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.
WASHINGTON — If anyone thought FERC dragging state and RTO stakeholders here for a technical conference might jolt everyone on the PJM playground into playing nice with each other, Robert Erwin of the Maryland Public Service Commission quickly disabused the standing-room-only crowd of that notion.
“Maryland does not consider the PJM markets as the sole definer of resource adequacy and reliability. … We’re not relying solely on Dr. Bowring and President Ott,” he said, referring to Joe Bowring, PJM’s Independent Market Monitor, and PJM CEO Andy Ott. “If the lights really do go out, Maryland ratepayers are not going to storm [PJM’s offices in] Valley Forge with pitchforks and torches. They’re going to come to the Maryland commission, and they’re going to say, ‘How did you let that happen?’ And when we talk to that reporter from The Baltimore Sun, we don’t want to be a position saying, ‘Well, Dr. Bowring and President Ott told us it was all going to be fine.’”
Erwin suggested that the RTO might need to rethink its premise of being cost-based and resource-neutral. His perspective was contrasted by other state regulators on the panel, who offered a gradient of opinions on PJM’s adequacy. Richard Mroz, the president of New Jersey’s Board of Public Utilities, said state regulators need help keeping up with industry oversight, while Andrew Place, the vice chairman of Pennsylvania’s Public Utility Commission, said he is “fuel-agnostic” and cautioned against increasing complexity and decreasing transparency and cost efficiency in the market.
Brien Sheahan, chairman of the Illinois Commerce Commission, defended the state’s controversial decision in December to legislate zero-emission credits that ostensibly created subsidies for two Exelon-owned nuclear plants. While the RTO plays “an important role,” and will continue to, he said “markets … exist to serve state purposes.” States that have “legitimate environmental concerns” have the legal authority to require RTOs to “reflect those priorities,” he said.
Place called for a different approach. “I would much rather see an integrated carbon price that’s fuel-agnostic, and I don’t think it will cause reliability issues,” he said.
Mroz reiterated his pride, as he often does, with New Jersey’s generator diversity — the Garden State powers itself mostly with nuclear, gas, coal, solar and wind — but expressed a common concern about fuel security.
“What if there is impingement of resources?” he asked, noting that the removal of integrated resource plans has reduced states’ ability to address such concerns.
The second PJM panel in the May 1 conference was made up of Bowring, Ott and representatives from generators, utilities, state consumer advocates and special-interest groups. (See also Power Markets at Risk from State Actions, Speakers Tell FERC.) Their comments often circled back to the ZECs approved in Illinois and the impacts they have on the market.
“The new war on coal is subsidies,” Dynegy CEO Robert Flexon said. “Coal cannot compete with nuclear subsidies.”
Jennifer Chen of the Natural Resources Defense Council said fossil fuels also receive subsidies. “Subsidies are everywhere, and they’re hidden,” she said.
Bowring said that only some nuclear and coal units in PJM are unable to run economically and reiterated Place’s endorsement of in-market pricing signals over state actions that bypass the market. “Clearly a market-based price on carbon is better than a subsidy,” he said.
Ott asked for FERC’s help in fixing a “fundamental inconsistency” in PJM’s energy market that creates negative prices by valuing some environmental externalities and not others. “We try to move 400 or 500 MW of wind, and we’ve got to send negative prices for a substantial number of hours,” he said. “It’s unsustainable and devalues assets that are inflexible and can’t move.”
However, Mike Cocco of Old Dominion Electric Cooperative saw “cheap gas” and high-efficiency gas-fired units as the main drivers of market stress rather than subsidies.
Throughout the day, acting FERC Chair Cheryl LaFleur and Commissioner Colette Honorable pressed speakers to explain what they thought needed to be done.
Asked about the future of PJM’s capacity market, Erwin was frank in his advice. “We would not encourage either you or PJM to continue to tweak the [Reliability Pricing Model] or the [minimum offer price rule]. … Every single year, there have been proposals for changing RPM. We don’t think that continuing to tweak that model is going to be very constructive.
“Do you really want to get rid of all of the nukes because they’re uneconomic? Is that really a good idea?” he asked.
“I’m saying no,” Honorable responded.
“I’m saying no too,” he said, adding that he is skeptical of letting all non-intermittent resources transition to gas.
