SAN DIEGO — The electricity sector continues to identify possible applications for energy storage while costs for the technology steadily decline, but the lack of cohesive federal, state and local policy remains the chief obstacle to integration, a panel of experts said Wednesday.
“The technology piece has caught up. What we cannot afford to do is let the policy drag it down,” Kiran Kumaraswamy of AES Energy Storage said during a panel discussion at the Infocast Transmission Summit West. Industry and policymakers can develop a framework for adopting storage once they determine the magnitude and type of need for the technology, he said.
Storage has not traditionally been seen as a workable solution to solving locational reliability needs on the transmission grid, and there are questions as to whether it should be regulated as a generation or transmission/distribution asset. The U.S., especially CAISO, is in a leadership position as far as deploying storage, “but the rest of the world is catching up,” Kumaraswamy said.
Storage can also defer transmission investment, and “the ISO has been very progressive in considering non-wires alternatives,” he said.
CAISO recently launched a yearslong effort to develop a load-shifting product for energy storage, the third phase of its Energy Storage and Distributed Energy Resources (ESDER) initiative. (See CAISO Load-Shifting Product to Target Energy Storage.)
Even in situations in which conventional generation would be much cheaper, California regulatory policy and public opinion are driving storage applications. After CAISO recently performed a study finding that the $299 million proposed Puente Power Project is the cheapest alternative to energy storage and distributed energy solutions costing up to $1.2 billion, the California Energy Commission still indicated that it might not approve the plant. (See CEC Members Recommend No-Go for Puente Plant.)
There is “a very good working relationship between renewables and energy storage,” according to Tom Dagenais of Duke-American Transmission Co., a joint venture between Duke Energy and American Transmission Co. created to develop new transmission projects — such as the Zephyr line to carry wind energy from Wyoming to California, and the San Luis transmission project in California’s Central Valley.
Dagenais cautioned that integrating energy storage is a challenge, and that the decisions being made today as the technology enters the market will set the tone for how it is perceived in the future.
“If we screw this up, there is going to be a lot of fingers pointed and a lot of questions,” he said.
FERC last November issued a Notice of Proposed Rulemaking that would require each RTO and ISO to recognize the physical and operational characteristics of storage, and accommodate storage and aggregated distributed resources in organized markets. (See FERC Rule Would Boost Energy Storage, DER.)
Harding Street Energy Storage | AES
But the agency lost its quorum shortly after the proposed rule was issued, and it is unclear whether the new commission will act on it. It is also unknown how FERC will view storage as the commission becomes embroiled in controversy over Energy Secretary Rick Perry’s new proposed rule designed to bolster coal-fired generation.
Idaho Public Commissioner Kristine Raper asked the panel how a state like hers, which is long on capacity and has an abundance of hydroelectric generation, could take advantage of energy storage.
Jin Noh of the California Energy Storage Alliance noted that California has sufficient capacity but is still pursuing energy storage. “It is a question of what type of capacity,” Noh said. “There is a major need for flexibility capacity and opportunities to save ratepayer money.”
Dagenais said: “Idaho is in a pretty unique situation,” adding that many other states have a rapidly changing resource mix. He said that storage is still something worth looking into to cut costs and reduce use of lower-efficiency generation units at peak times.
FERC on Wednesday granted MISO a six-month reprieve from a Tariff provision requiring it to include minimum zonal reserve requirements in its modeling of broader system reserve requirements.
The RTO currently calculates minimum reserve requirements using offline studies conducted three days in advance of a day-ahead market run, but it has said that study results aren’t always accurate because actual operating conditions, including transmission constraints, can deviate from original study assumptions.
A case in point: In early April, scarcity pricing was triggered in MISO because an offline study predicted an 84-MW minimum contingency reserve for Zone 6 covering Indiana and a slice of Kentucky, but it failed to account for actual transmission and generation outages modeled in the day-ahead process. Generation and transmission outages in MISO caused an outflow of energy from Zone 6, creating scarcity conditions for reserves and sending prices as high as $1,100/MWh.
In mid-July, MISO said it was evaluating changing the algorithm behind its minimum reserve requirement to reflect energy flow constraints. (See MISO Ponders Reserve Scheduling Fix.)
In its filing, the RTO told FERC it needed a waiver of “inflexible” offline studies while it holds stakeholder meetings exploring an additional modeling step to account for constraints and prepares a Tariff filing. It also noted that it could decide to permanently remove offline studies from the process.
MISO filed for the waiver last month, and the commission acted quickly given that the RTO has entered its shoulder season typified by planned outages (ER17-2466).
“MISO requests expeditious action on this waiver request because the conditions that could potentially lead offline studies to set minimum reserve requirements have previously occurred in the months of October and November,” FERC said.
The waiver remains in effect until April 12, 2018.
FERC allowed the waiver on the grounds that it will remedy current reserve price distortions through “ineffective constraint relief when minimum reserve requirements do not properly reflect real-time non-deliverability of reserves” and “protect the markets from price signals that do not properly reflect or resolve real-time reserve deliverability issues.”
WASHINGTON — Energy Secretary Rick Perry on Thursday defended his call for price supports for struggling coal and nuclear plants, telling the House Energy Subcommittee “these resources must be revived, not reviled.”
Perry also pushed back on criticism that his Notice of Proposed Rulemaking, which called for “full recovery” of the plants’ costs, would undermine competitive markets.
Republicans largely expressed support for the rule. But Perry did little to counter allegations that his action was motivated by President Trump’s campaign promises to help the coal industry — repeatedly sidestepping Democrats’ questions about the costs of his proposal and the evidence supporting the need for 90 days of on-site fuel. He also contradicted himself on whether the NOPR was a command to FERC or an invitation to “start a conversation.”
“The base reason that we asked for this … is that, for years, this has been kicked down the road,” Perry said of the NOPR, published in the Federal Register on Tuesday.
