WASHINGTON — President-elect Donald Trump’s nominee to head the Interior Department told a Senate panel Tuesday that climate change is real but that he would continue to allow fossil fuel production on public lands.
Zinke
“We need an economy and jobs, too,” Rep. Ryan Zinke (R-Mont.) told the Senate Energy and Natural Resources Committee during a nearly four-hour confirmation hearing. The former Navy Seal attempted to steer a path between climate deniers and fossil fuel opponents, citing President Theodore Roosevelt as a model and calling for continuation of an “all of the above” approach to energy production.
Sen. Bernie Sanders (I-Vt.) asked Zinke whether he agreed with Trump, who has called climate change a “hoax.”
“I don’t believe it’s a hoax,” Zinke responded.
“The climate is changing. That’s undisputable. [My district includes] Glacier National Park. I’ve seen glaciers over the period of my time recede,” Zinke said. “Man has had an influence. I think that’s undisputable as well … I think where there’s debate on it is what that influence is and what can we do about it.”
“There is a debate on this committee but not within the scientific community,” Sanders interrupted, before asking whether the U.S. should continue to allow fossil fuels to be produced on federal land.
Zinke said it is preferable to produce energy domestically, “under reasonable regulations,” rather than depend on foreign energy production without environmental rules.
‘War on Coal’
Sanders
In response to a question from Sen. John Barrasso (R-Wyo.), Zinke pledged to reverse the Obama administration’s moratorium on coal mining on federal lands.
“The war on coal I believe is real,” he said. “The moratorium, I think, was an example of one-size-fits-all [policy]. It was a view from Washington and not a view from the states.”
He called for investing in research and development on coal. “We know we have the asset. Let’s work together to make it cleaner, better. We should be leading the world in clean energy technology and I’m pretty confident that coal can be a part of that,” he said. “But it is about science. It is about investing in our future and not looking at our past.”
Zinke also promised to support Barrasso’s plan to use the Congressional Review Act to overturn the Bureau of Land Management’s Nov. 15 rule regulating venting and flaring rule of natural gas.
Zinke said he was troubled by the volumes of natural gas vented during production. “The amount of venting in North Dakota alone almost exceeds what we get out of the fields. A lot of the wasting can be [eliminated] by having the infrastructure [to capture it]. So let us build a system where we capture that energy that’s otherwise being wasted. That’s an enormous opportunity.”
Mining Restoration
Cantwell
Ranking member Sen. Maria Cantwell (D-Wash.) pressed Zinke on whether he would support an end to current policy allowing surface coal mine operators to “self-bond” for their obligations to reclaim lands. She cited a Government Accountability Office report released Tuesday that found all other energy and mineral producers on federal lands — mineral mines, onshore oil and gas drilling and wind and solar production — are required to purchase third-party bonds.
“I think bonding is important,” Zinke answered. “I think we need to have the courage today to look 100 years forward [so we can] look back and say we did it right.”
“Well, I hope that was a great endorsement of the stream protection rule,” Cantwell responded, smiling. The rule, issued by the Interior Department on Dec. 19, requires coal companies to restore their land to its condition before mining began, an effort to prevent mining debris from contaminating streams. It, too, is a target for Congressional repeal. (See Cost Trends Favor Renewables Despite Coming Policy Shifts.)
CAISO’s decision to consider reforms to its congestion revenue rights auctions as one of its top priorities for 2017 has provoked mixed reactions from stakeholders.
Opponents of the move say the ISO’s pursuit of the CRR issue lacks widespread stakeholder support and therefore doesn’t warrant a top spot within the policy roadmap for this year’s discretionary initiatives. They contend CAISO is elevating the concerns of its internal Market Monitor above those of most stakeholders, who want the ISO to focus on other priorities.
But the initiative has its backers, some of whom argue that the ISO should move as quickly as possible to determine why auction revenues are consistently outpaced by payments made to CRR holders, leaving ratepayers to make up the difference.
CAISO has included the issue in its draft final policy roadmap of “discretionary” stakeholder initiatives in response to concerns expressed by its internal Market Monitor. “Discretionary” initiatives represent policies the ISO can implement out of its own choosing rather than as a result of a regulatory mandate or market necessity.
The Department of Market Monitoring has pointed out that ratepayers lost $520 million from 2012 to 2015 through a market that pays $1 to CRR holders for every 45 cents in revenues received from auctions.
A 2016 report by the Monitor urged the ISO to altogether eliminate the auctions, contending that the program suffers from inherent design flaws that allow speculators to reap large financial gains at ratepayer expense. (See CAISO Monitor Proposes to End Revenue Rights Auction.)
“The consistent underpricing of CRRs calls into question a fundamental assumption of the CRR auction design that competition will drive auction prices to equal the CRR’s expected value,” the Monitor said in its report.
The Monitor’s report offered up a potential alternative to the current auction: a bilateral or exchange market for forward contracts-for-difference for pairs of ISO nodes — also known as locational basis price swaps.
Unlike in the current CRR market, the price swaps would be traded between willing counterparties, rather than leaving ratepayers as the unknowing, and technically outmatched, counterparty.
“We’re not jumping to DMM’s proposed solution,” Brad Cooper, CAISO manager of market design and regulatory policy, said during a Dec. 22 stakeholder meeting. CAISO is taking up the initiative “because DMM has pointed out a significant revenue gap that comes to big money,” he said.
In comments submitted to the ISO supporting the initiative’s inclusion in the roadmap, the “Six Cities” utilities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside attempted to put the size of that gap into perspective. Revenue deficiencies stemming from the auction equated to $130 million per year over a three-year period, compared with the estimated Energy Imbalance Market (EIM) benefits to ISO market participants in 2015 of $12.7 million, they pointed out.
