Page 1283 – RTO Insider

August 28, 2017

Progress Builds for MISO Energy Storage Effort

By Amanda Durish Cook

CARMEL, Ind. — While a MISO workshop last week fell short of defining potential market rules for energy storage devices, it did provide stakeholders an opportunity to hash out their thoughts on a technology that straddles the boundaries between generation and transmission.

During the RTO’s first energy storage workshop last month, stakeholders advised it to consider all the capabilities and types of battery storage before drafting market rules and creating definitions. (See MISO Rules Must Bend for Storage, Stakeholders Say.)

MISO FERC energy storage Market Monitor — MISO’s Energy Storage Workshop underway | © *RTO Insider*

At the second — and likely final — workshop Aug. 24, MISO took a stab at providing structure for addressing the complex issue by suggesting which committees should field various storage proposals.

MISO assigned Chief Compliance Officer Joseph Gardner to serve as its liaison to the newly created Energy Storage Task Force, which will gather ideas that could eventually become proposals at the Resource Adequacy Subcommittee, Market Subcommittee, Reliability Subcommittee and Planning Advisory Committee.

The RTO suggested that the PAC could handle storage interconnection methods and possible transmission cost recovery, while the MSC would tackle compensation rules. Either the MSC or RSC could work on the creation of no-harm tests, operating traits and market participation models, while the RASC could undertake capacity accreditation rules, said MISO Executive Director of External Affairs Kari Bennett.

But discussion at the workshop focused on the beguiling and intriguing issues around storage — and how to accommodate the increased adoption of a resource that defies MISO’s current market categories. The RTO currently has about 140 MW of battery storage requests in its interconnection queue.

‘A Giant Lego Set’

Lin Franks stressed the future importance of storage resources in MISO, saying she’s become a battery convert since volunteering to head the energy storage division at Indianapolis Power and Light.

“I feel like I learn something new about these things every day,” Franks said. “Like I said, I’m a born-again Christian when it comes to batteries. They can solve problems, and solve them quickly.”

IPL’s Harding Street Station was MISO’s first battery storage facility, commencing operation in May 2016. The facility can continuously deliver 5 MW for more than four hours, as well as move from a neutral state to full injection or withdrawal of energy in under one second. It serves only primary frequency response, reacting to unanticipated deviations.

“The faster you can solve the [frequency] degradation, the fewer megawatts you need,” Franks said.

IPL last year mounted an unsuccessful campaign to have FERC order MISO to compensate resources for providing automatic frequency control. (See MISO Ordered to Change Storage Rules Following IPL Complaint.)

Like all grids, MISO’s system was designed with control in mind, Franks said. Recent additions of rooftop solar and wind generation can erode that control, but autonomous storage resources can mitigate those risks and provide more resilience.

“We like to talk about storage as one kind of animal, but it’s not. It’s a whole zoo of animals,” Franks said. “When I talk about my lithium ion battery, that’s not what all lithium ion batteries are like. They morph with the industry. They’re like a giant Lego set.”

Franks urged stakeholders to educate themselves on stored energy resources.

“Real-time operators don’t like change. They know what works and they’re comfortable with it. … Just like you, I see some arms crossed out there,” Franks said, teasing the audience.

Franks noted that MISO and state and federal agencies are still working out policy details around storage, including capacity accreditation, facilities agreements, state-of-charge management, interconnection conditions, removal of Tariff barriers and clarification of state versus FERC jurisdiction. She also recommended that MISO lay out an “expedited path” in its annual Transmission Expansion Plan for storage resources.

Franks recounted the confusion Harding Street caused upon entering MISO’s interconnection queue in 2014.

“None of us knew how to model these at the time,” she said, adding that the RTO eventually settled on modeling the battery at its maximum injection and withdrawal.

Each of the storage array’s eight 2.5-MW cores contain more than 20,000 data points captured every two seconds and used to manage the state of charge, which IPL currently handles. But state-of-charge management could be passed to MISO.

