The entry of Arizona Public Service and Puget Sound Energy into the Western Energy Imbalance Market was largely “uneventful,” according to a CAISO official who helped lead the effort to integrate the two utilities into the region’s only real-time market.
“I’ve been through three sets of transitions, and I would say that each one is getting smoother,” Mark Rothleder, the ISO’s vice president of market quality and renewable integration, said during an Oct. 5 meeting of the EIM’s governing body.
Still, Rothleder noted that it took a “huge amount” of work on the part of CAISO to guide the Oct. 1 rollout, which required about 30 staff to be present at the ISO’s Folsom, Calif., headquarters while others joined APS and PSE at their operations sites.
“We found that the APS and PSE teams were very well prepared,” Rothleder said.
APS brought on 16 new hires, created four new operations and trading desks, and undertook 9,000 hours of training related to the EIM, said Justin Thompson, the utility’s director of resource operations and trading. Utility staff had been testing systems since late winter.
“My recommendation to our execs was that you need 20 months to execute this,” Thompson said. “We shoehorned it in 15 to 16 months, and I wouldn’t recommend that for anybody.”
Four days into the transition, Rothleder said that it was “not unexpected” that the ISO had observed price volatility. Staff are still reviewing the issue to determine whether it reflects actual system conditions or stems from a data anomaly or software problem in need of correction.
| CAISO
Delving into the operational underpinnings of the EIM, Rothleder explained that each balancing authority area (BAA) participating in the EIM needs to pass two tests heading into every hour.
The first: A BAA must be balanced between generation and load in order to match its forecast.
The second: It must demonstrate enough ramping capability or resource flexibility to meet expected variability within the hour.
“These two tests are an indication that they’re coming into the system sufficiently resourced without leaning on other parts of the system,” Rothleder said.
During the first four days of participation in the EIM, APS and PSE passed the balance test 95.8% and 100% of the time, respectively. Both utilities have so far rated 100% on the flexible ramp test.
“These are very good results — and don’t take 95.8% as an indication that anything’s wrong,” Rothleder said, adding that it can take time for a utility to adjust to the “new paradigm” of the EIM.
According to Rothleder, APS has so far shown good price convergence between the EIM’s 15-minute and five-minute markets, which have yielded averages of $16/MWh and $20.50/MWh, respectively.
The PSE system experienced more price volatility during the first day, but the market stabilized after that, Rothleder said.
PSE’s prices have been in the “normal range,” averaging in the upper teens to mid-$20s/MWh, “which is consistent with the [bilateral] market,” said Josh Jacobs, director of load-serving operations at PSE. “So that’s a good result.”
Arizona boasts ample transfer capacity with its three EIM neighbors – CAISO, NV Energy, and PacifiCorp. | APS
Day Four in the market also saw Arizona real-time price averages dip into negative territory, which CAISO attributes to maintenance-driven transmission constraints in Southern California trapping generation in an area currently experiencing low seasonal demand.
“This is the role of the Energy Imbalance Market — to absorb some of that energy which can then go somewhere else at those times,” Rothleder said. “If we didn’t have transfers to APS for that energy from the south, we would’ve probably been economically reducing — or potentially curtailing — renewable resources because there was too much energy at the time relative to the transmission constraints that were binding.”
Rothleder pointed out that the APS system boasts “quite a bit” of transfer capability.
“We can transfer a lot back and forth with PacifiCorp, NV Energy and the California ISO,” Thompson noted. “We’re kind of the freeway of the EIM system there.”
“Transfer capability is really the grease that makes the Energy Imbalance Market work well,” Rothleder said.
WASHINGTON — Seattle officials Monday deferred action on a proposal by the city-owned utility to join the Western Energy Imbalance Market. Seattle City Light could become the sixth utility to join the CAISO-run EIM, following recent additions Arizona Public Service and Puget Sound Energy, which began EIM operations Oct. 1, and Portland General Electric, which is scheduled to join in 2017. (See related story, Smooth EIM Transition for Arizona Public Service, Puget Sound Energy.)
An official of the Seattle utility joined several other Western energy leaders at the Energy Bar Association’s Mid-Year Energy Forum last week to discuss the growth of the EIM, “Caliphopia” and how the Western Interconnection is likely to change.
To Robert W. Cromwell Jr., director of regional affairs and contracts for Seattle City Light, the math of joining the EIM is a no-brainer. Cromwell said it will cost the city $8.8 million to join the EIM and $2.8 million a year in operating costs. The payoff? An estimated $4 million to $23 million in annual savings through arbitrage opportunities by “capturing low prices to serve load [and] high prices to sell surplus energy.”
Cromwell said the utility differs from other public power companies because its large hydropower facilities on the Skagit and Pend Oreille rivers “force us to sell into the market.”
He said the utility also is pressured by declining wholesale revenue — a trend likely to worsen as growing wind and solar power create more frequent periods of zero and negative pricing — and declining retail loads. “I’ve got about 60 tall cranes [constructing] very large buildings in my city and my load went down,” he said.
On Monday, the Seattle City Council delayed a vote on the EIM initiative for three weeks. The bill would allow City Light to enter an exploratory phase for joining the EIM, but some council members were concerned about the costs of doing even that.
Jonathan M. Weisgall, vice president of legislative and regulatory affairs for Berkshire Hathaway Energy, also sees the advantages of regionalization as undeniable. Pointing to a map showing the 38 balancing authorities in the Western Interconnection, he joked, “To call this Balkanized is to insult Macedonia.”
Bilateral trading with manual dispatch and little situational awareness of other BAs is like using Craigslist, he said. The EIM, he said, is like “Match.com for electrons,” with five-minute dispatch, which is more accommodating for renewable generation.
