A group of citizens groups has dusted off a forgotten provision of the 1978 Public Utility Regulatory Policies Act that it said requires FERC to provide public funding for interventions before the agency.
In a filing Monday, watchdog group Public Citizen and more than two dozen environmental and public interest groups called on FERC to create an Office of Public Participation, as they say was required by the act (RM16-9).
The act appropriated $2.4 million for compensating intervenors in fiscal year 1981, before FERC switched to its current funding mechanism, based on fees on industry participants.
“I don’t know how much money we’re talking about here,” said Tyson Slocum, director of Public Citizen’s energy program, adding that $2.4 million would be worth about $6.5 million now, adjusted for inflation. That, he said, does not include funding for the office’s staff.
Slocum said it’s unclear why the office was never created, speculating that FERC was unenthusiastic about complying and distracted by implementing other aspects of the act.
Although the Federal Power Act has been revised several times since 1978, he said, Congress never changed the public participation provision. “It just kind of dropped off the radar screen,” he said.
He said Public Citizen decided to file the petition to force compliance after informal entreaties to FERC commissioners failed to result in any action. “We’ve known about it for a long time,” he said.
The filing requests the commission to initiate a rulemaking to implement the directive.
“An Office of Public Participation is needed now, more than ever,” the petition states, noting the changes in the industry since 1978. “More ratemaking is decided in FERC-jurisdictional markets than in state utility regulatory commissions. But while state utility commissions often feature robust procedures and public money dedicated for household consumer representation, no equivalent exists at FERC, leaving entities representing the interests of households at a severe financial disadvantage compared to interests representing the owners of power plants, power marketers and transmission owners.”
FERC declined to comment.
Providing funding for ratepayer representation has also been an issue in some RTOs.
Last year, MISO rejected a request by the Public Consumer Advocates sector for $200,000 to help cover its legal costs in a fight over transmission owners’ return on equity. (See MISO to Consumer Sector: No Money for You.)
NEWTON, Mass. — Large hydropower projects shunned by New England’s renewable portfolio standards are elbowing their way into the clean energy conversation, speakers at the 13th Northeast Energy and Commerce Association Conference on Renewable Energy said Thursday.
Daniel-Johnson Dam (formerly known as Manic-5) Generating Station
Hydropower projects larger than 30 MW have not qualified for financial incentives under most New England states’ standards.
But with coal and nuclear fleets shrinking, large-scale Canadian hydropower is needed to avoid an overreliance on natural gas and meet aggressive carbon reduction goals, several speakers said. Wind and solar can’t develop at scale fast enough to replace thousands of megawatts of legacy generation, they said.
“If we’re going to achieve our climate and clean energy goals under the [Massachusetts] Global Warming Solutions Act and the various states’ renewable energy targets, we’re going to need a course correction,” said Leslie Malone, a senior analyst at the energy and environmental organization The Acadia Center.
The Massachusetts law and similar legislation in Connecticut mandate a 25% cut in greenhouse gas emissions from 1990 levels by 2020 and an 80% reduction by 2050.
One potential solution, Malone said, is a “bundling” of firm hydro resources with intermittent wind energy to create a steady supply of clean power into the region.
Natural gas accounts for about half of the region’s power mix, with that percentage expected to grow. ISO-NE estimates 4,200 MW of older generation will retire in the next few years, including the 1,517-MW coal-fired Brayton Point station and the 680-MW Pilgrim nuclear plant, both in Massachusetts.
Most of the new plants that have cleared in ISO-NE’s recent Forward Capacity Auctions are natural gas generators.
David Wilby, senior vice president for state policy at SunEdison, noted that the pace of plant retirements has been faster than added capacity in recent years. SunEdison began as a solar energy developer, but in 2014 it acquired Boston-based First Wind, a developer of wind projects from Maine to Hawaii.
“As much as my company and others have added renewable megawatts as quickly as we can, we’re basically treading water … so we need big, large long-term investments to grow and to help the [power source] diversity,” he said.
The proposed Northern Pass transmission project in New Hampshire would bring 1,090 MW of Canadian hydropower into the market. (See Vermont OKs Canadian Hydro Line.)
But those projects aren’t enough to replace the retiring generation, said David O’Connor of ML Strategies, a government relations and consulting firm.
