Page 1328 – RTO Insider

April 13, 2017

Utilities Ask to be Kept in Loop on DER Installations

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM invited two distributed energy resource developers to explain their operations and presented a case study of its own at Monday’s special session of the Market Implementation Committee. The presentations elicited concern from electric distribution companies, who asked that rules be implemented that keep them informed when customers want to install such systems.

“We simply need to know what’s happening before it happens and not after the fact. That will give us the opportunity to determine what needs to be done,” FirstEnergy’s Bruce Remmel said.

Calpine’s David “Scarp” Scarpignato said stakeholders could benefit from EDCs providing information to PJM on such interconnections. “A lot of small [projects] can add up to big numbers,” he said. “It seems to me like the notification should go two ways.”

PJM discussed a recent visit by staff members to Hopewell Valley Central High School in Pennington, N.J., where Public Service Electric and Gas has installed a solar and battery system. The 580-kWh Hopewell battery is an “in front of the meter” system but doesn’t qualify as an “energy storage resource,” PJM staff said, because it is primarily a backup power system for the school during an outage and therefore doesn’t fit the definition of a storage resource. Instead, it’s accounted for under “station power” rules, even though it provides regulation, capacity and energy services to the RTO.

DER market implementation committee — Hopewell Valley Central High School Solar Storage Project | *PJM*

PJM’s Andrew Levitt, who led the presentation, explained that a resource can be designated either in front of the meter — meaning it’s able to provide capacity and energy services — or behind the meter, meaning it can be used to net against load for wholesale transmission, capacity and ancillary services charges. The same megawatts cannot be used for both simultaneously, he said.

Drew Adams of A.F. Mensah and Adesh Harripersad of Distributed Asset Solutions highlighted how their businesses have handled installations of both types of resources in PJM.

It was A.F. Mensah’s problem statement and issue charge that precipitated development of the special sessions, borne out of the challenges faced with PJM’s policies on how systems combining batteries and renewables must be interconnected. (See PJM Considering Injection Rights for Demand Response.)

The company has moved forward with projects using the existing rules while they’re being discussed in this stakeholder process.

Adams highlighted some of the challenges and experiences when complying with all existing rules. Adams said his company paid a $500 application fee for each of 20 installations and that the installations are aggregated in PJM’s models as a single 0.1-MW market resource. He presented diagrams showing how the projects require two separate electric service lines to an end customer site: one for the existing service line including behind-the-meter solar panels, and a new service line for the battery storage system so its capabilities can be sold directly into PJM. The battery system acts independent of the customer load and solar in normal operation and is then connected to the load and solar through redundant switch gear during a bulk grid outage.

He explained that the systems have five meters, each providing different information to different recipients. FirstEnergy’s Ed Stein said that creates concerns because partial information may make it impossible to fully understand what’s going on with a system.

“Ultimately, I think there will be a lot more information sharing between EDCs, transmission owners [and] PJM,” Stein said. “We’re going to have to come up with an information-sharing paradigm that works for everybody. We may find ourselves that not one single entity has all of the information or ownership of all information at its disposal to give. … We’ve got a lot to consider with information here: who’s going to have it, who’s going to provide it, who’s going to be able to see it and access it and understand it.”

Adams said his company is supportive of those discussions.

Harripersad discussed the coordination issues that make project development and construction difficult. He works with funding provided by True Green Capital Management to develop photovoltaic solar arrays throughout the country. Even with long lead times — with delays created by the need to secure everything from state environmental approvals to local construction permits — projects are often a rush at the end, he said.

“All these things add up to, literally, down to the wire; you have three months to build everything,” he said. “The big thing is getting our projects interconnected.”

He praised project coordination among stakeholders within PJM’s footprint. “This coordination is unheard of in any other [RTO or ISO] territory in the country,” he said. He referenced a 16.7-MW solar rooftop project with the Port of Los Angeles in which he said CAISO has “no involvement.”

Work began on collecting stakeholder interests and potential solutions but didn’t get far, only advancing to design component 1.2. PJM staff assured this would be a main focus for the group’s next meeting.

April 13, 2017

California to Reconsider Retail Choice

By Robert Mullin

More than two decades after initiating a deregulation drive that faltered in the wake of the Western Energy Crisis of 2000/01, California officials are taking another look at offering consumers the ability to choose their electric supplier.

This go-round should be different, according to the state agencies heading up a new exploration of “the changing state of retail choice” in California, because of changes already in motion.

“Unlike electricity restructuring efforts of the past, when policymakers made a set of conscious decisions to move to open market competition, this transition is being driven by a range of economic and technological trends,” the California Public Utilities Commission and California Energy Commission said in a joint statement April 11.

To kick off the effort, the two agencies will hold a May 19 joint en banc public hearing to identify the “challenges and opportunities” stemming from “fast-approaching” changes overtaking the industry. The goal is “to ensure that reliable and low-carbon electricity will be available to all California consumers,” the agencies said.

Key among the factors now influencing the sector: the rapidly falling costs for renewable and energy storage technologies, which the CPUC and CEC say are “upending the nature of electricity service.”

The agencies estimate that by the end of this year, up to 40% of the state’s investor-owned utility customers will be receiving “some type” of electricity service from an alternative source, such as rooftop solar, community choice aggregators (CCAs) and direct access providers.