Berkshire Hathaway’s NV Energy and PacifiCorp have saved $60 million since joining the EIM — a 20-month information technology project, Weisgall said, that required no new physical infrastructure.
Not everyone is rushing to join CAISO’s expansion, of course. For some, any sentence containing the words “California” and “energy” sends shivers. It’s not just the state’s liberalism but also memories of the 2000 energy crisis and Enron, which purchased Portland General Electric before imploding following disclosures of accounting and power trading frauds.
“The Northwest didn’t forget. Memories are long up there,” said Jonathan D. Schneider, of Stinson Leonard Street, who moderated the discussion.
Weisgall acknowledged that what he called “Caliphobia” is a challenge to a West-wide RTO.
“You’re trying to marry three incredibly blue states — California, Oregon and Washington — where it’s almost a felony to produce coal — with three very red states — Wyoming, Idaho, Utah — states that do not care about getting to 50% renewables much less … about greenhouse gas emission programs,” he said. “That makes it very, very tough.”
“We should not underestimate the challenge of getting there,” agreed Kenneth G. Jaffe, a partner with Alston & Bird, who represents CAISO.
“There are a large number of public power brethren in the Northwest who simply will not join a centrally cleared market before they die,” agreed Cromwell.
He noted efforts by Xcel Energy and others to create a Day 2 market in the Front Range in central Colorado and southeastern Wyoming, which he predicted will be operated by SPP or MISO. “The Cal-ISO isn’t the only game in town. (See “Xcel Seeking Larger Dispatch Areas in the West,” Overheard at the Transmission Summit.)
In addition to the political challenges and governance questions, another obstacle to an RTO West has been the Pacific Northwest’s bounty of rivers. Cheap hydropower represents about half of the power generation in the Northwest.
That’s “one of the reasons why a standalone market in the Northwest hasn’t penciled out the way it would in a somewhat more diverse resource base as is so in the east,” Schneider said.
“If you’ve got a local public utility district and your embedded costs of delivering power is about 2 cents/kWh … [any change] is a cost adder,” agreed Cromwell.
Nevertheless, the Bonneville Power Administration has been seeking ways to collaborate with CAISO, said Sonya Baskerville, manager of BPA’s national relations office. The agency is concerned with serving BPA load located within BAs that have joined the EIM as well ensuring it has outlets for marketing surplus energy.
“We can’t just sit by and let things roll on without being a player in that. We are having active conversations with the Cal-ISO, with other utilities in our region to talk about our primary goal, which is to preserve the value of our system — both hydro and our federal transmission system,” she said.
Central to any agreement would be a governance structure that preserves BPA’s financial and operational interests, Baskerville said.
NYISO last week forwarded to New York regulators 12 proposals for transmission projects to help the state meet its public policy objectives (16-E-0558).
The proposed projects, coming at the start of the ISO’s 2016/17 transmission planning cycle, would provide the state with access to offshore wind resources off Long Island, Canadian hydropower and clean energy from PJM. There are also proposals to unbottle clean energy from upstate production areas that are distant from load centers.
| NYISO
The proposals follow the Public Service Commission’s adoption of a Clean Energy Standard that seeks to overhaul the state’s generation fleet by producing 50% of its energy needs from renewable resources by 2030. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
New York has other public policy initiatives to decarbonize its generation, including its Reforming the Energy Vision initiative, the Clean Energy Fund and compliance with the federal Clean Power Plan.
‘Holistic’ Approach Sought
New York City said a holistic approach is preferable to evaluating individual projects in isolation. “Identifying a single transmission line, or a segment of a line, as a need driven by public policy requirements is insufficient to achieve the state’s public policy goals, and such a piecemeal approach could effectively prevent timely achievement of those goals,” it wrote.
HQUS, a subsidiary of Hydro-Quebec, said proposals to import hydropower could satisfy much of the state’s requirements under the CES. “For example, a new 1,000-MW DC transmission project can deliver up to 8.7 TWh of incremental renewable energy to New York, nearly one-third of incremental renewable energy needed to meet the 2030 target.”
A joint filing by the New York Power Authority, National Grid and Central Hudson Gas & Electric, said the key to satisfying the goals is unlocking bottlenecks in northern New York that limit access to Canadian imports and wind and hydropower along the Saint Lawrence River.
“The possible addition of over 1,000 MW of new wind projects in northern New York, as reflected in the NYISO interconnection queue, potential increased renewable imports from Canada, and possible additional load reductions could exacerbate transmission constraints in delivering clean, renewable energy and its environmental benefits to the state’s load centers,” the filing said.
Transparency Concern
Competitive transmission developer NextEra Energy Transmission New York expressed concern that incumbents could hold advantages in any solicitation for projects.
“Regardless of whether the renewable assumptions include new wind generation and solar development in western New York or northern New York, or increased imports from Canada, all assumptions should be made public so that all transmission developers can begin on a level playing field,” NextEra wrote.
| Anbaric Transmission
Developers from outside of New York praised the CES provision that gives equal footing to projects from outside of the state. “Adding new transmission capability from PJM will facilitate delivery of the associated hourly matching energy to downstate loads, thereby helping reduce in-state transmission bottlenecks. Access to transmission-enabled, least-cost renewables is critical for New York state to meet the CES while minimizing ratepayer impacts,” wrote Poseidon, the developer of the proposed 500-MW Poseidon Transmission project, a 78-mile underground and undersea HVDC cable from South Brunswick, N.J., to Long Island.
Offshore Wind
PSEG Long Island, which operates the island’s distribution grid, said it and the New York State Energy Research and Development Authority are evaluating scenarios for delivering up to 4,000 MW of offshore wind.
“In all such cases, the offshore wind resources are likely to be distributed to several points of interconnection within [New York City and Long Island], with additional transmission system upgrades being required for deliverability to the rest of the New York Control Area,” it said.