“The markets don’t value the externalities that the state values, particularly the environmental attributes, but also other valuable attributes of baseload nuclear,” Sheahan said. “This was an urgent conversation three years ago. This is a crisis today.”
Place preferred consistency. “I’m torn. I’d probably come down that I’d rather see tweaking of capacity markets than starting fresh, though it comes with a lot of baggage,” he said.
He said the energy market, which dispatches generation in real time, is better for addressing issues such as the uneconomic nature of nuclear plants rather than trying to manipulate the capacity market to address it.
Collaborate, Don’t Litigate
One thing seemingly every speaker agreed on was that — having been frustrated with the courts’ narrow rulings on state-federal jurisdictional issues — collaboration to resolve the issues at the RTO would be more productive than litigating them. (See Court’s Reticence Frustrates Energy Bar.) The commissioners agreed. “I appreciate the fact that you’ve thought about … how we can do so in a way that allows us all to keep our eyes on the prize and [reduce] additional years of waiting around for a solution,” Honorable said.
Can a market with 13 states and D.C. find agreement?
“I do think that we can value these other attributes,” Mroz said. “The question is whether we all agree about what those valuations are, or what the attributes are.”
Plenty to Go Around
Honorable said the commission took away from the conference that it needs to become more active in coordinating the discussion, such as ordering a deadline for the RTO to determine what externalities it needs to address and how to incorporate them. She asked what the commission can do to further assist the process.
“We need to somehow discipline the output of generation in order to keep the supply/demand balance,” Ott said. “The resources that are needed to serve load should participate in setting price. It’s as simple as that.”
Chen said part of the problem is an overabundance of gas-fired units able to drastically lower auction clearing prices because of cheap fuel.
Bowring challenged that argument, saying the additional supply allows for lower prices and energy benefits. His protest drew a laugh from the crowd and prompted Ott to exclaim, “It’s a bargain!”
Erwin noted that PJM has a 22% reserve margin — well above its 15% requirement — “that potentially isn’t used at all.”
“Maryland does not see an adequacy problem in PJM,” Erwin said, asking FERC to consider consumers who pay the bills. “There’s only one source of revenue for all of this, and that’s your neighbors and my neighbors.”
[Editor’s Note: RTO Insider will have additional coverage of the technical conference in the May 9 newsletter.]
FERC’s agenda said the technical conference “may address matters at issue” in the following pending dockets:
WASHINGTON — RTO capacity markets are in serious danger from state renewable procurements and subsidies for nuclear plants, speakers told FERC on Monday.
Jeffrey W. Bentz, director of analysis for the New England States Committee on Electricity, said failing to coordinate ISO-NE’s capacity market with state renewable procurements will lead to oversupply and excessive costs to ratepayers in the region.
“Maybe that’s not in the next three to five years,” he said on the first day of a two-day technical conference on the impact of state electricity policies on ISO-NE, NYISO and PJM. “But down the road, clearly we can see that train wreck coming and it would probably be the end of the markets as we know them today.”
New Hampshire Public Utilities Commissioner Robert R. Scott also had a warning: “It is not possible to fully preserve the benefits of competition … with a market design that seeks to replace low-cost resources with resources that cost more,” he said in his written testimony.
FERC scheduled the conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).
The conferees discussed the grid operators’ efforts to address state-market conflicts, including white papers by PJM, and the New England Power Pool’s Integrating Markets and Public Policy (IMAPP). The conference also came as FERC has pending before it challenges to zero-emission credits for nuclear generators in New York and Illinois.
FERC staff indicated the high stakes posed by increasing tensions between state policies and RTO/ISO resource adequacy efforts, asking witnesses to consider whether there will be “a diminished role for the RTO/ISO.”
Taking Matters into Their Own Hands
During the hearing, some state officials said they had taken power procurement into their own hands because the capacity markets haven’t delivered the types of resources they desire.
Among the problems: the lack of a price on carbon emissions and no recognition of the value of fuel diversity.
“The market was only delivering one product: natural gas [generation],” said Robert Klee, the commissioner of the Connecticut Department of Energy and Environmental Protection, who said the dependence on gas caused reliability concerns during the winter peaks, when generators must compete for fuel with heating customers. “We’ve been pretty lucky to have mild winters the last few years. We don’t want to go back to the polar vortex.”