California officials are reconsidering the idea of “consumer choice” for retail electricity customers who continue to pay some of the highest rates in the country. Efforts would focus on giving more residents affordable access to renewable resources that help the state meet its environmental mandates. | *U.S. Energy Information Administration, Form EIA-861, “Annual Electric Power Industry Report.”*

California today boasts nearly 5,200 MW of installed rooftop solar capacity, according to California Distributed Generation Statistics, a website sponsored by the CPUC and the state’s IOUs. The state also has six CCAs, with more slated to begin operation within the next few years, a development that is expected to increasingly siphon off the customer base from the traditional IOUs.

“The implications of this migration away from ‘bundled’ utility service were not fully contemplated when the current regulatory rules were developed,” the agencies said.

The changes provide “tremendous opportunities” for California to meet its carbon reduction goals, but they will also create “unforeseen risks,” the agencies said.

The May 19 hearing will offer a closer examination of those opportunities and risks. A preliminary agenda indicates the event will start with a presentation on a still-pending CPUC white paper on retail choice, followed by an overview of the current state of retail choice in California and panel discussions focused on the perspectives of both the IOUs and electricity customers.

The agencies will also invite national electricity market experts to share their perspectives on retail choice in other regions, the role of technology in transforming electricity service and how California can restructure its regulatory framework and markets to help achieve its public policy goals.

California last set a course for deregulation in 1996 with the enactment of Assembly Bill 1890. Under the law, regulators first set out to restructure the state’s wholesale market while leaving retail price controls intact. The ensuing crisis — which resulted in the 2001 bankruptcy of wholesale market operator California Power Exchange — precluded the implementation of any retail market measure. Wholesale operations now reside with CAISO, which in 2009 rolled out a nearly statewide energy market designed to prevent the kind of manipulation that crippled the exchange.

April 12, 2017

Western Regulators Supportive of EIM Charter Changes

By Robert Mullin

Western state utility commissioners on Monday expressed support for providing the Energy Imbalance Market (EIM) Governing Body with increased authority over changes to the market’s governing charter.

The commissioners also agreed on a set of measures that would streamline the process for convening calls and meetings of their own EIM-related group, the Body of State Regulators (BOSR).

BOSR members were scheduled to hold a nonbinding vote on whether to endorse the charter revisions during the April 10 teleconference, but the group fell two members short of a quorum, which requires the presence of commissioners from five of the eight states in the EIM footprint.

In an April 5 memo, CAISO management proposed that any “substantive” modifications to the charter be first presented to the Governing Body for its “advisory” input — similar to the role body members play regarding ISO market rule changes that also affect the EIM. (See EIM Charter Changes Would Give Governing Body More Power.) The ISO initiated the move at the request of Governing Body Chair Kristine Schmidt.

Other revisions would enable the Governing Body to initiate changes to portions of the charter dealing with the BOSR and the Regional Issues Forum.

The Governing Body plans to present the changes to the CAISO Board of Governors, which is charged with reviewing any charter amendments during its May meeting. The board must formally approve any changes to the charter, but in practice it gives wide latitude to the Governing Body’s decisions on solely EIM matters. Timelines dictate that the amendments will advance without the BOSR’s formal endorsement, which is not required.

The state commissioners who spoke on Monday’s call voiced their informal support for the changes. No one expressed any opposition. They were relying, in part, on the advice of the commissions’ staffs.

“The official recommendation from the Advisory Committee is that you approve and support [the changes] to the Governing Body,” said Brian Thomas, policy director with the Washington Utilities and Transportation Commission and a member of the EIM Staff Advisory Committee.

Thomas noted that WUTC Commissioner and BOSR Chair Ann Rendahl — who couldn’t participate in the call because of a schedule conflict — supported the changes.

Changes ‘Make Sense’

CAISO EIM western state utility commissioners — White

Utah Public Service Commissioner Jordan White agreed with the staffs’ recommendation and the CAISO memo outlining the changes.

“It makes sense,” White said. “It’s consistent with how the charter works in terms of certain issues that go to [the] consent [agenda] of the full Board of Governors.”

“I don’t see any reason that we would oppose it, but it sounds like we’re not making any decision today, so I’ll take a look and get back with everyone,” said Oregon Public Utility Commission Chair Lisa Hardie.

White apologized to Schmidt for his group’s inability to provide full approval.

“Thank you very much for going ahead with the discussion,” Schmidt replied. “Because if there were some issues or concerns that any of the Body of State Regulators would have, we would want to know about that.”

The submission of a written recommendation from the Advisory Committee would be helpful to the Governing Body in its own deliberations, she added.

“I can write something up that summarizes what the staff committee did and recommended and provide that to you,” Thomas responded.

Speaking on behalf of the BOSR, White told Schmidt: “We appreciate the opportunity to at least have a say in this.”

‘Willingly Pay’

Commissioners also backed proposals to allow CAISO to post BOSR meeting agendas on the ISO’s website and to use its audio conferencing system to host calls.

Among those voicing support for the move was White, who pointed out that Rendahl and her WUTC staff had been “carrying the water” of setting up the agendas and conducting BOSR meetings.

western state utility commissioners, eim, caiso — Colussy | © *RTO Insider*

“We had reached out to [Rendahl] and mentioned that we would be happy to host and just try to take some of that administrative burden off of the group,” said Peter Colussy, CAISO external affairs manager.

“I think we’re comfortable with that,” Hardy said. “It seems like that would functionally work just fine from our perspective.”

