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.
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.
Among the Improvements are new Substations
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.
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.
| 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.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
“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.
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.
| NERC
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.
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.
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.
| 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.
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.
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.
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.”
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.
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 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.
SACRAMENTO, Calif. — Few parties in California are happy with the way the state’s community choice aggregator (CCA) program is turning out, legislators learned during a Wednesday hearing at the state capitol.
In a discussion that at times grew tense, state senators heard how the evolution of California’s CCA program has shifted hundreds of millions of dollars in costs to investor-owned utility customers because of long-term procurement contracts signed by IOUs a decade ago in a radically different energy environment. The result is consternation among ratepayers and elected officials about increased costs — rather than the promised benefits of restructuring — and alarm about resource planning.
The situation “has become a very obvious conflict to people such as myself, and I am sure other legislators have been caught in the crossfire of this debate,” State Sen. Ben Hueso, chairman of the Senate Committee on Energy, Utilities and Communication, said at the opening of the hearing.
The State Legislature authorized the creation of CCAs with the passage AB 117 in 2002, after municipalities in the Los Angeles and San Francisco areas lobbied in response to a failed deregulation effort that in part caused the Western Energy Crisis of 2000/01. The law allows local governments to form CCAs by aggregating retail customers and securing electricity supply contracts to serve them. CCAs are growing rapidly in California and also exist in Ohio, New York, Massachusetts, New Jersey, Rhode Island and Illinois.
California Public Utilities Commission President Michael Picker told the committee that the state’s retail electricity industry is being deregulated once again as it was in the mid-1990s, but this time by technology.
“We are being deregulated from the bottom up, and there is no real plan as to how it fits together,” Picker said. Amid later questioning and discussion, he told the lawmakers, “I am looking to you for direction.”
In an effort to spread the costs of legacy contracts, the IOUs in April proposed that the state adopt a new formula for allocating costs of departing CCA and other retail-choice customers, called the portfolio allocation methodology. (See Utility Proposal Would Increase Legacy Costs for California CCAs.) That approach would replace the current IOU exit fee levied on departing customers, called the power charge indifference adjustment (PCIA), which is meant to address the old contracts. The PUC is taking a look at its deregulation strategy. (See California to Reconsider Retail Choice.)
PG&E Calls for Quick Action
California’s IOUs initially resisted the creation of CCAs by introducing a ballot proposition to make their growth more difficult, but that measure failed. The utilities said they are left holding the bag for long-term procurement decisions made years ago in an industry environment that has changed significantly in terms of rate structures, prices and technology. Those costs are being borne by a dwindling rate base — including low-income customers.
PG&E Senior Vice President Steven Malnight told the committee that the legacy contracts, numbering more than 200 and signed in 2007 and 2008, enabled third-party resource developers to invest billions of dollars in California, create thousands of jobs and help the state to become an economic leader.
The IOUs “see a significant challenge that is in front of us — that needs to be addressed quickly — on cost allocation,” Malnight said. When the contracts were procured, the IOUs were planning to service their customers for up to 20 years.
“The assumption was that those customers would stay in our service territory, and that we would need to serve them,” he said. “Today, we know that reality is significantly different.”
About 30% of PG&E’s customers switched to third-party services, a number that is estimated to rise to 50% by 2020. PG&E procured energy on behalf of those customers and now must reallocate costs through the PCIA. Under that methodology, departing customers are assuming only about 65% of the costs that should be allocated to them. The remaining costs are being paid not by utility shareholders but by remaining IOU customers, many of them in areas without a CCA option, he said.
About $180 million has been shifted from CCA customers to IOU customers, he said, which will grow to $500 million by 2020. “I know in California that we do think big — but that is a lot of money,” Malnight said. Long-term contracts are often needed to provide resources to deal with renewable integration and protect grid reliability, and IOUs are generally over-procured and have limited options for solving that problem.
“We can’t arbitrarily walk away from that contract, [and] turn it over to a CCA or anybody else,” he said.