“There is the perception among some at FERC that having the RTO manage the state of charge creates a conflict of interest,” she added.

‘Slicker than Snot’

Stakeholders asked MISO officials how its markets could permit storage to serve two masters ― generation and transmission services.

RSC Chair Tony Jankowski, manager of electric system operations at We Energies, wondered how MISO could possibly allow a storage resource to switch between participating as a generating asset or a transmission asset using the RTO’s existing “clunky” market process.

“These things are slicker than snot and can do a lot of things in a very short period of time,” Jankowski said, adding that MISO might accommodate the chameleon-like nature of storage with an “either/or” asset registration.

Indiana Utility Regulatory Commission staffer David Johnston said asset registration raises a question of whether storage resources must enter the RTO’s generation interconnection or the MTEP process.

“I think these are all good questions,” said MISO Director of Planning Jeff Webb, who added that he could not yet venture a guess as to the solutions. One of his concerns is keeping enough available capacity on hand if storage can register as both capacity and transmission assets.

“But none of these [questions] are showstoppers. It’s just how to manage them,” Webb said.

“Whatever the process, I don’t want to halt the progress of these Lego blocks, as Lin called it,” said DTE Energy’s Nick Griffin.

Multiple stakeholders said MISO’s storage models must account for every kind of storage, from the more common battery storage to flywheel to compressed air to pumped storage.

Griffin pointed out that MISO is years away from modeling storage as both a transmission and generation resource. However, Jankowski pointed out that storage modeling could be simplified by distinguishing between synchronous and inverter connections.

Some stakeholders said collection of storage information is the key to creating participation models, but Customized Energy Solutions’ David Sapper said he would play the “contrarian” and caution about information overload. Sapper pointed to the risk of micromanagement through extensive communications and controls, an issue raised by University of Wisconsin engineering professor Bob Lasseter at the Organization of MISO States’ distributed energy resources workshop earlier this month. (See Stakeholders Hash out Future of DER at OMS Workshop.)

While Franks agreed, she countered that a lot of information may be necessary at the onset of market storage participation.

“This is new to [MISO operators], and until they get comfortable, they’re going to want to see more than less — and that may not take very long,” she said.

American Transmission Co.’s Bob McKee said it would be helpful for MISO to create a price menu showing the current compensation provided for possible storage-sourced services like energy arbitrage and frequency response.

“I think it’s fair to say if we did that now, we’d have a lot of question marks in there,” Bennett said.

“That’s fine. This [menu] would tee that up,” McKee said, and other stakeholders agreed.

August 28, 2017

Westar Agrees to Penalty for Violating SPP’s Tariff

By Tom Kleckner

Westar Energy will pay a civil penalty of $180,000 for submitting inaccurate mitigated energy offer curves (EOCs) under a settlement with FERC’s Office of Enforcement.

Westar also agreed to be subject to Enforcement monitoring under the settlement, which was approved by FERC on Thursday (IN15-8). The Kansas utility will submit annual compliance monitoring reports for two years, with a third year possible at the office’s discretion.

The violations occurred between October 2014 and February 2015, when Westar submitted cost inputs three times for its State Line plant that FERC said were “inconsistent” with the cost parameters on file with SPP’s Market Monitoring Unit. The incorrect data resulted in the utility receiving make-whole payments of about $60,000.

westar energy offer curves EOC SPP — Westar’s State Line facility | *Westar Energy*

The MMU requested in March that Westar produce data validating its mitigated EOCs. It found the data insufficient and referred the company to Enforcement.

Mitigated EOCs in the RTO’s Integrated Marketplace must be based on an individual resource’s costs and unit characteristics. They are generated according to a formula that contains several inputs, including a fuel cost adder for variable operations and maintenance (VOM) costs.

Enforcement’s investigation determined a Westar employee inadvertently increased the fuel VOM charge from 5 cents to 50 cents for the company’s share of the two State Line units. Staff also found the utility submitted incorrect heat rate coefficients for one of the units.

