities’ costs for legacy energy contracts are allocated among existing and departing customers. That plan is intended replace the current power charge indifference adjustment (PCIA) with a new system the utilities have dubbed the portfolio allocation methodology (PAM). (See Utility Proposal Would Increase Legacy Costs for California CCAs.)
“As California continues to engage in discussions on the ‘utility of the future,’ we view this as a foundational step for the continued growth of CCAs or other choices that our customers may have in the future,” Williams said, noting that the state’s CCAs also agree about the need to reform the PCIA.
PG&E has also kicked off a $130 million pilot to build the infrastructure to support 7,500 electric vehicle charging stations over the next three years. The utility’s service area currently contains about 5,000 charging stations, a number that’s expected to reach 150,000 by 2025.
Sony eVgo Chargers | NRG
The company earlier this month filed an additional request to spend $250 million to support the charging of medium- and heavy-duty vehicles, such as transit buses.
Williams couldn’t provide a definitive answer to an analyst question about whether PG&E would enter the competitive space of retail charging in addition to participating in the regulated side of providing the supporting infrastructure.
The utility is in a “great position to put in the make-ready” for the charging stations that will facilitate the adoption of EVs, Williams said.
“Looking beyond a regulatory play, we have to really take a look at the economics and the financing and the whole nine yards to see whether [the retail side] really makes sense for us,” she said.
The Tennessee Valley Authority’s Watts Bar 2 nuclear unit, which went offline in March because of an equipment problem, is expected to remain down until sometime this summer, according to CEO Bill Johnson.
The 1,100-MW reactor, the nation’s newest, had begun operation in October 2016. It has been out of service since March 23 following a structural failure in the unit’s condenser, a three-story-high heat exchanger.
Because of the tight space inside the condenser, “the logistics of doing this work are quite tricky,” Johnson said during a May 2 conference call on the federally owned utility’s financial results. He said he could not be more specific about the return-to-service date.
Unit 2 was more than half complete when construction on both units was stopped in the 1980s in part because of a projected decrease in power demand. Unit 1 was completed in the 1990s, but TVA didn’t revive plans for finishing Unit 2 until about a decade ago.
In response to a question, Johnson said that TVA has been working for more than a year to address concerns raised by the Nuclear Regulatory Commission and the corporation’s inspector general about the safety culture at Watts Bar. The commission cited a “chilled work environment” in a March 2016 report.
Watts Bar Nuclear Plant | TVA
Inspector General Richard Moore said last month that he remained unconvinced that “TVA corrective actions will bring about sustainable change.” Three-quarters of workers in a survey conducted last year for Moore’s office expressed reservations about raising safety concerns because of fear of retaliation from plant managers. Johnson says TVA has taken more than 100 corrective steps, many since the survey was done.
Awaiting Board Members
TVA is waiting for the Trump administration to make more nominations to the authority’s board of directors, Johnson noted during the conference call. The board has nine seats, but only six are filled, and two members will see their terms expire later this month. Johnson said it is possible that the two current directors could remain on board until the end of the congressional session or until successors are put in place. TVA would continue to operate without a board quorum, although it couldn’t undertake new projects, he said.
Clean Line Project
When asked by a reporter, Johnson declined to go into detail on TVA’s view of purchasing wind energy from Clean Line Energy Partners’ Plains & Eastern Clean Line project.
Johnson said that both Clean Line and in-house projects must “meet the same test” on whether a project can provide the lowest-cost price for TVA customers. “There are a lot of moving parts to it” beyond the price that Clean Line has quoted, Johnson said. Although TVA is seeing a decline in power demand, it is continuing to study the Clean Line proposal, he said.
On another matter, Johnson said that the Tennessee Valley region has experienced drought-like conditions in recent months. The situation has depressed hydroelectric output at a time when natural gas prices have been increasing, he said.
TVA reported net income of $313 million for the first half of fiscal year 2017, $32 million more than for the same period last year. (TVA operates on a federal fiscal year.) Sales in the second quarter of fiscal year 2017 were down by about 7% compared to the same period in 2016, driven mainly by milder winter weather.
Johnson said that TVA’s workforce has shrunk from roughly 13,000 employees two years ago to about 10,500 now. In addition to normal attrition, TVA has also used some buyout packages to trim payroll.
ERCOT said Tuesday it has sufficient capacity to meet demand for the next five years, including a forecast record peak this summer.