The proposal would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and real-time energy markets to ensure full cost recovery for any generation that is capable of providing “essential energy and ancillary services” and has a 90-day fuel supply on site “enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.” Units subject to cost-of-service rate regulation would be excluded.
Essential services include voltage support, frequency services, operating reserves and reactive power. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.
Rep. Bobby Rush (D-Ill.), ranking member of the subcommittee, asked how Perry reached the conclusions in the NOPR, given that FERC and NERC have said that the grid is reliable. In an apparent reference to the NOPR, FERC Commissioner Robert Powelson promised in an Oct. 4 speech “not to destroy” the markets, leading Commissioner Cheryl LaFleur to tweet, “Great message!”
“I respect the FERC members’ views,” Perry said. “I think their picture is one that is a snapshot in time. … What I think one of my roles is is to think outside of the box.”
The grid is normally resilient during “blue sky” days, he said, and his support for an “all of the above” generation mix was proven during his time overseeing wind growth as governor of Texas. “But the wind does not always blow. The sun doesn’t always shine. The gas pipelines — they can’t guarantee every day that that supply is going to be there.”
“It seems to me what you’re saying is, ‘Well my gut feeling has more of a priority … rather than what these experts have said,’” Rush responded.
While no Republican on the subcommittee criticized the proposal — and many offered their support and praise for Perry — party leadership did not tip its hand.
“While I reserve judgment on the policy solutions, the fact that the secretary stepped in to this complicated debate reflects the current need to have a broader conversation about the functioning of the nation’s electricity markets,” subcommittee Chair Fred Upton (R-Mich.) said in his opening statement.
Rep. Greg Walden (R-Ore.), chair of the full Energy and Commerce Committee, made no mention of the NOPR in his opening remarks, instead focusing on the Department of Energy’s budget.
Countering Subsidies
Perry said he was attempting to counter subsidies that have benefited renewables at the expense of coal and nuclear. “There is no such thing as a free market in the energy industry,” he said multiple times. “Government’s picking winners and losers every day by regulations … and I’m at least honest enough to say it.” He pointed to state utility commissions, policies such as renewable portfolio standards, and Texas’ own Competitive Retail Energy Zones as evidence.
Rep. Gene Green (D-Texas) pushed back on this, pointing to the retail choice offered in his state and the uncoupling of generators from utilities.
“Gene, you know me, I’m all about that competition,” Perry said. “That’s what we did … we deregulated that market and that competition came. But the idea is, we had an administration before that had their thumb on the scale. I think you’ll agree, [former President Barack Obama] liked green energy, and that’s where the subsidization came.”
Rep. Paul Tonko (D-N.Y.) pointed out that the production and investment tax credits for solar and wind resources, respectively, were passed by a Republican-controlled Congress.
Not Supported by DOE Study
Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said the NOPR was not supported by the grid study the department released in August. He asked Perry what analyses the department or its national labs had done to support the proposal.
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Perry did not respond to the question, instead challenging Pallone’s premise. The grid study, he said, didn’t address “with specificity the events I’m concerned about,” he said, citing the 2014 polar vortex. In fact, the report had about 17 references to “extreme weather” or the polar vortex. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Perry also sparred with Rep. Michael Doyle (D-Pa.), who said the committee had held eight hearings on markets and reliability. “We’ve actually been having the conversation you claimed to be starting,” he said.
“This has been discussed for a long time, as you rightfully said,” Perry conceded. But he said it was now time for action.
“Our RTO made that adjustment” after the polar vortex, Doyle said, referring to PJM’s Capacity Performance rules, which increased the penalties and bonuses for capacity resources during grid emergencies. “We feel pretty confident with our capacity in Pennsylvania.”
“‘Pretty confident’ is not going to get it [done],” Perry shot back.
Tonko asked if Perry considered consumer costs in developing the NOPR.
“What’s the cost of freedom?” Perry responded. “What does it cost to build a system that keeps America free? I’m not sure I want to put that straight out onto the free market.”
Directive or Conversation?
Perry said the NOPR was intended to “kick-start a national discussion about resiliency and about the reliability of the grid.” Noting the vociferous opposition his proposal provoked, he chuckled, “And best I can tell, we were pretty successful in doing that. … We’re having this conversation now that we really haven’t had in this country.” (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Indeed, at least 50 companies, regulatory agencies and trade groups have intervened or made comments in the docket FERC opened to respond to the NOPR (RM18-1).
Doyle pressed Perry on discrepancies between the NOPR, which repeatedly says FERC “must” act, and the secretary’s repeated references to starting a “conversation.”
“Is it a directive to FERC to do this or a conversation?” Doyle asked.
“Both,” Perry said.
“So, it’s a directive then?” Doyle asked.
“My words are what my words are. I don’t back off from them,” Perry said.
“It can’t be both,” Doyle protested. “So, which one is it?”
“Well actually it is both. It can be both. We can have a conversation and I think [FERC] must move. I think they must act. We’ve kicked this can down the road as long as we need to.”
Perry seemed to acknowledge multiple times that FERC would not be obligated to follow such a directive. Legal experts have said that Perry has no power to make FERC, an independent agency, provide the relief he is seeking. (See FERC’s Independence to be Tested by DOE NOPR.)
Rep. David McKinley (R-W.Va.), who said he was “100% behind” the NOPR, asked if “FERC were to follow through with your missive, don’t you think we’d have a better outcome” than what happened during the polar vortex?
“Well I do, but I mean, that’s why we’re having this conversation here,” Perry answered, saying he wanted to hear from both sides of the issue.
Rep. Kathy Castor (D-Fla.) also said the NOPR conflicted with the findings of the grid study and said it would cost consumers and businesses billions. “There is just no rational basis for this new FERC rule that you’re trying to move through as quickly as possible,” she said.
“If the request … the NOPR to FERC is what you say it is, [FERC] won’t go forward with it,” Perry responded.
When asked by Doyle if he had considered any better alternatives to the NOPR, Perry answered, “I don’t have any idea whether there are any better options. That’s one of the reasons we wanted to have this conversation is to bring those up and discuss them.