The utility voluntarily refunded the $60,000 to SPP in June 2015 and took “effective measures to identify mitigated EOCs that [it] failed to properly update,” FERC said.

The commission noted that the utility cooperated throughout the investigation and promptly responded to requests for data and testimony. The utility filed a detailed report in June 2015 explaining the origin of the errors, the steps taken to correct them and the plans implemented to prevent them in the future.

Westar is the largest electric company in Kansas, serving 690,000 residential, commercial and industrial customers in the eastern third of the state.

August 28, 2017

FERC Again Rejects Emissions Controls for NY Demand Curve

By Rich Heidorn Jr.

FERC on Wednesday again rejected a request that it include the cost of emissions controls in the peaking plant design for the New York Control Area (NYCA) capacity demand curve (ER17-386).

The commission rejected a rehearing request by the Independent Power Producers of New York (IPPNY), which contended that the state’s Siting Board is likely to require selective catalytic reduction (SCR) emissions controls in the future because of concerns over fossil fuel generation.

FERC repeated its conclusion that SCR controls are not required for peaking plants in NYCA load zones C and F and that peakers can meet environmental rules by limiting their operating hours, dismissing as “speculative” IPPNY’s prediction of tighter controls in the future.

IPPNY had asked the commission to reconsider its January ruling approving NYISO’s revised demand curve for delivery years 2017/18 through 2020/21. (See FERC OKs NYISO Demand Curve Reset.)

The January order continued the use of F class frame peaking turbines as the proxy unit for setting the cost of new entry. It also continued the requirement that peaking plants include dual-fuel capability and SCR emissions controls for the New York City, Long Island and G-J Locality demand curves.

FERC NYISO demand curve Demand Response — | *Analysis Group*

But the commission rejected the ISO’s proposal to extend the SCR requirement to the NYCA, where gas-only designs were permitted. Under current rules, FERC said, the NYCA peaking plant can operate under an annual operating hours limit in lieu of installing SCR emissions controls.

In its order this week, FERC also rejected IPPNY’s request to shorten the amortization period or increase the rates of return for peakers in zones C and F. IPPNY said the changes would capture the risk that emissions rules on those plants will be tightened in the future.

The commission deemed as “speculative” the risk of having to retrofit an NYCA peaking plant with SCR controls, and also found NYISO’s proposed amortization period and return on equity to be just and reasonable.

“The commission need not consider alternatives,” FERC said. “Nevertheless, IPPNY provides no alternatives, but only a scant statement that the commission should impose either ‘a significantly shorter amortization period than the NYISO’s proposed 20-year period or an increased required return.’ In contrast, NYISO’s amortization period and return on equity were the subject of analysis by [the ISO’s independent consultant] and extensive stakeholder discussions.”

August 28, 2017

FERC Approves PGE Transmission Cost Recovery

By Jason Fordney

FERC last week approved Pacific Gas and Electric’s request to recover from its customers a portion of the costs of a $1.8 billion package of planned transmission improvements if the company is forced to abandon construction for reasons beyond its control.

The commission approved abandonment cost recovery for only some of the substation improvements and transmission lines that PG&E plans to construct (EL16-47). It also ruled that the utility is eligible for a 50-basis-point adder to its base return on equity as an incentive because the improvements are part of a regional transmission planning process.

FERC PG&E cost recovery — PG&E Plans $1.8 Billion in Transmission Improvements | © *RTO Insider*

The California Public Utilities Commission objected to PG&E’s proposals, saying the company had not demonstrated the improvements would relieve congestion and had not provided enough information on the scope of the projects. PG&E was not transparent about cost control, projects costs had escalated since CAISO’s approval and the utility had failed to quantify the possible abandoned plant cost to ratepayers, the PUC argued.