PSC staff will review the filings and make recommendations to the commission.
In the previous planning cycle, which began in 2014, the PSC declared public policy needs for an AC project to serve the New York City area and one for western New York.
In response, the ISO issued a request for proposals in February for two projects in the Mohawk and Hudson valleys to deliver energy to load centers in and around New York City. (See New York Transmission Developers Ask FERC to Order a Do-over.)
CARMEL, Ind. — MISO is canvassing feedback on two Independent Market Monitor recommendations that seek to improve the Planning Resource Auction.
Manager of Resource Adequacy John Harmon said MISO agrees with the Monitor’s 2015 State of the Market recommendation to apply its 50-MW physical withholding threshold to affiliated market participants collectively, rather than to each individually. To do that, MISO would have to revise Module D of its Tariff, Harmon said at the Oct. 5-6 Resource Adequacy Subcommittee meeting.
The existing physical withholding framework allows a hypothetical company to increase its threshold by creating multiple market affiliates, according to the Market Monitor. | MISO
The Monitor has said its proposal would prevent a supplier from dodging mitigation by creating multiple affiliates to increase its withholding threshold.
Consumers Energy’s Jeff Beattie said he thought the proposal might be discriminatory, as his company cannot talk to its generation affiliates anyway because of requirements set by the Michigan Public Service Commission.
“It’s like Dynegy over there. I can’t collude with them!” he hollered across the room at Mark Volpe to lightheartedly make his point.
The Monitor’s proposal would subject a market participant and all of its affiliates to the threshold collectively. | MISO
Michigan PSC staffer Bonnie Janssen confirmed that both Consumers and DTE Energy have to file paperwork with the commission promising not to communicate with affiliates.
Harmon said MISO wants all stakeholder feedback by Oct. 21.
MISO is also tackling the Monitor’s 2013 suggestion to remove “inefficient barriers” for generators to participate in the PRA. The change would involve allowing a generation owner with an Attachment Y retirement request to participate in the auction and have the ability to postpone or cancel the retirement if it clears, which is not allowed under current Tariff language.
MISO adviser Neil Shah said the RTO will set aside time for discussions on the issue in future RASC and Planning Advisory Committee meetings to see if a rule change is warranted.
Minnesota Public Utilities Commission staff member Hwikwon Ham said he hoped changes to the rule would not further delay projects in MISO’s interconnection queue.
MISO to Move Ahead with Brattle Demand Curve for Forward Auction
MISO’s forward capacity auction proposal for merchant supply is nearly ready to be filed with FERC, and the RTO is using the final weeks to make presentations to support its stance.
| The Brattle Group
Jeff Bladen, MISO’s executive director of market design, said there have been more than 200 questions, comments and suggested edits since the redesign of the capacity market was first proposed. He said he didn’t anticipate “dramatic changes” at this point.
“We are closing in on that Nov. 1 filing date,” Bladen said. “It is late in the day to be bringing up issues, and we don’t anticipate new issues because we’ve gotten such a robust response so far.”
Bladen said the only unfinished business is MISO working with the Monitor to make any necessary additions to Module D Tariff language pertaining to the Monitor’s role in both the new auction and the PRA.
“In spite of the comments we’ve received, we’re still recommending the same curve,” Brattle analyst Sam Newell said.
Per stakeholder request, Brattle ran sensitivity analyses with higher price caps. Brattle analyst David Oates said moving the cap to 1.7 times net CONE moves the foot of the curve to the right but still manages to maintain reliability, at 109% of MISO’s planning reserve margin requirement. Moving the cap to two times net CONE results in procuring 106% of the planning reserve margin requirement.
But Oates also said that with higher price caps, price volatility increases by 30 to 80% compared with Brattle’s proposed curve. The two higher caps attract 100 MW and 220 MW, respectively, more merchant supply than Brattle’s 1,800 MW.
Newell again backed MISO’s forward proposal over the Monitor’s prompt, two-stage hybrid auction. “What most impresses me about this approach and the prompt hybrid that’s been discussed is that this approach allows all different suppliers to compete,” Newell said. “The hybrid proposal actually discriminates; it pays a much lower price to [regulated] supply than merchant supply. … It’s economic waste to buy a $150/MW-day resource when a lower-cost one is available.” He added that while relying solely on a sloped demand curve to price the marginal value of megawatts is “elegant,” it’s not realistic.
Jim Dauphinais of Illinois Industrial Energy Consumers said “it would make sense” to have a discussion to urge MISO to delay the Nov. 1 filing. “I’ll be frank: The word on the street is MISO is anxious to file this before FERC. The question is can some of these issues be worked out before the filing? There are certainly unresolved issues at this point.”
Dauphinais said delaying the filing to the end of the year might clear up issues. He is concerned that MISO’s Tariff language might be unclear, leading to a messy back-and-forth process with FERC, he said.
“I’ve also been walking on the streets and heard some people saying that,” Madison Gas and Electric’s Gary Mathis said. He said some were concerned that while implementation was delayed by a planning year, the filing date was only delayed by four months.
“I don’t think there’s uncertainty around the details. There’s disagreement about the details,” Bladen said. “It’s our conclusion that another month would not bring stakeholder consensus.”
Bladen said that MISO was already uncomfortable with the original “compressed” timeline to implement in planning year 2017/18. “The time we have in front of us is actually less than people realize,” he said. “We expect FERC to take 120 days to get back with an order. We expect it might well include guidance, maybe a technical conference; it might not. We need time to build the conclusion FERC orders. We have to have our systems up and running in the fourth quarter in 2017 in order to register units.”
Other stakeholders urged MISO to get language in front of FERC by Nov. 1 as planned.
