The projects include new construction, end-of-life replacements and upgrades to address reliability criteria violations and relieve congestion throughout the RTO’s 13-state footprint, which includes D.C. The board approved upgrades in areas served by American Electric Power; American Transmission Systems Inc.; Commonwealth Edison; Dominion Energy; Duke Energy Ohio & Kentucky; East Kentucky Power Cooperative; Pennsylvania Electric; and Public Service Enterprise Group.
“Maintaining the reliability of the grid is paramount and involves continuously reviewing small and large transmission projects,” PJM CEO Andy Ott said in a statement.
The two costliest projects are both in PSEG’s zone: one in northern New Jersey near New York City and one in the southern part of the state near Philadelphia. The northern project will consist of a 69-kV transmission network at an estimated cost of $197 million, while the southern project will consist of another 69-kV estimated at $98 million. Constructing a substation in ComEd’s zone will cost about $90 million.
The approvals also include results from the first proposal window of the 2017 Regional Transmission Expansion Plan, which closed on Aug. 25. PJM had requested proposals to correct 40 reliability violation flowgates identified in a reliability analysis for 2022. The RTO received 51 proposals from 10 entities addressing nine target zones and added five additional “immediate need” baseline upgrades that will be performed by incumbent transmission owners. (See “RTEP Window Results,” PJM PC/TEAC Briefs: Sept. 14, 2017.)
WASHINGTON — FERC on Thursday set a 40-year default term for hydropower licenses, a move it said will reduce administrative costs and encourage dam owners to upgrade capacity and make environmental or recreational investments.
“This is quite a big deal, because we’re changing a policy we’ve had in place for several decades,” said Commissioner Cheryl LaFleur.
The commission’s policy statement (PL17-3), which will apply to original licenses and license renewals, also set conditions under which it will consider terms longer or shorter than 40 years:
If necessary to coordinate license terms for projects located within the same river basin;
When a different term is included in a “generally supported” and “comprehensive” settlement agreement that does not conflict with terms for projects in the same river basin; and
When an applicant requests a longer term based on “significant measures” voluntarily implemented during the prior license term or expected to be required for renewal. The commission has previously found that the construction of pumped storage facilities, fish passage facilities, fish hatcheries, recreation facilities, dams and powerhouses warranted longer license terms.
FERC regulates more than 2,500 dams with 55,800 MW of capacity, more than half of all hydroelectric capacity in the U.S. The Federal Power Act allows the commission to issue original licenses for up to 50 years and renewals for between 30 and 50 years. There is no minimum license term for original licenses.
| FERC
The commission’s policy on renewals had been to set a 30-year term when there is little or no new construction or environmental mitigation required; a 40-year term for projects with a “moderate” amount of such activities; and a 50-year term for projects requiring “an extensive” amount of such activity.
The change resulted from the commission’s November 2016 Notice of Inquiry, which followed licensees’ complaints that the commission should consider longer license terms to recognize settlement agreements, prior investments, relicensing costs and losses in generation value resulting from environmental measures. (See FERC Considers Change to Hydro License Rules.)
The NOI generated more than 40 responses, most of which supported policy changes. Some complained that license applicants lack guidance on what measures will yield longer license terms. Others said that because the commission’s policy is forward-looking, licensees delay seeking approval for capacity upgrades and environmental and recreational enhancements until they apply for a new license.
Some industry commenters complained that the license term cannot be used as a “bargaining chip” in settlement talks because the commission might reject that term; they also said the current policy penalizes well-maintained and low-impact projects that don’t require substantial new investments and thus only receive a 30-year license.
Compromise
The 40-year default represents a compromise between industry stakeholders — who generally supported a 50-year default — and environmental groups and most federal and state resource agencies, who said making the default equal to the FPA’s maximum would eliminate incentives for applicants to agree to mitigation measures.
“The resource agencies also contend that such policy would result in applicants focusing their license application study efforts on disproving project effects rather than on identifying potential mitigation measures,” the commission said.
FERC staff expects more than 300 relicensing requests through 2025, which would have required case-by-case analyses under the current rules.
The commission said the change will provide licensees and other stakeholders with more certainty while reducing administrative burdens. Case-specific assessments will only be required for licensees seeking a term longer than 40 years that is not subject to a settlement agreement.