The potential CRR auction reform initiative would seek to address the concern that auction revenues have historically fallen well short of payments made to CRR holders. | CAISO
“Thus, the average annual costs to ISO LSEs resulting from the design of the CRR auction process have been more than 10 times the estimated EIM benefits to ISO market participants in 2015,” the utilities said.
Noting that the ISO has signaled a need to perform additional analysis before formally committing to the initiative, the Six Cities encouraged staff to move with all deliberate speed.
“Any preliminary analysis considered necessary should commence as soon as possible (and well before the middle of 2017) so that an appropriate solution to the CRR auction revenue deficiencies can be implemented prior to the auction for annual CRRs for 2018,” the utilities said.
Northern California Power Agency (NCPA), a joint powers agency established to serve the region’s municipal utilities, added its support to a measure that would address auction shortfalls.
“Modification of the auction process such that bids from entities willing to sell clear against those willing to buy is a reasonable approach to mitigating the long-standing revenue insufficiency concerns that we believe bears careful consideration,” the agency said in its comments.
Still, NCPA faulted the Monitor for its failure to suggest modifications rather than advocate for “abolition” of the auction process.
“NCPA does not at all support doing away with the CRR auction, which is an integral part of the risk mitigation services we provide our members,” the agency wrote.
Pacific Gas and Electric, the state’s largest investor-owned utility, said it was “eager” for the ISO to address CRR revenue inadequacy and “encouraged” by inclusion of the issue on the roadmap.
“In line with the DMM’s recommendation to assess the value of the CRR auction platform, PG&E hopes this initiative will provide an opportunity to consider and evaluate alternative solutions to CRR revenue inadequacy,” the utility wrote in its comments.
Opponents of the initiative include DC Energy, a proprietary trading firm focused on investments “related to the locational and temporal value and volatility in transport markets for power and natural gas,” according to the company’s website.
The company criticized CAISO for giving too much weight to the Monitor’s concerns about the auction issue when ranking the CRR initiative against other potential discretionary initiatives.
“DC Energy appreciates the need for CAISO consideration of DMM’s input,” the company said in its comments. “However, on its face, it appears that one stakeholder’s views were considered for its ranking, despite the volume of diverse comments received.”
The company said the Monitor’s analysis of the CRR market failed to focus on the benefits of the current system and that the ISO would be “best served” in considering various stakeholder and market perspectives when examining the market’s performance.
The current auction design provides a “superior opportunity for both price discovery and hedge acquisition” compared with a bilateral market, DC Energy argued.
“An entity seeking a hedge in the bilateral market might find it challenging or impossible to connect with a willing seller for an exact path,” the company said. “However, within the current CRR auction structure, network capacity is available to any qualified stakeholder, enabling liquidity and multiparty reconfiguration of electrical-location-specific (e.g., ‘nodal’) hedges.”
Western Power Trading Forum (WPTF), an interest group representing regional power traders, took DC Energy’s criticism a step further, contending that the Monitor’s “influence in the initiative-priority process belies [its] supposed independence and is contrary to [its] core functions” as set out in the ISO Tariff.
“WPTF contends that instead of devoting CAISO resources to a pet project of DMM, the CAISO should treat them like any other stakeholder who complained about a small aspect of the market that was naturally improving on its own — and ignore them,” WPTF wrote in its comments.
In support of that last point, the group pointed out that auction revenues as a percentage of payments increased after the ISO implemented practices that improved transparency into how it represents transmission outages in its market models. The Monitor’s findings indicate that the ISO took in 63 cents of auction revenue for every dollar paid out to CRR holders during the first half of last year. (See CAISO Monitor Seeks Congestion Revenue Rights Auction Reforms.)
In their comments, the Six Cities utilities appeared to anticipate the arguments of opponents of the initiative.
“The ISO should reject the efforts by recipients of the wealth transfers documented by the DMM to dissuade the ISO from addressing this misappropriation of the benefits of transmission assets paid for by ratepayers,” the utilities said.
LANCASTER, Texas — In a darkened room, seven video screens flicker to life. A crack of lightning lights up the darkness as the rumble of thunder suddenly explodes through six speakers in the ceiling and a sub-woofer in the corner.
That’s about the time most visitors have to be peeled off the ceiling.
“We like to give people a little jump … and we’re only running the [sound system at] about 60%,” Oncor Chief Technology Officer Michael Quinn says with an impish grin.
That’s a key part of the experience in the “Immersion Room” at Oncor’s Technology, Demonstration and Education Center (TDEC) on the plains south of Dallas. The facility is a peek into the grid’s future, showcasing almost three dozen vendors and their technologies and testing whether solar power, battery storage and microturbines can be integrated on a small scale to deliver reliable power to consumers.
Oncor’s Michael Quinn explains the TDEC’s three microturbines. | RTO Insider
“We want to immerse you in an outage,” Quinn explained. “Everybody who’s been in Texas a fair amount of time can appreciate a good old-fashioned Texas thunderstorm.”
The video begins with a somber voice: “This is life without electricity, without computers, without refrigeration. To meet the expectation of our grid today, we have to … reduce the length and frequency of power outages.”
The narrator then asks, “How do we create a more resilient, secure and even self-healing power grid? How do we integrate an increasing amount of solar and wind power to the grid? Perhaps most important, how do we achieve all this and keep your monthly bill affordable?”
Unlikely Tourist Stop
The facility has hosted more than 200 tours since opening in April 2015, including three busloads of engineers attending an Institute of Electrical and Electronics Engineers conference.
“We didn’t expect this to become a tourist destination,” said Oncor’s Don Clevenger, senior vice president of strategic planning, during the Gulf Coast Power Association’s fall conference in October. It’s Clevenger’s hologram that welcomes visitors to the TDEC with a recorded message.
The facility consists of four interconnected microgrids drawing their energy from nine distributed generation sources: two solar PV arrays, a microturbine, two energy storage units and four generators. Everything, it seems, but wind turbines — prohibited by a Lancaster city ordinance barring structures more than 35 feet tall.