“I’m not saying that my letter to FERC is the be-all-end-all, but it’s obviously been very successful in getting the conversation going.”
CARMEL, Ind. — MISO will make two points in its comments to FERC in response to Energy Secretary Rick Perry’s proposal to allow “resilient” resources with a 90-day on-site supply of fuel to fully recover their costs. (See Perry Orders FERC Rescue of Nukes, Coal.)
The first point, according to Executive Director of Strategy Shawn McFarlane: The commission’s response to the Department of Energy’s Notice of Proposed Rulemaking should respect MISO’s existing reliability process that incorporates state rules.
The second: Any monetary value placed on resiliency must be supported by research.
“MISO and MISO states have a well-established process to address reliability and resource needs … and any approach needs to respect those regional processes, and even those regional differences,” McFarlane said at an Oct. 11 Resource Adequacy Subcommittee meeting.
He also noted that “MISO supports a thorough and complete process” for detailing reliability and resiliency attributes, and will urge a well-researched approach.
McFarlane said the 21-day public comment period didn’t provide enough time to collect stakeholder comments and summarize them in MISO’s comments, and he urged stakeholders to make individual filings.
MISO Executive Director of System Operations Renuka Chatterjee echoed McFarlane’s comments a day later at an Oct. 12 Market Subcommittee meeting.
“MISO and the states have well-established processes and initiatives in place to protect reliability,” she said.
MISO will seek a thorough FERC process and sufficient time for the RTO to review any final rule “so we can judge the applicability while respecting regional differences,” Chatterjee said.
“How about the 15-day implementation period?” joked Kevin Murray, attorney for the Coalition of Midwest Transmission Customers, referring to the NOPR provision requiring RTOs to make a compliance filing within 15 days of a proposed rule becoming final (RM18-1).
“I don’t know that 15 days would be sufficient, but all jokes aside, MISO will probably ask for more time to review and assess. Stakeholders that think the 15 days is too short should comment,” Chatterjee said.
MISO Independent Market Monitor David Patton confirmed that he would file comments.
“We’re going to file comments that stress the importance of being careful and reasonable when picking policies,” Patton said. “I don’t know that we understand what [resiliency] is unless it’s related to reliability.”
Patton said he could see the need for resiliency in planning for future contingencies but didn’t know if the concept should be monetized.
“Treating it as a separate idea and pursing it outside the market process is very harmful,” Patton said.
The Public Utility of Commission on Wednesday approved a settlement in Oncor’s proposed swap of more than $400 million in assets with Sharyland Utilities, paving the way for the two parties to complete the transaction (Docket 47469).
The exchange will result in Oncor acquiring 54,000 retail distribution customers and assets from Sharyland, in exchange for 258 miles of Oncor transmission lines in West and Central Texas. The PUC’s approval would also dismiss Sharyland’s current rate case, providing “significant rate relief to our customers,” according to the utility’s CEO, David Campbell.
In 2015 the commission opened an inquiry into Sharyland’s rates, which spiked following the utility’s 2010 acquisition of a bundled package of financially troubled electric cooperatives. Sharyland is owned by the Hunt family of Dallas, which failed in a 2016 bid to buy Oncor.
“The Hunt organization and Sharyland took a lot of arrows from customers and others, for problems that really weren’t of their making,” Commissioner Ken Anderson said. “They were faced with an intractable problem. … This will solve that problem. Oncor didn’t have to do this. It couldn’t have happened but for the agreement of everybody.”
The agreement also avoids an expected rate increase for Sharyland’s retail customers in South Texas.
“Ultimately, the proposed transaction seeks to resolve the rate disparity that currently exists between Sharyland’s high retail electric delivery rates and those of Oncor” and other ERCOT transmission and distribution utilities, the order said.
The commission approved Sharyland’s request to recover up to $17 million in transition costs for the proposed transaction, although it directed the utility to use its “best efforts” to sell any assets not being exchanged and to minimize employee-related transition costs.
The PUC also approved the incorporation of Sharyland’s energy efficiency cost recovery factor (EECRF) and transmission cost recovery factor (TCRF) regulatory assets or liabilities into Oncor’s EECRF and TCRF.
Oncor plans to make its 2018 EECRF effective March 1, 2018, and will include a refund of $6,097,744 for its over-recovered 2016 energy efficiency costs. The transaction, expected to close before March 1, will result in a credit of $243,199 for Sharyland’s over-recovered 2016 energy efficiency costs. That total will be combined with Oncor’s EECRF and be refunded to the appropriate Oncor rate classes.
Oncor is already the largest utility in Texas, with 3.4 million wholesale and retail customers.
The commission’s approval led to a round of back-patting among the parties and commission staff.
“It’s been a long process, with a lot of tricky issues we didn’t anticipate,” said Vinson & Elkins’ Matt Henry, Oncor’s legal counsel. “Staff worked hard to help us fight through the things. Working with Sharyland and their team, there was never a point we didn’t find an obstacle we couldn’t work through.”
“Matt is probably just happy he finally has a change-in-control agreement,” said PUC Executive Director Brian Lloyd.
Schedules Set in LP&L, Sempra-Oncor Cases
The commissioners set tentative hearing dates in a pair of upcoming high-profile cases that will keep them busy well into 2018.
During an Oct. 9 prehearing conference, parties in Lubbock Power & Light’s plan to migrate part of its load from SPP into ERCOT agreed to Jan. 17-18, 2018, hearing dates (Docket 47576).
Lubbock on Sept. 1 filed its formal application to integrate 470 MW of its load with ERCOT by June 2021. That load is currently served through a wholesale contract with SPP member Southwestern Public Service; the contract expires May 31, 2021.
Another prehearing conference is scheduled Monday for Sempra Energy’s attempted acquisition of Oncor (Docket 47675). The PUC has blocked off Feb. 21-23 for a hearing on the merits.