Massachusetts Gov. Charlie Baker’s proposed legislation to authorize utilities to purchase 2,400 MW of large-scale imports also is insufficient, he said. “That would be … about one-third of Massachusetts’ needs, or only 10% for the entire region,” he said. (See Baker: Hydropower Contracts Best Way to Lower Costs.)
The region’s clean energy needs are sufficiently large that Canadian projects are no longer seen as crowding out local resources, Wilby said. “It’s not hydro, or wind, or renewables; it’s ‘and’ to get us where we need to go,” he said. “It’s not one thing that’s going to get us there.”
Low load growth and the shift from coal- to natural gas-fired generation mean a need for smaller and fewer baseline transmission projects, PJM said in its 2015 Regional Transmission Expansion Plan report last week.
A slow recovery from the last recession and evolving customer behavior — such as more efficient home appliances and behind-the-meter solar installations — have stunted load growth, the report said.
Those drivers also have lessened the need for new large-scale transmission projects.
In 2015, the Board of Managers approved 214 new baseline projects totaling $1.9 billion and 207 new network transmission projects totaling $1.3 billion.
The $3.2 billion total represented a $2.6 billion net increase in approved projects since the end of 2014. The new projects were partially offset by cost changes in existing projects as well as the removal of 202 network projects representing $677 million and 42 baseline projects totaling $300 million.
The canceled network upgrades were the result of the withdrawal of 157 generation interconnection requests, a quarter of which were for wind-powered units. Together, the requests totaled 15,302 MW. Withdrawals can reflect developers’ reactions to capacity auction prices and public policies on renewable fuel, PJM said.
The report notes the continuing shift from coal to natural gas because of plant retirements driven by environmental regulations and competition from cheap natural gas from the Marcellus and Utica reserves. PJM also is seeing new wind and solar units being encouraged by federal and state renewable energy incentives, while load has been tempered by demand resources and energy efficiency programs.
“Market activity suggests that total natural gas-fired generation capacity may exceed coal within several years,” the report said.
PJM projects 20,300 MW of coal will have retired between 2011 and the end of 2016, much of which is more than four decades old.
In 2015, PJM received deactivation notices totaling 1,626 MW, down from 4,291 MW the previous year and 7,745 MW in 2013. That compares with a total of 11,000 MW for the eight years ending Nov. 1, 2011.
Of all the active, under construction and suspended generation interconnection requests received by the end of 2015, more than 72% were for natural gas, more than 17% involved wind power and 2% represented nuclear units.
To address thermal and voltage reliability issues, PJM now includes low load and winter peak system conditions in its regional planning criteria.
Since 1999, PJM’s board has greenlit nearly $28.3 billion in transmission system upgrades, including $23.5 billion in baseline projects and $4.8 billion in facilities needed to connect more than 71,000 MW of new generation.
FERC last week approved PJM’s creation of a funding mechanism to support the Consumer Advocates of the PJM States (CAPS) through a charge to electric customers.
Commissioner Tony Clark dissented from the vote, saying never before had FERC “endorsed the policy that the activities of non-decisional intervenor groups be funded through a dedicated utility tariff under the auspices of the [Federal Power Act]” and that it set a “troubling precedent” (ER16-561).
CAPS’ participation in the stakeholder process should be funded through the appropriations of state legislatures, Clark said.
Beginning next year, CAPS will receive an initial annual budget of $450,000. FERC approval would be needed for any budget increase of more than 7.5%.
“This authorized 7.5% annual increase is described in the filing as a way to ‘promote fiscal restraint,’” Clark wrote. “Only in government could a budget that allows for a near doubling every decade be considered parsimonious.”
The assessment for a residential consumer using 12,000 kWh per year would be eight-tenths of a cent. The charge will be itemized on customers’ bills.
Those supporting the filing included the Independent Market Monitor, various state agencies, Exelon and the PJM Industrial Customer Coalition.
“The Market Monitor offers that [the] CAPS funding schedule is a ‘meaningful first step to obtain needed balance in the PJM stakeholder process’ and that ‘PJM consumers have been systematically underrepresented,’” the order said.
Opposing the funding were the PJM Power Providers Group, Talen Energy and Essential Power.
Protesters argued that FERC did not have the jurisdiction to approve the funding scheme, that PJM transmission customers that serve load would be forced to fund private speech with which they might disagree, and that CAPS’ comments cannot be considered government speech, in part because not all of its members are government representatives.
CAPS, made up of consumer advocates from PJM states and D.C., was formed in 2012 with start-up funding from a FERC enforcement settlement with Constellation Energy (IN12-7-00).