The microgrids can be controlled individually or in tandem, and can be connected with the grid or operate independently. The generation resources are capable of providing as much as 989 kW in emergency situations, accounting for two-thirds of the facility’s total load. A fully functioning SCADA system controls the entire facility.
The onsite energy storage, which draws energy from Oncor’s feeders or any of the facility’s generation sources, provides the site’s voltage signal, enables renewable integration, controls the microgrid frequency and is the first generating source to respond during an unexpected loss of power.
“We use energy storage for reliability and grid purposes. That’s it, end of story,” Quinn says, disputing the notion Oncor is trying to “distort” the marketplace by becoming a generator. He says the utility has saved customers connected to the storage devices more than 39 hours of outages they would have likely experienced.
“If, through energy storage, we can make a [significant improvement] in the number of [outage] minutes you have, we think that’s the energy experience you want. We’re trying to get that right, and then propagate it.”
Oncor divides the TDEC into three zones: one comprising all the green-energy sources, another a meter shop with automated technologies and a third with traditional utility elements, such as diesel and gas generators.
“Taking the old and the new together,” Quinn says.
Few details go unnoticed. One panel in the control room has space for a future energy source, labeled simply “Future Source.”
A gray-on-white pattern and rounded edges help lend an illusion of openness to the Immersion Room’s 25×17 space giving it a sense of “cavernous intimacy,” as one Oncor director described it.
The TDEC has two sets of solar panels, one facing south and the other facing west. That allows Oncor to monitor the different paths and solar peaks during the course of the year. The panels can power the facility’s entire HVAC system and some of the lighting, besides providing covered parking. They’re designed to withstand 2-inch hailstones and 90-mph winds.
“Solar panels and hailstorms are not complementary,” Quinn notes.
Entertain and Instruct
The TDEC exists both to test new technologies and to simplify the grid’s complexity, helping vendors understand what Oncor does and how their products might serve the utility’s needs.
“We recognized we needed to try and influence the DER world, but before we could influence that world, we found out there was a fair amount of education that needed to happen,” says Quinn, comparing the Immersion Room to an “EPCOT-style” performance. “To get to education, we figured out we had to entertain you just a little bit before we got to that transfer of knowledge. If you’re bored with it, you’re not going to remember it.”
Quinn says one of his staff members — a screenwriter in his spare time — offered a suggestion on how to grab the viewer’s attention. “He said in the first 30 seconds, you have to have one of two things: either a love scene or an explosion,” Quinn says. “I knew the former would get me fired, so we did our best to get the explosion element.”
The video not only jolts the viewer with all the subtleness of a cattle prod, it also makes the grid’s complexity accessible to those unfamiliar with the industry, using everyday language to lay out its history and underscore the importance of reliability.
Understanding Storage
The idea for the TDEC came from Oncor’s discussions with energy storage vendors about price points and sales forecasts.
“We’d bring them in originally for conversations, to see if their project or product overlaps with our needs, and from there start talking about specifics,” Quinn says. “Do [the products] do what the vendor community suggests they’ll do? We wanted our own unbiased perspective.”
Oncor recognizes that DERs can be “parked” in different locations on the grid — behind the meter, or integrated in transmission.
“Our philosophy was to understand what all these resources do for the grid, and if they do something to the grid, let’s understand that too,” Quinn says. “Rather than react constantly to the change, let’s understand and anticipate the change, and then build an electric grid to facilitate it.”
Case in point: Oncor is currently testing three different energy storage devices, allowing the utility to compare and contrast performance for each one.
“You can see which one does better with lots of cycling, which one does better if you leave it dormant for six weeks,” Quinn says. “Those are different needs in the ERCOT marketplace.”
Quinn points to a 65-kW natural gas-fired microturbine — “about the size of a football” — housed inside a metallic container as big as a standard domestic refrigerator. The turbine is fueled by a half-inch supply line, “the same thing you have in your home,” he says. When operating, the turbine whirs at 96,000 RPM, emitting a high-pitched sound like a jet engine.
Exhaust comes out at approximately 800 degrees Fahrenheit, making the waste heat useful in providing warmth or other “facility needs.” Quinn says that more than doubles the unit’s efficiency. Combined with its size, who’s to say consumers won’t find a use for it?
“These will be part of the electrical infrastructure,” Quinn says. “Our philosophy is to understand how we interact with it before it gets here.”
Integrating DER with Legacy Components
The center also allows Oncor to test how emerging technologies work with each other and the grid’s legacy components. Quinn uses the example of buying a fully integrated vehicle to make his point.
“Toyota is going to have all Toyota parts in that vehicle, but that’s not what the electric ecological system is going to look like in the future,” Quinn says. “It’s going to have a Toyota chassis, Chevy brakes, a Lexus steering wheel, a Cadillac engine. So to take all those and work them from a safety and optimization and harmony standpoint … we think that’s pretty stinking important.”
Oncor TDEC Microgrid | Oncor
Quinn says Oncor has found the “controls element” of the integration experiment to pose the biggest issues.
“Most people’s individual battery cells work how they say [they] will. It’s the control of the [entire] system that’s much more challenging.”
Which begs the question: Does Oncor incent one kind of technology over another?
“We don’t make that distinction today, but I think it’s a fair question,” Quinn says. “It’s not what the customer gets out of it, but what does the grid get out of it?”
And what does Oncor, the largest transmission and distribution utility in Texas, get out of the TDEC?
A greater understanding of new technologies and how they mesh with the grid, but perhaps most important, an “optimized” grid that works better for Oncor’s customers.
“Excess” wires and generation translate into higher costs for customers, Quinn says. Reducing those costs can help the utility retain customers.
“If we can facilitate a low bill and facilitate the energy experience that you want, our thought is you’re going to stay connected to our service territory and Oncor.”
Click below for a promotional video by Oncor showcasing the TDEC.