The Texas grid operator released its final seasonal assessment of resource adequacy (SARA) report for the summer months (June-September), projecting a peak demand of nearly 73 GW. That would break its current demand record of 71.1 GW, set last August; the ISO’s peak demand exceeded 70 GW nine times in 2016.
ERCOT also released its latest capacity, demand and reserves (CDR) report, which shows capacity increasing from almost 84.4 GW in 2018 to 87.9 GW through 2022. That is more than enough energy to meet summer load projections that climb from 71 GW in 2018 to 75.2 GW in 2022.
| ERCOT
Summer 2017
ERCOT anticipates almost 82 GW of capacity this summer, including nearly 2,500 MW of planned natural gas-fired generation and about 800 MW of wind and grid-scale solar additions.
“We should have adequate resources under extremely high-load or low-wind generation conditions,” ERCOT’s manager of resource adequacy Pete Warnken said during a conference call Tuesday. He cautioned that there is “a small risk” of conservation or other measures if an “unlikely combination of adverse system conditions occurs.”
The ISO expects “near normal summer conditions” based on the last 14 years, with the “strong potential” for more 100-degree days than the previous two summers.
The ISO’s preliminary SARA report for October and November also foresees enough capacity to meet demand, forecast at about 56 GW. The final fall report will be released in September.
ERCOT will likely be without the services South Texas Electric Cooperative’s three gas-fired units southwest of San Antonio, with a combined capacity of 61 MW. The co-op filed a suspension-of-operations notice with the ISO, saying it plans to decommission and retire the units in August.
Planning Reserve Margin Above 16%
The CDR report indicates ERCOT’s planning reserve margins will be above 16% for the next five years, with the margin exceeding 18% in four of those years, according to the report. The 2018 summer planning reserve margin of 18.9% is slightly lower than the December CDR report, following adjustments made for planned generation additions.
Warren Lasher, the ISO’s senior director of system planning, said ERCOT has received more than 75 generator interconnection requests each of the last two years, though not all projects will get built. The ISO’s target planning reserve margin is 13.75%.
More than 10 GW of planned resources, with anticipated summer peak capacity of almost 5,500 MW, are expected to be in commercial operation by summer 2018, including nearly 1,800 MW of new wind and grid-scale solar generation resources (summer capacity 437 MW) added since the December CDR.
Energy Imbalance Market (EIM) transfers out of CAISO were on the upswing in March, re-establishing a pattern first seen last spring as California’s growing solar surpluses turned the state into a significant exporter of renewable energy.
Real-time transfers out of CAISO were 243,908 MWh during the month, up more than 60% compared with February and March of last year, according to the ISO’s first-quarter EIM benefits report. Last year’s totals do not include transfers into Arizona Public Service, which began participating in the EIM in October 2016.
Normally heavily dependent on imports, the ISO’s balancing area first became a significant exporter of renewables through the EIM early last year. (See CAISO EIM Boosts Market for Renewables in Q1.)
The report also showed that the EIM last quarter saved its participants $31 million through more efficient generation dispatch and reduced greenhouse gas emission by 23,000 metric tons through avoided curtailments of renewables.
| CAISO
CAISO compares the cost savings of EIM dispatch to the same amount of real-time load imbalance in each balancing authority that would have occurred without transfers between them. The market optimizes generation both within and between regions in the 15-minute market and real-time dispatch.
“A significant contributor to EIM benefits is transfers across balancing areas, providing access to lower-cost supply, while factoring in the cost of compliance with greenhouse gas emissions regulations when energy is transferred into the ISO,” CAISO said.
Benefits can either be cost savings, profit or a combination, and now reach electricity consumers in Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming.
The EIM also reduced curtailment of renewable energy resources by about 53,000 MWh. That was down from avoided curtailments of about 113,000 MWh in the same period a year ago, a development the ISO is still investigating but says could be attributed to improved hydroelectric conditions in the West and advancements in how EIM participants are deploying their resources. (See Spring Oversupply Lifts CAISO Curtailments.)
The market also reduced “flexibility ramping reserves” by almost 399 MW in the upward direction and 488 MW in the downward direction, CAISO said.
CAISO’s Control Center in Folsom, Cal. | CAISO
The EIM has been growing since its launch with PacifiCorp as its first participant in November 2014, followed by NV Energy, Puget Sound Energy and APS. This October, Portland General Electric is due to begin participating, with Idaho Power following in April 2018; Seattle City Light and Sacramento Municipal Utility District in April 2019; and Salt River Project in April 2020.