California Coalition of Utility Employees counsel Marc Joseph told the committee that in 2007, IOUs were facing renewable mandates when their cost was much higher and the industry and its technologies were young. It was a seller’s market, but CCAs now function in a “buyer’s market.”
IOUs could be paying back those contracts for decades, and the PCIA does not work to make IOU customers “indifferent” to the creation of CCAs. But CCAs are basing their current economic decisions on the current structure of the PCIA program, he said.
“It is easy to see the train wreck that will come,” he said, telling the legislators CCAs “will come running to you to bail them out.” He urged a slowdown in the CCA program while the PUC examines the PCIA issue, he said. Many new renewable developers are ready to build, but the result is no customers because IOUs are over-procured. As a result, in California “we have had a crash in the construction of new renewable projects” after healthy growth in 2016 at a time when large federal subsidies are available.
Contract Holders Expect to Get Paid
Independent Energy Producers Association CEO Jan Smutny-Jones told the committee that the group’s members built a lot of the renewable projects in California and also do some business with CCAs, as well as holding the IOU contracts.
“We expect those contracts to be honored,” he said, adding that “we are not really interested when someone else says something else should happen with those contracts.” They are private contracts subject to contract law and out of the jurisdiction of the PUC, he noted.
“This is a big issue. This state has a very good history of honoring contracts with my member companies. … We need to keep that up,” Smutny-Jones said. Not honoring the contracts would send a strong negative signal to companies considering investing in California.
Bradford Questions CCA Fairness
Sen. Steven Bradford, who represents parts of Los Angeles County, said that CCAs can “pick and choose” which customers they serve. That assertion drew disagreement from Sonoma Clean Power CEO Geof Syphers, but Bradford insisted that “you can — that’s why you are in Marin, that’s why you are in Sonoma.”
IOUs have an obligation to serve customers, and “you wanted to be everything a utility is, other than report to the PUC,” Bradford said. As a State Assembly member in 2014, Bradford introduced legislation that was viewed as anti-CCA. It would have put default provider status back to the IOU rather than the CCA, but the bill was defeated after opposition from CCA supporters that argued that CCAs shouldn’t be subjected to the same oversight as IOUs.
At its conclusion, Hueso said the hearing had been “enlightening” and that he was concerned about creating an ungovernable system. The committee plans to hold more discussions on the future of CCAs.
“Nobody talked about a collapse of our system, but there were a lot of comments that alluded to that,” Hueso said.
The U.S. Energy Department grid study released Wednesday added no new information to debates that have been going on for months at FERC technical conferences and RTO/ISO stakeholder meetings.
The report also acknowledged that the department has virtually no authority over generation or wholesale markets, leaving it to FERC and RTOs to act on its recommendations. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
On Thursday, FERC and several RTOs responded. Their message: We’re already working on it.
Acting FERC Chairman Neil Chatterjee issued a statement saying the report “highlights many activities that the commission is carefully considering, including examining ways to enhance wholesale electric capacity markets and improve price formation in those markets, to increase electric and gas coordination, and to assure bulk power system reliability and resilience. The commission will remain focused on these and other issues that are critical to maintain the nation’s competitive wholesale electric markets and keep the lights on.”
PJM, ISO-NE, MISO, CAISO and SPP also issued statements assuring DOE that they are addressing the issues and that — despite the ominous warning Secretary Rick Perry used in his April 14 memo ordering the study — that there are no imminent risks to grid reliability.
Price Formation
Among the report’s recommendations were a call for FERC to “expedite its efforts with states, RTO/ISOs and other stakeholders to improve energy price formation in centrally organized wholesale electricity markets.”
| PJM
“After several years of fact finding and technical conferences, the record now supports energy price formation reform, such as the proposals laid out by PJM and others,” it said, citing PJM’s June report, “Energy Price Formation and Valuing Flexibility,” and MISO’s extended LMP initiative. (See PJM Making Moves to Preserve Market Integrity.)