MISO is also still weighing accelerating the creation of external resource zones in time for the 2017/18 PRA, ahead of the redesign implementation. Harmon said MISO was going to come back at the November meeting with a suggested approach, even though five of nine responding stakeholders were in favor of holding off on external zones until the 2018/19 planning year.
Dynegy’s Volpe said MISO not making a decision by October would make a 2017/18 implementation out of the question, though Harmon disagreed. In response to another question from Volpe, Harmon said it was possible that Tariff language would be presented by the next RASC meetings.
CARMEL, Ind. — Facing a FERC complaint from transmission customers, MISO last week defended its calculation of sub-regional transfer limits for the 2016/17 Planning Resource Auction and recommended that it continue to use the same numbers for future auctions.
The RTO made its recommendation based on stakeholder feedback it received, which shows general support for maintaining the status quo, said Kevin Sherd, director of forward operations planning, during a presentation at the Oct. 5-6 Resource Adequacy Subcommittee meeting.
MISO calculates the transfer limits between its North and South regions by deducting firm reservations from 2,500 MW for flows South to North and 3,000 MW for North to South. The initial transfer limits were prescribed in the RTO’s settlement with SPP that became effective in February.
Last month, a coalition of transmission customers filed a challenge to the results of the PRA with FERC, arguing that the limits are too strict and trapped capacity in MISO South, driving up clearing prices. (See MISO, IPPs Ask FERC to Reject Bid to Redo Capacity Auction.)
Six of 11 stakeholder respondents to a MISO survey on the issue endorsed deducting all firm reservations, while three wanted only pseudo-ties subtracted, and one apiece wanted nothing subtracted and net reservations subtracted. Seven recommended maintaining the current initial limits, with the minority split between using 1,000 MW or another method altogether.
Sherd said MISO doesn’t have much of a choice in subtracting firm reservations. “It’s firm transmission service. Firm transmission reservations can be scheduled at any point. It can’t be reduced absent a transmission congestion event,” he said.
But some stakeholders at the meeting disagreed that all firm reservations are absolute and must be subtracted.
In this year’s State of the Market report, MISO’s Independent Market Monitor recommended subtracting “a derating factor that represents the probability that MISO neighbors will request a derating” of the current initial limits.
“MISO is saying there’s no room for redispatch when all of the firm transmissions are subtracted,” Monitor Michael Chiasson said. “We’re saying there has to be something in between. … What’s the chance of that really being the norm and what’s the more likely case?”
| MISO
Steve Leovy, a transmission engineer at WPPI Energy, agreed and said a “probabilistic” approach was needed.
But ITC Holdings’ Ray Kershaw said he had never heard of using transmission-use probability. “We can throw out terms like ‘probability,’ but I don’t know of a method for calculating the probability of transmission use. There are certain things that need to be assumptions; there’s the [loss-of-load] expectation, I understand that. Could someone put this method down on paper?”
Leovy said MISO should make a best effort to estimate expected system capability and not focus so much on making sure it does not exceed the limit under any circumstances.
Sherd said it would be an “administrative nightmare” to track individual firm reservations and monitor the likelihood of it being used. “It’s not on a planning year basis; it’s on a daily, weekly, monthly basis,” he said.
According to MISO, the Monitor’s suggestion is not allowed, as MISO and SPP’s settlement agreement forbids a “unilateral” lowering of the sub-regional limit.
Firm Flow Limits Study
Rather than the existing initial limits or 1,000 MW, one stakeholder suggested a study of firm flow limits to establish new initial limits.
Per that request, MISO reviewed market flows compared with firm flow limits on several days this summer, examining 19 Tennessee Valley Authority flowgates that experienced transmission loading relief anytime in 2016. The analysis, MISO said, showed that South-to-North market flows “would generally be firm at flows near or above 2,500 MW.” The RTO said only one of the analyzed flowgates averaged below 2,500 MW.
MISO said it plans to continue reviewing transmission loading relief annually. The RTO is seeking final feedback on reusing the limit approach in the PRA by Oct. 12. MISO staff plan to review a limit proposal at the Nov. 2-3 RASC.
Per SPP and MISO’s settlement, firm transmission reservation holders have until Dec. 1 to confirm or cancel service above 1,000 MW for planning year 2017/18. MISO will publish its sub-regional import constraint and sub-regional export constraint values for the 2017/18 PRA before March.
Dynegy’s Mark Volpe asked if MISO could even discuss its North-South contract limit plans given the complaint at FERC.
“I think given the complaint is public and MISO’s response is public, there should be very little issue in discussing it,” MISO’s Jacob Krause said.
Massachusetts regulators have rejected fees National Grid sought to impose on small commercial and industrial customers that own distributed energy resources (15-155).
In an order approved Sept. 30 that granted the utility a $101 million rate increase, the Department of Public Utilities rejected proposed monthly charges for new stand-alone DER, including solar and wind. The customers who are most likely to be affected by the proposal include local governments and community-aggregated solar projects, which are intended to benefit low-income ratepayers and those otherwise unable to install solar panels on their own homes.
Solar Cell Panels on Gillette Stadium Roof | Wikipedia
National Grid had sought to impose the fees to help cover the fixed costs of the distribution grid and avoid shifting them to other ratepayers.
Regulators agreed with opponents who said the company failed to justify the charge or demonstrate cost-shifting. “With the exception of interval meters, the company has not quantified the costs that it contends stand-alone DG facilities impose on its distribution system,” the DPU wrote.
It did approve a $1 increase from the $4 minimum monthly charge for residential customers and a one-time interconnection charge of $28 for distributed resources to cover the application process.
National Grid had proposed a fixed fee of up to $20 for residential customers based on usage and $30 for small commercial customers.