The budget approved by FERC may be used for staffing and travel costs for the consumer advocates to participate in meetings. The funding may not be used for activities related to the proceedings of state or federal agencies other than FERC, litigation of matters at FERC stemming from Tariff or operating agreement changes by PJM or the hiring of counsel or expert witnesses to support the filings of other parties.
FERC on Tuesday approved New York regulators’ plan to keep the Ginna nuclear power plant operating but objected to elements that it said encroached on its jurisdiction over wholesale power markets (ER15-1047).
R.E. Ginna nuclear plant Source: Exelon
The commission ruled that the reliability support services agreement between the R.E. Ginna nuclear plant and Rochester Gas & Electric approved Feb. 23 by the New York Public Service Commission was just and reasonable. (See NYPSC OKs Ginna Deal.)
The RSSA is between distribution utility RG&E and Exelon’s Constellation Energy Group, which had threatened to close Ginna because it was losing money. RG&E will charge ratepayers $425 million to $510 million to cover Ginna’s full cost of service, with the final amount determined by Ginna’s revenues from the NYISO wholesale market. The utility also will apply $110 million in customer credits to the contract, making the total price tag as high as $620 million.
A parallel proceeding at FERC reviewed elements of the settlement, but it was suspended in January when it was apparent that most contested items were resolved in the state docket. However, one remaining issue was whether there was a sufficient disincentive for Ginna to prevent it from re-entering the market after the RSSA ended on March 31, 2017.
The environmental group Alliance for a Green Economy (AGREE) had contested that part of the settlement as inadequate.
AGREE says the $20.1 million capital recovery balance Ginna would have to repay if it re-enters the NYISO markets should be netted against RG&E’s one-time settlement payment of almost $11.5 million to Ginna, meaning the plant’s penalty would be only $8.6 million over two years, or 2% of the plant’s revenue.
FERC disagreed.
“The settlement payment represents costs that Ginna will have incurred during the settlement RSSA’s term, but, due to timing, Ginna will not yet have recovered those costs from RG&E by the end of the settlement RSSA’s term,” FERC said. “Therefore, we are not persuaded that Ginna’s recovery of those costs … should be netted against the capital recovery balance in assessing whether the capital recovery balance provides an adequate disincentive for Ginna to return to the NYISO markets.”
The commission ordered changes to elements of the settlement agreement and RSSA that it said could infringe on FERC’s jurisdiction because they allow the New York PSC to approve all aspects of the RSSA, “including the wholesale aspects of the settlement RSSA, and potentially reduce a wholesale rate in the settlement RSSA.”
Under Supreme Court precedent, the commission said, “once [FERC] approves a wholesale rate, a state commission must allow 100% of the wholesale rate to be passed through to customers in the utility’s retail rate design.”
FERC also ordered removal of language related to a reliability-must-run agreement that state officials may approve after the RSSA expires. NYISO is in a separate proceeding before the commission to address RMR concerns in New York. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)
A state court Friday blocked New York regulators from implementing sweeping new rules over retail electric providers, ordering a show cause hearing April 14 (870-16).
The ruling by the Albany County Supreme Court stayed the first phase of regulations passed by the New York Public Service Commission last month, which would have required retail suppliers to guarantee savings for new customers and those with renewing contracts.
The Retail Energy Supply Association asked the court Thursday to block the rules, saying it was an overreach of the commission’s authority and would effectively eliminate customer choice.
“This is great news for consumers, as it protects their right to freely decide for themselves what energy products offer value,” RESA spokesman Bryan Lee said. “RESA looks forward to working collaboratively with the commission regarding its concerns in a productive way so that consumers retain the right to choose their energy provider and the value-added products and services that come along with such a choice.”
The PSC said the rules, adopted Feb. 23, were put in place to counter deceptive business practices committed by some energy service companies. (See Zibelman: Rules Meant to Enable Markets.)
In its petition for a temporary restraining order, RESA said regulators were panicked by negative press coverage of unscrupulous retailers and rushed the order without giving proper notice or having fully developed procedures.
“The order sends a strong message that the commission and the attorney general’s office cannot be trusted with enforcing the existing consumer protection laws against a small handful of alleged bad actors in the retail energy market,” RESA wrote. “Further, the … order is an unconstitutional legislative act by an administrative agency with an expansive agenda, which has made a sweeping policy decision that monopoly pricing and monolithic commodity offerings in New York’s energy sector are preferable to competition and customer choice.”