Klee said difficulties getting additional gas pipelines to supply the region’s generators had heightened state officials’ concerns.
Still, he suggested state procurements likely won’t provide all of the new power supplies needed for New England states planning to electrify transportation and building heating. “That’s a lot of growth,” he said.
Angela M. O’Connor, chair of the Massachusetts Department of Public Utilities, said the markets “have provided tremendous benefits” and that the capacity market has produced new generation to maintain reliability.
“But we are at a crossroads, and what the legislature requires us to do, we have to do,” she said, referring to mandates to reduce greenhouse gas emissions by 80% below 1990 levels by 2050, and procure hydropower and offshore wind.
“The wholesale markets [are] … not going to get us our large-scale hydro or the offshore wind — or, frankly, gas pipelines.”
Susanne DesRoches, deputy director of infrastructure policy for New York City, agreed. “We support the wholesale markets, but we see that innovation is needed,” she said.
Scott Weiner, deputy for markets and innovation at the New York State Department of Public Service, said the state is at an “inflection point.”
“Is there a role for the markets? Absolutely. Is it going to change? Probably. … The energy markets will always be there. The capacity market may not be.”
Seth Kaplan, senior manager of regional government affairs for EDP Renewables, said the markets were constructed with gas turbines in mind at a time when renewables had little market share. Given the changes since then, he said, “it’s not surprising that a square peg doesn’t fit into a round hole.”
Grid Operators Respond
Matt White, chief economist for ISO-NE, insisted the RTO had no intention of relinquishing its role as the guarantor of resource adequacy standards.
“We believe that resource adequacy requires a single point of responsibility and accountability. ISO-NE currently bears this responsibility. Another option is for the states to take on this role through local utilities; to date, however, the New England states have not expressed interest in assuming this role,” the RTO said in its written testimony.
NYISO CEO Brad Jones said that while the ISO supports New York’s ZECs, the program needs to be incorporated into the market. He said it could take three years to work out a solution.
Generators’ Concerns
That was too long for witnesses representing independent power producers.
“The challenge before the commission, the states and all other stakeholders is no less than the question of whether the power industry will continue to use competitive markets as the basis for investment decision-making,” Peter Fuller, vice president of market and regulatory affairs for NRG Energy, said in his written testimony.
In his response to questions, Fuller was a bit more optimistic: “We believe the markets can be adapted to give the states what they need … and figure out a way for those resources to have their role in the markets while not undermining the markets for those of us who have invested strictly on the basis of market revenues.
“I don’t think we’re are the tipping point yet,” Fuller said. “But if we don’t move fairly quickly [to] … ensure that markets can actually support the … renewable-based future … then we could very well tip over.”
John Reese, senior vice president of Eastern Generation, said the issue is particularly acute in NYISO, which has a one-year forward capacity auction, unlike the three-year auctions in PJM and ISO-NE. Eastern Generation operates almost 5,000 MW of generation in NYISO and PJM, including 18% of New York City’s capacity.
“I can’t wait for seven years or eight years for this to work out,” he said. “Regardless of which model we end up with, we need to be sending investment signals now!”
Déjà vu
John Shelk, CEO of the Electric Power Supply Association, lamented that policymakers had not accomplished more since FERC’s September 2013 technical conference on the Eastern capacity markets. (See Capacity Market Attracts Praise, Criticism at FERC.)
“The one area of agreement is exactly the place that we’re headed to that everyone said four years ago, ‘Don’t go there,’ which was tranches: ‘Let’s pick X amount of nuclear, X amount of coal, X amount of gas.’ Now it’s worse. Now we’re not just picking fuels, we’re picking specific [generating] units that otherwise would have exited.
“This may have started in New York last year … but in short order it was adopted in my home state of Illinois and as everybody knows, it’s now being actively considered in Ohio, Pennsylvania and New Jersey and Connecticut. So this isn’t just a threat to the market in New York.” (See related story, PJM Stakeholders Offer Vastly Different Takes on Markets’ Viability.)
Without changes, Shelk said, his members may have to seek state approval of “flexible energy credits” to support generators that provide the ramping needed to support variable resources.