Vistra Energy announced Friday it will close two additional coal-fired plants, taking another 2,300 MW of capacity offline and slashing its coal portfolio by more than half.
The retirements of Big Brown, north of Houston, and Sandow, northeast of Austin, will leave Vistra’s Luminant generating subsidiary with just two operational coal plants rated at a combined 3,850 MW. Vistra announced Oct. 6 it would be retiring its three-unit, 1,800-MW Monticello plant in East Texas. (See First Shoe to Drop? Vistra to Retire 3 Texas Coal Units.)
Big Brown | Vistra Energy
CEO Curt Morgan again blamed the “economically challenged” environment the plants face in the ERCOT market. The company said sustained low wholesale power prices, an oversupply of renewable generation and low natural gas prices contributed to the decision.
“Though the long-term economic viability of these plants has been in question for some time, our yearlong analysis indicates this announcement is now necessary,” Morgan said.
ERCOT’s most recent Capacity, Demand and Reserves report indicated the ISO had an 18.9% reserve margin for next summer, with margins remaining above 18% the following three years. A revised CDR report will be released in December.
“The market will tighten from a reserve margin perspective, but it remains to be seen if on-peak forwards will rise in response,” Kevin Vo, a research analyst with Tudor, Pickering, Holt, & Co., told RTO Insider. “We don’t believe off-peak pricing would be affected due to the large amount of wind generation.”
The Vistra retirements include the 600-MW Sandow Unit 5, which went online in 2009 and has a 75% capacity factor. Only Luminant’s twin-unit Oak Grove plant, which began operations in 2010, is newer.
Sandow | Vistra Energy
Sandow was built to serve a nearby Alcoa smelter, which was closed in 2008. Shortly before making its announcement, Vistra agreed to an early settlement that terminates a long-standing power and mining agreement with the aluminum company.
A Luminant spokesperson said once the contract was terminated, it became clear the Sandow units were not economical in the ERCOT market.
“The contract has helped shield Sandow from significant exposure to the downturn in the wholesale power market,” the company said in a press release.
“Sandow’s retirement was a surprise but highlights that it is hard for any coal plant to make money in Texas right now,” Ko said. “If you are a coal plant generator, you’re waiting to see if prices will respond. If prices don’t rise meaningfully or any price increase isn’t sustained, we would not be surprised if there are further coal plant retirement announcements.”
The Three Oaks mine, which supports the plant, will also be closed.
Luminant has filed a 90-day notice of suspension of operations with ERCOT. The plant will cease operating Jan. 11 if the ISO’s reliability review shows the units are not needed.
Big Brown is the oldest coal plant in Luminant’s fleet, with its two units having begun operations in 1971 and 1972. The units are together capable of generating 1,150 MW and have a combined capacity factor of 59%. Both units burn lignite supplemented by Powder River Basin coal. The nearby Turlington mine that supplies the plant was already scheduled to wind down operations by the end of this year.
Vistra said it would explore a sales process for the site during ERCOT’s notification period. The company filed a 120-day suspension noticed with the ISO to allow for a “more complete sales process.” With ERCOT’s approval, the plant will cease operations on Feb. 12 if it has not been sold.
Luminant said about 650 employees will be affected by the plant and mine closures.
The company’s 2,250-MW Martin Lake plant in East Texas is now the fleet’s oldest, its three units having gone into service in 1977, 1978 and 1979. Luminant also has 7,500 MW of natural gas capacity and 2,300 MW of nuclear capacity.
WASHINGTON — FERC Chairman Neil Chatterjee praised Energy Secretary Rick Perry’s “bold leadership” in calling for price supports for coal and nuclear plants but promised the commission’s response will be “fuel-neutral” and will not undermine wholesale markets.
“I think the bold directive [Perry] took has initiated this conversation, and it’s something that we are going to look at very seriously, and I’m confident we’ll find a positive resolution to,” Chatterjee said in a nearly hour-long press conference at FERC headquarters Friday. “I’m sympathetic to some of the things that Secretary Perry has raised. This idea that there are perhaps attributes that certain generating sources have that have value [and] that are not appropriately being captured by our existing market structure, we need to look at that carefully…
“I also believe strongly in markets. We’ve invested nearly two decades and billions upon billions of dollars into our existing market structure, and I don’t want to do anything to disrupt that market structure,” he continued. “Accurately valuing resilience is not a zero-sum game. Compensating baseload generation does not equate to destruction of the markets. On the contrary, I think it’s a step toward accurately pricing contributions of all market participants.”
Chatterjee said the commission must act within 60 days in response to the Department of Energy’s Notice of Proposed Rulemaking, which was published in the Federal Register on Tuesday.
FERC’s Options
The NOPR would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and real-time energy markets to ensure full cost recovery for any generation that can provide “essential energy and ancillary services” and has a 90-day fuel supply on site. Units subject to cost-of-service rate regulation would be excluded. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.
Chatterjee outlined FERC’s options for responding: “We could do an Advance Notice of Proposed Rulemaking; we could do a Notice of Proposed Rulemaking superseding the DOE NOPR; we could issue a final rule; we could do an extension of the comment period and solicitation of further comments; we can convene technical conferences; we can do a notice of inquiry; we could initiate Federal Power Act Section 206 review proceedings.”
Asked whether the commission could take an up-or-down vote on the proposal within 60 days, Chatterjee responded, “It could be. We’re going to carefully look at it.”
Chatterjee said that while he would prefer to delay major actions until the commission is fully staffed with the addition of nominees Kevin McIntyre and Richard Glick, he wouldn’t hold up action pending their arrival. The two are awaiting a Senate floor vote after clearing the Senate Energy and Natural Resources Committee on Sept. 19.
“These challenges are too important to wait,” Chatterjee said, noting that the commission is planning a “big announcement” on hydropower licensing policy at its next open meeting Oct. 19.
He also defended the commission’s refusal to extend the comment period on the NOPR (RM18-1). The commission set an Oct. 23 deadline on comments, with reply comments due Nov. 7. “It’s not a new issue,” he said. “We have ample time to receive comments.”