The new rules will apply to all licenses issued following publication of the policy statement in the Federal Register. Those with pending license applications can file petitions demonstrating why the commission should grant a term longer than 40 years or settlement agreements that include longer terms. “The commission, however, will not entertain applications to amend existing licenses to extend their license terms simply on the basis of this new license term policy,” FERC said.
FERC on Thursday approved ISO-NE’s request not to disclose — even to non-market participants — any proprietary information from certain de-list bids for the RTO’s upcoming 12th Forward Capacity Auction.
The commission’s Oct. 19 order (ER17-2110) accepted the filing of de-list bids and granted the RTO’s request to waive a requirement that parties seeking privileged treatment for certain filings provide intervenors who execute a nondisclosure agreement access to that material.
ISO-NE in July submitted both privileged and public versions of a filing describing the permanent de-list bids and retirement de-list bids submitted for the upcoming FCA 12, to be held in February 2018 for the 2021-22 Capacity Commitment Period.
Pittsfield, Mass generator being scrapped
The RTO reported that it received one permanent delist bid and 23 retirement delist bids from six power suppliers for the upcoming FCA, covering resources located throughout all eight New England zones.
FERC staff in August issued a deficiency letter in response to ISO-NE’s filing of de-list bids, asking that the RTO also submit a form of NDA. The RTO responded two days later with an NDA as well as its waiver request.
The RTO’s auction qualification process requires owners of existing capacity resources that wish to exit their capacity supply obligation to submit delist bids specifying a price below which they do not wish to provide capacity. Such bids submitted ahead of an FCA may be “static” for a one-year exit from the capacity market; “permanent” for a permanent exit from the capacity market; or a “retirement” de-list bid for permanent exit from all ISO-NE markets, including that for energy.
Public Citizen Protest
Public Citizen filed the only protest to the request, contending that lack of access to the privileged components of the filing made it “impossible to determine” whether the permanent de-list bids and retirement de-list bids were just and reasonable.
ISO-NE countered that the privileged information includes “the [de-list] bidders’ expected cash flows, expectations regarding capacity market payments and information regarding opportunity costs … [and] critical aspects of suppliers’ likely bidding strategies … [which], in conjunction with the other confidential information, reveals the prices at which supply would be withdrawn in the auction.”
The grid operator asserted that the privileged portions of its filing contain “highly confidential, market sensitive information” that could “provide market participants who obtain it with an unfair competitive advantage” in future capacity auctions, thus negatively affecting the competitiveness of those auctions. The RTO referred to an earlier FERC order on FCA 8 in which the commission agreed that revealing resource-specific bid data would result in such significant harm to the Forward Capacity Market that it could not be provided to parties even if they signed an NDA.
Public Citizen argued that the FCA 8 order did not apply to its own request because the organization is not a market participant.
“We disagree,” the commission said in its ruling. Although the FCA 8 order referred to market participants, the commission reiterated its finding that harm could not result solely from disclosure to market participants. Rather, “the potential for harm to the FCM and to New England customers from any disclosure of this protected information could be significant.”
In the FCA 8 order, the commission noted that parties had access to a significant amount of publicly available information regarding the auction and therefore did not require ISO-NE to disclose the privileged information.
“We find that the same rationale applies here,” FERC ruled Thursday.
WASHINGTON — Gas supply for New England and Southern California is the top reliability concern for the coming winter, FERC officials said Thursday.
Commission staff said they saw no major risks of significant disruptions this winter but that they would be closely monitoring gas supplies in the Northeast and the area around California’s Aliso Canyon storage facility.
“You’d probably be the market that keeps me up at night,” Commissioner Robert Powelson told ISO-NE Vice President of System Operations Peter Brandien at the commission’s monthly open meeting, where officials of all six FERC-jurisdictional RTOs and ISOs gave their annual presentations on winter preparedness.
Brandien earlier had pronounced himself “cautiously optimistic.”
Bull’s-Eye
“I always feel like I have a bull’s-eye when on me when I come down to talk about these things,” Brandien said, prompting laughter.
While the 2014 polar vortex jolted PJM and others to tighten rules ensuring generators’ reliability, ISO-NE has been dealing with the issue since the 2004 “cold snap,” he said. New England produced 49% of electricity using gas in 2016, up from 15% in 2000.
Since a second scare in winter 2012-13, the RTO has been relying on temporary winter reliability measures that encourage gas operators to have dual-fuel capability and access to LNG. The temporary program will give way to the Pay-for-Performance rules beginning June 1, 2018, that contain stronger capacity market incentives for securing fuel.