“Speaking for the Washington staff that’s been doing this, we would willingly pay CAISO to take over this stuff,” Thomas joked.

The commissioners also endorsed the idea of subsuming the BOSR’s infrequent in-person meetings into those held by the EIM Governing Body.

“I think the jury is still out on how often to have [BOSR] meetings,” White said.

Because of the lack of quorum during the April 10 call, the meeting-related proposals were tabled by the BOSR until its next call on May 30.

April 11, 2017

PJM Outlines Aggregation Rules for Upcoming Capacity Auction

By Rory D. Sweeney

VALLEY FORGE — PJM staff on Friday detailed how the new rules for aggregating seasonal resources will be implemented in May’s Base Residual Auction, the first requiring all resources meet tougher Capacity Performance standards.

FERC staff tentatively approved PJM’s aggregation proposal March 21, allowing the RTO to relax current rules prohibiting seasonal resources from aggregating across locational deliverability areas (LDA) (ER17-367). PJM’s plan also creates additional winter capacity interconnection rights (CIRs) and modifies rules for measuring demand response performance in the winter. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)

The May BRA, which will provide capacity for delivery year 2020/21, will only procure resources available year-round, ending PJM’s longstanding use of summer-only DR and energy efficiency.

PJM’s Pete Langbein, Paul Scheidecker and Jeff Bastian told the Demand Response Subcommittee on Friday that there will be two aggregation categories:

Commercial aggregation, in which a market seller will match seasonal resources on its own and offer them together as a single year-round capacity resource. All resources must be within a single capacity market seller account.
Facilitated aggregation, in which seasonal resources offer into the BRA individually and will be grouped with complementary resources by PJM.

Eligible for aggregation will be intermittent generators, energy storage, environmentally limited resources, DR and energy efficiency. Winter resources (November-April) would be matched with summer resources (June-October and the following May).

PJM will clear all annual CP offers, summer-period offers and winter-period offers simultaneously to minimize the cost of satisfying the reliability requirements of the RTO and each modeled LDA. Total cleared summer-period offers must exactly equal total cleared winter-period offers across the entire RTO to ensure coverage for the entire year.

Commercial resources must be submitted to PJM for analysis and approval no later than two weeks before the BRA, or April 26.

When commercial offers are submitted, they must include an explanation of how the aggregation achieves a higher CP ability (measured in unforced capacity megawatts) than the resources individually. PJM will respond with the approved megawatt offer and what LDA the aggregate will be modeled in.

Cleared resources will receive a blend of the clearing prices of the LDAs in which the resources are located, Langbein said. Market sellers are guaranteed that the blend will be at least the resources’ cleared offer prices.

Seasonal resources can be replaced using a “similarly located” resource from any source, whether it’s an annual CP resource or an appropriate seasonal one. They can also be replaced in an Incremental Auction but would need to be bought in the same LDA the resource is physically located in.

For commercial aggregates, replacements can be from any LDA but must be available CP resources or cleared CP buy bids. “What you are not able to do is go in and replace the constituent components of your aggregate,” Langbein said. “So you can’t go in and replace the wind farm, for example, that’s part of your commercial aggregate.”

PJM demand response capacity auction — | *PJM*

Resources’ production during performance assessment hours (PAHs) will be netted between all of the resources required to perform during the PAH. Penalties for shortfalls and credits for overperformance will be assessed to the aggregate resource, not individual resources.

NRG Curtailment Solutions’ Brian Kauffman asked whether a resource in the same zone as the PAH that is not required, but that performs anyway, would be included as overperformance in the assessment. Bastian confirmed that it would automatically be included in PJM’s calculations.

April 11, 2017

Ex-Trump Transition Chief: Energy Efficiency ‘Had a Good Run’

By Rich Heidorn Jr.

WASHINGTON — Energy efficiency now accounts for about 1.9 million jobs in the U.S., with double-digit growth projected for 2017.

So how can the Trump administration reconcile its pledge to create jobs with the president’s proposed budget cuts to the Energy Department’s research programs, which have been credited with helping to improve energy efficiency technologies?

energy efficiency trump transition team — McKenna | © *RTO Insider*

“The EE folks have had a pretty good run for the last eight years and it’s time to rebalance a little bit,” energy lobbyist Michael McKenna told the Energy Bar Association’s annual meeting last week.

“You look at the DOE numbers, it tells you everything you need to know. $2.4 billion goes to EE and $670 million goes to the clean coal office and $430 million goes to the nuclear [power] industry [research],” said McKenna, president of MWR Strategies and former lead of President Trump’s transition team for the Energy Department. “The vibe is, let’s rebalance and to the extent possible take the government out of the equation. You can think that’s a good idea or a bad idea. But that’s the idea.”

(Lowell Ungar, senior policy advisor for the American Council for an Energy-Efficient Economy, cites somewhat different figures for fiscal year 2016. The Office of Energy Efficiency and Renewable Energy received $2,069 billion, but that includes both efficiency and renewables: Nuclear received $986 million, which includes funding for research beyond power plants; fossil fuels — coal, oil, etc. — $632 million.)

“Of course, how much it makes sense to spend in a given area depends on the potential impacts of the technologies, on how developed the industries are and thus able to support their own research, and on DOE’s capabilities to manage effective projects in the area,” Ungar said.)