CARMEL, Ind. — MISO is well-positioned to comply with FERC’s recent Notice of Proposed Rulemaking on fast-start pricing, RTO market design engineer Congcong Wang said at a Jan. 12 Market Subcommittee meeting.
Wang said the first phase of MISO’s Extended Locational Marginal Pricing (ELMP), already implemented, fulfills all the NOPR’s criteria. The second phase will expand the fast-start definition to online units with a one-hour start-up time. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)
MISO is currently drafting Tariff redline changes and hopes to post them publicly by Jan. 20, Wang said. Phase two of ELMP should be in place by May 1.
MISO IMM Warns Again of PJM Pseudo-Ties
MISO’s Market Monitor continues to be “very concerned” about the growing number of generators pseudo-tying into PJM.
In a recently issued report, Monitor David Patton identified several events during the period “where congestion management was negatively impacted by pseudo-tied resources.” Patton still advocates for MISO to develop a firm capacity delivery procedure to replace pseudo-ties.
Patton noted that MISO’s firm capacity delivery proposal — offered to PJM staff early last year — was “unilaterally” opposed by the neighboring RTO. He said he is not aware of any proposal developed by PJM.
“You could make the argument that PJM is not complying with FERC,” Patton said. He added that he didn’t blame MISO for the lack of action, as the RTO is not able to prohibit pseudo-ties unless there is a reliability concern or a transmission issue.
“Lights aren’t going to go out — it’s just going to be a lot more expensive to manage the congestion,” Patton said. “I don’t think on an economic basis, MISO can say, ‘We’re not going to allow pseudo-ties.’”
Last October, Patton said that he and MISO were considering opening a Section 206 proceeding against PJM to force a Tariff change, but they were discouraged by MISO’s board, which cautioned against “weaponizing” FERC filings. (See MISO Agrees to Implement Most of IMM’s Recommendations.)
MISO may retire its Credit Settlements Working Group because of a lack of substantive work and stakeholder volunteers willing to chair the group.
A motion to retire the group at its Jan. 10 meeting failed when stakeholders decided against altogether disbanding a forum dedicated to credit settlements, outgoing CSWG Chair Matt Pringle said. Stakeholders instead called for future educational conferences related to credit settlements.
“There’s been a lot of value in this working group over the years, and I think it should continue on in some form,” Pringle said.
The CSWG’s next meeting is tentatively scheduled for April, but it’s still unclear whether it will take place. The group met just three times in 2016.
MISO stakeholder relations representative Alison Lane said the working group could be repurposed into a user group, which means fewer meetings. Market Subcommittee liaison Jeff Bladen said credit settlement topics also could be handled by his subcommittee in the future.
Additionally, MISO’s Real Time Settlements Task Team was retired after the group completed work on Tariff changes for five-minute settlements. The RTO filed with FERC to implement five-minute settlement dispatch intervals on Jan. 11.
NextEra Energy, which received FERC approval of its $21 billion bid to acquire Oncor earlier this month, is still facing questions on the deal from Texas regulators and calls for more protections from stakeholders.
The Public Utility Commission of Texas, which is scheduled to hold a hearing on the merits of the proposed acquisition Feb. 21, issued a seventh set of questions to the companies Jan. 11. The commission must render a decision by April 29 (Docket No. 46238). (See Texas PUC Sets Questions in NextEra-Oncor Merger.)
The PUCT staff’s latest questions focus on credit ratings and NextEra’s funding plan for the acquisition.
Several stakeholders also filed comments on the acquisition last week. The Texas Energy Association for Marketers urged the commission “to ensure that there are no impediments to competition and no cross-subsidization from the transmission and distribution utility to competitive affiliates of the utility.” It asked the commission to change a commitment prohibiting co-branding of the utility with a competitive affiliate to improve its “clarity [and] enforceability.”
NRG Energy called on the commission to “expand the protections that have been in place since 2008 in recognition of the greater challenges posed by the conflicts and incentives created by” NextEra’s proposed corporate structure.
It said the commission should prohibit NextEra from connecting generation to the Oncor transmission system and require NextEra to divest its retail electric providers to ensure it does not favor them over competitors.
NRG also asked regulators to require transmission and other capital projects above a certain cost threshold — NRG proposed $50 million — be approved by the commission, with cost caps and post-completion prudency reviews.
“This requirement is especially important given the potential that Oncor would have competitive generation affiliates and the fact that Oncor would be inherently incented to build transmission to optimize the delivery of power from its affiliated wind resources from neighboring transmission systems,” NRG said.
The PUC last year scuttled Hunt Consolidated’s attempt to acquire Oncor — the transmission and distribution subsidiary of bankrupt Energy Future Holdings (now Vistra Energy) — when it imposed conditions that caused Hunt to back away from its proposal. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
NextEra had no comment on the impending hearings or FERC’s approval. The commission’s Jan. 5 order found the Florida-based company’s proposed deal in the public interest (EC17-23).
While Oncor operates within ERCOT, it owns a 100-MW interest in a HVDC tie between the Texas ISO and SPP. Oncor also provides transmission service over ERCOT’s North and East interconnections and the Rio Grande Valley interconnection under a FERC tariff.
FERC accepted the companies’ assertions that the acquisition would not incent NextEra to exercise market power and that Oncor’s facilities are subject to FERC open access rules.
VALLEY FORGE, Pa. — On the day PJM submitted its five-minute settlement compliance filing to FERC, the Market Implementation Committee endorsed two proposed Manual 11 revisions related to shortage pricing, both of which were developed in response to FERC Order 825.
The order requires RTOs to align their settlement and dispatch intervals and implement shortage pricing as soon as a reserve shortage is detected in real time, rather than the current practice of allowing an RTO to wait until it has determined that the shortage will last for a sustained period of time.