Brandien said tight pipeline capacity and limited visibility into LNG shipments remain his region’s concern.
“I think we’re pretty much coordinated-out,” he said when asked if additional gas-electric coordination would help New England. “The problem is we have full pipes.”
Brandien said the additional pipeline capacity provided by Spectra Energy’s Algonquin Incremental Market project in January has been offset by the retirement of the 1,500-MW coal-fired Brayton Point Power Station at the end of May.
“I actually was encouraged when I saw that some of the [gas] future prices for New England were higher than other places because those are the kind of things that are going to incent some contracts or some arrangements to be made to get [LNG] ships moving to New England,” he said.
Gas availability also could be a concern for New York City, which gets 95% of its generating capacity from gas or dual-fuel plants, said Wes Yeomans, NYISO’s vice president for operations.
The ISO’s 90-10 base case for the winter shows a statewide capacity margin of more than 11,000 MW, but that drops to 7,000 MW if generators receive only firm gas supplies and less than 4,300 MW if all gas is lost.
CAISO
The reduced capacity of the Aliso Canyon gas storage facility following the 2015 leak also was the subject of concern.
Sixty-two of the facility’s 114 wells were taken out of permanent operation. As a result, FERC staff said, the Southern California Gas system has 65 Bcf in storage, the lowest on record for this time of year since at least 2001 and far below its five-year average of 118 Bcf.
Although there were no supply interruptions this summer, staff said, Aliso Canyon’s limited storage “could challenge regional stability and increase natural gas and electricity prices” this winter. “The recent outages of SoCalGas Line 235-2 and Line 3000 may also limit flexibility in the region. This risk could also be magnified by upstream pipeline issues, like further outages or wellhead freeze-offs.”
Nancy Traweek, CAISO’s executive director of system operations, said California’s wildfires are not currently a threat to transmission but are having an impact on distribution.
One subject that was not raised as a reliability concern by the RTO officials who spoke to FERC was fuel diversity and the continued retirement of coal generation — an issue cited by Energy Secretary Rick Perry in his call for price supports for coal and nuclear plants. FERC Chairman Neil Chatterjee on Oct. 13 praised Perry for raising the issue. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)
In a press conference after the meeting, Chatterjee said the RTO officials were only some of those whose views will be considered by the commission in the Notice of Proposed Rulemaking (RM18-1).
“We will find out from a variety of stakeholders whether there are conditions today or in the future that we need to consider,” he said. “Perhaps the fuel mix is working for them today. As market conditions continue to change, we don’t know what the future will hold. As some of these assets are retired, that will change the fuel mix.
“We need to be constantly vigilant and monitor the grid, monitor market changes, to ensure that this winter and beyond we don’t have circumstances that could lead to catastrophic outcomes.”
Chatterjee said he was withholding judgment on whether high penetrations of wind pose a reliability concern.
Bruce Rew, SPP’s vice president of operations, said the RTO was forecasting a new wind penetration record of 66% Friday. Thanks to accurate forecasting, Rew said, the RTO has already handled penetration of 55% wind and wind output swings of 10,000 MW within a day “without any problems.” The region has added 3,000 MW of wind capacity since last winter.
[As it turned out, wind peaked at 13,039 MW in SPP Friday, short of the 13,342 MW record set Feb. 9.]
“We’re going to make a fact-based determination based on what the record reflects,” Chatterjee said. “I certainly respect the gentleman’s opinions, and I will defer to his expertise as well as others to make that assessment.”
Comments on the rulemaking are due Oct. 23.
On Thursday, a bipartisan group of eight former FERC commissioners — including former Chairmen Elizabeth Anne (Betsy) Moler, James J. Hoecker, Pat Wood III, Joseph T. Kelliher and Jon Wellinghoff — filed joint comments saying that Perry’s proposal would be “a significant step backward from the commission’s long and bipartisan evolution to transparent, open, competitive wholesale markets.”
“The commission’s adoption of the published proposal would instead disrupt decades of substantial investment made in the modern electric power system, raise costs for customers and do so in a manner directly counter to the commission’s long experience,” they said.
So big that, even before it made landfall in Texas on Aug. 25, the National Weather Service was warning via Twitter that it was “unprecedented.”