McKenna, a registered lobbyist who has represented Southern Co., Koch Industries and GDF SUEZ, resigned from the official transition team last November after Trump announced that no registered lobbyists would be permitted on the “landing teams” that met with agency officials.

McKenna and Shannon M. Bañaga — another lobbyist whose role on the official transition team was cut short by Trump’s directive — recounted their experiences as members of the transition team and their predictions on the next four years for a luncheon audience. Thomas J. Pyle, president of the Institute for Energy Research and former lead of the Energy transition team, canceled his appearance because of an illness.

“What that really meant was that the lobbyists — I think were two or three of us — got about quadruple the amount of work, and the official transition and Tom Pyle, our colleague, was able to meet with DOE … and those of us unsavory lobbyist-types, we got to meet with the rest of the industry and hear about the issues that” concerned them, she said.

“I can’t express to you how many man-hours were put into very specific ideas about what FERC should be working on in the next couple years; what DOE should and shouldn’t be working on,” said Bañaga, an attorney who worked previously for both FERC and Energy and now serves as TECO Energy’s director of federal affairs.

Slow Start

McKenna acknowledged the new administration has been somewhat slow in filling vacancies.

“I know from the outside things look confused,” he said. “Truth to be told, it isn’t any worse than any other transition. The one thing that [they] had a little trouble with is the switch out from the campaign to post-election. And that has shown up in personnel. We have about 497 appointments throughout the federal government that require Senate confirmation. As of four or five days ago, we had about 43 guys in the queue. So we’re a little slower than everybody else. It will probably get better as it goes along. But in all fairness, [he] came in with a Supreme Court justice waiting to happen so that absorbed a lot of mindshare.”

‘Ignore the Circus’

He had advice for those troubled by the Twitter-happy president. “Ignore the circus,” he said. “The president is a fellow who’s used to being on the camera and in the news and chewing up a lot of mindshare. And the media has not yet figured out that sometimes the best thing to do is just [ignore him]. I come from a large Irish Catholic family, and we have a tendency to say, ‘Just give him the nod. Whatever you say, boss.’

“Ignore the circus. Pay attention to what … he actually gets done. And if you think about that, everything that’s been done is pretty much everything you would expect that was going to be done. … From the first time he articulated … what he wanted to do on energy, he hasn’t wavered a lot. … It’s been pretty consistent.”

Electric Role in Infrastructure Bill

Responding to an audience question, Bañaga said utilities are unlikely to seek federal funding for capital expenditures in the infrastructure legislation Trump has promised. “So much of what we [utilities] do is critical infrastructure. From the pipes and wires … we tend to like paying for our own stuff. That’s part of the business [model] and I don’t think we’re going to be very boisterous on saying that we want fed government money for an infrastructure project.”

Banaga (left) and McKenna | © *RTO Insider*

She said the industry would support efforts to increase workforce training in “STEM” fields — science, technology, engineering and mathematics — in the bill and perhaps cybersecurity.

“Depending on what we’re asked to protect against and the standards we’re going to be held accountable for, cyber and physical security, I think that might be one that gets rolled into an infrastructure package.”

“We’re going to get infrastructure built,” McKenna promised. “The president didn’t run on tax reform. He ran on infrastructure. We’re going to build infrastructure.”

What would it include? “Anything that involves concrete,” he responded.

Changes at FERC?

Another questioner asked whether FERC was likely to be subject to the Trump requirement that agencies eliminate two regulations for every new one.

“I work in front of a lot of federal agencies like a lot of you do,” McKenna said. “The bottom line is, FERC process is, FERC people are the best in the government. So are the [FERC] nominees … going to want to take a hard look at things? Of course. Are they going to wander in knocking things over? I don’t think so.”

April 11, 2017

SPP Briefs

Two SPP stakeholder groups have endorsed staff’s recommendation to remove a Southwestern Public Service 345-kV line from projects recommended in the 2017 Integrated Transmission Planning 10-year assessment.

The Transmission and Economic Studies working groups met jointly April 3 to vote on staff’s re-evaluation of the 90-mile Potter-Tolk transmission line in the Texas Panhandle, one of 14 projects in the 2017 ITP10.

spp m2m payments potter-tolk transmission line — | © *SPP*

SPP’s Board of Directors and Members Committee directed staff in January to further evaluate the transmission line following pushback from SPS, which said it was “the wrong time” for the line. (See “Board Sends $144M Tx Project Back for Re-evaluation,” SPP Board of Directors/Members Committee Briefs.)

Staff gathered feedback from members in the West Texas/New Mexico area to determine expectations on resource expansion, load growth, gas prices and avoided reliability projects. A third-party review using more detailed routing assumptions increased the project’s $144 million cost estimate to $173 million, identifying a need to lengthen the project from 90 miles to 109.

ITC Holdings abstained from both working group votes, saying it believes “more realistic analysis scenarios” provide support for including the project in the ITP10 portfolio. Golden Spread Electric Cooperative abstained from the ESWG vote, citing positive benefit-cost ratios for the scenarios that included 8.8 GW of additional wind. South Central MCN abstained from the TWG vote over concerns with the re-evaluation process and modeling updates and adjustments.

Separately, the TWG unanimously approved the 2017 ITP near-term assessment, which includes 16 reliability projects at a combined cost of approximately $60 million. The Markets and Operations Policy Committee and board will vote on the near-term ITP and take up the Potter-Tolk recommendation at their April meetings.