Kentucky Native on Coal’s Role
Chatterjee defended comments he made in a podcast in August, which some FERC watchers interpreted as signaling a break from the commission’s traditional “fuel-neutral” policies.
After praising “baseload” coal and nuclear generation for their value to “resilience and reliability,” Chatterjee noted that coal provided more than 80% of the electricity in his home state of Kentucky last year. “As a nation, we need to ensure that coal, along with gas and renewables, continue to be part of our diverse fuel mix,” he said then.
“I wasn’t saying that FERC was not fuel-neutral,” he said Friday. “To be clear, whatever solution that we pursue here will be fuel-neutral as well. I agree with Commissioner [Cheryl] LaFleur’s assessment that we don’t start with a resource and work backwards. We come up with policies that will be applied in a fuel-neutral way.”
But he said he agreed with lawmakers who want to preserve “fuel diversity,” suggesting coal could act as a hedge against “unintended consequences” from technological changes on the grid.
He cited the switch of the Big Sandy generator in Kentucky from coal to natural gas. Much of the plant’s load was from the energy-intensive coal mines in the region.
“So, when the power plant shut down, the coal mines that fed that plant shut down with it. … Now the operators of the gas plant find themselves in a situation where they’ve got to come to the state for a massive rate increase to account for … lost load,” he said. “So that’s a perfect example of an unintended consequence that occurs when you have these technological shifts. And I just think we need to be very thoughtful and careful in assessing what the long-term future of our grid looks like when these types of unintended consequences can occur.”
Chatterjee declined to offer an opinion on whether a 90-day fuel supply is a valid way to measure reliability. The NOPR said such supplies enable a plant “to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.”
“I just think we have to go through our process, take in people’s comments. Look at the rationale to see how it would impact them,” Chatterjee said. “I’m not prepared at this stage of our process — not having all that complete information submitted — [to say] how we will address that.”
The commission also will consider data cited by members of the House Energy Subcommittee during a Thursday hearing with Perry indicating that most outages result from problems on the distribution system rather than from insufficient generation, the chairman said. (See Perry Defends Call for Coal, Nuclear Supports.)
“Staff put out an … extensive list of questions to facilitate this kind of dialogue and commenting. I fully expect comments in line with what you’re laying out will come in.”
Mum on White House Input on Staff
Chatterjee declined to answer concerns among some FERC watchers that his appointments of General Counsel James Danly and Chief of Staff Anthony Pugliese were directed by the Trump administration.
The commission has traditionally been independent and rarely decides issues on party lines. But some observers said the appointments suggested that could change because the two key positions were filled before the arrival of McIntyre, who was tapped by President Trump to lead the agency. New chairmen typically select their own general counsel and staff chiefs.
Danly, an Iraq War veteran, joined the commission from Skadden, Arps, Slate, Meagher & Flom.
Pugliese, who formerly lobbied on solar, oil and natural gas issues in Pennsylvania, came to FERC after serving as the White House’s eyes and ears at the Department of Transportation. Politico described Pugliese in May as one of Trump’s “White House-installed chaperones,” saying he clashed with Secretary Elaine Chao.
“Day to day, Pugliese and his counterparts inform Cabinet officials of priorities the White House wants them to keep on their radar,” The Washington Post reported in March. “They oversee the arrival of new political appointees and coordinate with the West Wing on the agency’s direction.”
At his press conference — which Pugliese and Danly attended — Chatterjee praised the two as “very talented people.” The two sat in the rear of the room, behind reporters and facing Chatterjee — Pugliese frequently shaking his head no or yes in response to the questions and answers.
“Mr. Pugliese has extensive experience in infrastructure and public policy, and I’ve been thoroughly impressed in the manner in which he has comported himself in his time here at the agency,” Chatterjee said.
He also praised Danly’s “astonishing resume,” calling him “one of the most talented brightest, capable energy lawyers in the country.”
Were they suggested to Chatterjee by White House officials?
“They were suggested to me by a number of people,” Chatterjee responded. “They have sterling reputations, and people who I respect and trust recommended them to me.”
Including the White House?
“I’m not going to speak [about] who recommended them,” Chatterjee said.
HOUSTON — When Missouri regulators recently rejected Clean Line Energy Partners’ application to build a high-voltage transmission line through the state, it seemed to sound the project’s death knell.
After all, it marked the company’s third unsuccessful attempt to gain Public Service Commission approval for its 780-mile Grain Belt Express, a $2.3 billion initiative that would deliver 4,000 MW of wind power from western Kansas through Missouri and Illinois to the Indiana border.
The company’s first attempt in 2015 was shot down after the PSC determined the project did not provide enough benefits to Missouri consumers. A second attempt last year failed on a technicality. The project has already been approved by Kansas and Illinois.
But Michael Skelly, Clean Line’s founder and president, was undeterred. Moments after the PSC determined that Grain Belt had not obtained approvals from all the counties it would cross, Skelly turned to his staff and said, “We’re not giving up.”
The commission rejected that request Sept. 19. This time Clean Line responded by hiring former Missouri Gov. Jay Nixon and his law firm as Grain Belt’s legal counsel.
Nixon’s first bit of advice? Take the case to the Missouri Court of Appeals’ Eastern District, because the Western District had greased the skids for the PSC’s previous rejection when it ruled that an infrastructure project must secure approvals from each county it crosses. (See Clean Line Ponders Options After Grain Belt Rejection.)
Clean Line did just that on Sept. 19.
Staying Power
Skelly does not easily take “no” for an answer. Developing long-term projects requires vision and staying power, something Skelly learned as a founding partner of the Rain Forest Aerial Tram in Costa Rica’s rainforest. Skelly had come to the country as a Peace Corps volunteer after earning a bachelor’s in economics from the University of Notre Dame and an MBA from Harvard Business School.