“All impacts are unknown and beyond anything experienced,” NWS said. “Follow orders from officials to ensure safety.”
| CenterPoint Energy
“If you follow the National Weather Service … on Twitter, there’s not usually a lot of hyperbole,” ERCOT CEO Bill Magness observed. “This one, you could tell, was like nothing they’d ever seen.”
There was no shortage of superlatives Tuesday as AEP Texas and CenterPoint Energy executives briefed ERCOT board members on the impact of the massive storm and their recovery from it.
| AEP Texas
The largest rain event in U.S. history dumped an estimated 40 to 60 inches of water in southeast Texas and southwest Louisiana — so much that the NWS had to add more colors to their maps to display the totals, Magness said.
Harvey made landfall at Rockport, Texas, as a Category 4 hurricane with winds of 130 mph on the evening of Aug. 25. The following day, it stalled over the state, picking up more moisture from the Gulf of Mexico before making a final landfall in Louisiana on Aug. 30.
While that meant unprecedented flooding, “from a transmission system perspective, the fact that it stopped was a good thing because … it was pretty much tearing up the transmission system that it passed through,” said Dan Woodfin, ERCOT’s senior director of system operations.
“When the storm was first coming onshore in the late hours of the 25th, we were having upwards of 20 … transmission elements tripping off each hour,” Woodfin continued.
“Our folks were running … N-1-1 studies — so, not just what it takes to be secure, but what it takes to be secure if the next line goes out. … Almost as soon as they finished the study, that line would trip and then we’d have to redo it for the next N-1-1.”
The ISO lost 12,000 MW of generation as gas-fired plants were evacuated or flooded and coal plants were derated as they switched to gas, their coal piles too sodden to burn. Wind turbines were shut down until the winds fell below their maximum operating speed. Other generators that could have run were unable to because they had no transmission.
Luckily, cooler weather meant that loads were as much as 25,000 MW lower than the week before.
The wind was the biggest problem for AEP Texas’ territory along the Gulf Coast, company President Judy Talavera told the ERCOT board. The utility, which had 220,000 customer meter outages at its peak, had to replace or repair 766 transmission structures and more than 5,700 distribution poles. Four million feet, or about 757 miles, of transmission and distribution conductor was replaced.
| AEP Texas
About 5,600 people, many from other utilities, helped the company restore 96% of outages within two weeks. “We drill for these types of events but those don’t quite prepare you for the actual event,” Talavera said.
For CenterPoint, which serves the Houston area, rain and lightning was the bigger challenge than wind, said Kenny Mercado, the company’s senior vice president of electric operations. The company recorded 42,000 lightning strikes. There were 150 tornado warnings in Houston, with more than 30 twisters touching down. The warnings created “a tremendous amount of anxiety” for residents, he said.
| CenterPoint Energy
Seventeen substations were impacted; half of them knocked out of service, the other half inaccessible because of the flooding of the San Jacinto River, the Buffalo Bayou and other waterways.
The unrelenting rain limited the utility’s ability to restore service. In 2008, by contrast, “[Hurricane] Ike moved through the city and then we could go to work,” Mercado said.
Only 200,000 metered customers were out of service at any time. “But the problem was every day we’d get another 200,000. And the next day we’d get another 200,000, and the next day. So, it never ended until eventually we saw blue skies,” Mercado recalled.
Helped by Hardening, Technology
The good news, utility officials said, was that flood protections and technology added in recent years limited damage or increased the speed of the recovery.
A flood wall built after 2001’s Tropical Storm Allison protected the Grant substation, which serves the Texas Medical Center in Houston, the world’s largest medical complex.
A 50-MVA mobile substation installed on a church’s grounds allowed the company to restore power for 10,000 customers after 10 days. “They would have been out for probably another five days without it,” Mercado said. “So, the mobile substation technology that we have today is very, very valuable in terms of resiliency of the grid.”
Hundreds of intelligent grid devices saved 140,000 customer outages and provided critical situational awareness for restoration. Smart meters allowed the company to bill 700,000 accounts with actual readings and execute 45,000 orders remotely during the storm.
The companies resorted to drones to survey damage, airboats and amphibious vehicles to reach flooded substations and helicopters to move new transmission poles.
| AEP Texas
When standing water became a health hazard to workers, AEP outfitted their workers with mosquito nets to wear over their hardhats.
One technology that was not so successful for CenterPoint was its Tiger Dam, water-filled balloons that can function like sandbags but are quicker to deploy. “Didn’t have so much luck with it in Round 1,” Mercado said. “But it’s a skill set. We’re going to have to learn a little bit better how to do something in real time in terms of planning and preparation to look at those kinds of solutions.”