Stakeholders asked PJM to perform a comprehensive review of the proposed manual changes — which would adjust the operating reserve demand curve — to ensure that all potential impacts are considered. Members were particularly concerned about whether the new three-step shortage pricing created any opportunities to take advantage of the system, or if it affected any existing market rules.
PJM believes the demand curve changes are necessary in order for it to appropriately implement Order 825’s five-minute interval requirement. The RTO hopes to submit revisions as a Section 205 filing sometime around March 1.
The revisions would insert an additional step in the curve at the $300 penalty factor allowing the reserves to be “extended” or increased. Under current practice, PJM can only extend reserve requirements in specific situations related to the issuance of hot or cold weather alerts. (See “Protocol Changes Proposed for Implementing Order 825,” PJM Market Implementation Committee Briefs.)
Citigroup Energy’s Barry Trayers asked whether the new steps would affect the “Four-Tick Rule,” which affects how some costs, such as balancing uplift charges, are allocated based on the number of intervals within an hour that certain conditions exist. PJM’s Dave Anders said that issue is being discussed through the Energy Market Uplift Senior Task Force.
“It seems like we’re finding [issues created by the new rules] instance by instance, and it might be better if somebody went through and … found [all of] the impacts,” Trayers said.
Other stakeholders asked about the potential for “opportunistic behavior” among some market participants if shortage pricing is implemented without simultaneously switching to five-minute settlements. PJM Independent Market Monitor Joe Bowring acknowledged that there is no rule against such activity, but he said “if people are taking advantage of that rule, we will refer them to FERC.”
While Order 825 specified a May 11, 2017, implementation date, PJM is requesting that its proposals on five-minute settlements and shortage pricing be implemented simultaneously on Feb. 1, 2018. The compliance filing seeks a response from FERC by Feb. 15.
If FERC approves the delayed implementation date, PJM would relax its timeline for the Section 205 filing related to the demand curve until April. Otherwise, it will keep its March 1 target for the filing and request that shortage pricing be implemented simultaneously with five-minute settlements.
PJM Gives First Take on NOPRs
PJM staff offered their initial impressions of two Notices of Proposed Rulemaking recently distributed by FERC.
One NOPR addresses price-setting related to fast-start resources, while the other considers rules for storage and distributed energy resource aggregation.
The fast-start NOPR issued on Dec. 15 has five proposed requirements to better integrate fast-start units in market pricing. PJM’s Lisa Morelli said the commission will likely need to expand its fast-start definition to cover resources with start-up times of an hour or less in order to realize intended benefits. The proposed rule limits the definition to units capable of ramping up within 10 minutes.
“We really have minimal resources that fall into the 10-minutes-or-less bucket,” Morelli said.
PJM’s response to FERC will clarify that it believes the fast-start category also applies to demand response. The RTO also believes that FERC intends for the rule to provide more flexibility for block-loaded resources such as combustion turbines, but Morelli said staff think disincentives for over-generation will be need to developed. RTO staff also have “some hesitation” about FERC’s proposal to allow offline resources to set the fast-start price, she said.
To fulfill FERC’s final proposal on including fast-start pricing in both day-ahead and real-time markets, PJM would focus on keeping the modeling and rules appropriate for each market, although not necessarily the same.
“In general, we like to keep the modeling consistent,” Morelli said, but she acknowledged the RTO is “not guaranteeing” it.
The deadline for filing comments is Feb. 28.
The DER and storage NOPR issued on Nov. 17 includes multiple proposals.
“It’s pretty broad,” PJM’s Andrew Levitt said. “Even within those sections, there’s quite a lot in play.”
Regarding the storage provisions, “PJM has already checked a lot of those boxes,” he said. The NOPR could be read to indicate that RTOs should be managing the state of charge for new offers, and “that’s something we’re chewing on internally.”
The DER section has prompted an “extensive” discussion about coordination with electric distribution companies, Levitt said.
Several stakeholders representing state interests expressed reservations about the proposal.
“In general, we states like to keep our hands on the mechanisms that control retail, and FERC [and RTOs] handle wholesale,” said Debbie Gebolys, a research analyst with the Public Utilities Commission of Ohio. “If we’re going to have them at the same party, how do we handle that?”
John Farber of the Delaware Public Service Commission said that debate is a “touchstone issue” because it’s not possible to “unmingle electrons.”
“Unless that issue is fully satisfied, it could create problems for states,” Farber said.
Levitt acknowledged the concerns. “We’re recognizing there’s much closer contact between retail and wholesale with DER.”
Problem Statement Endorsed to Address Pseudo-Tie Meter Correction
Stakeholders endorsed by acclamation a problem statement and issue charge proposed by the North Carolina Electric Membership Corp. to develop a protocol for monthly pseudo-tie meter correction.
Currently, no mechanism exists for monthly corrections of reported energy flow. Dave Pratzon of GT Power Group questioned whether the issue will be solvable within PJM or require collaboration with neighboring RTOs. PJM’s Ray Fernandez acknowledged that the question will be addressed in the research performed by the Market Settlement Subcommittee.
Spot-in Transmission Analysis Expanded to all Interfaces
Stakeholders approved revisions to a problem statement and issue charge intended to address spot-in transmission issues, expanding the analysis to consider all of PJM’s interfaces, not just that with NYISO.
The committee has already identified two potential solutions.
The first, more complex solution would entail NYISO modeling PJM’s available transfer capability (ATC) alongside its own in the ISO’s economic clearing engine. Spot-in transactions would then be allowed to clear economically up to the lower of the transfer values.
The second solution would move PJM’s earliest request time for spot-in service to 10 a.m. from the current 9 a.m. The delay would allow potential market participants to learn if their NYISO bid has been approved before requesting service into PJM. While this option would be easier to implement and easier to apply universally, it doesn’t directly address the issue.
Joe Wadsworth of Vitol, who has long sought resolution of the issue, prefers the first solution. “We wouldn’t oppose solution ‘B’, but it doesn’t get to the heart of the situation,” he said.