MISO Tops $15M in M2M Payments to SPP

MISO has paid SPP a net $15.3 million in market-to-market payments since the two RTOs began M2M activity in March 2015, SPP’s Will Ragsdale told the Seams Steering Committee on April 5.

MISO is responsible for seven of the top 10 congested flowgates between the two RTOs, resulting in $12.7 million in M2M payments. SPP has paid MISO $4.3 million for the other three flowgates in the top 10.

SPP’s M2M report for February indicates MISO paid just more than $889,950 for 434 hours of binding temporary and permanent flowgates.

MMU Market Report Shows Wind Up, Coal Down

Wind energy accounted for almost a quarter of all energy produced this winter, according to the SPP Market Monitoring Unit’s State of the Market report released last week.

Wind generation produced 23% of the footprint’s energy this winter (December-February), compared to 18% in 2016 and 15% in 2015. That corresponded with a drop in coal-fueled production, to 52% from nearly 58% in 2015.

The MMU said gas costs continue to rise in the region, with an average of $3.08/MMBtu at the Panhandle Hub, compared to $1.98/MMBtu in 2016. The rise in gas costs also resulted in increased LMPs; the average real-time LMP went from $17.82/MWh in 2016 to $24.57/MWh, and the average day-ahead LMP went from $18.33/MWh to $24.14/MWh.

— Tom Kleckner

April 11, 2017

MISO Stakeholders Question Electric-Gas Info Sharing

By Amanda Durish Cook

CARMEL, Ind. — MISO is preparing nondisclosure agreements and associated Tariff language to share gas usage estimates with pipeline operators, but some stakeholders are voicing reservations about the pilot program.

The RTO says the nondisclosure agreements will be required before staff of pipelines or local distribution companies can view hourly burn estimates based on the day-ahead market clearing. “MISO will not share any information before that signed nondisclosure agreement,” Mark Thomas, MISO manager of gas-electric coordination, told the April 6 Reliability Subcommittee meeting.

MISO has lined up three gas system operators for “limited sharing” of day-ahead gas usage profiles in 2017 under the pilot program, an effort to ensure gas-fired generators have fuel when they need it.

The RTO said it will outline the use of the nondisclosure agreements in section 38.9.1(A) of its Tariff and file the changes with FERC by April 26. Thomas asked for stakeholder comment on the language insertion by April 13.

MISO said it would wait for FERC acceptance before sharing profiles. Thomas said the RTO has not yet determined at what frequency the information would be provided.

Multiple stakeholders voiced apprehension that reliability will be harmed if operators act on partial, estimated data provided by MISO. Subcommittee Chair Tony Jankowski questioned why the RTO would move ahead on the program with what he said was incomplete data based solely on day-ahead market activity.

Phil Van Schaack, MISO gas-electric operations coordinator, reminded stakeholders that the program is a pilot and insisted the sharing of generator start and stop times and estimated burn rates will be helpful. “This is a way to start the exchange of some data,” Van Schaack said. “The pipeline operators are excited by this.”

Thomas said if the pilot program does result in the sharing of “bad information,” MISO will scrap the program.

Indianapolis Power and Light’s Lin Franks said that while she is usually “all for” the sharing of information, the pilot program could cause problems. If MISO’s information clashes with generator operators’ information, they might be in the position of defending their efficiency, she said.

“You’re feeding the public frenzy of challenging other people’s data, if this becomes public,” she said. “This does absolutely nothing for resource adequacy.”

MISO said the pilot was authorized by FERC Order 787, which allows RTOs to share nonpublic information with gas operators. Previously, staff has said that the RTO is not attempting to influence generator behavior with the use of hourly profiles. (See MISO to Continue Gas-Electric Coordination Efforts in 2017.)

“MISO believes that sharing nonpublic, operational information with gas system operators can increase reliability for both industries,” the RTO said in a presentation. “Gas usage profiles, notably in severe operating conditions, will increase fuel assurance and reliability for gas-fired generators and will facilitate lines of communication with gas system operators.”

April 11, 2017November 13, 2023

ERCOT Board of Directors Briefs

Wind energy and other renewable resources are providing so much of ERCOT’s generation mix that not even the ISO can keep up.

Delivering his CEO report to the Board of Directors, Bill Magness said ERCOT on March 23 had finally reached the 50% wind penetration mark — a percentage he said would have reached 55% had another 1,500 MW of wind energy not been curtailed. (See ERCOT Reaches 50% Wind Penetration Mark.)

Not included on the slide, which was produced to meet an earlier board deadline for the April 4 meeting, was ERCOT’s latest record for wind generation. That came March 31, when the ISO reported 16,141 MW of wind generation at 8:56 p.m., almost 40% of the total load.

The previous record came last Christmas, when ERCOT saw 16,022 MW of wind generation.

ERCOT has 18,064 MW of installed wind capacity, with just more than 10,000 additional megawatts that have interconnection agreements, according to its latest generator interconnection status report.

The ISO has also seen a rapid increase in solar energy, Magness said, though not at the scale of wind resources. He said ERCOT’s solar capacity nearly doubled in 2016; it currently has 556 MW of capacity and another 2,009 MW have interconnection agreements.

To help address the continued increase in variable generation, ERCOT has added a sixth desk in its operations center that is focused on reliability risk. The new desk went live in January and will respond to wind and solar forecasts errors, net load ramps, low inertia and variable ancillary service needs.