The PUC also contended that PG&E failed to disclose in CAISO’s competitive solicitation process that it intended to seek from FERC incentive rate treatment for the projects.

The Sacramento Municipal Utility District, Transmission Agency of Northern California and the Six Cities group also protested the incentives.

FERC disagreed, saying “the CPUC does not point to any commission order or provision of the CAISO Tariff requiring project sponsors to disclose, in advance, that they intend to seek transmission rate incentives for their respective projects from the commission.”

Public utilities can seek incentive-based rates for projects that preserve reliability or reduce delivered power costs by reducing congestion. To get the incentive and additional profit, PG&E must participate in a regional transmission planning process, which it does through CAISO.

The commission also held that PG&E was entitled to the rebuttable presumption that each of its projects would either increase reliability or reduce congestion because they were approved through CAISO’s FERC-sanctioned transmission planning process.

The projects listed in PG&E’s petition to FERC are the Wheeler Ridge substation; Northern Fresno 115-kV reinforcement; Midway-Andrew 230-kV project; Estrella 230/70-kV substation; Lockeford-Lodi Area 230-kV development; Martin Bus 2-kV bus extension; Oro Loma 70-kV reinforcement; and Spring 230-kV substation.

FERC approved PG&E’s requests for abandoned cost recovery for the Wheeler Ridge, Northern Fresno and Midway-Andrew projects but denied them for the others. The approved projects met FERC’s standard for a “nexus test” based on project scope and regulatory and construction risk because of land acquisition and other factors.

The commissioned also denied the company’s request for recovery of costs incurred up to the point of its March 10, 2016, filing.

August 28, 2017

Nuclear Industry Seeks PPAs, FERC, RTO Action After Grid Study

By Rich Heidorn Jr.

The nuclear industry hopes the grid study released by the U.S. Energy Department last week will accelerate RTO price formation efforts valuing baseload generation and that the federal government will begin purchasing nuclear power.

But states are still the first line of defense against premature plant closures, the Nuclear Energy Institute said at a press conference Thursday.

“We see the nearest-term opportunities for action to be at the state level while the RTOs and FERC [are] a little bit further out,” said John Kotek, NEI’s vice president for policy development and public affairs.

Kotek, a former DOE official, praised his former colleagues for what he called a “solid, fact-based, dispassionate analysis of the issues facing today’s electric grid.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)

“We know that states are more nimble in their ability to respond to the challenges immediately in front of them,” agreed Matt Crozat, NEI senior director of policy development and another ex-DOE staffer.

He also urged Congress to exercise its oversight authority to ensure prompt action by FERC and RTOs on price formation rules.

“I think FERC can create the requirement to demonstrate how the [RTO] tariffs reflect these attributes that are important to the system,” he said, adding, “I’ll be watching closely to see how FERC begins to frame the question for itself.”

“Based on what we’ve heard out of FERC leadership, it does sound like they’re poised — it sounds like the system operators are poised — to actually move out fairly smartly on these things,” Kotek said.

In a podcast interview with FERC’s chief spokeswoman earlier this month, acting FERC Chair Neil Chatterjee said, “Baseload power … including our existing coal and nuclear fleet, need to be properly compensated to recognize the value they provide to the system.” He cited their value to “resilience and reliability.”

NEI also noted the DOE report’s reference to the “important nonproliferation” implications of allowing the industry to decline.

DOE quoted Michael Webber, deputy director of the University of Texas’ Energy Institute, who cited the risk to “our most important anti-proliferation asset: a bunch of smart nuclear scientists and engineers…. The loss of expertise from a declining domestic nuclear workforce makes it hard for Americans to conduct the inspections that help keep the world safe from nuclear weapons.”

NEI officials saod they hope federal officials will consider making power purchase agreements from nuclear plants like the ones military bases with renewable power developers during the Obama administration.