The company also plans to raise substation equipment to make it less susceptible to flooding.
Automated Calls, Facebook
| AEP Texas
The utilities also made use of newer means of communicating with their customers, including Twitter and Facebook.
Although 1.2 million CenterPoint customers lost service, “we only had 175,000 customers call … letting us know the power was out. … Only 67,000 customers used a live agent,” Mercado said. “So, the world’s changing. We’re seeing more and more automation take care of customers’ needs. Our power alert service technology pushed [text messages] out to 350,000 customers.”
CenterPoint’s website saw six times as much traffic as normal.
AEP Texas saw its Facebook followers more than double as the company made about 100 informational postings.
Public Support
Talavera said she was touched by the customers’ expressions of thanks to the restoration workers.
Residents offered workers meals, water and Gatorade, “wanting to show how much they appreciated them,” she said. “It’s really humbling. We know we provide an essential service and we’re proud of the efforts that were undertaken to restore service to our communities. But it’s certainly a partnership in working together with them.”
ERCOT will face higher prices and lower capacity margins following Vistra Energy’s retirement of 4,100 MW of coal-fired generation, Independent Market Monitor Beth Garza told the ISO’s Board of Directors on Tuesday.
Assuming ERCOT’s analysis of the pending retirements doesn’t identify local reliability concerns that would result in reliability-must-run contracts for any of the units, Garza said, “We’re looking at a much different situation going into the summer of 2018 than the fat and happy times … of the last couple of years.
“We’ve had really two years of clearly unsustainably low prices with high reserve margins,” she continued. “I think I’ve been saying it in those terms for the last couple of years, and I think we’re now seeing evidence of that unsustainability.”
Since Oct. 6, Vistra Energy’s Luminant unit has announced retirements of the two-unit Big Brown generator north of Houston (1,150 MW); the two-unit Sandow, northeast of Austin (1,137 MW); and its three-unit Monticello plant in East Texas (1,800 MW). The retirements will leave the company with just two coal plants totaling 3,850 MW. (See Vistra Energy to Close 2 More Coal Plants.)
In addition, the Texas Municipal Power Agency announced in July that it will put its 470-MW Gibbons Creek unit in seasonal mothball status, operating only from June through September.
| Potomac Economics
Garza said the announcements were no surprise given that coal units’ fuel costs have been consistently above combined cycle gas units since the beginning of 2015 and coal units were likely unprofitable in 2016.
Although the trends have been clear for some time, Garza said the timing of the Luminant announcements forced her to revise her presentation to the board.
Her presentation showed a 15% reserve margin for 2018. But that could fall to 12% because of the new retirements, she said. She cautioned that her data did not reflect changes in the interconnection queue since ERCOT’s last Capacity, Demand and Reserves report in May.
| Potomac Economics
“It seems to me like the market’s working and folks are responding to appropriate market incentives,” said Director Peter Cramton. “And now it’s time for us to let the market work.”
“I would echo that,” Garza responded. “Generators have a fairly low barrier to entry to the market. Along with that, I think it’s important to have an easy exit as well.”
“You’ve been rubbing the dark side of your crystal ball here pretty good,” Director Karl Pfirrmann pressed Garza. “Now let’s start rubbing the other side a little bit. Tell me, what is it in our marketplace that’s going to correct this problem?”
Garza said the retirements are likely to push forward prices higher, creating pressure for load-serving entities. “If I were a load-serving entity, I would be a little more anxious about the surety of supply going into the forward years than I am right now,” she said. “So, you might see contracting opportunities for new generators that haven’t been there in the past.
“I’m hopeful … that we won’t try to keep units in the market longer than they would like to be there,” she continued. “We just have to be comfortable with what that means — likely higher, more volatile prices going forward than what we’ve experienced in the last couple of years.”
Cramton, an economist at the University of Maryland, agreed. “If we let the market work, it will be a higher forward price — and especially the forward prices many years out. There’ll be pressure on the demand side.”
But he said he feared the transition could be interrupted by “regulatory uncertainty around large subsidies for keeping guys in the market that shouldn’t be there.” It was an apparent reference to Energy Secretary Rick Perry’s call for price supports for coal and nuclear units, although his proposal is limited to FERC-jurisdictional RTOs and ISOs.