A law passed in the spring by the Massachusetts legislature opened the door for the company to collect a “monthly minimum reliability contribution” (MMRC) for customers who receive net metering credits. (See Massachusetts Raises Net Metering Cap, Cuts Payments.)
The law also allows for the consideration of an access fee once solar capacity reaches 1,600 MW statewide, a threshold expected next year. National Grid has met its share of that total.
The DPU agreed with opponents of the proposal that the fees did not qualify as MMRCs because the rate case was filed before the law’s enactment. It also said that once the 1,600-MW threshold is passed, a fee could be considered in a separate proceeding.
The company had proposed a monthly access fee of $7/kW, reduced by an assigned capacity factor (40% for solar and 30% for wind). National Grid said the fee was necessary to recover its costs for the operation and maintenance of the transmission and distribution grids and the increase in costs it says will result from further penetration of distributed resources.
Several intervenors contended that the proposal ran contrary to Massachusetts’ efforts to have its rate design more accurately reflect market conditions.
“Reforms to electricity rate design must strike a careful balance between economic efficiency, equity for all customers, protection of low-income ratepayers and access to community distributed generation,” Mark LeBel, staff attorney at Acadia Center, said in a statement.
AUSTIN, Texas — Industry insiders last week gathered here for the Gulf Coast Power Association’s 31st Annual Fall Conference, which featured presentations on ERCOT pricing and the effect of market forces, as well as discussions on distributed generation, Mexico’s reformed energy market, wholesale market design and efficiency improvements, new developments on ERCOT’s seams, current cyber threats and cross-border transmission issues with Mexico.
Taking a look at current market conditions, the opening panel discussed what the future will hold. Sam Newell, a principal with The Brattle Group, said should solar costs continue to drop, it could replicate what ERCOT saw in the early years of the 21st century.
“At the beginning of the market, we built out [gas-fired combined cycle plants] in spades, and that’s why prices were so low,” he said. “I think that could happen with solar. [If I] were thinking about investing in traditional power gen in this market, I’d be worried because of that prospect. If we get 25-MWh, all-in solar, that will just kill prices for everybody else.”
“I think [pricing] is as big an issue for the coal,” said Bob Helton, director of market design and policy for ENGIE. “If you look at capacity factors, a baseload coal plant runs at 88, 89%. They’re running today down in the 30s. I think you will potentially see some changes in operations. It’s like my car is not running, but I’m not about to put new tires on it. You’re going to see some of those issues in maintenance that are going to change for coal plants with large capital expenditures.”
“Many generators [in ERCOT] have another revenue stream from their integrated retail side,” pointed out Charles Griffey, president of Peregrine Consultants. “Retail margins are very, very high right now in certain sectors of the market.”
“It’s in the best interest of the ERCOT market for us to be constantly moving forward, whether it’s real-time co-optimization, which is brought up by the [Independent Market Monitor] from time to time, or something else,” said ERCOT COO Cheryl Mele during her panel’s discussion on balancing efficient markets with economics. “We need efficiency, we need reliability and we need people to get behind us and support us when we have reliability issues.”
“We all put ERCOT in a tough spot,” Market Monitor Beth Garza said. “We want the highest and best and most impartial decisions out of that organization, but they’re also responsible to their members. Sometimes those interests aren’t always advocated for. … We expect the highest and best, but that’s never good enough. There is a role for the [Public Utility Commission of Texas] in some of these decisions that is even higher and broader than ERCOT and its stakeholder organization. It seems like that’s at a level at which disparate interests can be effectively adjudicated.”
“If ERCOT is a democracy, then the PUC is a benevolent dictator,” responded Barbara Clemenhagen, vice president of market intelligence for Customized Energy Solutions. “If the recommendations are coming from ERCOT and IMM, they should be based on perfect information. It may not always be correct, but the stakeholders have the right and the opportunity to weigh in on those things.”
Randa Stephenson, vice president of wholesale markets for the Lower Colorado River Authority, also defended ERCOT’s stakeholder process. “Even though there are different advocates, the voting structure is very balanced within ERCOT. Our communications and structure ensures there’s equal weighting of all the market participants,” she said. “We have to find ways to work together to find the best solution. When you have the pull and tug, we’re going to come out with very different compromise solutions.”
Mexican market participants can buy and sell power, ancillary services, financial transmission rights and clean energy certificates (CELs). The first auction of energy and CELs last year saw an average price of $48/MWh, which decreased to $33/MWh in this year’s second auction. Regulo Salinas, vice president of Ternium Mexico, said he is optimistic about the third auction.
“That is where the private sector will come in,” he said, welcoming their expertise. “We need more specialized people that understand the markets. We have hardly any of them in Mexico … traders, meteorologists, pricing, financial and accounting specialists. … It’s an opportunity for intelligent communication types to come into Mexico.”
“I’m confident we are on the right path. There’s plenty to be done, but plenty has already been achieved,” said Eduardo Andrade, a member of the advisory board for Mexico’s Energy Regulatory Commission. “We have a framework based on competition. As a country, we’re moving away from having the government looking over your shoulder and determining who should generate the electricity and at what price.”
Panelists credited Jeff Pavlovic, managing director of electric industry coordination for Mexico’s Ministry of Energy, with much of the market’s success, though he politely declined to accept their praise. “Our guiding principle has been to make as many decisions as possible and not give any more control to the government than is absolutely necessary,” said Pavlovic, who left Xcel Energy eight years ago to work on the Mexican market.
“We know a lot of companies are interested in the market,” he said. “We’re asking them to make big investments, and that takes information. We’ve been doing this one step at a time, but until all rates are public, it will be hard to get that investment.”
Enrique Giménez Sainz de la Maza, managing director of The Blackstone Group affiliate Fisterra Energy, said the “next challenge” is developing a retail market. “Without a robust retail market, I have my doubts about the wholesale market.”