Total EIM cost savings are $174 million since the market was launched, according to the ISO. Savings grew from $8.1 million in January to $10.4 million in February and $12.6 million in March.
LITTLE ROCK, Ark. — SPP announced Tuesday it has named CAISO’s Keith Collins as the new executive director of its Market Monitoring Unit, effective June 1.
Collins
Collins was CAISO’s manager of monitoring and reporting and had been with the organization since May 2010. He will replace MMU Director Alan McQueen, who announced his plans to retire last year. McQueen will remain on staff to help Collins through a transition period.
In a statement, Collins said he was excited to work with SPP and its members “on the changing dynamics in the SPP markets. I believe my experiences will bring a unique perspective to these challenges,” Collins said in a statement.
When reached by RTO Insider, he declined further comment.
Collins will be leading a unit that was recently the subject of a 17-month audit by FERC over concerns the monitors lacked sufficient independence and separation from SPP management and staff. Oversight Chairman Joshua W. Martin III told SPP’s Board of Directors last week that the MMU is on track to complete the changes recommended by FERC’s audit. (See “MMU Nears Compliance with FERC Audit,” SPP Board of Directors/Members Committee Briefs.)
At CAISO, Collins was responsible for identifying behavioral and market-design issues. He led market analysis of energy and ancillary services markets, congestion revenue rights and virtual bids, and led investigations into inappropriate market participant behavior.
Collins came to CAISO from FERC, where he served in the commission’s Office of Enforcement and oversaw its Electric Analysis Branch from 2004 to 2010. Prior to that, he was with LECG, an international economics consulting firm that focused on energy economics.
Collins holds a master’s degree in public policy from George Mason University and a bachelor’s degree in economics and government from Bowdoin College.
The Oversight Committee, which oversees the MMU, voted to select Collins as executive director in April following a nationwide search. SPP said the search firm recommended Collins based on his experience and deep knowledge of wholesale energy markets.
“We had an exceptional pool of candidates, and we’re fortunate to welcome Mr. Collins to this role,” Martin said in a statement. “He will be a great fit at SPP. He has big shoes to fill but has the experience and expertise to do so successfully.”
Martin also thanked McQueen for delaying his retirement “until we found the appropriate candidate to assume his responsibilities.”
CAISO’s Board of Governors on Monday approved Tariff measures that will enable the ISO to procure additional black start resources in the San Francisco Bay Area and create a new transmission access charge (TAC) zone in Southern California to accommodate a transmission owner that doesn’t intend to become a participating member.
CAISO’s developed its “black start” measure to acquire more system restoration resources for the transmission-constrained San Francisco area. | SF Travel
Another amendment passed by the board clarifies the role of the Energy Imbalance Market (EIM) Governing Body in making changes to the market’s charter.
Black Start
The ISO launched the accelerated black start procurement initiative in January after identifying the need for additional emergency resources in the transmission-constrained Bay Area within Pacific Gas and Electric’s service territory. (See CAISO Kicks Off Effort to Procure Black Start Resources.)
The ISO’s plan entails significant involvement of the affected transmission owner — in this case PG&E — in drawing up technical specifications and vetting proposals from resources bidding into the solicitation. The ISO would have authority to accept or reject PG&E’s recommended resources.
Responding to stakeholder feedback, ISO staff settled on a cost-of-service approach to compensating selected resources, rather than providing a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.
Those aspects of the plan prompted concerns from at least one market participant, who otherwise expressed support for the proposal.
Andy Brown, an attorney representing Diamond Generating, said that California’s power market functions under a “hybrid” structure in which utility-owned generation benefits from a “life-of-asset” arrangement with a guaranteed revenue requirement, while independent power producers depend on power purchase agreements with relatively “truncated” terms. That would put IPPs at a disadvantage in bidding on a black start contract that only covers the cost of that service, he said.
“Our concern is that when it comes down to the evaluation period [for a black start resource], the commercial review is going to create a sort of unnecessary competitive advantage to [utility-owned generation] as opposed to those generators that might be under PPA terms, particularly if” the PPA is close to its expiration date, Brown said.
Scott Vaughan, a CAISO lead engineer, explained that ISO stakeholders generally agreed that a bidding resource’s existing PPA term should factor into the evaluation because upgrading a plant to black start capability would require capital expenditures to be recovered from ratepayers through reliability provisions in PG&E’s tariff.