“That’s what’s going to damage the market,” Cramton added. “So, I would urge everyone to tell their congressmen to stop that.”
Speaking Tuesday at the Energy Bar Association’s midyear conference, the former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) tallied off six objectives for revising FERC’s regulatory posture.
They ranged from streamlining project review for natural-gas and hydropower projects, to determining a “just and reasonable” return on equity for transmission projects; from changing FERC’s interpretation of de novo review and revising the Public Utility Regulatory Policies Act, to addressing cyber threats. Chatterjee said he also wants to ensure the industry doesn’t outrun itself with technology advancements.
Reliability
But although it was buried deep in his speech, his timeliest goal appears to be maintaining grid reliability “during a time of rapid change,” which comes in light of the Department of Energy’s recent Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants.
Chatterjee has already said he supports investigating the issue. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.) On Tuesday, he suggested that those baseload resources may be needed to avoid changing the generation fleet too much, too quickly.
“Reliability is and will continue to be our foremost priority,” he said, listing off several of FERC’s responsibilities related to reliability. “In my view, the DOE NOPR fits comfortably within those efforts. … We must ensure we don’t find ourselves coming to regret not having asked hard questions like these amongst all the changes in the energy industry.”
He also said that news of attempts by Russia and North Korea to hack the grid highlight other reliability needs.
“It’s clear that defending our nation from international cyber threats is one of the most serious challenges of our time,” he said.
Streamlining Review
Chatterjee also voiced support for streamlining the review process for natural gas pipeline and hydropower projects.
“The FERC review process continues to get longer and longer, due in large part to increased participation in the process by stakeholders, including numerous legal challenges,” he said. “FERC owes both sides an opportunity … to receive a timely up-or-down decision.”
Chatterjee dismissed suggestions that FERC depart from its “longstanding” reliance on customer agreements to gauge the economic need for a project “in favor of weighing a broad range of economic, social and aesthetic values.” Gas subscriptions on pipelines are “clear, unequivocal statements of economic need by the market itself.” (See FERC Chair: Court Ruling Won’t Change Pipeline Reviews.)
He blamed project delays on incomplete applications, negotiations with federal and state agencies and the “sheer number” of comments, saying “FERC is most definitely not the principle source of those delays.” He urged applicants to use FERC’s prefiling process and said he hopes to “pursue understandings that can be reached on an agency-to-agency basis” to improve response time. There is no way to speed up comments or responding to them thoughtfully, he said.
Additional Issues
With the generation fleet changing and transmission constraints raising prices, consumers stand to benefit from developing additional transmission infrastructure, Chatterjee said. The “most critical near-term piece” is finding the right financial incentives for enticing project investment, which will involve determining “what represents a just and reasonable return on equity for transmission projects.”
Courts have rejected FERC’s interpretation of its de novo review authority five times, he said, so the commission must develop a “proper scope” that is “fair and legally defensible.” FERC has been chastised by Congress in the past for not properly handling enforcement cases. (See FERC Enforcement Process Under Fire in House Hearing.)
Finally, Chatterjee indicated he plans to address FERC’s implementation of PURPA, specifically the “1-mile rule” for qualifying facilities. FERC has ruled that QFs located within 1 mile of each other are considered to be “located at the same site” and that wind farms of 20 MW or larger within ISO/RTO regions are presumed to have access to competitive markets and thus ineligible for PURPA’s must-purchase obligation on incumbent utilities. However, stakeholders have complained that QF developers are circumventing the 20-MW cap by creating separate corporate entities for individual turbines or small groups of turbines, or disaggregating large projects by siting turbines more than 1 mile apart. (See Witnesses Offer Alternate Realities on Need for PURPA Reform.)
RENO, Nev. — Energy storage can provide many benefits to the Western electricity grid, but it will require complex and costly modeling to be integrated properly, a panel of regional energy experts said this week.
The power industry, and its regulators, will require a long-term effort to accurately analyze the benefits and costs of storage, the panel of utility representatives and others said during an Oct. 17 joint meeting of the Committee on Regional Electric Power Cooperation (CREPC) and the Western Interconnection Regional Advisory Body.
Sector participants must study what ancillary services and sub-hourly and locational benefits storage resources can offer along with the range of other uses being explored for the technology.
Fully modeling the impact of energy storage across the existing utility system “is going to be a very difficult nut to crack” and a big computational problem, said Elaine Hart, a Portland General Electric power analyst.