ERCOT Frontera Tie to Mexico | Fisterra Energy
Fisterra owns the 524-MW combined cycle Frontera plant in Mission, Texas, just 2 miles from the Mexican border. Frontera only recently withdrew from the ERCOT system and dispatches power into Mexico through a DC tie and a 400-kV line. “We now have something very interesting. We have a market on both sides … one is an energy market, the other is an energy capacity market. At the end of the day, we have managed to develop the reality of a market in Mexico thanks to this interconnection.”
Gerardo Serrato, InterGen Mexico’s commercial director, said future interconnections will only help the price convergence between the two markets. “Theoretically, those prices have to converge, but reliability issues might stop that convergence. Not all the Mexican systems are interconnected. If they can interconnect the whole system, we can see convergence between the Mexican and U.S. system.”
Genscape’s Rick Margolin said strengthening the energy infrastructure between Mexico and the U.S. will only feed further economic development. The senior natural gas analyst pointed to the NET Mexico Pipeline that connects the Agua Dulce Hub in South Texas with Monterrey in northern Mexico as an example.
“Gas prices aren’t what Mexican consumers can get by tapping into the U.S. market, so there’s a major push to gain access to the international markets, which means primarily the U.S.,” Margolin said. “Consumers are insanely frustrated by the level of service they get from [Mexico’s national gas supplier] Pemex. Global manufacturers are very interested in expanding operations into the Mexican market. Mexico has more trading partnerships than the U.S., but they’re hesitant … because of the lack of service or reliable service. We’re seeing a massive buildout of both gas and power infrastructure to the border.”
Dynegy CEO Shares Thoughts
Dynegy CEO Robert Flexon celebrated his company’s emergence from bankruptcy in 2012 and its entry into ERCOT earlier this year with the acquisition of almost 4,000 MW of ENGIE combined cycle gas turbines. Fifteen percent of Dynegy’s capacity is part of the Texas ISO.
“ERCOT’s view around generating assets tends to be fuel neutral. They’re not trying to create winners and losers; they’re trying to create a competitive market,” Flexon said. “We like our position, we like the assets we have. The market is going to continue to have need for flexible resources. The way wind affects price formation and with solar shaving peak pricing, it’s just going to be a really difficult environment for non-flexible resources to survive that.
“Is the price signal going to be there to change the resources?” he asked. “Will it force Texas into a situation where we’re doing out-of-market things? We hope Texas doesn’t do that.”
Anil Kumar, a senior research economist and adviser for the Federal Reserve Bank of Dallas, said the regional economy is expanding at a moderate pace, thanks to “robust” job growth in services and goods-producing sectors overcoming oil prices in the $40s. “Sharp drops in oil prices used to drop us into a recession, but that’s no longer the case,” he said, pointing to an unemployment rate of 4.7%, slightly below the national average. “We are probably looking at the worst of the energy bust being over.”
October being National Cyber Security Awareness Month, it was only appropriate one of the GCPA panels examine the growing cyber threats to electric utilities and how to fend them off. Renee Tarun, deputy director of the National Security Agency’s Cyber Task Force, warned attendees that external cyberattacks are growing increasingly sophisticated.
But she also said not to ignore the dangers from inside.
“We’re seeing these attacks surface as more and more technologies are connected to the Internet. We’ve seen ransomware becoming more prevalent. We’re seeing nation actors develop specific harmful code. These different types of malicious actions can range from hackers in their basement to sophisticated nation actors,” Tarun said.
“But there’s also the uniformed user, someone accidentally clicking on a phishing link that introduces malware to the network. It’s important we leverage our technologies to be more automated in our defenses, but also the user being educated in the system as well. Security needs to be built in at the beginning, not as an afterthought.”
“I would say 50% [of cyberattacks] are pure human negligence,” said Boris Segalis, a partner with Norton Rose Fulbright. “Vendors can lose track of hard drives that include critical customer data … small companies may not vet the vendor … not having your anti-virus up to date … you can’t really prevent hackers, but humans can take measures to mitigate the effects of these incidents.”
Asked by an audience member whether cybersecurity insurance is available, moderator Doug Henkin, a partner with Baker Botts, said insurance brokers do specialize in the product, but “it’s a growing market that essentially didn’t exist. It’s not a simple insurance to buy, it’s not a simple insurance to be underwriting. With respect to anti-virus software, you might be underwriting 15,000 different companies, but those companies are using five to 10 subsets of the software.”
Developers Look Beyond ERCOT’s Seams
Bill Bojorquez, vice president of planning for Hunt Transmission Services, suggested ERCOT’s DC ties with Mexico — which include a connection through Hunt subsidiary Sharyland Utilities — could provide an alternative to building more transmission in the Rio Grande Valley.
“We believe these ties … give ERCOT the ability to say, ‘Wait a minute, we have an extra tool’ and call their neighbor when there are unplanned outages,” said Bojorquez, who helped develop the ERCOT market while at the ISO in the early 2000s. “One of the things I’m most proud of is establishing relationships with Mexican utilities. They have the ability to respond in emergency situations, and they are highly motivated because it helps with trade.”
David Parquet, senior vice president of special projects for Pattern Energy, is looking eastward instead. His company’s HVDC Southern Cross Transmission Project, a project six years in development, is scheduled to connect ERCOT with the Southeast in 2021.
“If you think back 10, 15 years ago when the whole renewable business started, there was a lot of low-hanging fruit where you could find wind relatively close to load,” he said. “Those days are gone. Today’s big efficient renewable projects are a long way from load so therefore, you have to think about transmission. Sometimes, you can hook up to the local grid through a wheel, or you can put together your own project.”
But Parquet reminded his audience that transmission projects across the seam must “ensure no change in FERC jurisdiction over flows into ERCOT. [Maintaining ERCOT’s independence] is the Holy Grail. You will not change that. Period. Full stop.”