Numerous energy service companies (ESCOs) had asked the PSC for a 45-day delay in implementing the rules, saying they were imprecise and that the companies needed more time to comply.
The Public Utility Law Project of New York opposed the extension, saying three related proceedings before the PSC should have alerted the ESCOs that tighter state regulation was coming.
“The reforms instituted by the Feb. 23 order have been foreshadowed for years, and if the ESCO industry chose not to put contingency plans into place, that is unfortunate for them,” PULP wrote. “Meanwhile, mass market consumers have been overcharged, slammed and subjected to numerous other practices that have wrought considerable financial harm upon small commercial and low-income households who have long awaited the consumer protections soon to be in force.”
Public Citizen last week called for a House and Senate investigation into the Commercial Energy Working Group, an industry association the watchdog says appears to be violating federal lobbying rules by not disclosing its membership.
The energy group operates out of the offices of D.C. law firm Sutherland, Asbill & Brennan, which has represented it in filings with FERC, the Commodity Futures Trading Commission, the Securities and Exchange Commission, the Federal Reserve and Congress.
In the second quarter of 2015, the firm reported to Congress $60,000 in lobbying income for the group, but the filing did not list the sources of that income despite a requirement that lobbyists disclose contributions of $5,000 or more, Public Citizen says. Based on records obtained through the Freedom of Information Act, Public Citizen said the group’s members appear to include Vitol, Royal Dutch Shell, NextEra Energy, ConocoPhillips and Hess Corp.
NRC Engineers Urge Fix for Flaw in Most US Reactors
Lochbaum
A group of Nuclear Regulatory Commission engineers is urging the agency to order U.S. nuclear plant operators to fix a problem that lurks in nearly all reactors.
In February, the seven engineers petitioned the agency to order immediate action to address a flaw that puts the reactors at risk of so-called “open phase events” where unbalanced voltage could cause motors to burn out and deactivate emergency cooling systems. Such an event happened at Exelon’s Byron 2 reactor in 2012, shutting down the unit for a week.
Although NRC alerted operators of that event, the agency didn’t require any action. Dave Lochbaum, a nuclear expert and frequent industry critic, said NRC has known about the issue and didn’t push for action. “Why the NRC snatched defeat from the jaws of victory, I don’t know,” he said. By NRC’s own procedure, the agency has until March 21 to respond to the engineers’ request.
The environmental group Delaware Riverkeeper Network is suing FERC, charging that the agency’s oversight process for pipeline projects is “infected with bias” and demanding substantial changes to how the commission works.
The suit alleges that FERC is essentially financed by the industries it oversees through charges and fees. “Because FERC gets its funding from the big companies it is supposed to be monitoring, it has become, perhaps inevitably, a corrupt, rogue agency,” says Maya van Rossum, leader of the Delaware Riverkeeper Network. “That’s why FERC has approved 100% of pipeline projects — literally every single one of them — that it has considered since 1986.”
The suit, filed in U.S. District Court., seeks a declaration that FERC’s approval process is biased and that its funding structure is unconstitutional. The commission said it does not comment on pending lawsuits.
Chief Justice John Roberts on Thursday rejected a request from 20 states to block the enforcement of EPA’s Mecury and Air Toxics Standards.
Michigan and 19 other states asked for a stay or an injunction blocking enforcement of the MATS rule, noting that the court itself last year ruled 5-4 that the rule is illegal.
But EPA said a stay was not necessary as the agency was addressing the parts of the rule the court found invalid. “The requested stay would harm the public interest by undermining reliance interests and the public health and environmental benefits associated with the rule,” the agency said. “The application lacks merit and should be denied.”
Roberts acted unilaterally, without taking the question to the whole court.
The fledgling U.S. energy storage market deployed 112 MW of capacity in the fourth quarter of 2015, more than in 2013 and 2014 combined. According to GTM Research and the Energy Storage Association’s U.S. Energy Storage Monitor 2015 Year in Review, 161 MW were added in 2015, bringing the U.S. total to 221 MW.
The report, broken down into residential, nonresidential and utility segments, notes the last segment continues to be the largest, accounting for about 85% of all new storage. Most of that was deployed in PJM, which saw 160 MW of new storage introduced.
But residential behind-the-meter systems grew at the fastest pace, showing an increase of 405% in 2015.