New York regulator Weiner also called for urgency. “We’ll be having this same discussion two years from now unless there’s a recognition that things have changed,” he said.
LaFleur: FERC Will Act
In opening remarks Monday, acting FERC Chair Cheryl LaFleur acknowledged, “I’m very well aware that the wholesale markets … only can exist and continue through the buy-in of the states.
“I have said very many times there are three ways this could go: a designed market solution, a litigated outcome or a planned change in the regulatory construct of how we handle resource adequacy. The fourth outcome — an unplanned change in the regulatory construct, or unplanned and piecemeal regulation — is one that I think we should avoid because I think it would be a bad outcome for customers and market participants.
“Once we restore our quorum, this commission will almost certainly have to decide litigated complaints that are already pending before us, even as regions may be working on market solutions to file with us,” she continued. “While we can’t decide anything immediately because we lack a quorum, we must shape options and recommendations for a FERC 2.0 based on the record we develop today and tomorrow.”
[Editor’s Note: RTO Insider will have full coverage of the technical conference later this week and in the May 9 newsletter.]
FirstEnergy is encouraged by possible new state and federal support for nuclear and coal-fired plants, but the company said it has not changed its plan to divest its merchant generation and become a fully regulated company by the middle of next year.
“There is absolutely no change in the strategic direction that we want to take this company in,” FirstEnergy CEO Charles Jones said during an April 28 call to discuss first-quarter earnings. “We do not want to be exposed to commodity-exposed generation any longer than we have to be.”
In light of a $164 million first-quarter charge over unfulfilled coal delivery contracts, the Ohio-based utility holding company is eyeing a proposed nuclear subsidy from its home state and signals from U.S. Energy Secretary Rick Perry that federal policies toward coal generation could change.
The company reported earnings of $205 million in the quarter on revenues of $3.6 billion, including the charge related to coal delivery contracts. In the first quarter last year, the company earned $328 million on revenue of $3.9 billion.
Subsidiary FirstEnergy Solutions recently reached a $109 million settlement with BNSF Railway and CSX over long-term coal delivery contracts it terminated. The payments, guaranteed by FirstEnergy, are set to have begun on May 1, the company told the U.S. Securities and Exchange Commission in an April 27 filing. If that settlement is not completed — or a similar dispute with BNSF and Norfolk Southern Railway is not settled — damages could be much higher and lead FES to file for bankruptcy.
Coal supplier Tunnel Ridge also filed suit against First Energy subsidiary AE Supply over a terminated coal supply contract, which the company said could “be material.”
FirstEnergy executives are hopeful that a bill for a proposed “zero-emission nuclear resource program” will reach Ohio Gov. John Kasich’s desk by the end of June. The legislation would require electric distribution companies to secure the credits from qualified generation resources and recover the costs from ratepayers. Awarded according to nuclear output, the credits would gain FirstEnergy about $300 million/year.
“That amount in and of itself, I don’t think, is enough to necessarily avoid a FES bankruptcy,” Jones said. “It would be enough potentially for those assets to emerge from bankruptcy and for a reputable nuclear operator to be willing to take them on and run them forward.”
FirstEnergy touts the proposal as helping the state meet its energy goals, but critics say it is a bailout for the company’s nuclear plants. Ohio Citizen Action said the money should instead be invested in renewable energy and energy efficiency projects.
FirstEnergy owns the 889-MW Davis-Besse nuclear plant near Toledo and the 1,231-MW Perry plant near Cleveland, but the company wants to close or sell them.
Perry Nuclear Plant | Wainstead
Jones said that as the company assesses the implications of a FES bankruptcy, it is closely monitoring whether a new Energy Department study will lead to some type of support for coal plants.
Perry last month ordered his department to present by mid-June its evaluation of the premature retirements of baseload power plants, which is in part intended to determine whether energy markets adequately compensate the reliability benefits they provide. It is unclear what initiatives might flow from the process.
Perry’s memo mentioned “the market-distorting effects of federal subsidies that boost one form of energy at the expense of others” and said the study would provide “concrete policy recommendations and solutions.”
Jones said the Bulk Electric System is being overlaid on a congested and “not robust” natural gas delivery system, and problems with the natural gas system will flow to the electricity system.