The report says that although all RTOs/ISOs have some type of shortage pricing, the designs differ, a “variance [that] could present challenges to market participants who require a threshold level of certainty to make an investment decision.” Although it acknowledged that FERC Order 831 doubled energy offer caps in the organized markets to $2,000/MWh, it cited concerns expressed by Market Monitors Joe Bowring and David Patton over the volatility of shortage pricing revenue. (See Lawyers Take an Economics Class: Capacity Markets vs. Scarcity Pricing.)
| Energy Information Administration, based on Intercontinental Exchange (ICE) prices as reported by Ventyx, February 23, 2012
It also called for mitigating negative prices “to the broadest extent possible,” quoting from the department’s January Quadrennial Energy Review report that “price suppression is occurring in RTO/ISO wholesale markets with noticeable amounts of wind and solar generation (and low-cost gas generation).”
Essential Reliability Services
The department also urged FERC to require valuation of “essential reliability services” through fuel- and technology-neutral markets or regulatory mechanisms. The report includes in that description ancillary services such as frequency and voltage support, and ramping capability.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
A table in the report shows that only MISO and CAISO have any product in the “ramp reserve” category. SPP’s David Kelley said the RTO is evaluating the benefits of a ramping product for the Integrated Marketplace and is exploring designs deployed in other markets. It has no current timeline for implementation.
Resilience
The report also called for further study on mandatory capacity markets, which it noted have “been the subject of near-constant debate” and the development of metrics and tools for evaluating “resilience.”
The department said NERC “should consider adding resilience components to its mission statement and develop a program to work with its member utilities to broaden their use of emerging ways to better incorporate resilience.”
“RTOs and ISOs should further define criteria for resilience, identify how to include resilience in business practices and examine resilience-related impacts of their resource mix,” it continued.
The report acknowledged that while wholesale markets “do not explicitly recognize or compensate system resilience,” PJM and ISO-NE have changed their capacity market rules to incentivize generator performance during scarcity conditions. It notes that only some RTOs — naming PJM, ISO-NE and NYISO — value onsite fuel storage, a characteristic of coal and nuclear plants that natural gas plants without oil-fired back-up lack.
Quoting PJM, the report notes that “criteria for resilience are not explicitly defined or quantified today.”
“Each RTO/ISO should strive to explicitly define resilience on its system and conduct resource diversity assessments to more fully understand the resilience of different resource portfolios,” the department said. “Federal, state and local work to define and support systemwide resilience is also needed.”
NERC issued a statement saying that reliability and resiliency “are key priorities for NERC and we appreciate the recognition of our work on these matters.”
ISO-NE
ISO-NE spokeswoman Marcia Blomberg said the RTO is reviewing the study. “However, in the two decades since their creation, competitive wholesale electricity markets in New England have achieved what they were designed to accomplish, including power system reliability supported by an adequate resource base, competitive wholesale power prices that accurately reflect the cost of reliable power production and a shift in resource investment risk from ratepayers to investors.
“As the energy landscape evolves, ISO New England will continue working with industry stakeholders and state policymakers to ensure that the markets can adapt to changing industry dynamics, such as state environmental policies and fuel security challenges, while continuing to produce competitive prices that support the resources needed to reliably meet consumer demand for power.”
PJM
PJM called the report “thoughtful” and “comprehensive.”
“The report acknowledges that wholesale power markets are working and providing reliability at the lowest possible cost and that power supply resources are more diverse than they have ever been. It also highlights the importance of expediently addressing needed reforms in energy price formation followed by a focus on grid resilience. These issues are a top priority.”
The RTO noted that it has posted discussion papers on price formation and capacity market reform to accommodate state policies. “Earlier this year, we published a paper, ‘PJM’s Evolving Resource Mix and System Reliability,’ which demonstrated that the PJM region has remained reliable throughout the rapid changes in the resource mix. PJM’s analysis also indicated a need to focus on fuel assurance and resilience to take into account the changing operational risks that the industry faces.” (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
CAISO
CAISO said it has “experienced success in integrating large amounts of renewable resources without threatening grid reliability. There’s no doubt that energy markets are evolving as the fundamental resource mix changes. The ISO will continue to operate a reliable grid that can capture the benefits of this transformation.”