“In planning the future of the grid, we’re very much looking at distributed generation resources,” said Oncor’s Don Clevenger, senior vice president of strategic planning. “The numbers are still small, but they really don’t tell the whole story as far as looking ahead into the future. … Last year, only one-third of our feeds had any DG; today, it’s half. In four to five years, that [growth] is going to be astronomical.”
“If you look at overall capacity, 80% of the DG installed throughout the [ERCOT] system by the end of 2016 will be dispatchable. We’ll have close to a gigawatt by the end of the year,” said Greg Thurnher, general manager for regulatory policy with Shell Energy North America. “We’re very interested in that gigawatt as it becomes very intelligent as far as price. You will have a comparable playing field for wholesale resources when they act as true resources … and have the ability to influence the price.”
Austin’s Pecan Street Project, a collaboration between the University of Texas at Austin, Austin Energy, city officials and industry and environmental representatives, has been testing DG’s “intelligence.”
“We can manage every single circuit in the house,” said the project’s engineering director, Scott Hinson. “It’s a rather granular management … air conditioning controls, creating an electric vehicle charging control, looking at solar controls … things as simple as pointing the solar panels west, so their peaking output is available later in the day.”
Renewables Key to Texas’ CPP Compliance
Participating in a panel discussing the Clean Power Plan’s potent effects on the Texas market, the Environmental Defense Fund’s John Hall said the state is already “90% closer” to compliance, thanks primarily to its abundant renewable resources. “We currently produce more wind power than any other state. We have more potential for solar, energy efficiency and demand response than any other state,” he said.
“From our perspective, the market in Texas and our vast, clean-energy assets are putting us in a position where the market is driving us to the use of clean-energy resources,” Hall continued. “We have an opportunity to take the massive clean-energy resources we have and we can significantly rebuild this economy.”
“There may be permanent coal-plant reductions that occur as a part of the Clean Power Plan, but fuel diversity is going to suffer,” said a more cautious Susana Hildebrand, Energy Future Holdings’ director of environmental policy. “It affects our power prices, because there may be a day where for whatever reason, you need coal or baseload plants to be available. Betting on the future of natural gas prices doesn’t always work out.”
Greg Sopkin, a partner with Wilkinson Barker Knauer, warned about increased costs to rural customers. “Urban areas have a lot more customers to spread around the costs,” he said. “If you’re talking about forcing a change on rural areas in a very short period of time by shutting down baseload plants, you’re looking at real, very significant costs.”
WASHINGTON — The Supreme Court’s stay of the Clean Power Plan has largely ended the progress states were making toward creating regional frameworks for compliance, says Alexandra Dapolito Dunn, executive director of The Environmental Council of States (ECOS).
But even the most coal-dependent states are pondering ways to reduce their carbon footprints, she told a panel discussion at the Energy Bar Association’s Mid-Year Energy Forum last week.
“‘Carbon-considered’ is [the term used by] states that might have at one time been questioning whether or not there was climate change,” said Dunn, whose organization represents state environmental officials. “They’ve come around now.
“I think states will be more open to bringing renewables into their [generation] mix than they may have been before,” she explained. “There are companies that are located in very coal-oriented states that are already projecting ahead with their boards of directors and their shareholders to bring in a little bit of renewables, a little wind, a little solar, do some research and development in battery technology. You might not have seen that before.”
Two CPP opponents told the EBA forum that even if the EPA rule withstands legal challenges by states and utilities, its implementation will likely be delayed. The D.C. Circuit Court heard arguments on challenges to the rule on Sept. 27. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
“The likelihood of this rule being implemented the way it was finalized in August of last year is getting lower all the time,” said former EPA General Counsel Roger Martella Jr., of Sidley Austin. If the rule is upheld, he said, its 2030 deadlines could be pushed back to 2032 if the court also “tolls” the deadlines to account for inaction during the stay.
Allison Wood of Hunton & Williams, who argued before the D.C. Circuit on behalf of non-state challengers, agreed. Wood said the postponement of the D.C. Circuit arguments, which had originally been scheduled for June, means no Supreme Court review is likely until its next term, starting October 2017.
Dunn said the stay ended discussions among state officials on the technical issues concerning compliance, such as the development of emission trading programs.
“There were some really fantastic forums … where people were really putting their noses to the grindstone and trying to sort out these technical questions,” she said. “I almost wish we were still putting the same level of intensity into sorting out some of these questions that probably will be part of any future … carbon-managed environment.”
While some states are continuing their work and renewable generation is continuing to benefit from technological innovation, she said, “People are definitely following their own playbook at this point.”
The proposed protocol — which would continue on a smaller scale than the New York-PJM-New York flows of the wheel — has attracted criticism from stakeholders, which continued at last week’s PJM committee meetings. The influence and resiliency of phase angle regulators received some scrutiny from Citigroup Energy’s Barry Trayers at the Operating Committee meeting.
| PJM
“In a way you can kind of be picking winners and losers by adjusting [their] flows,” he said, asking how they had been factored into the grid operators’ guidelines for developing the replacement protocol.
“We consider PAR moves just like switching: a non-cost move that we’ll do prior to redispatching generation,” PJM’s Mike Bryson explained. “If we start running up against some of the either daily or monthly PAR adjustments, we’re going to have to take a step back and say, ‘Are we moving them too often? What’s the impact?’”
One challenge for the new protocol: One of the PARs on the 5018 line at Consolidated Edison’s Ramapo facility is not functional, which limits the ability to export power to NYISO. The grid operators have identified 1,800 MW as the maximum that needs to be available for export to NYISO, but the nonfunctional PAR limits PJM’s export capability to 1,400 MW.