PJM Has No Objection to IMM’s ‘Paper Capacity’ Report
Bowring presented updated results of his team’s ongoing study on replacement capacity. The report found that some market participants are offering “paper capacity” into Base Residual Auctions and buying out of the obligations during subsequent Incremental Auctions to take advantage of price differences. (See PJM Monitor Asks FERC to Act on ‘Paper Capacity’.)
EnerNOC’s Katie Guerry contended that Bowring hadn’t sought comments from stakeholders before publishing the report and filing it at FERC. She asked what PJM’s stance was on the topic.
“Generally speaking, we don’t disagree with the report,” PJM Senior Counsel Jen Tribulski said. “We wouldn’t file anything with FERC to say we disagree with the report.”
PJM is proposing rules that would exempt certain substation equipment from competitive bidding because issues stemming from existing components are typically resolved by equipment upgrades, Mark Sims, transmission planning manager for the RTO, explained during last week’s Planning Committee meeting.
Exempting those types of upgrades, which won’t result in greenfield proposals, from competitive bidding will prevent the process from becoming overly complicated, PJM believes.
While transmission-level transformer upgrades were initially listed in the scope, they have been removed from the proposed rules. Instrument-level transformers will be exempted.
If the analysis shows that a greenfield project is possible, PJM would open a competitive window, Sims said.
“We wanted to avoid situations where we had to make a lot of judgements,” said Steve Herling, vice president of planning.
Gas, Solar Lead Interconnection Queue as PJM Seeks to Streamline Process
Natural gas generation represents the majority of projects seeking interconnection since 2011, although solar is quickly increasing, according to a queue analysis presented by PJM’s David Egan.
Solar projects are typically seeking 60 to 70% capacity interconnection rights — or even more for those utilizing panel-tracking technology, Egan said. Tens of thousands of additional megawatts remain in the queue, partly because PJM receives more than a third of interconnection requests the day before the queue closes, with more than half of them arriving within the final week. PJM is working on ways to increase earlier submissions.
“We’re actively trying to relieve that backlog,” he said.
“These numbers are way down from where they were several years ago,” Herling said. “We’ve made substantial progress, but there’s more work to do.”
PJM Largely in Compliance with Interconnection NOPR
PJM has already implemented many of the rules proposed in FERC’s Dec. 15 Notice of Proposed Rulemaking on generator interconnection, Aaron Berner, manager of interconnection analysis, said during an explanation of the new proposal.
Among the many provisions, the NOPR would require transmission providers that conduct cluster studies to develop a periodic restudy process; modify large generator interconnection agreements to require that transmission owners and interconnection customers mutually agree to have the owner opt to initially self-fund the costs of network upgrades; and require RTOs to establish an interconnection dispute resolution process.
The new rules would improve certainty, transparency and other aspects of the process, Berner said. The proposal comes after the American Wind Energy Association filed a petition with FERC that prompted a technical conference on the issue.
The RTO has no protocols for NOPRs, PJM’s Dave Anders explained, but it does have precedent. With the need to review and respond within 60 days after the notice is published in the Federal Register, going through the stakeholder process will likely take too long, he said.
Load Estimates Drop in Mid-Cycle RTEP Assumptions
The long-term proposal window for the 24-month market-efficiency cycle of the Regional Transmission Expansion Plan closes Feb. 28, PJM staff told stakeholders during last week’s Transmission Expansion Advisory Committee meeting. The mid-cycle window, open from January to April, will update major assumptions, including load and demand forecasts, fuel prices, generation expansion and topology. Proposals will be reviewed until October, with final determinations published in December.
The mid-cycle updates include a drop in expected annual peak load compared with last year’s forecast, with 2031’s projection down 5%.
Sue Glatz, PJM manager of infrastructure coordination, confirmed that projects already under construction based on old assumptions won’t be scrapped if they aren’t economic under the new ones. Paul McGlynn, senior director of system planning, said most approved RTEP projects have such a healthy benefit-to-cost ratio that a slight load change won’t make much of a difference.
Additionally, Baltimore Gas and Electric’s Crane generating units and Exelon’s Quad Cities have withdrawn their deactivation notifications.
Artificial Island Finalists to Be Announced at Special TEAC
PJM plans to recommend at least two finalists when it presents its re-evaluation of the Artificial Island project to the Board of Managers in April, Herling said. Staff are nearly done with reanalysis of the project, PJM’s first competitive solicitation under Order 1000, and are developing a “fairly substantial document” to present to the board. Herling said his staff will schedule a special meeting of the TEAC to go over the plans.
The document will address issues previously raised by stakeholders, and changes to the project’s scope will reduce project costs by about $130 million, Herling estimated. However, the reanalysis will not address cost allocation, which has been a contentious issue with stakeholders.
Requests for Information Dominate TEAC
Staff’s review of RTEP proposals elicited a barrage of questions — and requests for the RTO to provide more information.
American Municipal Power’s Ed Tatum led the inquiry, repeatedly asking what criteria made certain proposals preferable and why alternatives hadn’t been considered.
He said that American Electric Power had provided a “nice document” explaining its infrastructure-replacement process and guidelines in response to his questions from previous TEAC meetings. “This is a good start, and we look forward to getting more detail,” Tatum said.
LS Power’s Sharon Segner questioned why certain projects hadn’t been opened to a competitive bidding window.
“I don’t think it should be an automatic assumption that just because something is ‘immediate need,’ there is no window for it because that’s not what the tariff says,” she said.
PJM’s Mike Herman said staff will attempt to indicate whether a project should be subject to competitive bidding.
Stakeholders were also concerned about additions to the Bergen-Linden Corridor project in Public Service Electric and Gas’ northern New Jersey district.
PJM is recommending that four shunt reactors be installed to add 600 MVAr of reactive power to address potential voltage violations after the current project is constructed.