“Those types of arrangements were clearly struck both to meet electric demand but also to promote, in this case, the growth of renewable energy deployment across the United States,” Kotek said. “If we as a nation determine that the national security benefit of a strong domestic nuclear industry, along with the clean air benefits and the resiliency and reliability of nuclear plants are worth keeping around, then that’s one avenue you could pursue in the effort to ensure we retain the plants that we’ve got.

FERC DOE price formation Nuclear Power — | *Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017*

“And it’s a potential means for building new [plants],” Kotek continued. “You may know [that] the sustainability order that was put in place by the last administration included small modular reactors, for example, as a technology that would qualify as meeting clean energy demand going forward. It’s one … potential tool in the tool box.”

The officials cautioned against attempting to precisely price resiliency attributes into wholesale power markets.

“I think there are more expansive ways to go at this question without having to necessarily settle on ‘Reliability is worth $4/MWh’ or something like that,” Crozat said. “That’s going to be a difficult calculation to derive.”

Crozat said he was encouraged by PJM’s June report proposing to allow nuclear and coal plants needed for reliability to set clearing prices based on their marginal costs. This would be particularly helpful in addressing negative clearing prices in off-peak hours, he said. (See PJM Making Moves to Preserve Market Integrity.)

“If I know I have units that are going to be needed for reliability, I’ll ensure that the prices are being set in a way that recognized the cost of those units,” he explained. “It just changes slightly the economic logic of who’s allowed to set prices and who isn’t.”

Exelon, the nation’s largest nuclear operator, said it was encouraged by the Energy Department’s recommendation that FERC “expedite” its efforts to improve energy price formation in organized wholesale markets. The company is defending zero-emission credits for its plants in New York and Illinois.

“These reforms will help preserve clean energy sources and ensure critical American assets remain part of the mix, including baseload nuclear plants that provide more than 60% of our nation’s emissions-free energy,” the company said in a statement. “We applaud the Department of Energy for their work, and urge FERC and the RTOs to swiftly enact common-sense reforms that will help safeguard the reliability, resilience, diversity and affordability of our supply of electricity.”

NRG Energy, one of the independent power producers that have fought ZECs, also urged FERC to act on price formation and provide fuel- and technology-neutral ways to value reliability services.

“These efforts — and not expensive and market-destroying state subsidy programs to benefit particular generating facilities — would do more than anything else to ensure resiliency and reliability in an environmentally responsible and consumer-friendly way,” the company said in a statement.

August 28, 2017

SPP Registered Entities Face Oct. 31 Deadline for New RE Choice

NERC staff told SPP’s registered entities Friday they have until Oct. 31 to submit their transfer requests to another Regional Entity, following the dissolution last month of the RTO’s RE. (See SPP to Dissolve Regional Entity.)

Requests may be submitted by an individual entity or as part of a group, staff said. NERC is working with the 120 registered entities within SPP’s footprint to smooth their transfer to new compliance enforcement authorities, with ReliabilityFirst, Midwest Reliability Organization and SERC Reliability seen as the most likely landing spots.

Registered entities should provide in their requests the location of their bulk power facilities, their relationship to their desired RE and their views on the proposed destinations for other entities in their regions. The regulatory authority will provide a weekly list of questions and answers to SPP’s registered entities, along with other materials.

“An entity does have the ability to request the NERC Board [of Trustees] reconsider a move if they don’t agree with it,” NERC General Counsel Charlie Berardesco said during a webinar for the SPP RE’s members.

Berardesco said registered entities must meet all obligations during the transition period, including compliance with reliability standards. Pending approval by NERC’s board and FERC, the SPP RE will cease to exist by the end of 2018.

— Tom Kleckner

August 28, 2017December 13, 2023

Sempra Begins ‘Listening Tour’ of Key Stakeholders

By Tom Kleckner

Sempra Energy has wasted little time getting to know Texas stakeholders, embarking on a “listening tour” just days after its surprise announcement it was seeking to acquire the state’s largest utility, Oncor.

“We’re approaching North Texas with a fair amount of humility,” Sempra CFO Jeff Martin told financial analysts Friday during a conference call.