MISO
MISO said it “has been preparing for the challenges of the evolving resource mix, and we will continue to ensure that planning constructs, market designs and operational practices are in place to support the reliability of the electric grid across our footprint. We look forward to continuing our work with DOE, regulators, policymakers and stakeholders as that effort continues.”
SPP
SPP spokesman Derek Wingfield said the RTO “is pleased the report acknowledges the value of transmission investments in enabling ‘an array of benefits’ including reliability, congestion relief, market competition, diversity of fuel sources and more, and that our own Value of Transmission study had some influence on the Department of Energy’s analysis. The report’s recommendation to further study market structures and the impacts of renewable integration is also welcome, and we pledge to assist the DOE and FERC with such analyses should the opportunity arise.” (See SPP Begins Promotional Campaign to Tout Transmission Value.)
Last month, SPP stakeholders approved recommendations from a study on how much wind energy the RTO’s system can safely and reliably absorb. The RTO has routinely broken the 50% penetration level for wind energy, and has said it can go even higher. The recommendations include the installation of online transient-stability and voltage-stability analysis tools. (See “Wind Integration Study’s Recommendations Move On,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
ERCOT
ERCOT, which is not subject to FERC jurisdiction, held a discussion with the Texas Public Utility Commission on Aug. 11 on price-formation issues including scarcity pricing and marginal losses. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
ERCOT has also successfully integrated renewables at 50% penetration levels.
NYISO officials had no immediate comment, saying they were digesting the report.
CARMEL, Ind. — While MISO officials were unsurprised that the Aug. 21 solar eclipse did not impact Midwestern grid operations, they do say an increase in solar capacity will complicate matters by the next total eclipse in 2024.
MISO Communications Director Jay Hermacinski on Tuesday said the RTO will study eclipse impacts over the next few weeks and request data from CAISO, a grid operator that was “truly” impacted by the eclipse. (See Grid Operators Manage Solar Eclipse.)
MISO’s US footprint outlined in green | GreatAmericanEclipse.com
All of MISO’s footprint fell within the 80 to 100% eclipse band, and Hermacinski said the footprint’s solar generation reacted “as predicted.” Grid-scale solar output dropped 100 MW during the eclipse, plunging to a nearly zero output during the peak and picking back up to about 40 MW around 3 p.m.
| MISO
Hermacinski said that MISO operators had no problem meeting demand with stifled solar output.
“Our portfolio looked like it always does. We did not have to do anything special or bring on additional generation,” he said during an Aug. 22 Informational Forum. “Quite frankly, our operators prepared for the solar eclipse as if it were any other day. … We did not expect the eclipse to have an impact on our grid operations, and it did not.”
However, storms in the Upper Midwest and cooler-than-expected systemwide temperatures that day cut load, and MISO load dropped by 2 GW during the eclipse window.
“What we didn’t expect was the number of pop-up storms in the MISO region that brought about a 5- to 8-degree drop in temperature,” Hermacinski said.
MISO will use CAISO’s data to complement its own to help prepare for the next solar eclipse in April 2024, which will cut a path of totality from southwest Mexico to the northeastern U.S., putting the RTO’s Carmel, Ind., headquarters in the direct path. By that time, MISO is expected to have an additional 13.5 GW of grid-connected solar generation participating in its market, an amount exceeding that participating in the CAISO market today. MISO currently has about 180 MW of utility-scale solar and 350 MW of distributed solar in its footprint.
“MISO will be in a much different position in 2024 in terms of solar capacity than it is today,” Hermacinski said. A partial solar eclipse occurring in October 2023 will serve as a practice run before the 2024 event, he added.