Brown also sought assurances about the impartiality of an evaluation process that would heavily involve PG&E — a potentially competing supplier — in the selection process.
Keith Casey, CAISO vice president of market and infrastructure development, said that as the transmission owner, PG&E has a “Tariff-defined” role in providing black start services and must be part of the technical review of the effectiveness of proposed resources.
“There are steps that the company takes to wall off that function from other commercial functions within the company, and we’ll rely on that to ensure the integrity of the process,” Casey said.
“These studies involve sensitive and confidential NERC critical infrastructure,” said Eric Eisenman, director of ISO and FERC policy at PG&E. “It’s appropriate that only PG&E’s transmission operations as the transmission owner and the ISO as the transmission operator jointly conduct this effort.”
‘One-off’ TAC
The CAISO measure creating a TAC area for the Metropolitan Water District of California (MWD) met with little stakeholder concern and no objections as it sailed through the initiative process. (See CAISO to Create New TAC Area for Water District.)
Southern California Edison has been operating MWD’s transmission under a decades-long interchange agreement that provided the ISO with effective control of the agency’s transmission assets. However, the utility declined to renew the contract when it expires Sept. 30.
Under what CAISO has called a “one-off” proposal, the ISO will assume operation of MWD’s 230-kV network, while the district will retain its transmission operating rights. In justifying the unorthodox arrangement, ISO management has explained that the water agency possesses sufficient generation and transmission to serve its own load and does not at all lean on the grid operator.
The need to create a separate area stems from a technicality in which ISO uses TAC areas as a billing determinant to allocate costs for resource adequacy requirements among load-serving entities.
“This will allow MWD to stay within the ISO balancing authority area, which is good for us,” said Deb Le Vine, CAISO director of infrastructure contracts and management.
Among the benefits for CAISO: It will maintain its current level of access to key electricity delivery points along the California-Nevada border, including Mead. The ISO will also retain use of MWD’s excess transfer capacity, which includes 70 MW out of Hoover Dam.
MWD, which delivers water to 26 member agencies serving 19 million consumers in six counties, owns about 300 miles of transmission that deliver power to five pumping plants moving water from the Colorado River Aqueduct and State Water Project into Southern California.
‘Lessons Learned’
In approving a measure to define the EIM Governing Body’s role in making changes to the market’s governing charter, the ISO board formalized what has already become standard practice based on the body’s “advisory” function set out in a guidance document approved late last year. (See EIM Leaders OK Governance ‘Guidance’ Proposal.)
The measure came at the request of body Chair Kristine Schmidt, who earlier this year asked CAISO management to clarify her group’s responsibility over the charter, which previously stipulated only that any “substantive changes” to the charter be approved by the board. (See EIM Changes Would Give Governing Body More Power.)
“Now that we have some experience and understanding under our belt, we’d like to propose some clarification,” Schmidt told the board, noting that the need for clarity was “just one of those lessons learned.”
Substantive modifications to the charter will now be presented to the Governing Body for its advisory input before being submitted to the ISO board — similar to the procedure for ISO market rule changes that also affect the EIM.
“I’ve read a couple articles where it said that the EIM Governing Body is looking to expand its authority — and it is not,” Schmidt told the board.
The measure does make explicit the Governing Body’s power to initiate changes to sections of the charter dealing with the EIM’s Body of State Regulators and Regional Issues Forum.
For nearly three hours this summer, a solar eclipse will blackout much of California’s growing volume of solar generating resources, forcing the state’s grid operator to cover the shortfall with a bevy of resources equipped to quickly react to dispatch instructions.
CAISO is already well into developing its response to the Aug. 21 event.
On that date, the California sun will be reach its dimmest point at 10:22 a.m., the eclipse’s moment of maximum “obscuration.” By that time, CAISO’s “net load” — the portion of electricity demand not served by renewable resources — will have surged to about 6,000 MW more than what it would normally be on a sunny summer day.
The primary reason: The temporary loss of 5,600 MW of energy from grid-connected solar that would typically be generating at that time under full-sun conditions.
An accompanying drop-off in output from behind-the-meter solar will add to the impact, bumping up net load by about 8%.
Solar declines are forecast to be uneven throughout the state, with obscuration rates ranging from 76% in the northern San Joaquin Valley to 58% near the border with Mexico.