Tenacity also was essential in his role developing wind farms as employee No. 3 for Zilkha Renewable Energy in the 1990s. Skelly was the firm’s chief development officer when it became Horizon Wind Energy after Goldman Sachs bought it in 2005. The banking giant sold Horizon (now EDP Renewables North America) for $2.2 billion in 2007.
Skelly then took a brief stab at politics, but after an unsuccessful run for Congress as a Democrat in Texas’ 7th District (he lost by 13 points), he turned his attention back to the power industry and wind energy.
Sensing an opening, he founded Clean Line in 2009. Skelly had financial backing from Houston’s Zilkha family, which had also bankrolled the wind company, and ZBI Ventures, owned by the Ziff family of New York.
Clean Line’s business model is building long-distance transmission lines to deliver wind energy to urban population centers. “We thought transmission was going to be the linchpin of expanding wind energy,” Skelly said. “If you look at the right technical solution to move lots of wind a long distance, you pretty quickly come to the conclusion that DC lines are the right answer. For anything over 100 miles [long], DC makes more sense. Then, thinking about it further, it was clear that the incumbents weren’t going to do this. It’s not their job to move energy to the Southeast or PJM. Their job is to focus on native load” and meeting demand.
“That felt like an opportunity for an individual to come in and tackle this job. No one else is going to do it.”
HVDC can cost as much as $2 million a mile, according to Clean Line. The high capital costs and the regulatory obstacles that have delayed construction led the company to seek additional financial backers. The company, which has almost 40 employees, has no current source of revenue.
In 2012, National Grid USA announced it was investing $40 million for about a 40% stake in Clean Line. In 2015, Bluescape Resources, an energy investment and operating company headed by former TXU Chairman and CEO C. John Wilder, agreed to spend up to $50 million for equity in Clean Line, with the potential to invest more in the company’s transmission projects.
Clean Line spokeswoman Sarah Bray said Bluescape is now the company’s “principal investor,” although National Grid, ZBI and the Zilkha family have retained equity stakes.
Project development for Grain Belt began in 2010, and in late 2012, the company was hoping to begin construction as early as 2015. Clean Line now says construction could begin in 2019, with the project operational as soon as 2021.
Besides Grain Belt, Clean Line is developing four other projects. Below is a description of the projects and their current status, contrasted with the company’s projections from 2012, where applicable:
The Rock Island Clean Line, a 500-mile project from northwest Iowa to Illinois, delivering 3,500 MW of wind energy. The project was originally expected to be operational in 2017. But on Sept. 21, the Illinois Supreme Court rejected the Rock Island application because Clean Line held only an option agreement on a parcel for a converter station — rather than a completed purchase agreement — when it applied to the Illinois Commerce Commission. The company said the ruling will cause “great delay” for the project. “Although we are disappointed with the Supreme Court ruling on the Rock Island Clean Line, on the positive side, the decision did not impact the authority of the ICC, and the court made clear that we have an opportunity to refile with the ICC at a later date,” the company said in a news release. The company hasn’t decided on its next steps.
The Plains & Eastern Clean Line, an approximately 700-mile project from the Oklahoma Panhandle through Arkansas to Memphis, Tenn., delivering 3,500 MW of power to the Tennessee Valley Authority and 500 MW to Arkansas. The company is involved in commercial negotiations with potential customers, both wind generators and loads seeking power. It will begin construction once it has contracts for 2,000 MW of capacity.
The Centennial West Clean Line, a 900-mile project delivering 3,500 MW of renewable energy from New Mexico and Arizona to California. The company had expected construction to begin in 2017 and be operational in 2019. Development has slowed down while the company works on its other projects.
The Western Spirit Clean Line, a 140-mile project complementing the Centennial West project, delivering 1,000 MW of renewable power from east-central New Mexico to markets in the western U.S. Clean Line acquired the project, originally named Power Network New Mexico, in 2013. Construction, which will take about one year, could begin by the end of 2018.
Like jugglers, Skelly and his staff must keep their eyes on many balls at the same time. The project teams are regionally based, but they enjoy legal, financial, communications, environmental and other support from Clean Line headquarters in downtown Houston, where black-and-white photographs of rock stars and the New York punk scene hang on the walls.
“You would think in eight years, you would have sort of a lull, but it’s a sort of a mad dash every day to move these projects forward,” Skelly said. “It’s more like an Ironman [Triathlon], not a marathon. It’s more like a decathlon, but it goes on for eight years.”
Projects that take so many years to put together will inevitably face changes at the federal, state and utility commission levels, Skelly said.
“One of the things you want to think about is putting together projects that can last through administrations,” he said.
One example: In March, the Arkansas congressional delegation — all Republicans — asked Energy Secretary Rick Perry to “preserve states’ rights” and reverse the Department of Energy’s decision to partner on the Plains & Eastern project over the objections of Arkansas officials. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.) The department had invoked Section 1222 of the Energy Policy Act of 2005, which, the legislators said, “risks codifying into law the practice of federal eminent domain seizures.”
The lawmakers also are sponsoring a bill that that would prevent the department from using eminent domain for Section 1222 transmission projects without the approval of both the governor and utility commission of affected states.
The project also has drawn the ire of Sen. Lamar Alexander (R-Tenn.), a member of the Energy and Natural Resources Committee, who said it could burden TVA with expensive wind power it does not need.
TVA has signed a memorandum of understanding with Clean Line, which has begun buying rights of way for the project. But neither TVA nor any other utility has signed a contract to buy the power the project would transmit.
Bray said she’s confident that Perry, the former Texas governor, will see the value of the project. “He’s seen the benefits of wind power first hand,” she said, citing the economic growth the state’s Competitive Renewable Energy Zone projects brought to rural Texas.
Skelly has said seeking DOE authority for the Grain Belt and Rock Island lines is an option but not his first choice because it is slow and costly.
Nothing to Show
Skelly doesn’t have to be reminded that Clean Line has yet to see a project come to completion, but that’s through no fault of the staff, he says.