While the future of Con Ed’s PAR has received a lot of discussion from other stakeholders, PJM has not received any details on when or if it will be fixed. One plan under review is to compensate by adjusting flows on the western interconnections across the Pennsylvania-New York border.
PJM and NYISO are currently working on updates to their joint operating agreement, which PJM will present upon completion for stakeholder review. NYISO plans to begin its stakeholder approval process at the end of October and complete it by January, which would allow the grid operators to make a joint filing to FERC later that month.
Stakeholders Urged to Submit Unit-Specific Parameter Adjustments
Generation unit operators have until Feb. 28 to submit adjustments to their unit-specific parameters, but PJM is urging them to begin the process as soon as possible because it can take several weeks.
PJM is aiming to have the status of delivery year 2017/18 adjustment requests posted by April 15. Parameters will be implemented in June. Any adjustments that are already approved remain valid, PJM’s Alpa Jani said, and don’t require resubmittal. Requests will receive a case identification number, with which requesters will be able to look up their current status through the RTO’s online member portal.
eDART Improvements Will Slow in Anticipation of Overhaul
PJM’s eDART system is getting an overhaul to incorporate new functionality, including single sign-on. To allow staff the time necessary to develop the new system, refreshes of the current system will be reduced to only those that are operationally necessary.
What won’t be changing are the business rules, the system interfaces or email notifications, said PJM’s Chidi Ike-Egbuonu. “One thing we can agree on is that it’s going to be a multiyear project; it’s not going to happen overnight,” she said.
PJM Moving Flat-File Data to Data-Management Tool
Raw data files are becoming too cumbersome and are being retired in favor of access through PJM’s Data Miner 2 tool, the RTO’s Thomas Zadlo explained. The tool will allow access to all data that is currently being stored on flat files, including five-minute settlements. Progress on the transition will be shared with stakeholders through PJM’s new Tech Change Forum.
WASHINGTON — “Pernicious subsidy” or “rough justice”?
Audience members got to decide for themselves how to characterize net metering for rooftop solar generation during a debate at the Energy Bar Association’s Mid-Year Energy Forum last week.
Richard L. Roberts, head of the electric group at Steptoe & Johnson, said it’s unfair that rooftop solar owners are paid retail prices as high as $0.13/kWh for the power they inject into the grid while central station generators are paid wholesale rates of about $0.04/kWh.
As a result, a customer whose solar panels generate energy equal to their consumption for the month “pays nothing for their electric service. They pay nothing for the reserves that they’ve been given. They pay nothing for transmission. They pay nothing for distribution. They pay nothing for public purpose programs, all of which go into retail service.”
Scott Hennessey, SolarCity’s regulatory counsel and vice president of policy and electricity markets, responded by citing a Sept. 30 ruling by the Massachusetts Department of Public Utilities last week that he said found rooftop solar provided more benefits than costs to the state’s grid. (See related story, Regulators Reject DER Surcharge in Rate Case.)
Glick | RTO Insider
He dismissed as a “common trope” the notion that rooftop solar is only for the “wealthy and well meaning.” The introduction of smart inverters allows rooftop solar to provide voltage support and other services to the grid, he said, while the introduction of financing options makes it available to the middle class.
Also participating in the discussion — though not staking a position on either extreme — was Mark Glick, administrator for the State Energy Office in Hawaii, a state that has provided a cautionary tale for regulators as generous subsidies have threatened to overwhelm the islands’ grids with solar generation.
Utility-Scale vs. Distributed Solar
Hennessey | RTO Insider
The session, moderated by Caileen Gamache of Chadbourne & Parke and Matthew R. Rudolphi of Duncan, Weinberg, Genzer & Pembroke, also touched on the virtues of distributed versus centralized solar generation.
“The question of whether or not [rooftop solar is] harmful to the grid or harmful to the average consumer I would turn around,” Hennessey said. “When you have infrastructure purchased by a utility and then spread across the entire rate base — with a fat profit, by the way, for the utility — that is a choice made decades in advance — and I think we’ve seen now, not always with the best of foresight,” he said. “Whereas when you have solar and the other distributed energy resources I’ve mentioned, that’s private investment in infrastructure that then benefits everyone around, with less peaking generation required.”
Hennessy said utilities that want to develop large-scale solar should be required to use a nonutility business unit rather than competing with other developers by using the utility’s low cost of capital and other advantages.
“What we’ve found is that every time they have tried that they have failed and they’ve had to close up shop, as [Arizona Public Service] did in Arizona.”
Jurisdictional ‘Mess’
Roberts | RTO Insider
Roberts said the Supreme Court’s FERC v. Electric Power Supply Association ruling, which preserved FERC’s right to regulate demand response, left a “jurisdictional mess” because the commission has no authority over net metering sales. Such sales should be a FERC-regulated wholesale sale under the Public Utility Regulatory Policies Act (PURPA), he said.
Roberts also cited studies showing utility-scale solar is two to three times more efficient than rooftop solar.
The rush to distributed generation could repeat the kind of mistakes California regulators made with the first retail choice program in the 1990s, which resulted in overpayments to qualifying facilities under PURPA and politicized integrated resource processes, he said.
“The goal of grid modernization should be to allow — without preferences or without predetermining who’s the winner and who’s the loser — equal access to all of these forms of technology to compete against each other and then wait and see where the next innovations come from,” he said.
“Nobody knows what the next big technological breakthrough is going to be. It might be large-scale generation, and if we’ve skewed our investments in the grid toward microgrid or small-scale [generation], we could find ourselves once again looking at investments and wondering why we did that.”
Hawaii’s Glick said “there’s no doubt” that utility-scale solar is cheaper than distributed resources. “But ultimately that will change and we have to allow the market to develop while that change occurs,” he said.