Oregon-based PGE has been using software tools to model storage, Hart said, utilizing a production cost model for its integrated resource plan (IRP) that simulates the electricity system and dispatch over 20 years and 30 different potential future scenarios based on gas prices, resource output, energy prices and other factors. The effort requires significant computing power and lengthy running of software programs to model possible outcomes.
“We are really lucky that we had this tool when we started evaluating energy storage,” Hart said. To reduce computational time, timelines for modeling could be expanded to every few years instead of every year, for example, and other adjustments could be made, she noted.
Getting it Right
The Washington Utilities and Transportation Commission is working to help that state’s investor-owned utilities integrate energy storage into their IRPs, commission energy adviser Jeremy Twitchell said. The regulator has directed utilities to improve their analysis of energy storage options, an initiative launched after it observed activities at FERC and in California, New York and around the country.
“The key takeaway as we looked around was there were niche storage applications at the time: There were cost-effective applications in a limited scope,” he said. The commission knew utilities needed to be more flexible and that technology costs were dropping, but its modeling capabilities were inadequate.
The commission felt that if it got the modeling right, utilities would integrate the technology in a cost-effective way, Twitchell said. It held workshops to identify challenges, bringing in national laboratories to provide modeling advice and finding that storage can perform well as frequency support and fast response. He also said storage should also be studied for its impact on the transmission and distribution grid, and not just as an IRP resource.
The UTC earlier this month issued a policy statement saying that the absence of an organized market in the West is creating many of the challenges of integrating energy storage, but Twitchell said that perspective is changing because regulated utilities can still capture the benefits of storage without relying on wholesale market outcomes.
FERC in January issued its own storage policy statement “to provide guidance regarding electric storage resources seeking to receive cost-based rate recovery for certain services while also receiving market-based revenues for providing market-based rate services.” According to FERC, the main issues around integrating storage relate to protecting cost-based ratepayers from the potential for double-recovery of costs, preventing adverse market impacts, and maintaining RTO and ISO independence from market participants.
Commissioner Cheryl LaFleur dissented against the policy statement, which was approved by former Chairman Norman Bay and former Commissioner Colette Honorable, saying she disagreed that the issue should be split off from a Notice of Proposed Rulemaking that FERC issued in November 2016.
Travis Kavulla, CREPC co-chair and Montana Public Utilities Commissioner, asked the panel how more “price discovery” could be incorporated into the modeling process. He said that storage has generally been implemented in two ways: as a “mandate backed up with technocratic guess-work shoved into the rate base,” or with ISOs designing products that let batteries compete in markets.
Tucson Electric Power’s Lee Alter said that IRPs covering all resources could discover pricing and compare different technologies, and that studying storage “jibes really well with the IRP process.” He said his utility is beginning to model energy storage, including sub-hour modeling that serves to study not just integration of batteries, but other impacts from the Western Energy Imbalance Market, pumped storage and other resources.
The discussion made clear that modeling the impacts of energy storage, identifying the benefits and turning energy storage services into a consistent revenue stream will be an ongoing challenge for utilities, regulators and other stakeholders.
While stakeholders are still deciding what topics MISO’s Energy Storage Task Force must take on to prepare the RTO for integrating a revolutionary technology, they must also recognize which are off-limits in order to avoid intruding on state jurisdiction.
The new task force has been charged with creating a list of detailed storage issues to be assigned to other MISO stakeholder groups. The RTO in August already floated its suggestions on how to dole out the work. (See Progress Builds for MISO Energy Storage Effort.)
Invenergy’s 31.5 MW Grand Ridge Energy Storage project | BYD
Invenergy’s John Fernandes, the task force’s chair, doesn’t want his group to simply provide MISO’s Steering Committee “a laundry list of issues and wish them luck.” That committee is responsible for assigning specific storage-related issues to other stakeholder committees.
“I don’t want to leave things open-ended,” Fernandes said during the group’s first conference call Oct. 16.
He said the task force should identify in what ways existing market rules might impede participation by storage resources, while also providing the committee with a recommended course of action. That would include helping to determine how to assign issues across committees and identifying which parts of the Tariff require revision.
Clarity from Complexity
The task force’s draft charter stipulates that the group consult storage experts to sort out issues that arise from market integration “that may introduce complexity to the footprint.”
MISO liaison Joe Gardner said the RTO’s goal for the task force is to identify possible near- and long-term changes and additions to market rules.