“Because of our changing resources, certain things have grown over time to be much bigger issues than they traditionally have been,” ERCOT Senior Director of System Operations Dan Woodfin told the board in a separate presentation.

Woodfin was recently honored by the Utility Variable-Generation Integration Group with an award for “sustained leadership” in integrating variable generation. He said reliability risk increases as more renewables are added to the Texas grid.

“We have the same percentage of forecasting error, but the number of [renewable] megawatts in any given hour will be higher,” Woodfin said. “We want to assess them in real time, not just quarterly or at the beginning of the year.”

“The things we’re doing and the investments we’re making are just part of the day-to-day business as we adjust to these changes,” Magness said.

He said training staff would be a “big priority” the next couple of years. “We’re training our operators and giving them as much simulation of the conditions they’re seeing on the grid they’ve never seen before. We’re taking as much advantage as we can of our operational expertise to prepare for the future.”

Higher Capacity Factors Increase Wind Energy’s Output

The Independent Market Monitor’s report picked up on the renewables discussion, with Director Beth Garza highlighting wind energy’s growing share of ERCOT’s fuel mix. Wind produced 15% of ERCOT’s power last year, up from 3% in 2007. Coal has seen its fuel share drop from a high of 40% in 2010 to a low of 28% in 2015, while gas has ranged from 38 to 48%.

“More wind is displacing some of the fossil fuels as the price disparities between gas and coal change through time,” Garza said.

She attributed much of the growth to wind energy’s higher capacity factors, a “reflection of improving and increasing technology.” Garza said the Monitor is also seeing an increase in installations on the Gulf of Mexico because the “wind output coincides more with load requirements” peaking in the afternoon.

Raising the question as to whether coal is “on the way out,” Garza pointed out that ERCOT’s coal fleet is “vintage.”

“What we see with our coal fleet,” she said, “is that the bulk of it was installed in the 70s and 80s. It’s achieving the end of its economic life as we speak.”

Ending Greens Bayou RMR to Save $21.9M

Magness told the board that terminating NRG Texas Power’s Greens Bayou Unit 5 reliability-must-run contract early will save the ERCOT market $21.9 million. He credited efforts made by staff and stakeholders to change protocols and criteria for reviewing RMR contracts, saying they “clearly had a big impact and allowed us to make this change.”

He also pointed to the Public Utility Commission of Texas’ RMR rulemaking, which is currently open to comments. The rule changes include requiring board approval of RMR contracts and adjusting the notice requirements and complaint timeline applicable to suspending a resource’s operation. (See “PUC Approves ERS, RMR Rulemakings,” Texas PUC Briefs.)

The Greens Bayou RMR contract was approved last June and scheduled to last through June 2018. It was expected to cost the market more than $58 million, but that number was revised down to $43.9 million in February. Instead, the early termination means ERCOT will only have made $22.1 million in standby payments to NRG at $3,185/hour during on-peak hours for the Houston-area plant.

ERCOT announced the contract’s termination in February. It said studies using new criteria indicated the unit would not be needed for transmission system reliability after Exelon’s 1,148-MW Colorado Bend II Generating Station in nearby Wharton County becomes operational in June. (See ERCOT Ending Greens Bayou RMR May 29.)

Magness also told the board that ERCOT now declares level 3 energy emergency alerts (EEA3) when operating reserves hit 1,375 MW, as required by NERC reliability standard EOP-011-1.

The ISO’s normal operating procedure had been to declare an EEA3 and load shed when reserves fall to 1,000 MW. It has revised its procedures to still go into load shed at 1,000 MW but declare the EEA3 earlier. Staff is drafting a revision request to change the EEA3 trigger in the protocols.

“Our studies have indicated as long as we have sufficient responsive reserves, we’re able to maintain and not need to go into load shed until 1,000 MW,” Magness said.

Dallas Fed: Texas Surviving an Oil Bust

Mine Yücel, senior vice president and research director for the Federal Reserve Bank of Dallas, once again delivered an annual report on the Texas economy, saying the state has survived the recent energy bust “with few deep scars.”

Yücel pointed to a 2.7% employment growth rate and 54,500 jobs created in the first two months of 2017, this after a 1.7% growth rate and 203,000 new jobs last year. The Fed is projecting a 2.3% growth rate and 280,000 new jobs in Texas this year.

“The worst may be behind us, but of course, we have quite a few risks,” Yücel said, alluding to oil prices and the dollar’s strength.

Despite a slowdown in the Permian Basin and the rest of the oil patch, Texas still saw more than 210,000 people migrate to the state from July 2015 to July 2016. That was a drop from about 260,000 the year prior and trails Florida nationally, but still outpaces California, New York and Illinois.

Multi-Interval

ERCOT Commercial Operations Vice President Kenan Ögelman shared staff’s Multi-Interval Real-Time Market (MIRTM) feasibility study with the board, getting little pushback with his recommendation that now is not the right time to implement the market.

Ögelman said the estimated $20 million cost of the market’s software would not produce sufficient production cost savings. The Technical Advisory Committee reached the same conclusion last month. (See ERCOT Technical Advisory Committee Briefs.)

“The study found there were production cost savings, but that was in the environment of $2 to $3 gas,” he said. “Unless you see gas prices driving up, I’m trying to create savings off a very low baseline price.”