Martin and Sempra CEO Debbie Reed conducted the call from a hotel room in Austin, Texas, taking a break from meeting with Texas regulators, intervenors and other key Sempra and Oncor stakeholders.

The San Diego-based company last week announced an agreement to acquire Energy Future Holdings, Oncor’s bankrupt parent and indirect 80% owner, for $9.45 billion, besting Berkshire Hathaway Energy’s $9 billion offer. (See Sempra Outmuscles Berkshire for Oncor.)

Sempra had been eyeing Oncor for several years, but “this deal came together very quickly,” Reed said. Company staff have been reviewing the history and transcripts of previous proceedings before the Public Utility Commission of Texas, which denied previous attempts by Hunt Consolidated and NextEra Energy to acquire the utility. The PUC rejected both suitors because of their inability to meet strict ring-fencing measures put in place after EFH declared bankruptcy in 2007.

“We tried to listen and learn from prior transactions, and we’re working to understand the issues that are important to the regulators and intervenors,” Reed said. “We intend to be a long-term owner of Oncor and want to ensure the company continues to do an exceptional job meeting the needs of its customers.”

Reed pointed to Oncor’s “incredible history of success,” its ability to pay dividends and recent completion of a rate case as reasons for Sempra “to get comfortable with the requirements that the regulators had put on in prior transactions.”

Those requirements have included an independent board of directors, a continued Texas presence and reinvestment of capital expenditures.

“If Oncor needs those funds to invest in their business, we are very supportive of that because we see the utility investment is positive,” Reed said, referring to Oncor’s plans to spend about $7.5 billion in capital over the next five years.

“We’re all about partnerships and making sure that from a stakeholder analysis standpoint, we’re doing all the right things to address those concerns,” Martin said. “We’re just starting that process, and we’re confident about telling our own story. I think we’re comfortable with a lot of the issues that have been raised with us.”

However, some intervenors in Oncor’s prior proceedings are skeptical of Sempra’s offer, a source told RTO Insider. BHE had reached a settlement agreement with key intervenors based on its ability to wipe out the utility’s debt overhang with an all-cash deal, but those parties now complain that Sempra is providing very little information in what has been called a “half-baked” proposal.

Sempra executives said Friday that they intend to fund the $9.45 billion purchase with $3 billion of investment-grade non-course debt, with the company providing about 60% of the remaining $6.45 billion and third-party investors covering the rest.

Martin said Sempra is not considering EFH’s current creditors or hedge funds; instead, it is looking to partner with investors that are “aligned with our long-term interest in reinvesting and growing Oncor,” such as pension or infrastructure funds. He said the company plans to issue a combination of debt and equity to fund its 60% portion, with equity representing at least half that.

Sempra agreed to a $190 million termination fee, compared with BHE’s $270 million fee.

The California company now faces two important regulatory hurdles. The U.S. Bankruptcy Court for Delaware will consider the merger agreement Sept. 6, followed by a hearing to confirm EFH’s reorganization plan. That second hearing would take place about 30 days should the PUC approve Sempra’s offer. Reed said Sempra plans to file with the commission shortly after the merger agreement is approved.

The PUC meanwhile last week sent Oncor CEO Bob Shapard a letter asking him and board Chair Jim Adams to appear at Thursday’s open meeting in Austin.

The commission told Shapard it wants to discuss Oncor’s views “as to the likely structure and timing” of Sempra’s proposal, and the utility’s current financial condition and liquidity as it relates to the PUC’s “legal obligation to protect” the company’s financial integrity. The commission said it also wants to delve into accrued expenses over the last two years as a result of the Hunt and NextEra acquisition attempts.

August 28, 2017

FERC OKs Missouri River ROE Settlement over Staff Objections

FERC last week approved a settlement agreement granting five municipalities belonging to Missouri River Energy Services a 9.6% base return on equity, with a 50-basis-point adder for SPP membership (ER15-2324).