“We haven’t done anything yet. We haven’t built anything yet,” he said. “You have to have a very motivated team. You have to be tremendously tenacious, you have to be creative. You’ve got to think long, long term. You have to have a team that works.”
Skelly said that while landowners’ opposition to transmission projects is “understandable,” the pushback from within the industry is more frustrating.
“We need to do a better job in embracing new ideas and innovation,” Skelly said. “If you separate [transmission and generation], you generally get more innovation. You don’t have the same level of common interests.”
Pointing to Commonwealth Edison’s opposition to the Rock Island project in Illinois, he said, “Why are they doing that? They’re doing that to protect their generation. If you look at what other countries are doing to build up their grid, they are embracing new ideas and innovation. They’re coming up with cost-effective solutions and they’re getting big projects done.”
ComEd did not respond to a request for comment.
In May, ComEd asked the Illinois Supreme Court to dismiss Clean Line’s appeal seeking to overturn an appellate ruling that reversed the ICC’s approval of the project. ComEd said the project had changed since the ICC’s approval in 2012.
Interregional Planning
Skelly is among those who have been frustrated that FERC Order 1000 hasn’t resulted in interregional transmission projects. WIRES, an industry organization supporting transmission investment, says the order has failed to produce true interregional planning because of inconsistencies in how neighboring regions evaluate projects.
“It is common for projects that are shown to provide benefits in interregional evaluations to fail regional evaluations for inclusion in regional plans,” the group said in comments following a FERC technical conference last year (AD16-18). (See Five Years Later, FERC Takes Another Look at Order 1000.)
WIRES also says transmission planning should model “a broader range of plausible market conditions, system contingencies and public policy environments” to consider the “flexibility benefits and insurance value that a more robust interregional transmission infrastructure can offer.”
In its grid study released in August, DOE called for a review of “regulatory burdens for siting and permitting” of transmission and actions to “accelerate the process and reduce costs.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Building Relationships
Clean Line has worked hard in Missouri to gain community support for Grain Belt. The company signed up more than three dozen cities to purchase about 100 MW of power from the project; many of the cities also offered statements of support. That $525 million project, the company says, will save the state’s consumers $10 million annually and create more than 500 permanent jobs to maintain and operate the wind farms and the transmission line.
“You have to build alliances,” Skelly said. “We’ve got support from labor groups, environmental groups, business groups, from political leaders … doing these projects without building those types of alliances would be really, really difficult.”
That relationship-building extends to RTOs. While SPP, MISO and other grid operators don’t manage long-distance DC lines, their responsibility for grid reliability comes into play when interconnections are discussed.
Clean Line also must “fit within the context of how they do their market operations,” Skelly says.
The RTOs’ “paradigm is around the cost allocation of projects built by incumbents, which comes out of their planning process. Their planning process doesn’t plan around significant transmission exports. We have to make sure and work with them, so our projects fit within the context of those plans.”
Skelly said Clean Line recently spoke with an SPP member concerned about congestion caused by wind farms in the RTO’s western footprint. “They said, ‘We used to think you were too early. Now, we can’t get you to build your project soon enough,’” he recalled.
‘Preservation and Adaption’
While his business is focused on energy sources of the future, Skelly is also a history buff and preservationist. He and his wife, Anne Whitlock, live in a renovated firehouse in East Houston, which was recently recognized by Preservation Houston as a “shining example of preservation and adaption.” Nearby sit six Victorian homes that Skelly had moved and refurbished.
Firestation No. 2 and the other buildings served as a refuge for residents forced from their homes during the flooding during Hurricane Harvey, an act that drew attention from The Washington Post.
Skelly writes occasional op-eds in the Houston Chronicle, in which he has advocated for making the car-centric city more pedestrian- and cyclist-friendly.
Optimistic About the Future
Meanwhile, an optimistic Skelly continues to look to the future. Although federal production tax credits for wind projects will expire at the end of 2019, he thinks continued technological advances in wind turbines will compensate for that loss.
“We thought that the combo of open-access, low-cost wind [that is] relatively easy to permit … would result in an overbuild of wind,” requiring transmission to move the excess energy to load centers, he said. “We didn’t think that would happen until 2030, but it’s upon us now. Over time, we are moving to a leaner energy mix, there’s no question. Economics favor that. That’s just reality.
“There’s a lot of people pulling for us. I don’t think [demand for renewable energy] is going away any time soon. There are very large consumers of power in this country that care about carbon [emissions], and they’re putting their money where their mouth is in how they source electricity.”
RENSSELAER, N.Y. — NYISO year-to-date monthly energy prices averaged $35.34/MWh in September, a 3% increase from a year earlier, Michael DeSocio, senior manager for market design, said Wednesday in presenting the ISO’s market operations report to the Business Issues Committee.
Locational-based marginal prices (LBMPs) averaged $29.57/MWh for the month, down 3.3% from August and 4.3% from September 2016.
The ISO’s average daily sendout was 437 GWh/day in September, down from 477 GWh/day in August and 458 GWh/day a year earlier.
New York natural gas prices gained 5% in September, averaging $2.27/MMBtu at the Transco Z6 hub. Prices were up 72.2% from a year ago. Distillate prices gained 32.3% year-on-year, with Jet Kerosene Gulf Coast averaging $13.40/MMBtu, up from $11.53/MMBtu in August. Ultra-Low Sulfur No. 2 Diesel NY Harbor averaged $12.80/MMBtu, compared with $11.65/MMBtu in August.
The ISO’s local reliability share was 16 cents/MWh, one-third higher than the previous month, while the statewide share “is trending lower at -50 cents/MWh,” compared with -31 cents/MWh in August, DeSocio said. Total uplift costs were lower than in August.
In speaking about the Broader Regional Markets report, DeSocio only highlighted that FERC last month accepted NYISO’s proposed Tariff revisions regarding cost recovery for the Ramapo PARs, as filed by the ISO in June. NYISO foresees negotiating with PJM by year-end the cost sharing for the replacement of PAR 3500.