ERCOT dispatches its market in five-minute intervals. Staff and stakeholders have been discussing potential alternatives under different names (look-ahead security-constrained economic dispatch, multi-interval SCED, etc.) since 2011.

“The question has been, can we improve the market’s efficiency and functionality by looking ahead longer than five minutes. At 15 minutes, we were more accurate with the forecast, but we left a lot of resources behind,” Ögelman said, referring to fast-responding resources and load resources that currently participate in the real-time market through voluntary self-commitment.

Ögelman said the TAC had assigned the Wholesale Marketing Subcommittee to consider whether real-time co-optimization might be a better solution to pursue. The subcommittee held a preliminary discussion April 5.

“It’s been dormant for a while,” Ögelman said of the optimization discussions. “There’s a need to get everyone up to speed on how it works.”

Board Approves 16 Revision Requests

The board’s consent agenda, approved unanimously, included 10 nodal protocol revision requests (NPRRs) and three revisions to the Planning Guide (PGRRs).

NPRR776: Aligns protocol language with currently used verbal communication practices between transmission service providers (TSPs), qualified scheduling entities (QSEs) and generation resources. Also identifies new requirements for data that TSPs provide to ERCOT, QSEs and generators. The committee tabled NOGRR167, which aligns the Nodal Operating Guide with NPRR776.
NPRR799: Requires that TSPs and resource entities — generation and load that can reduce electricity usage or provide ancillary services — submit updates to the outage scheduler within one hour of the facility’s outage start or completion.
NPRR802: Clarifies current settlement practices and protocol language, including how reliability unit commitment resources opting out of RUC settlement are treated in calculating real-time online reserve capacity.
NPRR804: Clarifies that ERCOT should post both a systemwide network model and a set of station one-line diagrams, and that the model posting does not disclose data about private-use networks.
NPRR808: Extends the congestion revenue right (CRR) auction process into the third year forward, revises the percentages sold in the auction’s long-term sequence and aligns modifying load zones to the timetable.
NPRR809: Defines the terms “initial energization” and “initial synchronization;” adds a reference to a quarterly stability assessment for interconnecting generation resources when evaluating the need for a generic transmission constraint; and clarifies a resource’s requirements prior to initial synchronization.
NPRR810: Removes the applicability of an RMR’s incentive factor to reservation and transportation costs associated with firm-fuel supplies, and accordingly separates costs in the RMR standby payment equation.
NPRR812: Clarifies short-term system adequacy report language; aligns protocol language with current ERCOT practices and Texas PUC rules for posting resource and load information; and modifies the requirement for posting a RUC initial-conditions report to only include the process as originally intended in NPRR314.
NPRR813: Requires references to service organization controls for the annual ERCOT market settlement audits.
NPRR818: Clarifies that the ISO can curtail DC tie loads during a watch, before declaring an emergency condition. (See ERCOT Stakeholders OK Change to DC Tie Curtailments.)
PGRR052: Ensures a new generating unit’s operating limits are established by setting a timeline for stability studies following a full interconnection study (FIS), incorporating model data or transmission system changes, not known during the FIS, before a new unit is brought online.
PGRR054: Clarifies the content, review period and process for posting an FIS’ results, and establishes a process for identifying, proposing and implementing solutions to stability issues identified during the FIS.
PGRR055: Defines the process for revising the Planning Guide to first consider PGRRs at the subcommittee level.

— Tom Kleckner

April 10, 2017

Stakeholders Advance on Western Regional Forum Proposal

By Robert Mullin

Participants in a West-wide forum created by CAISO to discuss issues related to the Energy Imbalance Market (EIM) want to move quickly to complete an evaluation that will shape the group’s future role.

One point of difference has arisen among stakeholders: disagreement over whether the Regional Issues Forum (RIF) should produce its own recommendations on matters affecting the EIM.

RIF members are in “considerable” alignment over what structure and procedures the group should adopt within the EIM’s governance framework, according to a draft issue paper detailing members’ evaluations.

They also agree they can meet a July deadline to present the EIM’s Governing Body with a final proposal outlining the RIF’s procedures and responsibilities.

The RIF was established in 2015 as CAISO began its effort to expand its operations into other parts of the West. The forum was conceived under the EIM charter as an informal body to allow stakeholders and the public to discuss wide-ranging issues related to the West’s only real-time energy market.

Five Sectors

The forum is organized along five industry sectors: independent power producers and power marketers; transmission-owning utilities; publicly owned utilities; consumer advocates; and balancing areas neighboring the EIM. Each sector appoints two liaisons as representatives.

The EIM charter calls for the Governing Body and stakeholders to begin re-evaluating the continued existence of the RIF this month.

During a Feb. 28 joint meeting of the Governing Body and RIF, a consensus emerged that the RIF should be preserved. (See Western Stakeholders Support Continuing Regional Forum.)

But one “existential” question arose, according to Governing Body Vice Chair Doug Howe: What’s the RIF’s purpose?

Stakeholders and their liaisons are still seeking to develop an answer.

The issue paper notes that the RIF’s operating guide “is limited in detail” but “clearly contemplates the possibility of the RIF providing recommendation or written work products on issues.” The guide also allows the group to establish a procedure to express a common position.

caiso eim western regional forum proposal — Braun | © *RTO Insider*

“Of all the issues that we got written comments on, the issue that the RIF acting through the liaisons should produce written opinions or recommendations on market design issues was clearly the one in which we got the most disparate comments,” RIF Chair Tony Braun said during an April 7 call to discuss the issue paper.