The settlement revises SPP’s Tariff, adding formula rates that allow Moorhead, Minn.; Orange City and Sioux Center, Iowa; and Pierre and Watertown, S.D., to recover annual transmission revenue requirements for facilities that moved under the RTO’s functional control.

FERC Missouri River Energy Services — | *MRES*

FERC trial staff opposed the settlement, saying its discounted cash flow (DCF) analysis indicated the municipalities should have an 8.42% base ROE. Staff also said the capital structures of four of the five MRES members have abnormally high equity ratios and that hypothetical capital structures should be used for them instead.

Nebraska Public Power District filed comments expressing concern over the ROE but did not oppose certification of the settlement.

FERC approved the settlement despite staff’s concerns because, the commission said, it “reaches compromises on issues other than the ROE and capital structure issues raised by trial staff, and rejecting the settlement because of these components would upset the negotiated agreement reached by the settling parties on many other issues.”

The commission said the base ROE of 9.6% is a rate reduction from what MRES originally proposed and “is consistent” with FERC-approved ROEs in other recent uncontested settlements in the SPP transmission zone.

“Trial staff’s DCF analysis would not go unchallenged by the parties during litigation,” the commission added. “A contested hearing might not produce an ROE appreciably lower than the settlement’s base ROE and could produce one that is even higher. Moreover, the settlement includes a rate moratorium providing customers with rate certainty for the future.”

The RTO was given 30 days to file revised Tariff records.

— Tom Kleckner

August 28, 2017

UPDATE: ERCOT Reports ‘Stable’ Conditions as Harvey Hovers

By Tom Kleckner

ERCOT said Monday that conditions remained stable on its system, despite the loss of two 345-kV transmission lines and other major high-voltage outages that cut power to more than 300,000 customers following Hurricane Harvey’s landfall in Texas on Friday night.

ERCOT Hurricane harvey — Downed power lines | *ERCOT*

The two 345-kV lines serve the Texas Gulf Coast near Corpus Christi and Victoria, at the center of the storm’s landfall. More than 6,700 MW of generation capacity were offline for storm-related reasons, including a very small volume of renewables.

ERCOT said electricity demand has been about 20,000 MW below normal since Harvey came ashore, peaking at less than 44,000 MW because of structural damage along the coast and cooler temperatures. System restoration times will vary depending on the extent of damage, outage locations and weather conditions, the ISO said.

The ISO issued an emergency notice Friday and brought on extra engineering staff throughout the weekend to support efforts in its Taylor operations center for Harvey, the first Category 4 storm to hit Texas since 1971.

ERCOT spokesperson Robbie Searcy said the day-ahead market cleared on time over the weekend.

Harvey was downgraded to a tropical storm Saturday afternoon, but it has spawned tornadoes and continues to drench much of the Texas Gulf Coast with torrential rains. The downpours are expected to continue well into the week.

MISO ERCOT Hurricane Harvey — Harvey’s after-effects in Corpus Christi | *Frances Hale Hall*

The number of consumers without power peaked at just more than 300,000 early Saturday afternoon, based on reports from transmission providers in the affected areas. As many as 157 circuits were out of service at one point, with outages heaviest near Corpus Christi and Victoria.

ERCOT said extended outages are likely in most of those areas, and the outage numbers will fluctuate as transmission providers work to restore power.

The ISO has created a special page on its website to provide the latest updates on restoration efforts.

Houston’s two major airports — William P. Hobby and George Bush Intercontinental — were both closed over the weekend. They may be reopened as soon as Wednesday.

The U.S. Coast Guard closed multiple ports along the Texas Gulf Coast, including those at Houston, Galveston, Texas City, Freeport and Corpus Christi.

ERCOT is responsible for about 90% of Texas’ load, including Houston and much of the affected coastal region. MISO is responsible for Southeast Texas, which includes the cities of Beaumont, Port Arthur and The Woodlands.