“Getting as much clarity and consensus now will behoove us in the long run … for planning, reliability and markets,” Gardner said. MISO has set aside funding to conduct storage-specific planning studies, he added.
However, stakeholders attending the task force meetings are at odds over the specifics of discussions.
Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that the task force should not interfere with state jurisdiction, saying stakeholders can explore whether MISO should create potential market products if states decide to allow aggregators to offer storage, but they should steer clear of deciding rules for interconnection.
“We have to have a discussion about what we can do within the law,” Ham said.
“I have no interest in treading on state jurisdiction,” Fernandes said, adding that the group will also steer clear of retail tariffs and distribution rules. “But the industry is going to force our hand,” he warned, predicting a future influx of storage participation that will require market rules.
Generation or Transmission?
Indianapolis Power and Light’s Lin Franks said the task force should be clear that it will not consider storage as it pertains to transmission planning, instead focusing on how to get it unfettered access to the wholesale market.
Fernandes responded that the group should not limit its consideration of possible storage benefits. “Storage as transmission is a very viable business model,” he said.
“Storage is not wires. It’s a substitute,” Franks countered.
Fernandes said storage-owning stakeholders have “been having the discussion with MISO on storage acting as wires” and the group should consider all storage, whether it functions as a generation or transmission asset.
“Storage as a transmission asset should be on the table … and very much front and center in MISO because it’s envisioned by FERC,” American Transmission Co.’s Bob McKee said. “FERC has already said storage should be recognized as transmission.”
MISO stakeholders also debated whether the group should only tackle grid-scale storage issues, leaving distributed energy resources unaffected. Fernandes said he had concerns with ignoring DER “considering it’s a grid-scale storage developer that signs my checks.”
The task force will meet again in late November to finalize a charter and agree on topics, while most of its substantive work will occur next year. Stakeholders will weigh in on the group’s draft charter through Nov. 3. The task force is slated to meet through the end of 2018, when stakeholders will determine whether the group will be retired or extended.
NRG Energy on Monday asked the California Energy Commission to suspend its review of a proposed 262-MW gas-fired plant in Oxnard, likely closing the book on a project that met with stiff resistance from community and environmental groups.
The company’s request came after Commissioners Janea Scott and Karen Douglas earlier this month issued what they acknowledged was an “unusual” notice recommending denial of the Puente Power Project. They wrote that it would be “inconsistent with several laws, ordinances, regulations or standards and will create significant unmitigable environmental effects.” (See CEC Members Recommend No-Go for Puente Plant.) The commission is responsible for issuing construction and operating permits for new generating plants.
Scott and Douglas, who together constituted the committee preparing the commission’s decision on Puente, said they made their recommendation so early in the process because they saw a need to study alternatives to the plant after CAISO filed comments contending that the economic feasibility of preferred — or non-emitting — resources could only be established through a new request for offers. While Southern California Edison selected Puente through a standard procurement process, CAISO pointed out that costs for preferred resources have since declined enough to warrant a new RFO. The ISO also noted that cost should not be the only factor driving the decision.
“An economically feasible option need not be the least expensive option, especially given the environmental and performance issues that are unique to each portfolio,” the ISO said.
The commission also received hundreds of comments opposing construction of the plant.
In its Oct. 16 filing with the commission, NRG said it is still considering whether to fully withdraw its application for certification (AFC) for Puente.
“Granting this motion [to suspend the proceedings] will ensure effective use of resources of the committee and the parties to these proceedings in the event that the applicant determines to withdraw the AFC,” NRG said.
The Puente plant would have been built on the site of the Mandalay Generating Station in Oxnard (shown), where NRG plans to shut down two existing steam turbine units to comply with California’s once-through cooling restrictions. | NRG
The company proposed to build the plant on the site of its Mandalay Generating Station, where it will shut down two existing gas-fired steam turbine units that don’t comply with California’s upcoming regulations restricting once-through cooling. About 2,000 MW of generation in the area is due to retire by 2020 because of the regulations.
The fast-ramping Puente plant would have been capable of reaching more than 95% of its capacity within 10 minutes, helping to integrate renewable resources and ensure reliability in the state’s Ventura/Moorpark subarea, a load pocket that imports much of its electricity through a single substation, the company has said.
The California Public Utilities Commission has already authorized SCE to enter into a long-term resource adequacy contract with the plant, which was slated to begin operating in 2020.