Jim Jablonski, executive director of the Public Power Association of New Jersey, asked how the project, which already has a $1.2 billion price tag, produced another $90 million in costs.
PSE&G’s Esam Khadr explained that retirement of generating units with reactive capabilities has been a major driver of the additional issues. Building underground is the only option in the region because of congestion. However, underground circuits so close together act as capacitor plates that create high-charging and high-voltage problems, McGlynn said.
The Western Area Power Administration has selected a route for the TransWest Express transmission project, a proposed 730-mile, extra-high-voltage DC line designed to deliver large volumes of renewable energy into the desert Southwest.
The announcement comes a month after the U.S. Interior Department’s approval of the project — which would cross about 440 miles of Bureau of Land Management land — after eight years of environmental studies.
TransWest Express transmission line map | TransWest Express LLC
The proposed 600-kV line would run from south-central Wyoming, passing through Colorado and Utah and ending at the Marketplace Hub substation about 25 miles south of Las Vegas. That hub functions as a major wheeling point for transmitting power from the interior West into Southern California.
WAPA’s decision will enable project developer TransWest Express to proceed with design and engineering activities, as well as position the agency “to better evaluate its options for participation in or financing of the project,” the agency said in a statement.
The federal power marketing administration is supporting the project through its Transmission Infrastructure Program, which allows transmission developers to “leverage” the agency’s development experience and provides eligible infrastructure projects with access to federal financing.
“Collaboration between WAPA and energy developers is critical to developing infrastructure capable of meeting our nation’s growing energy needs while minimizing environmental impacts,” WAPA Administrator Mark A. Gabriel said. “This decision and comprehensive study provides the foundation to further the project’s development.”
TransWest Express is a subsidiary of the Denver-based Anschutz Corp., a privately held company with extensive investments in energy and real estate.
The project will boast 3,000 MW of bidirectional capacity when completed. The line’s primary function will be to allow loads in Arizona, California and Nevada to tap the output of planned wind resources in Wyoming.
Project specifications include two 200-acre AC/DC converter stations at each terminating point, a fiber optic network communications system and two 600-acre ground electrode facilities.
The project is expected to cost about $3 billion and take three years to complete after the start of construction. WAPA and BLM were the lead agencies in preparing the environmental impact statement for the project, which is still subject to approval from additional state and federal regulatory bodies.
VALLEY FORGE, Pa. — PJM staff last week outlined a proposal to lengthen the RTO’s Regional Transmission Expansion Plan cycle for reliability projects from 12 months to 18 months.
Staff explained the plan at a special session of the Planning Committee on redesigning the Transmission Expansion Advisory Committee.
The proposal comes in response to more detailed analysis of the optimal timing for the planning cycle, a component of the TEAC redesign that began about a year ago, staff said.
The expansion of the cycle — along with the development of a flowchart for how projects will move through proposal windows — would represent a “memorialization” of existing processes that have never been specifically defined, PJM’s Mike Herman said.
The proposed change would take effect for the 2018 planning year, moving the beginning of the cycle to September 2017. The RTEP cycle for market efficiency projects would remain unchanged.
Stakeholders expressed concern about the decisional-process flowchart and asked for additional transparency around why certain projects are rejected. They also sought more opportunities to provide input.
Staff acknowledged some of the concerns but pushed back on others.
Paul McGlynn, PJM senior director of planning, said it would be challenging to rank projects against each other because of the difficulty in comparing the relative benefits of dissimilar project factors.
Vice President of Planning Steve Herling provided a hypothetical example of the challenge: “There’s no way to show how much a perceived benefit is going to wipe away the ability to get a right of way through the Gettysburg Battlefield.”
Alex Stern of Public Service Electric and Gas questioned the wisdom of trying to incorporate all project drivers into a single comprehensive manual and warned that critical pieces might get “lost in the sauce.”
PJM staff acknowledged his concerns. “Ultimately, I’m less concerned about the format of the manuals than about the content,” Herling said.
Stern also suggested that PJM include a provision to limit the potential for selling a project before or after it’s built, which attorney Steve Huntoon warned might create “unintended consequences that raise risk.”
The next meeting on the issue is scheduled for Feb. 10.
CARMEL, Ind. — MISO is poised to implement a laundry list of changes intended to improve its capacity market, some of which should take effect in time for the 2017/18 Planning Resource Auction.
The most significant — and controversial — is a proposal that would apply a 50-MW physical withholding threshold to affiliated market participants on a collective basis, rather than to each affiliated company individually.
The RTO’s Independent Market Monitor recommended the change in its 2015 State of the Market report, contending it would prevent a supplier from avoiding mitigation by creating multiple affiliates to increase its withholding threshold. (See “MISO Takes 1st Steps in Monitor Recommendations,” MISO Resource Adequacy Subcommittee Briefs.)
MISO plans to file the change with FERC on Jan. 17, MISO Manager of Resource Adequacy John Harmon said during Wednesday’s Resource Adequacy Subcommittee meeting.
In light of the change, the Monitor will this year begin to review bids made by affiliated market participants during the offer window. Monitor staff will contact affiliates once to notify them of a violation, providing an opportunity for violators to resubmit offers. Affiliates that continue to exceed the 50-MW threshold after the offer window closes will be subject to sanctions.
“It’s important to remember the offer window is a three-day window,” Harmon said. “Most offers are received on the first day, but there are three days” to submit offers.
Monitor staff member Michael Chiasson said the Monitor will not tell affiliated companies the specific volume of their collective shortfall of offers.
“It’s on or off, like any other light on the dashboard,” Chiasson said. Penalties will be identical to sanctions already detailed in Module D of the Tariff, which include fines, ineligibility for revenue sufficiency guarantee payments, bans on submitting virtual transactions or a condition that all of a company’s power requirements be scheduled in the day-ahead market.