The eclipse will have its greatest impact on solar generation in Northern California, where “obscuration” rates will be above 75%. | CAISO
“We’re going to start losing solar during the morning ramp,” Amber Motley, CAISO manager of short-term forecasting, said during a May 1 meeting of CAISO’s Board of Governors, where she described the ISO’s ongoing preparations. (See CAISO Planners Looking Ahead to Summer 2017 Solar Eclipse.)
Motley called the timing of the eclipse “a little bit of a blessing” compared with the situation faced by European system operators in 2015, when a similar event there coincided with the sharper evening ramp.
Still, the ISO expects to lose about 70 MW of solar output per minute from the start of this summer’s eclipse to its fullest point, accelerating the morning ramp to two to three times its normal rate.
CAISO could confront two to three times its normal morning ramping rate as the Aug. 21 solar eclipse stifles output from California’s immense number of solar generating resources. | CAISO
Mark Rothleder, CAISO vice president for market quality and renewable integration, pointed to another notable detail: Aug. 21 falls on a Monday.
“It’s not unusual on a Monday during summer, especially if you have several hot days leading up to that Monday, that you could have a high load and potentially a peak condition for the year,” Rothleder said.
But Motley counted other blessings, including the fact that populous areas of California are subject to “marine layers” — low-altitude cloud cover — during August mornings.
And then there’s heavy snowpack that is feeding the state’s hydroelectric system to the point of oversupply this spring. (See Spring Oversupply Lifts CAISO Curtailments.)
“We know we have a lot of hydropower this year. It’s a blessing,” Motley said, referring to the ramping capability of those resources. “That’s something we expect will still be available in August.”
To help manage the ramp, CAISO will increase its coordination with hydroelectric producers to ensure that they’re prepared to bid into the wholesale market that day. The ISO also plans to increase regulation reserves by about one-third — 350 to 400 MW, a number that staff will revisit after performing market simulations. Those simulations will also provide insight into whether the ISO needs to make any adjustments to how its flexible ramp product performs during the eclipse period.
CAISO will also “coordinate very heavily” with natural gas suppliers to ensure that gas-fired generators procure an adequate supply of fuel.
Another potential option: the manual curtailment of renewables ahead of the eclipse.
“I think that the market simulation will really show us how the market can handle this particular set of movements throughout the day, but [curtailment] was something that was utilized in Europe,” Motley said.
With solar output expected to increase at a rate of 90 MW/minute coming out the eclipse, the ISO is considering placing a constraint on that upward ramp, which will necessitate a corresponding downward ramp for dispatchable resources.
“That 90-MW return is quite steep,” Motely said.
The ISO will depend on the Western Energy Imbalance Market (EIM) for additional measures. With other EIM areas experiencing the eclipse at different times, the market’s software “will be able to optimize EIM transfer capability and use that as a feature as we go through the eclipse,” Motley said.
Grid-connected solar output will decline by 866 MW in other EIM balancing areas during the eclipse. Nearly all the reductions will be concentrated in Arizona and Nevada.
CAISO staff plan to present stakeholders with their preparations for the eclipse during a Market Performance and Planning Forum on July 18 — about one month before the event.
“We look forward to being informed about this,” said ISO board member Angelina Galiteva. “This is interesting — and it’s going to be a test case for what’s to come in the future on a much more regular basis.”
FERC has approved MISO’s uncontested settlement for allocating costs among its members for the use of SPP’s grid.
The settlement covers the costs for transmission flows between MISO Midwest and MISO South in excess of 1,000 MW. It is based on an agreement the RTOs struck in early 2016.
| Aces
The May 2 letter order accepts MISO’s proposal to allocate costs using a declining percentage through a load ratio calculation and an increasing amount through a flow-based benefits methodology (ER14-1736). (See “Cost Allocation Set in MISO-SPP Settlement,” MISO Market Subcommittee Briefs.) The allocation will be used from Feb. 1, 2016, to Jan. 31, 2021:
While waiting on the order, MISO collected payments to SPP using a market ratio share method, and that status quo will stay in place for the funds collected from Jan. 29, 2014, to Jan. 31, 2016. MISO pays SPP $1.3 million per month, subject to true-up. Staff say MISO will begin resettling amounts collected after Jan. 31, 2016, once the allocation method was approved.
MISO filed the settlement package on Aug. 31, and a FERC administrative law judge certified it in October.