Powerex opposes the RIF making any formal recommendations, contending that the group’s membership is limited and does not represent the market as a whole. The company wants the RIF to be opened up to a larger number of sectors.

“We think that the current sector definitions are fairly inclusive,” Braun said, speaking on behalf of the liaisons, adding that “if there are additional improvements we need to make in that regard, we certainly would encourage comments.”

Disagreement over RIF Work Products

PacifiCorp, the EIM’s first member, said the RIF should only produce summaries of stakeholder discussions and comments on particular issues, while Portland General Electric thinks that positions should be communicated only by individual stakeholders or “voluntary alignments” of sectors.

Both the California Municipal Utilities Association and Puget Sound Energy recommend maintaining the option of generating written opinions, but only under “detailed” procedures setting out how to produce the papers and capture majority and minority positions. The Natural Resources Defense Council, Public Generating Pool (PGP), Western Resources Advocates and the EIM’s Body of State Regulators (BOSR) largely backed that view.

While the liaisons acknowledged that producing position papers would increase the RIF’s workload and change the character of the group’s meetings, Braun said they wanted to retain the option of producing written work.

“We’ve created … a trigger whereby written work products would be triggered by specific requests,” Braun said. “The requests would come from the EIM governance structure and also would come with a host of procedures that would need to occur.”

Therese Hampton, a liaison from PGP, pointed out that stakeholders generally agreed that the RIF should continue to meet three times a year but reserve the option to convene more frequently if issues warrant — or if requested by the BOSR, the Governing Body or stakeholders. The issue paper suggests that RIF meetings be coordinated with those of the Governing Body, a position with strong stakeholder support.

RIF liaison Matt Lecar, principal at Pacific Gas and Electric, pointed out that the liaisons were proposing a quorum provision requiring at least one liaison from each sector to attend each meeting.

Sara Edmonds, general counsel at PacifiCorp Transmission, said the liaisons have so far discerned “no obvious need” for changes to the EIM’s governing charter or the RIF’s operating guidelines.

“We also note that there would be a need for the ISO’s legal department to take a look at the governance documents following the conclusion of this reevaluation process,” Edmonds said.

Stakeholder comments on the proposals set out in the draft issue paper are due May 3.

“We appreciate all the attention and input that we’ve gotten in the RIF meetings,” Braun said. “And we’d greatly encourage stakeholder comment, because we can’t anticipate all the issues in here.”

April 10, 2017

MISO to Make Up Manitoba Hydro Reserves During Spring Outages

By Amanda Durish Cook

CARMEL, Ind. — Manitoba Hydro will reimburse MISO for providing extra contingency reserves during May, when maintenance outages are expected to reduce transfer capability between the Canadian utility and the RTO.

The MISO/Manitoba Hydro Contingency Reserve Sharing Group has a 2,000-MW contingency reserve requirement, with MISO ordinarily supplying 1,850 MW and Manitoba Hydro responsible for 150 MW.

Although Manitoba Hydro expects bountiful water supplies for May, maintenance outages will reduce the transfer limit between it and MISO below normal minimum cleared energy levels for the month, officials told the April 6 Reliability Subcommittee (RSC) meeting.

Following discussions between MISO staff and the Manitoba Hydro Electric Board, the RTO agreed to clear the utility’s share of contingency reserves, resulting in an additional 60 MW of spinning reserves and 90 MW of supplemental reserves.

Manitoba Hydro transfer capability miso — Swan | © *RTO Insider*

“Much of the [maintenance] work is on the U.S. side of the border, but the MISO-Manitoba transfer capability will be reduced … during the work,” said Steve Swan, MISO senior manager of dispatch and scheduling.

Swan said Manitoba Hydro will still have reserves but might not be able to supply them because of the outages. “I think rather than saying they have reserves, they’ll have water,” Swan said.

A Manitoba Hydro representative confirmed the utility will have sufficient water to supply reserves but could encounter difficulties delivering them because of insufficient transmission capacity.

The utility has agreed to reimburse the MISO loads charged for contingency reserves through a miscellaneous charge in settlements for the entire month because transfer capability will be difficult to forecast.

“We will be carrying them for the entire period, and they will be reimbursing us for the entire period,” Swan said. “This was the best solution we could come up with.”

Manitoba Hydro will post updated limits during maintenance to MISO’s OASIS site. Swan said changes to the RTO’s clearing requirement will begin April 31.

Stakeholders at the RSC meeting did not appear to have a problem with MISO’s plan.

“That’s what I think the market is for,” RSC Chair Tony Jankowski joked.

At this year’s Gulf Coast Power Association MISO South Regional Conference, MISO CEO John Bear said he wished the RTO boasted more hydro power in the footprint and that one of its biggest contingencies is the transmission line connecting it to Manitoba Hydro.

Manitoba’s hydro exports to MISO are expected to increase in 2020 when the 500-kV line Great Northern Transmission Line between the province and Minnesota is scheduled to go into service. (See Manitoba-Minnesota Tx Line Granted Rate Incentives.)

Belt-Tightening

Manitoba Hydro, which underwent a management restructuring in February, last week began offering voluntary buyouts in an effort to cut 15% of its workforce and save about $60 million, CBC reported. The utility’s debts — $13 billion debt as of late 2015 — could increase to $25 billion over the next three years, according to CBC.