Chiasson noted that the Monitor will notify violators of shortfalls by phone or emails and rely on contact information from the operating cost survey contact list and MISO’s official market participant registry.
“I just worry about the nightmare scenario that you’re calling and no one is picking up the phone,” said Jamie Watts, an attorney with the Long Law Firm.
Harmon said that MISO would not simply “leave a voicemail with a random individual and then shrug our shoulders.”
Some stakeholders are still wary of the change, maintaining that FERC Order 697 already prohibits affiliates from colluding to dodge withholding mitigation.
“I’d love to see what antitrust officials think of this,” said David Sapper of Customized Energy Solutions. “But that’s not relevant — or it might be.”
Tariff Clarifications
MISO will revise Module D of its Tariff to allow planning resources to request facility-specific reference levels for the auction. Offers for resources that make no such request will be set to $0/MW-day, as required by FERC. (See FERC OKs MISO Use of PJM Cost Estimates for Mitigation.)
Because a cost of new entry conduct threshold continues to apply to the auction’s initial reference level, the Monitor recommends that all resources whose competitive cost of selling capacity exceeds $26/MW-day request a facility-specific reference level. The RTO and Monitor are also proposing to exempt demand resources, energy efficiency resources and external resources from mitigation measures. The changes will be filed Jan. 17.
One stakeholder contended that resources external to the RTO should also be subject to mitigation, but MISO pointed out that external resources have no obligation to offer into the market and should not be discouraged from volunteering offers at their own prices.
The RTO has yet to establish an effective date for the changes because the filing will be made so close to auction registration, according to Jacob Krouse, MISO’s corporate counsel, but implementation could occur in time for the 2017/18 auction.
Indianapolis Power and Light’s Ted Leffler said the new reference levels were confusing. “I’m hearing zero, 10% of cost of new entry, and it all seems to be a bit of mush to me,” he said.
North-South Limit Calculation Specified
MISO will update its Tariff to specify a method for calculating transfer limits of flows between its North and South regions that cross SPP’s system, as directed by FERC late last year. (See FERC Backs MISO on Transfer Limit, Seeks Details.) The new provision will direct RTO staff to determine a megawatt limit by reviewing seams, transmission service and coordination agreements. Transmission providers will then be required to conduct a feasibility analysis to determine whether tighter limits are needed.
Harmon said MISO will submit a compliance filing by the end of the month (EL16-112), but the RTO is open to receiving stakeholder feedback up until Jan. 20.
Chiasson objected to the subtraction of all firm transmission service in determining the calculation for the limit and encouraged MISO to study the probability of actual firm transmission use to come up with a more accurate limit.
“When capacity import limits and capacity export limits are determined between [other MISO] zones, those determinations don’t use any firm transmission reservations,” Chiasson said. “We think that should also be true for limits between the North and South regions.”
The Monitor is likely to protest the filing, he added.
For the FERC directive to develop going-forward costs for facility-specific reference levels, also contained in the transfer limit order, MISO will use two years of data and a formula in which the hypothetical cost of suspension or retirement at the beginning of a planning year is subtracted from costs incurred during a 24-month period if the resource retires or suspends at the end of the planning year. MISO defines going forward costs as the sum of operations, administrative, taxes and insurance, maintenance and capital expenses.
Harmon said the calculation will become effective in time for the 2017/18 auction. While FERC did not require a specific deadline for implementation, the order did stipulate that the changes become effective in “future planning years.”
Dynegy’s Mark Volpe objected to the short gap between the filing and effective date, as many auction data collection deadlines occur on Feb. 15.
“Now you’re telling us that you’ve only got two weeks to change gears,” Volpe said. “You’ve led us to believe it was on a prospective basis for the 2018/19 Planning Resource Auction. … Now you’re saying it’s the seventh inning and we’re going to switch the rules.”
Chiasson said market participant data requirements are largely unchanged from prior years, adding that the Monitor has already asked for two years of planning data.
“I don’t think it will be work wasted,” Chiasson said. “But it would have been nice to know before the work started.”
Tim Bachus, MISO capacity market administration analyst, said the 2017/18 PRA is on schedule. He said 94% of market participants have submitted data for the Generator Verification Test Capacity reporting.
MISO is considering other improvements for the PRA — in addition to a proposal for seasonal categories and six new external resource zones — while awaiting FERC’s verdict on a request to implement a bifurcated capacity market.
Harmon said the RTO is seeking stakeholder evaluation of five potential changes, including:
Penalizing participating units that expect to be on planned or forced outages for most the planning;
Relaxing auction accreditation rules for hydroelectric assets that serve as load-serving entities, rules that MISO says might be too “onerous” and might not recognize capacity benefits;
Improving the partial unit clearing algorithm, which Harmon says clears marginal offers on a pro rata basis “that can result in resources clearing a small percentage of their unforced capacity, resulting in capacity revenue less than their costs”;
Creating a capacity accreditation formula for battery storage before widespread adoption of batteries occurs; and
Clearing up MISO rules and the Tariff with respect to treatment of behind-the-meter generation in the capacity auction.
Chris Plante of WEC Energy Group asked if any of the improvements could be implemented by the 2017/18 planning year.
With stakeholder support, improvements will be discussed throughout 2017 and implemented in the 2018/19 planning year, alongside the first separate forward capacity market for retail choice areas, Harmon replied.
MISO has sidelined the discussion of seasonal and locational auction issues until February, RASC liaison Shawn McFarlane said.
“Certainly the [Competitive Retail Solution] is the primary objective and we need to get that through before we tackle too much, but we’re looking at other resource adequacy improvements, including seasonal and locational improvements,” McFarlane said.
Leffler questioned whether seasonal constructs should continue to be a priority, given that stakeholder support has cooled since MISO revealed design specifics last year.
“I’d encourage people to provide that feedback,” Leffler said to stakeholders.