The Nuclear Regulatory Commission has put Entergy on notice for three apparent violations relating to a leaking storage tank discovered at its Palisades nuclear generating station in Michigan in 2013. The agency sent the company a letter alleging that Palisades deliberately failed to properly document the leak at a safety injection and refueling water storage tank during the event.
Entergy was cited for “willful failure” to document the leak, as well as failure to “perform adequate operability determinations” after the leak and to undertake additional testing of the leak site.
The company said the conditions have been corrected since the incident. “Entergy does not tolerate deliberately failing to follow procedures or falsifying or manipulating data in any way,” the company said.
Feds Move to Drop McClendon Indictment After Fatal Crash
McClendon
Authorities are taking steps to drop the indictment against former Chesapeake Energy CEO Aubrey McClendon, who died hours after the indictment was handed up last week. McClendon was under investigation for alleged bid rigging relating to natural gas leases.
A federal grand jury handed up the indictment Tuesday. McClendon died in Oklahoma City last week when his SUV crashed at high speed into a bridge abutment. That accident remains under investigation.
FERC attended to some housekeeping Friday by putting to rest a rehearing request rendered moot by MISO and SPP’s settlement of their transmission dispute.
SPP-MISO 1,000 MW contractual tie Source: SPP
The commission dismissed MISO’s rehearing request of its December 2014 order approving the RTO’s use of a “hurdle rate” to manage its north-south flows (ER14-2445-002). The commission also dismissed a related compliance filing.
MISO, its Market Monitor and several regulatory agencies and utilities had sought rehearing, arguing that FERC’s order would cause the $9.57/MWh hurdle rate to climb by 4.5 times, rendering MISO’s North-South interface transfers of more than 1,000 MW uneconomical.
“Because the hurdle rate is no longer effective, and in the [December 2014] order, the commission exercised its discretion to not order refunds … there is no need to address the” matters raised by MISO and others, the commission said.
Under the settlement, MISO will pay SPP $1.33 million monthly until February 2017 to cover flows over 1,000 MW passing through MISO’s North-South interface. MISO is temporarily collecting the funds from members through a miscellaneous charge based on market load ratio share while the RTO and stakeholders continue settlement discussions to decide on a long-term cost allocation (ER14-1736).
FERC last week approved a request by CAISO to eliminate from its Tariff a long-suspended provision establishing convergence bidding at scheduling points on the interties into California.
The commission’s order eliminated the prospect that CAISO would reinstate a market mechanism it revoked within months of implementing it in 2011 (ER15-1451-001). At the time, the ISO’s Market Monitor determined that bidding strategies at the interties underpinned a complex scheme to manipulate prices and inflate payouts in other areas of the California market.
CAISO has in recent years explored reviving the mechanism in light of structural changes in Western markets, but it ultimately sought a full repeal based on concerns that illiquidity in 15-minute trading left intertie points vulnerable to gaming.
FERC’s ruling did not affect convergence bidding at points inside the ISO balancing area. At the request of municipal utilities in Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, FERC also directed CAISO to delete from its Tariff an additional reference to virtual bidding in order to avoid ambiguity.
Convergence — or virtual — bidding allows market participants to hedge their physical positions and limit exposure to day-ahead and real-time price differentials. A convergence bid is a purely financial bid implying no obligation to take or deliver electricity. Instead, a market participant buys or sells “virtual” energy in the day-ahead market, a position required to be automatically liquidated in the opposite direction in real time.
Depending on the relative movements in the two markets, the participant either pockets or pays the difference between the two prices. Bidders are not required to control physical resources or serve loads in the ISO, allowing speculators to take positions in the market.
RTOs have adopted convergence bidding under the theory that the practice narrows the gap between day-ahead and real-time prices as traders arbitrage spreads between the two markets. The benefit is a more predictable spot market, protecting utilities from price swings stemming from load fluctuations and unplanned generating outages.
Troubled from the Start
In California, convergence bidding was fraught with problems since CAISO introduced the practice two years after restoring its day-ahead market. A week after implementing the market in February 2011, CAISO suspended bidding at nodes on nine interties linked to the Mountain States region because of a software glitch that risked overscheduling those points in the physical day-ahead market.
That incident was followed months later by the more serious discovery that some CAISO market participants were using virtual supply bids on the interties to offset virtual demand bids at nodes located just inside the state, a gaming strategy that produced no benefit for the physical market and cost the ISO more than $50 million.