Proposed Tariff Changes for Energy Storage
Solar inverter battery
The committee approved proposed Tariff and Ancillary Services Manual changes to define the role of inverter-based energy storage in providing synchronized reserves.
Daniel F. Noriega, NYISO associate market design specialist, presented the BIC-proposed Tariff changes that would allow generators and demand-side resources that use inverter-based energy storage technology to provide spinning reserves.
The ISO last year asked the Northeast Power Coordinating Council (NPCC) to clarify whether such resources can provide synchronized reserves. The NPCC responded that “a storage resource with inverter technology complies with the original intent of the synchronized reserve requirement and therefore shall qualify towards a [balancing authority’s] complement of synchronized reserves.”
NYISO in January presented its Market Issues Working Group with proposed Ancillary Services Manual revisions to reflect that clarification. Stakeholders provided feedback on the wording, which NYISO incorporated in the updated proposal presented Wednesday. NYISO intends to bring the proposed Tariff and manual changes to the Operating and Management committees for action this month.
Fuel Cost Adjustment Calculation to be Refined
The BIC also approved a proposal that would more closely align the real-time and day-ahead impact tests and penalty calculations used to identify generator misuse of fuel cost adjustments (FCAs). The current day-ahead process is considered more precise because it tests the impact on real-time LBMPs based on market reruns.
NYISO Mitigation Reference Analyst Nicholas Shelton explained that FCAs allow generators to submit a fuel type or fuel price — or a combination of both — along with their energy offers. Once the ISO validates the FCA is within posted thresholds, a generator can update its incremental energy and minimum generation reference levels to reflect the new information. The ISO’s Market Mitigation & Analysis unit reviews all FCAs, and those that fail the conduct and impact tests may be subject to penalty.
The ISO has found that reviewing FCAs from only the prior seven days does not ensure enough data are available to draw conclusions about tendencies toward an upward bias in prices. The proposed changes would combine the day-ahead and real-time market penalties into one section and lengthen the FCA review period to 90 days from the previous seven days.
According to the proposal, the 10% threshold used in screening for bias has become increasingly restrictive with the decline in natural gas prices, so that a $2/MMBtu price translates into a very tight threshold. Rather than using a 10% threshold to identify bias, the proposal would rely on the greater of 10% or 50 cents/MMBtu.
The proposed changes will go to the Management Committee in October and, if approved, be submitted to the Board of Directors in November prior to filing with FERC.
Editor’s note: An earlier version of this story incorrectly used data from the ERCOT North zone, and not the Houston Hub.
By Tom Kleckner
ERCOT’s Houston Hub saw real-time prices spike as high as $1,251/MWh on Monday during an early fall heat wave.
Hub prices first cracked $1,000/MWh during the 15-minute interval ending at 1:45 p.m. on Oct. 9, and then again during each of the 11 intervals between 2:30 and 5 p.m. The systemwide hub average peaked at $520.59/MWh during the 3:15 p.m. interval.
According to ERCOT data, the Houston Hub has now produced 47 intervals of $1,000/MWh this year. That’s the most since 2011, the first full year of the nodal market, when the hub recorded 163 high-priced events. It only had 87 occurrences in 2012-2016.
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Congestion has long been an issue in the Houston zone, but the high temperatures caught the market with several plants on maintenance outages.
Speaking during a Tuesday webinar, Dinesh Madan, an ICF technical director, said scarcity pricing has been “almost missing from this market.” Madan pointed to a volatile market, thanks to an overabundance of wind energy and short load forecasts.
“ERCOT is a weather-and-wind story now,” Madan said. “In 2016, the story was wind. In 2017, the story was weather.”
In 2016, wind resources generated 2,024 MW more than their forecasted output coinciding with the summer peak. In 2017, the market’s peak load was 3,428 MW below forecast, thanks to a milder summer. With ample reserves (and lower loads), ERCOT was able to withstand 2016 and 2017 peak loads despite generation outages exceeding forecasts by 1,780 MW and 2,713 MW, respectively, during each summer’s peak.
Monday’s spike came as Texas temperatures soared into the mid 90s. The ISO set a new record for October peak demand at 62,263 MW — just above projections — during the hour ending at 5 p.m., breaking the previous mark set the year before by more than 2.3 GW.
Houston Hub prices peaked at $34.11/MWh on Tuesday, when temperatures and ERCOT load both dropped.
Reservoir of Retirements
During the same webinar Tuesday, ICF Senior Vice President Judah Rose also addressed Vistra Energy’s recent decision to retire three aging coal-burning units in East Texas. (See First Shoe to Drop? Vistra to Retire 3 Texas Coal Units.)
He referred to a “reservoir” of potential retirements among ERCOT’s coal fleet, driven by fat reserve margins, low gas prices and cheaper renewable resources. Rose also pointed out that many of the coal plants, once reliant on cheap, local lignite — including Vistra’s Monticello plant — now depend on Powder River Basin coal brought in on rails from the Rocky Mountains.
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“Almost ironically, these plants are facing the least environmental pressure in a long time,” Rose said, referring to the Trump administration’s efforts to roll back the Clean Power Plan. (See EPA to Announce Clean Power Plan Repeal.)
He said the Energy Department’s recent Notice of Proposed Rulemaking to FERC to support out-of-market baseload plants would likely have little effect on Texas coal units, as the agency has no jurisdictional authority over ERCOT.
Any FERC policy “will not provide additional revenue,” Rose said. “The exit of these plants will be related to low power prices.”
Rose said ICF will be watching ERCOT’s reserve margins, which the ISO forecasts will be 16.3% next year. The firm expects that margin to dip below the planning reserve margin of 15.6% in 2019.
“That’s significant, because generally, when you start getting below 15% in markets, you have the potential for all hell breaking loose,” he said. “You get a lot of potential for price spikes.”
The Monticello retirement may provide $1 to $2/MWh of upside in scarcity equilibrium in 2019, Rose said.