FirstEnergy last quarter entered into an agreement to sell about 1,500 MW of AE Supply’s gas and hydro assets for $925 million, a deal expected to close in the third quarter. A $40 million agreement to sell property and assets at the Hatfield’s Ferry power station is expected to close in the third quarter of next year. Mon Power in March agreed to purchase the Pleasants power plant from AE Supply for $195 million.
WILMINGTON, Del. — John Horstmann of Dayton Power and Light expressed concern that PJM’s proposed regulation changes will have a “huge impact” on existing Reg D providers and noted that complaints have been filed at FERC opposing the changes PJM implemented in January. (See “New Regulation Rules Improving ACE Control,” PJM Operating Committee Briefs.)
Based on the potential issues, Horstmann made a motion at Thursday’s Markets and Reliability Committee meeting to defer a vote on the package until June, which would allow for the comment period at FERC to close. Members approved the delay in a 3.76 sector-weighted vote.
The package, jointly developed by PJM and the Independent Market Monitor, would replace the benefit factor with the “regulation rate of technical substitution,” and the effective megawatt calculation would be the area under its curve. The mileage ratio from the regulation performance credit would be replaced with the “marginal rate of technical substitution” (MRTS), which will be added to the regulation capacity credit. Bowring said later that PJM meeting rules prevented him from responding to comments from Horstmann that he believed to be inaccurate.
The 24-month transition period will have a minimum MRTS of .65 for the first year, followed by a floor of .5 for the last year. The minimum allowable participation threshold will be raised from 40% to 50%.
“The transition offer by PJM, while a nice gesture, [is] not really compensatory for existing Reg D providers,” Horstmann said.
CCPPSTF Charter Approved
The MRC approved the charter for the Capacity Construct/Public Policy Senior Task Force, declining to adopt language changes proposed by Market Monitor Joe Bowring.
Bowring suggested that one of the group objectives in the charter, which calls for “modifications to [the Reliability Pricing Model] that could accommodate/address both capacity construct objective and state actions,” wasn’t consistent with the charter’s mission to “ensure potential state public policy initiatives and Reliability Pricing Model objectives are not at odds.”
Bowring found no members willing to take up his suggested edits, and the charter passed with one objection and two abstentions.
PJM’s David Schweizer presented a first read of the RTO’s plan to address FERC’s recent Notice of Proposed Rulemaking on frequency response. PJM’s proposal has suggested that it might consider compensating units for maintaining primary frequency response, even though the NOPR is silent on the topic. (See “PJM Wants to Study Frequency Response,” PJM Operating Committee Briefs.)
John Farber of the Delaware Public Service Commission staff took issue. “If we’re purchasing this premium [Capacity Performance product], it should include this primary frequency response,” he said.
He asked that the problem statement and accompanying issue charge include language that the compensation would be considered “if appropriate or necessary.” Schweizer said the documents were developed to allow dialogue on the topic while designing proposed solutions.
| PJM
He said he will be seeking the Operating Committee’s approval on Wednesday and asked that any proposed changes be submitted as soon as possible.
Manual Changes OK’d
Stakeholders endorsed by acclamation two manual revisions:
Manual 14B: PJM Region Transmission Planning Process. The changes correcting wording in the baseline thermal analysis section to match analytical procedures and replace all occurrences of “special protection system” with “remedial action scheme” per a change to the NERC glossary of terms.
Manual 18: PJM Capacity Market. The revisions conform to FERC’s March 21 order tentatively approving PJM’s “enhanced aggregation” plan to allow seasonal capacity participation as CP resources. Stakeholders deferred sunsetting the Seasonal Capacity Resources Senior Task Force until the May meeting so they can be informed of any action on the seasonal capacity filing at FERC. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)
Members Committee
Members Endorse Pricing Revisions
The Members Committee endorsed revisions to PJM’s Tariff and Operating Agreement to address shortage pricing through the operating demand curve. (See “Shortage Rule Takes Effect amid FERC Silence,” PJM Market Implementation Committee Briefs.)
Both changes had received substantial discussion in previous meetings, so members had little to say about them Thursday. Bowring reiterated concerns he has mentioned previously about PJM’s approach to handling fuel-cost policies.