(Virtual trades at CAISO’s New Melones intertie are at the center of market manipulation allegations filed by FERC in December. The defendant last week asked FERC to compel CAISO to disclose information about market design flaws (IN16-2). See earlier story, FERC Seeks $2.5M Fine in CAISO Market Manipulation.)
The strategy was facilitated by predictable differences in prices stemming from what the ISO referred to as a “bifurcated” settlement process, with the interties settled at the hour-ahead price and internal points in real time. Shortly after identifying the issue, CAISO suspended bidding at the interties indefinitely — or at least until it could resolve the bifurcation issue.
Liquidity Concerns
That goal would ultimately elude CAISO. While FERC Order 764 — which mandated 15-minute scheduling between neighboring balancing areas — should have helped, the ISO became concerned about declining short-term trading volumes at the interties, which could reintroduce opportunities for strategic bidding. A 2015 report from the ISO’s Market Monitor indicated that “most of the dozens of CAISO interties have no market participants providing economic bids in the 15-minute market and only a few interties have multiple market participants providing such bids.”
CAISO hoped Bonneville Power Administration’s implementation of 15-minute scheduling — synching it with CAISO’s schedule — would boost exports from the Pacific Northwest. But the change had little impact on trading activity.
“The CAISO does not yet understand the causes of this low market liquidity,” the grid operator wrote in an April 2015 filing asking FERC to extend the suspension of convergence bidding on the interties. “Based on informal feedback from market participants, the CAISO believes that some of the possible causes may be neighboring balancing areas not supporting 15-minute schedule changes, difficulty in procuring transmission in 15-minute blocks, an absence of bilateral trading at a 15-minute granularity and reticence of resource owners to adjust their output within the hour.”
According to a report by CAISO’s Department of Market Monitoring (DMM), low 15-minute liquidity could translate into a situation in which convergence bids would first settle at a day-ahead market price that includes intertie congestion, then be liquidated at a 15-minute market price not subject to congestion because of light physical volumes. That would give bidders incentive to profit from the structural differences between congestion prices in the day-ahead market and the 15-minute market.
“Regardless of the causes,” CAISO wrote in its April 2015 filing, “based on DMM’s recent analysis, the CAISO has determined that the existence of such low market liquidity, as evidenced by the lack of economic bids submitted in the 15-minute market, makes it problematic to reinstate intertie virtual bidding.”
ERCOT said last week it continues to expect to have sufficient resources to meet projected peak-demand during the spring and summer, with more than 79,000 MW of generation capacity available.
The Texas grid operator is projecting a spring demand peak of 58,279 MW, a 700-MW increase from last November’s preliminary spring assessment, said Pete Warnken, ERCOT’s manager of resource adequacy, during a March 1 conference call. The revised peak is based on weather conditions from May 2006; the previous estimate used average weather conditions from 2002 to 2014.
Warnken said staff took into account multiple scenarios under a variety of conditions in issuing its Seasonal Assessment of Resource Adequacy (SARA) for this spring. The report includes a new scenario based on low wind power output during peak hours.
ERCOT’s control room Source: ERCOT
ERCOT estimates that even with 9,482 MW of maintenance and forced outages in May, it will still have 11,598 MW of capacity available for operating reserves, well above the 2,300 MW considered acceptable.
The spring forecast is based on expected weather conditions similar to those that occurred in May 2006 and typical seasonal generation outages, based on historical performance. ERCOT expects the spring peak to occur in late May, following completion of most seasonal plant maintenance to prepare for summer’s heat.
“The month of May shows potential for above-normal temperatures, which could lead to an early taste of summer,” said ERCOT meteorologist Chris Coleman.
The grid operator’s latest SARA includes more than 200 MW of installed solar capacity. ERCOT estimates solar resource availability at a 58% capacity factor — or 171 MW — based on its typical performance during peak spring conditions.
ERCOT’s preliminary summer SARA projects a summer peak of 70,588 MW, its first peak above 70,000. The current record is 69,877 MW, set last August.
ERCOT estimates it will have more than 79,000 MW of available generation this summer, including an additional 731 MW of fossil, nuclear and biomass generation from the preliminary spring SARA, 1,068 MW of new gas-fired generation and 723 MW of additional wind energy.
The final summer SARA is scheduled to be released in May.
Public Citizen last week called for a House and Senate investigation into the Commercial Energy Working Group, an industry association the watchdog says appears to be violating federal lobbying rules by not disclosing its membership.