MISO also manages parts of Arkansas, Louisiana and Mississippi, where the National Weather Service was forecasting as much as 4 inches of rain over the next five days.

MISO South Region Operations Director Tag Short said the RTO was activating its “established protocols” to maintain grid reliability and had additional operators and support staff in place and on call.

Spokesman Mark A. Brown said Sunday night that the MISO transmission grid remained stable, but that the RTO remained in a severe weather alert.

“Our region could still face significant amounts of rainfall and potential flooding,” he said. “We will be carefully monitoring those conditions and will be prepared to take the appropriate steps to maintain the reliability of the transmission grid across the MISO footprint.”

MISO ERCOT Hurricane Sandy natural gas pipelines — Projected rainfaill totals | *NOAA*

Entergy Texas reported more than 7,600 customers were without power as of 8:30 a.m. Sunday. “Crews are safely restoring power as quickly as possible, but the storm’s continued wind, rain, flooding and falling trees could make it difficult to access Entergy’s equipment and slow restoration,” the company said. It serves more than 440,000 customers in 27 counties.

August 25, 2017

RGGI States Agree to Increased Emission Reductions

By Michael Brooks

The nine states comprising the Regional Greenhouse Gas Initiative have agreed to accelerate reductions in power sector carbon dioxide emissions by lowering the cap-and-trade program’s annual allowances by 30% over 10 years.

The changes to the program, announced Wednesday, also include the addition of an Emissions Containment Reserve (ECR), in which the participating states — Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont — can withhold emission allowances from the quarterly auctions if prices fall below a certain threshold.

“The RGGI states are demonstrating our commitment to a strengthened RGGI program that will utilize innovative new mechanisms to secure significant carbon reductions at a reasonable price on into the next decade, working in concert with our competitive energy markets and reliability goals,” Connecticut Public Utilities Regulatory Authority Chair Katie Dykes, who serves as chair of the RGGI board of directors, said in a statement.

RGGI currently reduces the emissions cap by 2.5% annually, targeting 78.2 million tons in 2020. The changes set the 2021 cap at about 75.1 million tons and reduces it by 2.275 million tons (3%) annually after.

RGGI carbon emissions — RGGI auction clearing prices fell over the course of 2016, spurring calls for reforms to the cap-and-trade program. | *Potomac Economics*

Environmentalists and Massachusetts officials last year called for doubling the current rate of reduction, but Maryland Environment Secretary Ben Grumbles balked at the proposal, arguing that the state would be at a disadvantage because its coal-fired power plants must compete in PJM, while most states in the program are in the ISO-NE footprint. (See Md. Balks at Proposed Emission Cuts as RGGI States Ponder Future.)

Grumbles said such an aggressive rate could cause Gov. Larry Hogan to withdraw the state from the program, as New Jersey Gov. Chris Christie did in 2011.

“Maryland is proud of the teamwork among states to achieve consensus for a stronger and broader, balanced and sustainable RGGI,” Grumbles, who serves as the RGGI board secretary and treasurer, said about the agreement.

“Maryland is committed to finding real bipartisan, common sense solutions to protect our environment, combat climate change and improve our air quality,” Hogan said in a statement. “By working together, we are showing that it is possible to find consensus to protect our natural resources, promote clean energy, and grow our economy for current and future generations.”

With the implementation of ECRs starting in 2021, states would be able to withhold up to 10% of their allowances if auction prices fall below $6/ton, with the price trigger rising 7% each year after. The withheld allowances would not be bankable, meaning they could not be resold in a future auction.

Low prices in previous auctions spurred the initial calls for reforms last year, and prices have only continued to fall since. The latest auction, on June 7, saw a $2.53/ton clearing price, a 15% drop from the previous quarter and 44% from a year ago.

RGGI will hold a meeting at the Maryland Public Service Commission in Baltimore on Sept. 25 to solicit public and stakeholder feedback on the changes.